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form10-q.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

	FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2009
OR
£	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

	FOR THE TRANSITION PERIOD FROM TO

______________________________

Commission file number 1-31447

CENTERPOINT ENERGY, INC.

(Exact name of registrant as specified in its charter)

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

1111 Louisiana
Houston, Texas 77002	(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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes 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 19, 2009, CenterPoint Energy, Inc. had 390,371,433 shares of common stock outstanding, excluding 166 shares held as treasury stock.

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CENTERPOINT ENERGY, INC.

QUARTERLY REPORT ON FORM 10-Q

FOR THE QUARTER ENDED SEPTEMBER 30, 2009

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PART I.	FINANCIAL INFORMATION

Item 1.	Financial Statements	1

	Condensed Statements of Consolidated Income
	Three and Nine Months Ended September 30, 2008 and 2009 (unaudited)	1

	Condensed Consolidated Balance Sheets
	December 31, 2008 and September 30, 2009 (unaudited)	2

	Condensed Statements of Consolidated Cash Flows
	Nine Months Ended September 30, 2008 and 2009 (unaudited)	4

	Notes to Unaudited Condensed Consolidated Financial Statements	5

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	29

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	45

Item 4.	Controls and Procedures	46

PART II.	OTHER INFORMATION

Item 1.	Legal Proceedings	46

Item 1A.	Risk Factors	46

Item 5.	Other Information	56

Item 6.	Exhibits	57

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

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

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

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 Texas Supreme Court regarding rulings obtained to date;

•

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

•

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

•

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

•

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

•

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

•

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

•

the timing and extent of changes in the supply of natural gas, including supplies available for gathering by our field services business;

•

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

•

weather variations and other natural phenomena;

•

changes in interest rates or rates of inflation;

•

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

•

actions by rating agencies;

•

effectiveness of our risk management activities;

•

inability of various counterparties to meet their obligations to us;

•

non-payment for our services due to financial distress of our customers;

•

the ability of RRI Energy, Inc. (RRI) (formerly known as Reliant Energy, Inc. and Reliant Resources, Inc.)

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

•

the ability of NRG Retail, LLC, the successor to RRI’s retail electric provider and the largest customer of CenterPoint Houston, to satisfy its obligations to us and our subsidiaries;

•

the outcome of litigation brought by or against us;

•

our ability to control costs;

•

the investment performance of our 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 II of this Quarterly Report on Form 10-Q 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

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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,
	2008			2009			2008			2009

Revenues	$	2,515		$	1,576		$	8,548		$	5,982

Expenses:
Natural gas		1,532			582			5,675			3,081
Operation and maintenance		371			415			1,078			1,226
Depreciation and amortization		194			208			540			562
Taxes other than income taxes		81			84			285			288
Total		2,178			1,289			7,578			5,157
Operating Income		337			287			970			825

Other Income (Expense):
Gain (loss) on marketable securities		(36	)		47			(73	)		68
Gain (loss) on indexed debt securities		33			(30	)		66			(54	)
Interest and other finance charges		(116	)		(126	)		(346	)		(384	)
Interest on transition bonds		(34	)		(32	)		(102	)		(98	)
Equity in earnings of unconsolidated affiliates		23			(3	)		46			8
Other, net		6			9			10			31
Total		(124	)		(135	)		(399	)		(429	)

Income Before Income Taxes		213			152			571			396
Income tax expense		(77	)		(38	)		(212	)		(129	)
Net Income	$	136		$	114		$	359		$	267

Basic Earnings Per Share	$	0.40		$	0.31		$	1.08		$	0.75

Diluted Earnings Per Share	$	0.39		$	0.31		$	1.05		$	0.74

See Notes to CenterPoint Energy’s Interim Condensed Consolidated Financial Statements

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CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Millions of Dollars)

(Unaudited)

ASSETS

	December 31, 2008		September 30, 2009
Current Assets:
Cash and cash equivalents	$	167	$	61
Investment in marketable securities		218		286
Accounts receivable, net		1,009		609
Accrued unbilled revenues		541		161
Natural gas inventory		441		225
Materials and supplies		128		148
Non-trading derivative assets		118		50
Taxes receivable		-		108
Prepaid expenses and other current assets		413		347
Total current assets		3,035		1,995

Property, Plant and Equipment:
Property, plant and equipment		14,006		14,463
Less accumulated depreciation and amortization		3,710		3,915
Property, plant and equipment, net		10,296		10,548

Other Assets:
Goodwill		1,696		1,696
Regulatory assets		3,684		3,701
Non-trading derivative assets		20		15
Investment in unconsolidated affiliates		345		471
Notes receivable from unconsolidated affiliates		323		-
Other		277		227
Total other assets		6,345		6,110

Total Assets	$	19,676	$	18,653

See Notes to CenterPoint Energy’s Interim Condensed Consolidated Financial Statements

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CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS – (continued)

(Millions of Dollars)

(Unaudited)

LIABILITIES AND SHAREHOLDERS’ EQUITY

	December 31, 2008			September 30, 2009
Current Liabilities:
Short-term borrowings	$	153		$	40
Current portion of transition bond long-term debt		208			221
Current portion of other long-term debt		125			339
Indexed debt securities derivative		133			187
Accounts payable		897			351
Taxes accrued		189			138
Interest accrued		180			139
Non-trading derivative liabilities		87			45
Accumulated deferred income taxes, net		372			425
Other		504			427
Total current liabilities		2,848			2,312

Other Liabilities:
Accumulated deferred income taxes, net		2,608			2,757
Unamortized investment tax credits		24			18
Non-trading derivative liabilities		47			42
Benefit obligations		849			851
Regulatory liabilities		821			916
Other		276			342
Total other liabilities		4,625			4,926

Long-term Debt:
Transition bonds		2,381			2,160
Other		7,800			6,667
Total long-term debt		10,181			8,827

Commitments and Contingencies (Note 11)

Shareholders’ Equity:
Common stock (346,088,548 shares and 390,331,500 shares outstanding at December 31, 2008 and September 30, 2009, respectively)		3			4
Additional paid-in capital		3,158			3,650
Accumulated deficit		(1,008	)		(944	)
Accumulated other comprehensive loss		(131	)		(122	)
Total shareholders’ equity		2,022			2,588

Total Liabilities and Shareholders’ Equity	$	19,676		$	18,653

See Notes to CenterPoint Energy’s Interim Condensed Consolidated Financial Statements

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CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS

(Millions of Dollars)

(Unaudited)

	Nine Months Ended September 30,
	2008			2009
Cash Flows from Operating Activities:
Net income	$	359		$	267
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		540			562
Amortization of deferred financing costs		21			29
Deferred income taxes		471			250
Unrealized loss (gain) on marketable securities		73			(68	)
Unrealized loss (gain) on indexed debt securities		(66	)		54
Write-down of natural gas inventory		24			6
Equity in earnings of unconsolidated affiliates, net of distributions		(45	)		(4	)
Changes in other assets and liabilities:
Accounts receivable and unbilled revenues, net		441			796
Inventory		(252	)		190
Taxes receivable		(289	)		(108	)
Accounts payable		(119	)		(527	)
Fuel cost over (under) recovery		(11	)		(53	)
Non-trading derivatives, net		(28	)		24
Margin deposits, net		(96	)		89
Interest and taxes accrued		(173	)		(93	)
Net regulatory assets and liabilities		(48	)		19
Other current assets		(2	)		(1	)
Other current liabilities		(6	)		(18	)
Other assets		(15	)		1
Other liabilities		(20	)		14
Other, net		(35	)		8
Net cash provided by operating activities		724			1,437

Cash Flows from Investing Activities:
Capital expenditures		(632	)		(809	)
Decrease (increase) in restricted cash of transition bond companies		(8	)		3
Decrease (increase) in notes receivable from unconsolidated affiliates		(175	)		323
Investment in unconsolidated affiliates		(207	)		(111	)
Other, net		31			12
Net cash used in investing activities		(991	)		(582	)

Cash Flows from Financing Activities:
Decrease in short-term borrowings, net		(82	)		(113	)
Long-term revolving credit facilities, net		737			(1,431	)
Proceeds from commercial paper, net		-			15
Proceeds from long-term debt		1,088			500
Payments of long-term debt		(1,373	)		(215	)
Debt issuance costs		(11	)		(4	)
Payment of common stock dividends		(183	)		(202	)
Proceeds from issuance of common stock, net		45			489
Other, net		1			-
Net cash provided by (used in) financing activities		222			(961	)

Net Decrease in Cash and Cash Equivalents		(45	)		(106	)
Cash and Cash Equivalents at Beginning of Period		129			167
Cash and Cash Equivalents at End of Period	$	84		$	61

Supplemental Disclosure of Cash Flow Information:
Cash Payments:
Interest, net of capitalized interest	$	447		$	507
Income taxes, net		188			57
Non-cash transactions:
Accounts payable related to capital expenditures		218			77

See Notes to CenterPoint Energy’s Interim Condensed Consolidated Financial Statements

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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). 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, 2008 (CenterPoint Energy Form 10-K).

Background. CenterPoint Energy, Inc. is a public utility holding company. CenterPoint Energy’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, 2009, CenterPoint Energy’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 Corp. own interstate natural gas pipelines and gas gathering systems and provide various ancillary services. A wholly owned subsidiary of CERC Corp. offers variable and fixed-price physical natural gas supplies primarily to commercial and industrial customers and electric and gas utilities.

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.

CenterPoint Energy’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 CenterPoint Energy’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 CenterPoint Energy’s reportable business segments, reference is made to Note 15.

(2)	New Accounting Pronouncements

Effective January 1, 2009, CenterPoint Energy adopted new accounting guidance which 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. These disclosures are included as part of CenterPoint Energy’s Derivatives Instruments footnote (see Note 5).

In May 2008, the Financial Accounting Standards Board (FASB) issued new accounting guidance on accounting for convertible debt instruments that may be settled in cash upon conversion (including partial cash settlement) which changed the accounting treatment for convertible securities that the issuer may settle fully or partially in cash. Under this new guidance, cash settled convertible securities are separated into their debt and equity components. The value assigned to the debt component is 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

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amount reflected as a debt liability is recorded as additional paid-in capital. As a result, the debt is recorded at a discount reflecting its below-market coupon interest rate. The debt is then subsequently 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. CenterPoint Energy adopted this new accounting guidance effective January 1, 2009, which required retrospective application to all periods presented. CenterPoint Energy currently has no convertible debt that is within the scope of this new guidance, but did during prior periods presented. Accordingly, the implementation of this new guidance had a non-cash effect on net income for prior periods and the consolidated balance sheets when CenterPoint Energy had contingently convertible debt outstanding. There was no effect on net income for the three months ended September 30, 2008. The effect on net income for the nine months ended September 30, 2008 was a decrease in net income of $1 million. There was no impact on basic or diluted earnings per share. Upon adoption of this new guidance, the effect on the balance sheet as of January 1, 2009 was a credit to Additional Paid-In-Capital of $23 million, with an offsetting debit to retained earnings.

In December 2008, the FASB issued new accounting guidance on employers’ disclosures about postretirement benefit plan assets which expands the disclosures about employers’ plan assets to include more detailed disclosures about the employers’ investment strategies, major categories of plan assets, concentrations of risk within plan assets and valuation techniques used to measure the fair value of plan assets. This new accounting guidance is effective for fiscal years ending after December 15, 2009. CenterPoint Energy expects that the adoption of this new guidance will not have a material impact on its financial position, results of operations or cash flows.

In April 2009, the FASB issued new accounting guidance on interim disclosures about fair value of financial instruments which expands the fair value disclosures required for all financial instruments to interim periods. This new guidance also requires entities to disclose in interim periods the methods and significant assumptions used to estimate the fair value of financial instruments. This new accounting guidance is effective for interim reporting periods ending after June 15, 2009. CenterPoint Energy’s adoption of this new guidance did not have a material impact on its financial position, results of operations or cash flows. See Note 13 for the required disclosures.

In May 2009, the FASB issued new accounting guidance on subsequent events that establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. This new accounting guidance is effective for interim or annual periods ending after June 15, 2009. CenterPoint Energy’s adoption of this new guidance did not have a material impact on its financial position, results of operations or cash flows. See Note 16 for the subsequent event related disclosures.

In June 2009, the FASB issued new accounting guidance on consolidation of variable interest entities (VIEs) that changes how a reporting entity determines a primary beneficiary that would consolidate the VIE from a quantitative risk and rewards approach to a qualitative approach based on which variable interest holder has the power to direct the economic performance related activities of the VIE as well as the obligation to absorb losses or right to receive benefits that could potentially be significant to the VIE. This new guidance requires the primary beneficiary assessment to be performed on an ongoing basis and also requires enhanced disclosures that will provide more transparency about a company’s involvement in a VIE. This new guidance is effective for a reporting entity’s first annual reporting period that begins after November 15, 2009. CenterPoint Energy expects that the adoption of this new guidance will not have a material impact on its financial position, results of operations or cash flows.

In June 2009, the FASB issued new accounting guidance on the FASB Accounting Standards Codification (Codification) and the hierarchy of generally accepted accounting principles. This new accounting guidance establishes the Codification as the source of authoritative U.S. generally accepted accounting principles recognized by the FASB to be applied by nongovernmental entities. Rules and interpretive releases of the Securities and Exchange Commission (SEC) under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. This new accounting guidance is effective for financial statements issued for interim and annual periods ending after September 15, 2009. CenterPoint Energy’s adoption of this new guidance did not have any impact on its financial position, results of operations or cash flows.

Management believes the impact of other recently issued standards, which are not yet effective, will not have a material impact on CenterPoint Energy’s consolidated financial position, results of operations or cash flows upon adoption.

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(3)	Employee Benefit Plans

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

	Three Months Ended September 30,
	2008						2009
	Pension Benefits			Postretirement Benefits			Pension Benefits (1)			Postretirement Benefits
	(in millions)
Service cost	$	8		$	-		$	7		$	-
Interest cost		25			6			28			7
Expected return on plan assets		(37	)		(3	)		(24	)		(2	)
Amortization of prior service credit		(2	)		-			-			-
Amortization of net loss		6			-			17			-
Amortization of transition obligation		-			2			-			2
Net periodic cost	$	-		$	5		$	28		$	7

	Nine Months Ended September 30,
	2008						2009
	Pension Benefits			Postretirement Benefits			Pension Benefits (1)			Postretirement Benefits
	(in millions)
Service cost	$	23		$	1		$	19		$	1
Interest cost		76			20			85			21
Expected return on plan assets		(111	)		(9	)		(73	)		(7	)
Amortization of prior service cost (credit)		(5	)		3			2			2
Amortization of net loss		18			-			51			-
Amortization of transition obligation		-			4			-			5
Net periodic cost	$	1		$	19		$	84		$	22

(1)

Net periodic cost in these tables is before considering amounts subject to overhead allocations for capital expenditure projects or for amounts subject to deferral for regulatory purposes. CenterPoint Houston’s actuarially determined pension expense for 2009 in excess of the 2007 base year amount is being deferred for rate making purposes until its next general rate case pursuant to Texas law. CenterPoint Houston deferred as a regulatory asset $8 million and $21 million in pension expense during the three and nine months ended September 30, 2009, respectively.

CenterPoint Energy expects to contribute approximately $22 million to its pension plans in 2009, of which $2 million and $19 million, respectively, have been contributed during the three and nine months ended September 30, 2009.

CenterPoint Energy expects to contribute approximately $26 million to its postretirement benefits plan in 2009, of which $8 million and $20 million, respectively, have been contributed during the three and nine months ended September 30, 2009.

Effective January 1, 2008, CenterPoint Energy adopted new accounting guidance on accounting for deferred compensation and postretirement benefit aspects of endorsement split-dollar life insurance arrangements which required CenterPoint Energy to recognize the effect of implementation through a cumulative effect adjustment to retained earnings or other components of equity as of the beginning of the year of adoption. CenterPoint Energy calculated the impact as negligible at the time of adoption on January 1, 2008. During the quarter ended June 30, 2009, CenterPoint Energy determined that its adoption calculation had omitted the impact that increasing future premium costs would have on the liability and, therefore, it recorded as a cumulative effect adjustment a $15 million correction to increase other non-current liabilities and accumulated deficit as of January 1, 2008. The effects of the correction on the previously reported accumulated deficit and net income for 2008 and for 2009 were not material to CenterPoint Energy’s financial position, results of operations or cash flows.

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(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.

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 $28 million.

CenterPoint Houston deferred the uninsured system restoration costs as management believed it was probable that such costs would be recovered through the regulatory process. As a result, system restoration costs did not affect CenterPoint Energy’s or CenterPoint Houston’s reported operating income for 2008 or the first nine months of 2009. In April 2009, CenterPoint Houston filed with the Public Utility Commission of Texas (Texas Utility Commission) an application for review and approval for recovery of approximately $608 million in system restoration costs identified as of the end of February 2009, plus $2 million in regulatory expenses, $13 million in certain debt issuance costs and $55 million in incurred and projected carrying costs, pursuant to the legislation described below.

In April 2009, the Texas Legislature enacted legislation that authorized the Texas Utility Commission to conduct proceedings to determine the amount of system restoration costs and related costs associated with hurricanes or other major storms that utilities are entitled to recover, and to issue financing orders that would permit a utility like CenterPoint Houston to recover the distribution portion of those costs and related carrying costs through the issuance of non-recourse system restoration bonds similar to the securitization bonds issued previously. The legislation also allowed such a utility to recover, or defer for future recovery, the transmission portion of its system restoration costs through the existing mechanisms established to recover transmission level costs. The legislation required the Texas Utility Commission to make its determination of recoverable system restoration costs within 150 days of the filing of a utility’s application and to rule on a utility’s application for a financing order for the issuance of system restoration bonds within 90 days of the filing of that application. Alternatively, if securitization is not the least-cost option for rate payers, the legislation authorized the Texas Utility Commission to allow a utility to recover those costs through a customer surcharge mechanism.

In its application filed in April 2009, CenterPoint Houston sought approval for recovery of a total of approximately $678 million, including the $608 million in system restoration costs described above plus related regulatory expenses, certain debt issuance costs and carrying costs calculated through August 2009. In July 2009, CenterPoint Houston announced that it had reached a settlement agreement with the parties to the proceeding. Under the terms of that settlement agreement, CenterPoint Houston would be entitled to recover a total of $663 million in costs relating to Hurricane Ike, along with carrying costs from September 1, 2009 until system restoration bonds were issued. The Texas Utility Commission issued an order in August 2009 approving CenterPoint Houston’s application and the settlement agreement and authorizing recovery of a total of $663 million, of which $643 million is attributable to distribution service and eligible for securitization and the remaining $20 million is attributable to transmission service and eligible for recovery through the existing mechanisms established to recover transmission costs.

In July 2009, CenterPoint Houston filed with the Texas Utility Commission its application for a financing order to recover the portion of approved costs related to distribution service through the issuance of system restoration bonds. As discussed above, in August 2009, the Texas Utility Commission issued a financing order allowing CenterPoint Houston to securitize $643 million in distribution service costs plus carrying charges from September 1, 2009 through the date the system restoration bonds are issued, as well as certain up-front qualified costs capped at approximately $6 million. In accordance with the financing order, CenterPoint Houston is to place into effect a separate customer credit related to accumulated deferred federal income taxes (ADFIT) associated with the storm restoration costs to be recovered. This separate credit (ADFIT Credit) is to be applied to customers’ bills to reflect the benefit of those deferred taxes at a carrying charge of 11.075%. The beginning balance of the ADFIT related to storm costs is approximately $207 million and will decline over the life of the system restoration bonds as taxes are paid on the system restoration tariffs. The ADFIT Credit will become effective on the same date as the tariff for the

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system restoration charges and will reduce operating income in 2010 by approximately $24 million. CenterPoint Houston expects to issue the system restoration bonds in the fourth quarter of 2009. Assuming system restoration bonds are issued, CenterPoint Houston will recover the distribution portion of approved system restoration costs out of the bond proceeds, with the bonds being repaid over time through a charge imposed on customers. CenterPoint Houston expects to recover the remaining approximately $20 million of Hurricane Ike costs related to transmission service through the existing mechanisms established to recover transmission costs.

In accordance with the orders discussed above, as of September 30, 2009, CenterPoint Houston has recorded a net regulatory asset of $642 million associated with distribution-related storm restoration costs and $20 million associated with transmission-related storm restoration costs. These amounts reflect carrying costs of $50 million related to distribution and $2 million related to transmission through September 30, 2009, based on the 11.075% cost of capital approved by the Texas Utility Commission. The carrying costs have been bifurcated into two components: (i) return of borrowing costs and (ii) an allowance for earnings on shareholders’ investment. During the three months and nine months ended September 30, 2009, the component representing a return of borrowing costs of $6 million and $20 million, respectively, has been recognized and is included in other income in CenterPoint Energy’s Condensed Statements of Consolidated Income. That component will continue to be recognized as earned until the associated system restoration costs are recovered. The component representing an allowance for earnings on shareholders’ investment of $32 million is being deferred and will be recognized as it is collected through rates.

(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.

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 (REPs); and

•

affirmed the True-Up Order in all other respects.

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

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

•

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

•

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

•

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

•

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

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

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

In June 2009, the Texas Supreme Court granted the petitions for review of the court of appeals decision. Oral argument before the court was held in October 2009. Although CenterPoint Energy 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, CenterPoint Energy 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, CenterPoint Energy 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 CenterPoint Energy’s consolidated financial statements. However, if the court of appeals decision is not reversed or modified as a result of further review by the Texas Supreme Court, CenterPoint Energy 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 $170 million to $385 million (pre-tax) plus interest subsequent to December 31, 2008.

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

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treatment, if required by the IRS, could have a material adverse impact on CenterPoint Energy’s results of operations, financial condition and cash flows in addition to any potential loss resulting from final resolution of the True-Up Order. In its opinion, the court of appeals ordered that this issue be remanded to the Texas Utility Commission, as that commission requested. No party, in the petitions for review or briefs filed with the Texas Supreme Court, has challenged that order by the court of appeals although the Texas Supreme Court has the authority to consider all aspects of the rulings above, not just those challenged specifically by the appellants. CenterPoint Energy and CenterPoint Houston will continue to pursue a favorable resolution of this issue through the appellate and administrative process. Although the Texas Utility Commission has not previously required a company subject to its jurisdiction to take action that would result in a normalization violation, no prediction can be made as to the ultimate action the Texas Utility Commission may take on this issue on remand.

The Texas electric restructuring law allowed the amounts awarded to CenterPoint Houston in the Texas Utility Commission’s True-Up Order to be recovered either through securitization or through implementation of a 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 REPs to recover the portion of the true-up balance not recovered through a financing order. The CTC Order also allowed CenterPoint Houston to collect approximately $24 million of rate case expenses over three years without a return through a separate tariff rider (Rider RCE). CenterPoint Houston implemented the CTC and Rider RCE effective September 13, 2005 and began recovering approximately $620 million. The return on the CTC portion of the true-up balance was included in CenterPoint Houston’s tariff-based revenues beginning September 13, 2005. Effective August 1, 2006, the interest rate on the unrecovered balance of the CTC was reduced from 11.075% to 8.06% pursuant to a revised rule adopted by the Texas Utility Commission in June 2006. Recovery of rate case expenses under Rider RCE was completed in September 2008.

Certain parties appealed the CTC Order to a district court in Travis County. In May 2006, the district court issued a judgment reversing the CTC Order in three respects. First, the court ruled that the Texas Utility Commission had improperly relied on provisions of its rule dealing with the interest rate applicable to CTC amounts. The district court reached that conclusion based on its belief that the Texas Supreme Court had previously invalidated that entire section of the rule. The 11.075% interest rate in question was applicable from the implementation of the CTC Order on September 13, 2005 until August 1, 2006, the effective date of the implementation of a new CTC in compliance with the revised rule discussed above. Second, the district court reversed the Texas Utility Commission’s ruling that allows CenterPoint Houston to recover through 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. In June 2009, the Texas Supreme Court agreed to hear those appeals and oral argument before the court was held in October 2009. The ultimate outcome of this matter cannot be predicted at this time. However, CenterPoint Energy does not expect the disposition of this matter to have a material adverse effect on CenterPoint Energy’s or CenterPoint Houston’s financial condition, results of operations or cash flows.

During the 2007 legislative session, the Texas legislature amended statutes prescribing the types of true-up balances that can be securitized by utilities and authorized the issuance of transition bonds to recover the balance of the CTC. In June 2007, CenterPoint Houston filed a request with the Texas Utility Commission for a financing order that would allow the securitization of the remaining balance of the CTC, adjusted to refund certain unspent environmental retrofit costs and to recover the amount of the final fuel reconciliation settlement. CenterPoint Houston reached substantial agreement with other parties to this proceeding, and a financing order was approved by

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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. During the nine months ended September 30, 2008, CenterPoint Houston recognized approximately $5 million in operating income from the CTC.

As of September 30, 2009, CenterPoint Energy had not recognized an allowed equity return of $196 million on CenterPoint Houston’s true-up balance because such return will be recognized as it is recovered in rates. During the three months ended September 30, 2008 and 2009, CenterPoint Houston recognized approximately $4 million and $5 million, respectively, of the allowed equity return not previously recognized. During the nine months ended September 30, 2008 and 2009, CenterPoint Houston recognized approximately $10 million and $11 million, respectively, of the allowed equity return not previously recognized.

Texas. In March 2008, the natural gas distribution businesses of CERC (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. In 2008, Gas Operations implemented rates that are expected to increase annual revenues by approximately $3.5 million. The implemented rates have been contested by 9 cities. CenterPoint Energy and CERC do not expect the outcome of this matter to have a material adverse impact on the financial condition, results of operations or cash flows of either CenterPoint Energy or CERC.

In May 2009, CenterPoint Houston filed an application at the Texas Utility Commission seeking approval of certain energy efficiency program costs, an energy efficiency performance bonus for 2008 programs and carrying costs totaling approximately $10 million. The application seeks to begin recovery of these costs through a surcharge effective July 1, 2010. CenterPoint Houston expects an order from the Texas Utility Commission in the fourth quarter of 2009.

In July 2009, Gas Operations filed a request to change its rates with the Railroad Commission and the 29 cities in its Houston service territory, consisting of approximately 940,000 customers in and around Houston. The request seeks to establish uniform rates, charges and terms and conditions of service for the cities and environs of the Houston service territory. If approved by the Railroad Commission and the cities, the proposed new rates would result in an overall increase in annual revenue of $25.4 million. The proposed increase would allow Gas Operations to recover increased operating costs, which include higher pension expense. It would also provide a return on the additional capital invested to serve its customers. In addition, Gas Operations is seeking an adjustment mechanism similar to that obtained in the Texas Coast rate proceeding discussed above that would annually adjust rates to reflect changes in capital, expenses and usage. CERC and CenterPoint Energy do not expect an order from the Railroad Commission and the cities until the first quarter of 2010.

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. In July 2009, the Minnesota Supreme Court issued its decision in which it reversed the decision of the Minnesota Court of Appeals and upheld the MPUC’s decision to deny the requested variance. The court’s decision had no negative impact on CenterPoint Energy’s or CERC’s financial condition, results of operations or cash flows, as the costs at issue were written off at the time they were disallowed.

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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, higher pension 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 and provide a return on 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. In December 2008, the MPUC accepted the case and approved an interim rate increase of $51.2 million, which became effective on January 2, 2009, subject to refund. CERC and CenterPoint Energy do not expect an order from the MPUC until early 2010.

Mississippi. In July 2009, Gas Operations filed a request to increase its rates for utility distribution service with the Mississippi Public Service Commission (MPSC). If approved by the MPSC, the proposed new rates would result in an overall increase in annual revenue of $6.2 million. The proposed increase would allow Gas Operations to recover increased operating costs, including higher pension and benefit expenses, and provide a return on the additional capital invested to serve its customers. The MPSC is expected to issue an order in mid-November 2009.

(d) Regulatory Accounting

CenterPoint Energy has a 50% ownership interest in Southeast Supply Header, LLC (SESH) which owns and operates a 270-mile interstate natural gas pipeline. In 2009, SESH discontinued the use of guidance for accounting for regulated operations, which resulted in CenterPoint recording its share of the effects of such write-offs of SESH’s regulatory assets through non-cash pre-tax charges for the quarters ended March 31, 2009 and September 30, 2009 of $5 million and $11 million, respectively. These non-cash charges are reflected in equity in earnings of unconsolidated affiliates in the Condensed Statements of Consolidated Income. The related tax benefits of $2 million and $4 million, respectively, are reflected in the income tax expense line of the Condensed Statements of Consolidated Income.

(5)	Derivative Instruments

CenterPoint Energy is exposed to various market risks. These risks arise from transactions entered into in the normal course of business. CenterPoint Energy utilizes derivative instruments such as physical forward contracts, swaps and options to mitigate the impact of changes in commodity prices and weather on its operating results and cash flows. Such derivatives are recognized in CenterPoint Energy’s Condensed Consolidated Balance Sheets at their fair value unless CenterPoint Energy elects the normal purchase and sales exemption for qualified physical transactions. A derivative may be designated as a normal purchase or sale if the intent is to physically receive or deliver the product for use or sale in the normal course of business.

In prior years, CenterPoint Energy entered into certain derivative instruments that were designated as cash flow hedges. The objective of these derivative instruments was to hedge the price risk associated with natural gas purchases and sales to reduce cash flow variability related to meeting CenterPoint Energy’s wholesale and retail customer obligations. If derivatives are designated as a cash flow hedge, the effective portions of the changes in their fair values are reflected initially as a separate component of shareholders’ equity and subsequently recognized in income at the same time the hedged items impact earnings. The ineffective portions of changes in fair values of derivatives designated as hedges are immediately recognized in income. Changes in derivatives not designated as normal or as cash flow hedges are recognized in income as they occur. CenterPoint Energy does not enter into or hold derivative instruments for trading purposes.

CenterPoint Energy has a Risk Oversight Committee composed of corporate and business segment officers that oversees all commodity price, weather and credit risk activities, including CenterPoint Energy’s marketing, risk management services and hedging activities. The committee’s duties are to establish CenterPoint Energy’s commodity risk policies, allocate board-approved commercial risk limits, approve use of new products and commodities, monitor positions and ensure compliance with CenterPoint Energy’s risk management policies and procedures and limits established by CenterPoint Energy’s board of directors.

CenterPoint Energy’s policies prohibit the use of leveraged financial instruments. A leveraged financial instrument, for this purpose, is a transaction involving a derivative whose financial impact will be based on an amount other than the notional amount or volume of the instrument.

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(a) Non-Trading Activities

Derivative Instruments. CenterPoint Energy 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. CenterPoint Energy 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, 2008, CenterPoint Energy recorded increased natural gas revenues from unrealized net gains of $80 million and increased natural gas expense from unrealized net losses of $34 million, resulting in a net unrealized gain of $46 million. During the three months ended September 30, 2009, CenterPoint Energy recorded decreased natural gas revenues from unrealized net losses of $37 million and decreased natural gas expense from unrealized net gains of $31 million, resulting in a net unrealized loss of $6 million.

During the nine months ended September 30, 2008, CenterPoint Energy recorded increased natural gas revenues from unrealized net gains of $51 million and increased natural gas expense from unrealized net losses of $37 million, resulting in a net unrealized gain of $14 million. During the nine months ended September 30, 2009, CenterPoint Energy recorded decreased natural gas revenues from unrealized net losses of $71 million and decreased natural gas expense from unrealized net gains of $49 million, resulting in a net unrealized loss of $22 million.

Weather Hedges. CenterPoint Energy has weather normalization or other rate mechanisms that mitigate the impact of weather on its gas operations in Arkansas, Louisiana, Oklahoma and a portion of Texas. The remaining Gas Operations jurisdictions do not have such mechanisms. As a result, fluctuations from normal weather may have a significant positive or negative effect on the results of the gas operations in the remaining jurisdictions and in CenterPoint Houston’s service territory.

In 2007, 2008 and 2009, CenterPoint Energy entered into heating-degree day swaps to mitigate the effect of fluctuations from normal weather on its financial position and cash flows for the respective winter heating seasons. The swaps were based on ten-year normal weather. During the three and nine months ended September 30, 2008, CenterPoint Energy recognized losses of $-0- and $13 million, respectively, related to these swaps. During the three and nine months ended September 30, 2009, CenterPoint Energy recognized losses of $-0-and $3 million, respectively, related to these swaps. The losses were substantially offset by increased revenues due to colder than normal weather. Weather hedge losses are included in revenues in the Condensed Statements of Consolidated Income.

(b) Derivative Fair Values and Income Statement Impacts

The following tables present information about CenterPoint Energy’s derivative instruments and hedging activities. The first table provides a balance sheet overview of CenterPoint Energy’s Derivative Assets and Liabilities as of September 30, 2009, while the latter tables provide a breakdown of the related income statement impact for the three and nine months ended September 30, 2009.

Fair Value of Derivative Instruments
	September 30, 2009
Total derivatives not designated as hedging instruments	Balance Sheet Location	Derivative Assets Fair Value (2) (3)		Derivative Liabilities Fair Value (2) (3)
		(in millions)
Commodity contracts (1)	Current Assets	$	59	$	(9	)
Commodity contracts (1)	Other Assets		16		(1	)
Commodity contracts (1)	Current Liabilities		26		(137	)
Commodity contracts (1)	Other Liabilities		2		(94	)
Indexed debt securities derivative	Current Liabilities		-		(187	)
Total		$	103	$	(428	)

_________

(1)

Commodity contracts are subject to master netting arrangements and are presented on a net basis in the Condensed Consolidated Balance Sheets. This netting causes derivative assets (liabilities) to be ultimately presented net in a liability (asset) account within the Condensed Consolidated Balance Sheets.

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(2)

The fair value shown for commodity contracts is comprised of derivative gross volumes totaling 668 billion cubic feet (Bcf) or a net 138 Bcf long position. Of the net long position, basis swaps constitute 61 Bcf and volumes associated with price stabilization activities of the Natural Gas Distribution business segment comprise 56 Bcf.

(3)

The net of total non-trading derivative assets and liabilities is a $22 million liability as shown on CenterPoint Energy’s Condensed Consolidated Balance Sheets, and is comprised of the commodity contracts derivative assets and liabilities separately shown above offset by collateral netting of $116 million.

For CenterPoint Energy’s price stabilization activities of the Natural Gas Distribution business segment, the settled costs of derivatives are ultimately recovered through purchased gas adjustments. Accordingly, the net unrealized gains and losses associated with interim price movements on contracts that are accounted for as derivatives and probable of recovery through purchased gas adjustments are recorded as net regulatory assets. For those derivatives that are not included in purchased gas adjustments, unrealized gains and losses and settled amounts are recognized in the Condensed Statements of Consolidated Income as revenue for retail sales derivative contracts and as natural gas expense for natural gas derivatives and non-retail related physical gas derivatives. Unrealized gains and losses on indexed debt securities are recorded as Other Income (Expense) on the Condensed Statements of Consolidated Income.

Income Statement Impact of Derivative Activity
Total derivatives not designated as hedging instruments	Income Statement Location	Three Months Ended September 30, 2009
		(in millions)
Commodity contracts	Gains (Losses) in Revenue	$	(4	)
Commodity contracts (1)	Gains (Losses) in Expense: Natural Gas		(27	)
Indexed debt securities derivative	Gains (Losses) in Other Income (Expense)		(30	)
Total		$	(61	)

_________

(1)

The Gains (Losses) in Expense: Natural Gas includes $(31) million of costs associated with price stabilization activities of the Natural Gas Distribution business segment that will be ultimately recovered through purchased gas adjustments.

Income Statement Impact of Derivative Activity
Total derivatives not designated as hedging instruments	Income Statement Location	Nine Months Ended September 30, 2009
		(in millions)
Commodity contracts	Gains (Losses) in Revenue	$	80
Commodity contracts (1)	Gains (Losses) in Expense: Natural Gas		(218	)
Indexed debt securities derivative	Gains (Losses) in Other Income (Expense)		(54	)
Total		$	(192	)

_________

(1)

The Gains (Losses) in Expense: Natural Gas includes $(148) million of costs associated with price stabilization activities of the Natural Gas Distribution business segment that will be ultimately recovered through purchased gas adjustments.

CenterPoint Energy enters into financial derivative contracts containing material adverse change provisions. These provisions require CenterPoint Energy to post additional collateral if the Standard & Poor’s Rating Services or Moody’s Investors Service, Inc. credit rating of CenterPoint Energy is downgraded. The total fair value of the derivative instruments that contain credit risk contingent features that are in a net liability position at September 30, 2009 is $151 million. The aggregate fair value of assets that are already posted as collateral at September 30, 2009 is $82 million. If all derivative contracts (in a net liability position) containing credit risk contingent features were triggered at September 30, 2009, $69 million of additional assets would be required to be posted as collateral.

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(6)	Fair Value Measurements

Effective January 1, 2008, CenterPoint Energy adopted new accounting guidance on fair value measurements which requires additional disclosures about CenterPoint Energy’s financial assets and liabilities that are measured at fair value. Effective January 1, 2009, CenterPoint Energy adopted this new guidance for nonfinancial assets and liabilities, which adoption had no impact on CenterPoint Energy’s financial position, results of operations or cash flows. Beginning in January 2008, assets and liabilities recorded at fair value in the Condensed Consolidated Balance Sheets are categorized based upon the level of judgment associated with the inputs used to measure their value. Hierarchical levels, as defined in this guidance 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. Unobservable inputs reflect CenterPoint Energy’s judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. CenterPoint Energy develops these inputs based on the best information available, including CenterPoint Energy’s own data. CenterPoint Energy’s Level 3 derivative instruments primarily consist of options that are not traded on recognized exchanges and are valued using option pricing models.

The following tables present information about CenterPoint Energy’s assets and liabilities (including derivatives that are presented net) measured at fair value on a recurring basis as of December 31, 2008 and September 30, 2009, and indicate the fair value hierarchy of the valuation techniques utilized by CenterPoint Energy to determine such fair value.

	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 December 31, 2008
	(in millions)
Assets
Corporate equities	$	218	$	-	$	-	$	-		$	218
Investments, including money market funds		70		-		-		-			70
Derivative assets		8		155		49		(74	)		138
Total assets	$	296	$	155	$	49	$	(74	)	$	426
Liabilities
Indexed debt securities derivative	$	-	$	133	$	-	$	-		$	133
Derivative liabilities		44		244		107		(261	)		134
Total liabilities	$	44	$	377	$	107	$	(261	)	$	267

__________

(1)

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

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	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, 2009
	(in millions)
Assets
Corporate equities	$	287	$	-	$	-	$	-		$	287
Investments, including money market funds		67		-		-		-			67
Derivative assets		2		94		7		(38	)		65
Total assets	$	356	$	94	$	7	$	(38	)	$	419
Liabilities
Indexed debt securities derivative	$	-	$	187	$	-	$	-		$	187
Derivative liabilities		16		207		18		(154	)		87
Total liabilities	$	16	$	394	$	18	$	(154	)	$	274

__________

(1)

The following tables present additional information about assets or liabilities, including derivatives that are measured at fair value on a recurring basis for which CenterPoint Energy has utilized Level 3 inputs to determine fair value:

	Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Derivative assets and liabilities, net
	Three Months Ended September 30,
	2008			2009
	(in millions)
Beginning balance	$	6		$	(17	)
Total unrealized gains or (losses):
Included in earnings		(61	)		2
Included in regulatory assets		-			3
Purchases, sales, other settlements, net		(4	)		1	(1)
Ending balance	$	(59	)	$	(11	)
The amount of total gains 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		$	3

__________

(1)

Purchases, sales, other settlements, net include a less than $1 million gain associated with price stabilization activities of CenterPoint Energy’s Natural Gas Distribution business segment.

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	Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Derivative assets and liabilities, net
	Nine Months Ended September 30,
	2008			2009
	(in millions)
Beginning balance	$	(3	)	$	(58	)
Total unrealized gains or (losses):
Included in earnings		(52	)		-
Included in regulatory assets		-			(13	)
Purchases, sales, other settlements, net		(4	)		60	(1)
Ending balance	$	(59	)	$	(11	)
The amount of total gains (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		$	2

_________

(1)

Purchases, sales, other settlements, net include a $57 million gain associated with price stabilization activities of CenterPoint Energy’s Natural Gas Distribution business segment.

(7)

Goodwill

Goodwill by reportable business segment as of both December 31, 2008 and September 30, 2009 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

CenterPoint Energy 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.

CenterPoint Energy performed the test at July 1, 2009, its annual impairment testing date, and determined that no impairment charge for goodwill was required.

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(8)	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,
	2008			2009		2008			2009
	(in millions)
Net income	$	136		$	114	$	359		$	267
Other comprehensive income (loss):
Adjustment to pension and other postretirement plans (net of tax of $2, $2, $3 and $5)		-			3		3			9
Net deferred loss from cash flow hedges (net of tax of $-0-, $-0-, $2 and $-0-)		(1	)		-		(4	)		-
Reclassification of deferred gain from cash flow hedges realized in net income (net of tax of $-0-, $-0-, $2 and $-0-)		-			-		(4	)		-
Total		(1	)		3		(5	)		9
Comprehensive income	$	135		$	117	$	354		$	276

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

	December 31, 2008			September 30, 2009
	(in millions)
Adjustment to pension and postretirement plans	$	(127	)	$	(118	)
Net deferred loss from cash flow hedges		(4	)		(4	)
Total accumulated other comprehensive loss	$	(131	)	$	(122	)

(9)	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, 2008, 346,088,714 shares of CenterPoint Energy common stock were issued and 346,088,548 shares were outstanding. At September 30, 2009, 390,331,666 shares of CenterPoint Energy common stock were issued and 390,331,500 shares were outstanding. Outstanding common shares exclude 166 treasury shares at both December 31, 2008 and September 30, 2009.

During the three months ended September 30, 2009, CenterPoint Energy received proceeds of approximately $11 million from the sale of approximately 0.9 million common shares to its defined contribution plan and proceeds of approximately $4 million from the sale of approximately 0.3 million common shares to participants in its enhanced dividend reinvestment plan. During the nine months ended September 30, 2009, CenterPoint Energy received proceeds of approximately $47 million from the sale of approximately 4.1 million common shares to its defined contribution plan and proceeds of approximately $11 million from the sale of approximately 1.0 million common shares to participants in its enhanced dividend reinvestment plan.

CenterPoint Energy received net proceeds of $148 million from the issuance of 14.3 million shares of its common stock through a continuous offering program during the nine months ended September 30, 2009.

In September 2009, CenterPoint Energy received net proceeds of approximately $280 million from the issuance of 24.2 million shares of its common stock in an underwritten public offering.

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

(a) Short-term Borrowings

Receivables Facility. On October 9, 2009, CERC amended its receivables facility to extend the termination date to October 8, 2010. Availability under CERC’s 364-day receivables facility now ranges from $150 million to $375 million, reflecting seasonal changes in receivables balances. As of December 31, 2008 and September 30, 2009, the facility size was $128 million and $150 million, respectively. As of December 31, 2008 and September 30, 2009, advances under the receivables facilities were $78 million and $40 million, respectively.

Inventory Financing. In December 2008, CERC entered into an asset management agreement whereby it sold $110 million of its natural gas in storage and agreed to repurchase an equivalent amount of natural gas during the 2008-2009 winter heating season for payments totaling $114 million. This transaction was accounted for as a financing and, as of December 31, 2008 and September 30, 2009, CenterPoint Energy’s financial statements reflect natural gas inventory of $75 million and $-0-, respectively, and a financing obligation of $75 million and $-0-, respectively, related to this transaction.

Revolving Credit Facility. On October 6, 2009, CenterPoint Houston terminated its $600 million 364-day credit facility which was secured by a pledge of $600 million of general mortgage bonds issued by CenterPoint Houston. From inception through its termination, there had been no borrowings under the credit facility.

(b) Long-term Debt

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

Revolving Credit Facilities. CenterPoint Energy’s $1.2 billion credit facility has a first drawn cost of the London Interbank Offered Rate (LIBOR) plus 55 basis points based on CenterPoint Energy’s current credit ratings. The facility contains a debt (excluding transition and other securitization bonds) to earnings before interest, taxes, depreciation and amortization (EBITDA) covenant, which was modified (i) in August 2008 so that the permitted ratio of debt to EBITDA would continue at its then-current level for the remaining term of the facility and (ii) in November 2008 so that the permitted ratio of debt to EBITDA would be temporarily increased until the earlier of December 31, 2009 or CenterPoint Houston’s issuance of bonds to securitize the costs incurred as a result of Hurricane Ike, after which time the permitted ratio would revert to the level that existed prior to the November 2008 modification. Non-recourse securitization bonds are not included within the definition of debt for purposes of this covenant.

CenterPoint Houston’s $289 million credit facility contains a debt (excluding transition and other securitization bonds) to total capitalization covenant. The facility’s first drawn cost is LIBOR plus 45 basis points based on CenterPoint Houston’s current credit ratings.

On October 7, 2009, the size of the CERC Corp. revolving credit facility was reduced from $950 million to $915 million through removal of Lehman Brothers Bank, FSB (Lehman) as a lender. Prior to its removal, Lehman had a $35 million commitment to lend. All credit facility loans to CERC Corp. that were funded by Lehman were repaid in September 2009. CERC Corp.’s $915 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 CenterPoint Energy’s $1.2 billion credit facility, CenterPoint Houston’s $289 million credit facility and CERC Corp.’s $915 million credit facility, an additional utilization fee of 5 basis points applies to borrowings any time more than 50% of the facility is utilized. The spread to LIBOR and the utilization fee fluctuate based on the borrower’s credit rating.

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As of December 31, 2008 and September 30, 2009, the following loan balances were outstanding under CenterPoint Energy’s long-term revolving credit facilities (in millions):

	December 31, 2008		September 30, 2009
CenterPoint Energy credit facility borrowings	$	264	$	-
CenterPoint Houston credit facility borrowings		251		-
CERC Corp. credit facility borrowings		926		10
Total credit facility borrowings	$	1,441	$	10

In addition, as of both December 31, 2008 and September 30, 2009, CenterPoint Energy had approximately $27 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 $289 million credit facility. There was no commercial paper outstanding that would have been backstopped by CenterPoint Energy’s $1.2 billion credit facility as of December 31, 2008 and September 30, 2009. There was $-0- and $15 million of outstanding commercial paper backstopped by CERC Corp.’s credit facility as of December 31, 2008 and September 30, 2009, respectively. CenterPoint Energy, CenterPoint Houston and CERC Corp. were in compliance with all debt covenants as of September 30, 2009.

(11)	Commitments and Contingencies

(a) Natural Gas Supply Commitments

Natural gas supply commitments include natural gas contracts related to CenterPoint Energy’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 CenterPoint Energy’s Condensed Consolidated Balance Sheets as of December 31, 2008 and September 30, 2009 as these contracts meet the 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, 2009, minimum payment obligations for natural gas supply commitments are approximately $151 million for the remaining three months in 2009, $449 million in 2010, $466 million in 2011, $383 million in 2012, $371 million in 2013 and $738 million after 2013.

(b) Capital Commitments

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

Under the terms of the agreements, CEFS commenced gathering and treating services immediately utilizing the acquired facilities. CEFS will also expand the acquired facilities to gather and treat up to 700 million cubic feet (MMcf) per day of natural gas from their current throughput of over 100 MMcf per day. If EnCana or Shell elect, CEFS will further expand the facilities in order to gather and treat additional future volumes.

New construction to reach capacity of 700 MMcf per day includes more than 200 miles of pipelines, nearly 25,500 horsepower of compression and over 800 MMcf per day of treating capacity.

Each of the agreements includes volume commitments for which CEFS has exclusive rights to gather Shell’s and EnCana’s natural gas production.

CEFS estimates that the purchase of existing facilities and construction to gather 700 MMcf per day will cost up to $325 million. If EnCana and Shell elect expansion of the project to gather and process additional future volumes of up to 1 billion cubic feet per day, CEFS estimates that the expansion would cost as much as an additional $300 million and EnCana and Shell would provide incremental volume commitments.

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Legal Matters

Gas Market Manipulation Cases. CenterPoint Energy, 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 CenterPoint Energy and RRI (formerly known as Reliant Resources, Inc. and Reliant Energy, Inc.), CenterPoint Energy and its subsidiaries are entitled to be indemnified by RRI for any losses, including attorneys’ fees and other costs, arising out of these lawsuits. Pursuant to the indemnification obligation, RRI is defending CenterPoint Energy and its subsidiaries to the extent named in these lawsuits. 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 2000-2002. CenterPoint Energy’s former affiliate, RRI, was a participant in gas trading in the California and Western markets. These lawsuits, many of which have been filed as class actions, allege violations of state and federal antitrust laws. Plaintiffs in these lawsuits are seeking a variety of forms of relief, including, among others, recovery of compensatory damages (in some cases in excess of $1 billion), a trebling of compensatory damages, full consideration damages and attorneys’ fees. CenterPoint Energy and/or Reliant Energy were named in approximately 30 of these lawsuits, which were instituted between 2003 and 2009. CenterPoint Energy and its affiliates have been released or dismissed from all but two of such cases. CenterPoint Energy Services, Inc. (CES), a subsidiary of CERC Corp., is a defendant in a case now pending in federal court in Nevada alleging a conspiracy to inflate Wisconsin natural gas prices in 2000-2002. Additionally, CenterPoint Energy was a defendant in a lawsuit filed in state court in Nevada that was dismissed in 2007, but the plaintiffs have indicated that they will appeal the dismissal. CenterPoint Energy believes that neither it nor CES is a proper defendant in these remaining cases and will continue to pursue dismissal from those cases. CenterPoint Energy does not expect the ultimate outcome of these remaining matters to have a material impact on its financial condition, results of operations or cash flows.

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

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 sought review of that dismissal from the Tenth Circuit Court of Appeals, which affirmed the district court’s dismissal in March 2009. Following dismissal of the plaintiff’s motion to the Tenth Circuit for rehearing, the plaintiff sought review by the United States Supreme Court, but his petition for certiorari was denied in October 2009.

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

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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. In September 2009, the district court in Stevens County, Kansas, denied plaintiffs’ request for class certification of their case, but the plaintiffs have sought rehearing of that dismissal.

CERC believes that there has been no systematic mismeasurement of gas and that these lawsuits are without merit. CERC and CenterPoint Energy do 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 CenterPoint Energy or CERC.

Gas Cost Recovery Litigation. In October 2004, a lawsuit was filed by certain CERC ratepayers in Texas and Arkansas in circuit court in Miller County, Arkansas against CenterPoint Energy, CERC Corp., Entex Gas Marketing Company (EGMC), CenterPoint Energy Gas Transmission Company (CEGT), CenterPoint Energy Field Services (CEFS), CenterPoint Energy Pipeline Services, Inc. (CEPS), Mississippi River Transmission Corp. (MRT) and various 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, CenterPoint Energy, 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 CenterPoint Energy, CERC Corp., EGMC and the other defendants in the Miller County case. In January 2009, the court entered a final declaratory judgment ruling that the Railroad Commission has exclusive jurisdiction over Texas claims. All appellate deadlines expired without an appeal of the final declaratory judgment.

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. In February 2009, the Arkansas plaintiff notified the APSC that he would no longer pursue his claims, and in July 2009 the complaint proceeding was dismissed by the APSC. All appellate deadlines expired without an appeal of the dismissal order.

Environmental Matters

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

At September 30, 2009, CERC had accrued $14 million for remediation of these Minnesota sites and the estimated range of possible remediation costs for these sites was $4 million to $35 million based on remediation continuing for 30 to 50 years. The cost estimates are based on studies of a site or industry average costs for remediation of sites of similar size. The actual remediation costs will be dependent upon the number of sites to be remediated, the participation of other potentially responsible parties (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, 2009, 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

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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. 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. In September 2009, the federal district court granted CERC’s motion for summary judgment in the proceeding. Although it is likely that the plaintiff will pursue an appeal from that dismissal, further action will not be taken until the district court disposes of claims against other defendants in the case. CERC and CenterPoint Energy do not expect the ultimate outcome to have a material impact on the financial condition, results of operations or cash flows of either CenterPoint Energy or CERC.

Mercury Contamination. CenterPoint Energy’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. CenterPoint Energy has found this type of contamination at some sites in the past, and CenterPoint Energy 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 CenterPoint Energy’s experience and that of others in the natural gas industry to date and on the current regulations regarding remediation of these sites, CenterPoint Energy believes that the costs of any remediation of these sites will not be material to CenterPoint Energy’s financial condition, results of operations or cash flows.

Asbestos. Some facilities owned by CenterPoint Energy contain or have contained asbestos insulation and other asbestos-containing materials. CenterPoint Energy 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 CenterPoint Energy, but most existing claims relate to facilities previously owned by CenterPoint Energy’s subsidiaries. CenterPoint Energy anticipates that additional claims like those received may be asserted in the future. In 2004, CenterPoint Energy sold its generating business, to which most of these claims relate, to Texas Genco LLC, which is now known as NRG Texas LP. Under the terms of the arrangements regarding separation of the generating business from CenterPoint Energy and its sale to NRG Texas LP, ultimate financial responsibility for uninsured losses from claims relating to the generating business has been assumed by NRG Texas LP, but CenterPoint Energy has agreed to continue to defend such claims to the extent they are covered by insurance maintained by CenterPoint Energy, subject to reimbursement of the costs of such defense from NRG Texas LP. Although their ultimate outcome cannot be predicted at this time, CenterPoint Energy intends to continue vigorously contesting claims that it does not consider to have merit and does not expect, based on its experience to date, these matters, either individually or in the aggregate, to have a material adverse effect on CenterPoint Energy’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 January 2009, CERC and the plaintiffs reached agreement on the terms of a settlement that, if ultimately approved by the Louisiana Department of Natural Resources, is expected to resolve this litigation. CenterPoint Energy and CERC do not expect the outcome of this litigation to have a material adverse impact on the financial condition, results of operations or cash flows of either CenterPoint Energy or CERC.

Other Environmental. From time to time CenterPoint Energy 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, CenterPoint Energy 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, CenterPoint Energy does not expect, based on its experience to date, these matters, either individually or in the

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aggregate, to have a material adverse effect on CenterPoint Energy’s financial condition, results of operations or cash flows.

Other Proceedings

CenterPoint Energy 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. CenterPoint Energy regularly analyzes current information and, as necessary, provides accruals for probable liabilities on the eventual disposition of these matters. CenterPoint Energy does not expect the disposition of these matters to have a material adverse effect on CenterPoint Energy’s financial condition, results of operations or cash flows.

(d) Guaranties

Prior to CenterPoint Energy’s distribution of its ownership in RRI to its shareholders, CERC had guaranteed certain contractual obligations of what became RRI’s trading subsidiary. When the companies separated, RRI agreed to secure CERC against obligations under the guaranties RRI had been unable to extinguish by the time of separation. Pursuant to such agreement, as amended in December 2007, RRI has agreed to provide to CERC cash or letters of credit as security against CERC’s obligations under its remaining guaranties for demand charges under certain gas purchase and transportation agreements if and to the extent changes in market conditions expose CERC to a risk of loss on those guaranties. As of September 30, 2009, RRI was not required to provide security to CERC. If RRI should fail to perform the contractual obligations, CERC could have to honor its guarantee and, in such event, collateral provided as security may be insufficient to satisfy CERC’s obligations.

(12)	Income Taxes

During the three months and nine months ended September 30, 2008, the effective tax rate was 36% and 37%, respectively. During the three months and nine months ended September 30, 2009, the effective tax rate was 25% and 33%, respectively. CenterPoint Energy’s settlement of its federal income tax return examinations for tax years 2004 and 2005 affected the comparability of the effective tax rate. As a result of the settlement, CenterPoint Energy recognized a reduction in the liability for uncertain tax positions of approximately $42 million, which included approximately $4 million of uncertain tax positions existing as of December 31, 2008 which reduced income tax expense. Additionally, CenterPoint Energy recognized approximately $9 million as a reduction in accrued interest.

The following table summarizes CenterPoint Energy’s uncertain tax positions at December 31, 2008 and September 30, 2009:

	December 31, 2008		September 30, 2009
	(in millions)
Liability for uncertain tax positions	$	117	$	169
Portion of liability for uncertain tax positions that, if recognized, would reduce the effective income tax rate		14		9
Interest accrued on uncertain tax positions		10		2

(13)	Estimated Fair Value of Financial Instruments

The fair values of cash and cash equivalents, investments in debt and equity securities classified as "available-for-sale" and "trading" and short-term borrowings are estimated to be approximately equivalent to carrying amounts and have been excluded from the table below. The fair values of non-trading derivative assets and liabilities are equivalent to their carrying amounts in the Condensed Consolidated Balance Sheets at December 31, 2008 and September 30, 2009 and have been determined using quoted market prices for the same or similar instruments when

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available or other estimation techniques (see Notes 5 and 6). Therefore, these financial instruments are stated at fair value and are excluded from the table below. The fair value of each debt instrument is determined by multiplying the principal amount of each debt instrument by the market price.

	December 31, 2008				September 30, 2009
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in millions)
Financial liabilities:
Long-term debt (excluding capital leases)	$	10,396	$	9,875	$	9,266	$	9,754

(14)	Earnings Per Share

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2008		2009		2008		2009
	(in millions, except share and per share amounts)
Basic earnings per share calculation:
Net income	$	136	$	114	$	359	$	267

Weighted average shares outstanding		342,228,000		369,512,000		333,652,000		356,570,000

Basic earnings per share:
Net income	$	0.40	$	0.31	$	1.08	$	0.75

Diluted earnings per share calculation:
Net income	$	136	$	114	$	359	$	267

Weighted average shares outstanding		342,228,000		369,512,000		333,652,000		356,570,000
Plus: Incremental shares from assumed conversions:
Stock options (1)		841,000		514,000		846,000		459,000
Restricted stock		1,515,000		1,716,000		1,515,000		1,716,000
3.75% convertible senior notes		-		-		6,174,000		-
Weighted average shares assuming dilution		344,584,000		371,742,000		342,187,000		358,745,000

Diluted earnings per share:
Net income	$	0.39	$	0.31	$	1.05	$	0.74

__________

(1)

Options to purchase 2,720,083 shares were outstanding for both the three and nine months ended September 30, 2008, and options to purchase 2,521,030 shares were outstanding for both the three and nine months ended September 30, 2009, 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 3.75% contingently convertible senior notes provided for settlement of the principal portion in cash rather than stock. The portion of the conversion value of such notes that was required to be settled in cash rather than stock is excluded from the computation of diluted earnings per share from continuing operations. CenterPoint Energy included the conversion spread in the calculation of diluted earnings per share when the average market price of CenterPoint Energy’s common stock in the respective reporting period exceeded the conversion price. In April 2008, CenterPoint Energy called its 3.75% convertible senior notes for redemption on May 30, 2008. Substantially all of CenterPoint Energy’s 3.75% convertible senior notes were submitted for conversion on or prior to the May 30, 2008 redemption date.

(15)	Reportable Business Segments

CenterPoint Energy’s determination of reportable business segments considers the strategic operating units under which CenterPoint Energy 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

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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. CenterPoint Energy uses operating income as the measure of profit or loss for its business segments.

CenterPoint Energy’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 CenterPoint Energy’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 CenterPoint Energy’s business operations.

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

	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	(3)
Field Services		60			11			44
Other Operations		3			-			7
Eliminations		-			(73	)		-
Consolidated	$	2,515		$	-		$	337

	For the Three Months Ended September 30, 2009
	Revenues from External Customers			Net Intersegment Revenues			Operating Income (Loss)
Electric Transmission & Distribution	$	608	(1)	$	-		$	218
Natural Gas Distribution		400			2			(15	)
Competitive Natural Gas Sales and Services		395			4			(8	)
Interstate Pipelines		119			34			64
Field Services		51			12			23
Other Operations		3			-			5
Eliminations		-			(52	)		-
Consolidated	$	1,576		$	-		$	287

	For the Nine Months Ended September 30, 2008
	Revenues from External Customers			Net Intersegment Revenues			Operating Income			Total Assets as of December 31, 2008
Electric Transmission & Distribution	$	1,471	(1)	$	-		$	457	(2)	$	8,880
Natural Gas Distribution		2,969			7			119			4,961
Competitive Natural Gas Sales and Services		3,599			33			36			1,315
Interstate Pipelines		337			131			227	(3)		3,578
Field Services		164			27			121	(4)		826
Other Operations		8			-			10			2,185	(5)
Eliminations		-			(198	)		-			(2,069	)
Consolidated	$	8,548		$	-		$	970		$	19,676

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	For the Nine Months Ended September 30, 2009
	Revenues from External Customers			Net Intersegment Revenues			Operating Income		Total Assets as of September 30, 2009
Electric Transmission & Distribution	$	1,541	(1)	$	-		$	450	$	9,017
Natural Gas Distribution		2,334			7			105		4,281
Competitive Natural Gas Sales and Services		1,585			11			-		1,065
Interstate Pipelines		355			106			194		3,478
Field Services		158			18			72		934
Other Operations		9			-			4		1,864	(5)
Eliminations		-			(142	)		-		(1,986	)
Consolidated	$	5,982		$	-		$	825	$	18,653

________

(1)

Sales to subsidiaries of RRI and its successor, CenterPoint Houston's largest customer, in the three months ended September 30, 2008 and 2009 represented approximately $199 million and $200 million, respectively, of CenterPoint Houston’s transmission and distribution revenues. Sales to subsidiaries of RRI and its successor in the nine months ended September 30, 2008 and 2009 represented approximately $492 million and $493 million, respectively.

(2)

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.

(3)

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.

(4)

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.

(5)

Included in total assets of Other Operations as of December 31, 2008 and September 30, 2009 are pension-related regulatory assets of $800 million and $758 million, respectively.

(16)	Subsequent Events

On October 22, 2009, CenterPoint Energy’s board of directors declared a regular quarterly cash dividend of $0.19 per share of common stock payable on December 10, 2009, to shareholders of record as of the close of business on November 16, 2009.

On October 27, 2009, the U.S. Department of Energy (DOE) notified CenterPoint Houston that it was awarded a $200 million grant for its advanced metering system and intelligent grid projects. The award is contingent on successful negotiation with the DOE.

CenterPoint Energy has evaluated all subsequent events through the date these Interim Condensed Consolidated Financial Statements were issued, which was October 28, 2009.

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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, 2008 (2008 Form 10-K).

EXECUTIVE SUMMARY

Recent Events

Hurricane Ike

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

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2009 through the date the system restoration bonds are issued, as well as certain up-front qualified costs capped at approximately $6 million. In accordance with the financing order, CenterPoint Houston is to place into effect a separate customer credit related to accumulated deferred federal income taxes (ADFIT) associated with the storm restoration costs to be recovered. This separate credit (ADFIT Credit) is to be applied to customers’ bills to reflect the benefit of those deferred taxes at a carrying charge of 11.075%. The beginning balance of the ADFIT related to storm costs is approximately $207 million and will decline over the life of the system restoration bonds as taxes are paid on the system restoration tariffs. The ADFIT Credit will become effective on the same date as the tariff for the system restoration charges and will reduce operating income in 2010 by approximately $24 million. CenterPoint Houston expects to issue the system restoration bonds in the fourth quarter of 2009. Assuming system restoration bonds are issued, CenterPoint Houston will recover the distribution portion of approved system restoration costs out of the bond proceeds, with the bonds being repaid over time through a charge imposed on customers. CenterPoint Houston expects to recover the remaining approximately $20 million of Hurricane Ike costs related to transmission service through the existing mechanisms established to recover transmission costs.

In accordance with the orders discussed above, as of September 30, 2009, CenterPoint Houston has recorded a net regulatory asset of $642 million associated with distribution-related storm restoration costs and $20 million associated with transmission-related storm restoration costs. These amounts reflect carrying costs of $50 million related to distribution and $2 million related to transmission through September 30, 2009, based on the 11.075% cost of capital approved by the Texas Utility Commission. The carrying costs have been bifurcated into two components: (i) return of borrowing costs and (ii) an allowance for earnings on shareholders’ investment. During the three months and nine months ended September 30, 2009, the component representing a return of borrowing costs of $6 million and $20 million, respectively, has been recognized and is included in other income in our Condensed Statements of Consolidated Income. That component will continue to be recognized as earned until the associated system restoration costs are recovered. The component representing an allowance for earnings on shareholders’ investment of $32 million is being deferred and will be recognized as it is collected through rates.

Long-Term Gas Gathering and Treatment Agreements

In September 2009, CenterPoint Energy Field Services, Inc. (CEFS), a wholly-owned natural gas gathering and treating subsidiary of CenterPoint Energy Resources Corp. (CERC Corp. and, together with its subsidiaries, CERC), entered into long-term agreements with an indirect wholly-owned subsidiary of EnCana Corporation (EnCana) and an indirect wholly-owned subsidiary of Royal Dutch Shell plc (Shell) to provide gathering and treating services for their natural gas production from the Haynesville Shale and Bossier Shale formations in Texas and Louisiana. CEFS has also acquired existing jointly-owned gathering facilities from EnCana and Shell in De Soto and Red River parishes in northwest Louisiana.

New construction to reach capacity of 700 MMcf per day includes more than 200 miles of pipelines, nearly 25,500 horsepower of compression and over 800 MMcf per day of treating capacity.

Each of the agreements includes volume commitments for which CEFS has exclusive rights to gather Shell’s and EnCana’s natural gas production.

CEFS estimates that the purchase of existing facilities and construction to gather 700 MMcf per day will cost up to $325 million. If EnCana and Shell elect expansion of the project to gather and process additional future volumes of up to 1 billion cubic feet per day (Bcf), CEFS estimates that the expansion would cost as much as an additional $300 million and EnCana and Shell would provide incremental volume commitments. Funds for construction will be provided from anticipated cash flows from operations, lines of credit or proceeds from the sale of debt or equity securities.

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Debt Transactions

On August 13, 2009, Southeast Supply Header, LLC (SESH) issued $375 million of 4.85% senior notes due 2014. SESH used one-half of the proceeds of the notes to repay a construction loan to CERC in the amount of $186 million. CERC Corp. used the proceeds from the construction loan repayment to repay borrowings under its credit facility.

On October 6, 2009, CenterPoint Houston terminated its $600 million 364-day secured credit facility which had been arranged in November 2008 following Hurricane Ike.

On October 7, 2009, the size of CERC Corp.’s revolving credit facility was reduced from $950 million to $915 million through removal of Lehman Brothers Bank, FSB (Lehman) as a lender. Prior to its removal, Lehman had a $35 million commitment to lend. All credit facility loans to CERC Corp. that were funded by Lehman were repaid in September 2009.

On October 9, 2009, CERC amended its receivables facility to extend the termination date to October 8, 2010. Availability under CERC’s 364-day receivables facility ranges from $150 million to $375 million, reflecting seasonal changes in receivables balances.

Equity Transactions

During the three months ended September 30, 2009, we received proceeds of approximately $11 million from the sale of approximately 0.9 million common shares to our defined contribution plan and proceeds of approximately $4 million from the sale of approximately 0.3 million common shares to participants in our enhanced dividend reinvestment plan. During the nine months ended September 30, 2009, we received proceeds of approximately $47 million from the sale of approximately 4.1 million common shares to our defined contribution plan and proceeds of approximately $11 million from the sale of approximately 1.0 million common shares to participants in our enhanced dividend reinvestment plan.

We received net proceeds of $148 million from the issuance of 14.3 million shares of our common stock through a continuous offering program during the nine months ended September 30, 2009.

In September 2009, we received net proceeds of approximately $280 million from the issuance of 24.2 million shares of our common stock in an underwritten public offering. Proceeds were used for general corporate purposes, including to repay borrowings under our revolving credit facility and the money pool and to make loans to subsidiaries, including CERC to fund capital investments by CEFS.

Asset Management Agreements

The natural gas distribution businesses of CERC (Gas Operations) entered into various asset management agreements associated with its utility distribution service in Arkansas, Oklahoma, Louisiana, Mississippi and Texas. Generally, an asset management agreement is a contract between an asset holder and an asset manager that strives to maximize the revenue-earning potential of the asset. In these agreements, Gas Operations agreed to release transportation and storage capacity to another party to manage gas storage, supply and delivery arrangements for Gas Operations when the released capacity is not needed and thereby maximize the value of the assets. Gas Operations will be compensated by the asset manager, in part based on the results of the asset optimization, and entering into the asset management agreements will reduce working capital requirements. The agreements are expected, subject to regulatory approval, to commence in the fourth quarter of 2009 and to continue for various terms extending up to 2016.

Gas Operations has filed applications with state regulatory commissions in Arkansas, Louisiana, Mississippi and Oklahoma for approval of the applicable asset management agreements and to retain a share of the proceeds, with the remainder to benefit customers. Commission approval has been obtained in Louisiana, Oklahoma and for one of two agreements in Arkansas. Action is expected by the Mississippi commission in the fourth quarter of 2009. A filing is expected to be made in Texas in the fourth quarter of 2009.

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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,
	2008			2009			2008			2009
Revenues	$	2,515		$	1,576		$	8,548		$	5,982
Expenses		2,178			1,289			7,578			5,157
Operating Income		337			287			970			825
Interest and Other Finance Charges		(116	)		(126	)		(346	)		(384	)
Interest on Transition Bonds		(34	)		(32	)		(102	)		(98	)
Equity in Earnings of Unconsolidated Affiliates		23			(3	)		46			8
Other Income, net		3			26			3			45
Income Before Income Taxes		213			152			571			396
Income Tax Expense		(77	)		(38	)		(212	)		(129	)
Net Income	$	136		$	114		$	359		$	267

Basic Earnings Per Share	$	0.40		$	0.31		$	1.08		$	0.75

Diluted Earnings Per Share	$	0.39		$	0.31		$	1.05		$	0.74

Three months ended September 30, 2009 compared to three months ended September 30, 2008

We reported consolidated net income of $114 million ($0.31 per diluted share) for the three months ended September 30, 2009 compared to $136 million ($0.39 per diluted share) for the same period in 2008. The decrease in net income of $22 million was primarily due to a $50 million decrease in operating income (discussed by segment below), a $26 million decrease in the equity in earnings of unconsolidated affiliates and a $10 million increase in interest expense, excluding transition bond-related interest expense. This decrease was partially offset by a $39 million decrease in income tax expense, a net gain on our indexed debt and marketable securities of $20 million and $6 million of carrying costs related to Hurricane Ike restoration costs included in Other Income, net.

Nine months ended September 30, 2009 compared to nine months ended September 30, 2008

We reported consolidated net income of $267 million ($0.74 per diluted share) for the nine months ended September 30, 2009 compared to $359 million ($1.05 per diluted share) for the same period in 2008. The decrease in net income of $92 million was primarily due to a $145 million decrease in operating income (discussed by segment below), a $38 million decrease in the equity in earnings of unconsolidated affiliates and a $38 million increase in interest expense, excluding transition bond-related interest expense. This decrease was partially offset by an $83 million decrease in income tax expense, a net gain on our indexed debt and marketable securities of $21 million and $20 million of carrying costs related to Hurricane Ike restoration costs included in Other Income, net.

Income Tax Expense

During the three months and nine months ended September 30, 2008, the effective tax rate was 36% and 37%, respectively. During the three months and nine months ended September 30, 2009, the effective tax rate was 25% and 33%, respectively. The settlement of our federal income tax return examinations for tax years 2004 and 2005 affected the comparability of the effective tax rate. As a result of the settlement, we recognized a reduction in the liability for uncertain tax positions of approximately $42 million, which included approximately $4 million of uncertain tax positions existing as of December 31, 2008 which reduced income tax expense. Additionally, we recognized approximately $9 million as a reduction in accrued interest.

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RESULTS OF OPERATIONS BY BUSINESS SEGMENT

The following table presents operating income (loss) (in millions) for each of our business segments for the three and nine months ended September 30, 2008 and 2009.

	Three Months Ended September 30,						Nine Months Ended September 30,
	2008			2009			2008		2009
Electric Transmission & Distribution	$	202		$	218		$	457	$	450
Natural Gas Distribution		(6	)		(15	)		119		105
Competitive Natural Gas Sales and Services		35			(8	)		36		-
Interstate Pipelines		55			64			227		194
Field Services		44			23			121		72
Other Operations		7			5			10		4
Total Consolidated Operating Income	$	337		$	287		$	970	$	825

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 II of this Form 10-Q.

The following tables provide summary data of our Electric Transmission & Distribution business segment for the three and nine months ended September 30, 2008 and 2009 (in millions, except throughput and customer data):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2008		2009		2008		2009
Revenues:
Electric transmission and distribution utility	$	455	$	503	$	1,220	$	1,281
Transition bond companies		97		105		251		260
Total revenues		552		608		1,471		1,541
Expenses:
Operation and maintenance, excluding transition bond companies		167		194		502		563
Depreciation and amortization, excluding transition bond companies		71		70		208		207
Taxes other than income taxes		48		52		153		158
Transition bond companies		64		74		151		163
Total expenses		350		390		1,014		1,091
Operating Income	$	202	$	218	$	457	$	450

Operating Income:
Electric transmission and distribution utility	$	169	$	187	$	352	$	353
Competition transition charge		-		-		5		-
Transition bond companies (1)		33		31		100		97
Total segment operating income	$	202	$	218	$	457	$	450

Throughput (in gigawatt-hours (GWh)):
Residential		8,446		9,243		19,623		20,041
Total		21,594		22,963		58,523		57,947

Number of metered customers at end of period:
Residential		1,824,238		1,849,158		1,824,238		1,849,158
Total		2,068,568		2,094,847		2,068,568		2,094,847

___________

(1)

Represents the amount necessary to pay interest on the transition bonds.

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Three months ended September 30, 2009 compared to three months ended September 30, 2008

Our Electric Transmission & Distribution business segment reported operating income of $218 million for the three months ended September 30, 2009, consisting of $187 million from the regulated electric transmission and distribution utility (TDU) and $31 million related to transition bond companies. For the three months ended September 30, 2008, operating income totaled $202 million, consisting of $169 million from the TDU and $33 million related to transition bond companies. TDU revenues increased $48 million primarily due to higher transmission-related revenues ($16 million), in part reflecting the impact of a transmission rate increase implemented in November 2008, the impact of Hurricane Ike in 2008 ($17 million), revenues from implementation of the advanced metering system (AMS) ($9 million), higher revenues due to increased usage ($5 million) primarily as a result of warmer weather and higher revenues due to customer growth ($5 million) from the addition of over 26,000 new customers, partially offset by lower other revenues ($4 million). Operation and maintenance expenses increased $27 million primarily due to higher transmission costs billed by transmission providers ($9 million), increased operating and maintenance expenses that were postponed in 2008 as a result of Hurricane Ike restoration efforts ($5 million), increased labor and benefit costs ($4 million), expenses related to AMS ($3 million) and increases in other expenses ($6 million). Taxes other than income taxes increased $4 million as a result of a refund in 2008 of prior year state franchise taxes ($5 million).

Nine months ended September 30, 2009 compared to nine months ended September 30, 2008

Our Electric Transmission & Distribution business segment reported operating income of $450 million for the nine months ended September 30, 2009, consisting of $353 million from the TDU and $97 million related to transition bond companies. For the nine months ended September 30, 2008, operating income totaled $457 million, consisting of $352 million from the TDU, exclusive of an additional $5 million from the CTC, and $100 million related to transition bond companies. TDU revenues increased $61 million primarily due to higher transmission-related revenues ($43 million), in part reflecting the impact of a transmission rate increase implemented in November 2008, the impact of Hurricane Ike in 2008 ($17 million), revenues from implementation of AMS ($17 million) and higher revenues due to customer growth ($11 million) from the addition of over 26,000 new customers, which were partially offset by declines in use ($18 million) primarily occurring in the first quarter and lower other revenues ($3 million). Operation and maintenance expenses increased $61 million primarily due to higher transmission costs billed by transmission providers ($24 million), increased operating and maintenance expenses that were postponed in 2008 as a result of Hurricane Ike restoration efforts ($5 million), higher pension and other employee benefit costs ($10 million), increased support services ($5 million), expenses related to AMS ($8 million) and a gain on a land sale in 2008 ($9 million). Taxes other than income taxes increased $5 million as a result of a refund in 2008 of prior year state franchise taxes ($5 million). Changes in pension expense over our 2007 base year amount are being deferred until our next general rate case pursuant to Texas law.

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 II of this Form 10-Q.

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The following table provides summary data of our Natural Gas Distribution business segment for the three and nine months ended September 30, 2008 and 2009 (in millions, except throughput and customer data):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2008			2009			2008		2009
Revenues	$	550		$	402		$	2,976	$	2,341
Expenses:
Natural gas		351			198			2,196		1,538
Operation and maintenance		139			157			436		478
Depreciation and amortization		40			40			118		121
Taxes other than income taxes		26			22			107		99
Total expenses		556			417			2,857		2,236
Operating Income (Loss)	$	(6	)	$	(15	)	$	119	$	105

Throughput (in Bcf):
Residential		13			13			117		111
Commercial and industrial		41			38			171		154
Total Throughput		54			51			288		265

Number of customers at period end:
Residential		2,936,777			2,954,095			2,936,777		2,954,095
Commercial and industrial		244,959			241,036			244,959		241,036
Total		3,181,736			3,195,131			3,181,736		3,195,131

Three months ended September 30, 2009 compared to three months ended September 30, 2008

Our Natural Gas Distribution business segment reported an operating loss of $15 million for the three months ended September 30, 2009 compared to an operating loss of $6 million for the three months ended September 30, 2008. Operating margin (revenues less cost of gas) increased $5 million primarily due to increased rates ($4 million). Operation and maintenance expenses increased $18 million primarily due to increased pension expense ($8 million), higher labor and non-pension related benefits expense ($4 million), customer related expenses and support services costs ($5 million) and increases in other expenses ($4 million), partially offset by lower bad debt expense ($4 million). Taxes other than income taxes decreased primarily due to lower gross receipts taxes.

Nine months ended September 30, 2009 compared to nine months ended September 30, 2008

Our Natural Gas Distribution business segment reported operating income of $105 million for the nine months ended September 30, 2009 compared to operating income of $119 million for the nine months ended September 30, 2008. Operating margin improved $23 million primarily as a result of rate increases ($18 million), recovery of higher energy-efficiency costs ($4 million), increased non-utility revenues ($5 million), residential customer growth ($2 million), with the addition of approximately 17,000 customers, and increased margin from commercial and industrial customers ($2 million), partially offset by decreased gross receipts taxes ($10 million). Operation and maintenance expenses increased $42 million primarily due to increased pension expense ($26 million), higher labor and non-pension related benefits expense ($11 million) and increased customer-related expenses and support services costs ($11 million), partially offset by lower bad debt expense ($8 million) and other expense reductions ($3 million). Depreciation expense increased due to higher plant balances. Taxes other than income taxes decreased due to the gross receipts taxes above, partially offset by an increase in property taxes ($2 million).

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 II of this Form 10-Q.

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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, 2008 and 2009 (in millions, except throughput and customer data):

	Three Months Ended September 30,					Nine Months Ended September 30,
	2008		2009			2008		2009
Revenues	$	1,269	$	399		$	3,632	$	1,596
Expenses:
Natural gas		1,225		396			3,567		1,562
Operation and maintenance		8		10			26		30
Depreciation and amortization		1		1			2		3
Taxes other than income taxes		-		-			1		1
Total expenses		1,234		407			3,596		1,596
Operating Income (Loss)	$	35	$	(8	)	$	36	$	-

Throughput (in Bcf)		125		115			392		370

Number of customers at period end		8,988		10,934			8,988		10,934

Three months ended September 30, 2009 compared to three months ended September 30, 2008

Our Competitive Natural Gas Sales and Services business segment reported an operating loss of $8 million for the three months ended September 30, 2009 compared to operating income of $35 million for the three months ended September 30, 2008. The decrease in operating income of $43 million was primarily due to the unfavorable impact of mark-to-market accounting for non-trading financial derivatives for the third quarter of 2009 of $6 million versus a favorable impact of $46 million for the same period in 2008. 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 derivative contracts create the mark-to-market accounting adjustment. This decrease was partially offset by the absence of a write-down of natural gas inventory to the lower of cost or market in the current quarter as compared to a $24 million write-down in the third quarter 2008. The remaining $15 million decrease was comprised of reduced margin of $12 million, due to lower sales volume and reduced locational spreads and increased operating expense of $3 million.

Nine months ended September 30, 2009 compared to nine months ended September 30, 2008

Our Competitive Natural Gas Sales and Services business segment reported operating income of $-0- for the nine months ended September 30, 2009 compared to operating income of $36 million for the nine months ended September 30, 2008. The decrease in operating income of $36 million was primarily due to the unfavorable impact of the mark-to-market valuation for non-trading financial derivatives for the first nine months of 2009 of $22 million versus a favorable impact of $14 million for the same period in 2008. This decrease in operating income was partially offset by a $6 million write-down of natural gas inventory to the lower of cost or market for the nine months ended September 30, 2009 compared to a $24 million write-down in the same period last year. The remaining $18 million decrease was comprised of reduced margin of $13 million and increased operating expense of $5 million for the nine months ended September 30, 2009 compared to the same period last year.

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 II of this Form 10-Q.

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The following table provides summary data of our Interstate Pipelines business segment for the three and nine months ended September 30, 2008 and 2009 (in millions, except throughput data):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2008		2009		2008		2009
Revenues	$	143	$	153	$	468	$	461
Expenses:
Natural gas		24		22		97		85
Operation and maintenance		47		47		93		123
Depreciation and amortization		11		12		34		36
Taxes other than income taxes		6		8		17		23
Total expenses		88		89		241		267
Operating Income	$	55	$	64	$	227	$	194

Transportation throughput (in Bcf) :		360		378		1,145		1,235

Three months ended September 30, 2009 compared to three months ended September 30, 2008

Our Interstate Pipeline business segment reported operating income of $64 million for the three months ended September 30, 2009 compared to $55 million for the three months ended September 30, 2008. Margins (revenues less natural gas costs) increased $12 million primarily due to a new backhaul agreement on the Carthage to Perryville pipeline ($10 million) and new contracts with power generation customers ($6 million). These increases were partially offset by reduced other transportation margins and ancillary services ($4 million) primarily due to the decline in commodity prices from the significantly higher levels in 2008. Operations and maintenance expenses increased due to costs associated with incremental facilities and increased pension expenses ($7 million), but that increase was offset by a write-down associated with pipeline assets removed from service in the third quarter of 2008 ($7 million). Depreciation and amortization expenses increased $1 million and taxes other than income increased by $2 million, $1 million of which was due to 2008 tax refunds.

Equity Earnings. In addition, this business segment recorded equity income of $18 million and equity loss of $5 million for the three months ended September 30, 2008 and 2009, respectively, from its 50 percent interest in SESH, a jointly-owned pipeline that went into service in September 2008. Approximately $17 million of income in the third quarter of 2008 was pre-operating allowance for funds used during construction in 2008. The third quarter 2009 loss of $5 million included a non-cash pre-tax charge of $11 million associated with the write-off of certain regulatory assets resulting from SESH’s decision to discontinue the use of guidance for accounting for regulated operations. The charge more than offset the equity income from SESH’s ongoing operations of $6 million for the third quarter of 2009. These amounts are included in Equity in Earnings of Unconsolidated Affiliates under the Other Income (Expense) caption.

Nine months ended September 30, 2009 compared to nine months ended September 30, 2008

Our Interstate Pipeline business segment reported operating income of $194 million for the nine months ended September 30, 2009 compared to $227 million for the nine months ended September 30, 2008. Margins (revenues less natural gas costs) increased $5 million primarily due to the Carthage to Perryville pipeline ($22 million) and new contracts with power generation customers ($15 million). These increases were partially offset by reduced other transportation margins and ancillary services ($32 million) primarily due to the decline in commodity prices from the significantly higher levels in 2008. Operations and maintenance expenses increased primarily due to a gain on the sale of two storage development projects in 2008 ($18 million) and costs associated with incremental facilities and increased pension expenses ($19 million). These expenses were partially offset by a write-down associated with pipeline assets removed from service in the third quarter of 2008 ($7 million). Depreciation and amortization expenses increased $2 million and taxes other than income increased by $6 million, $3 million of which was due to 2008 tax refunds.

Equity Earnings. In addition, this business segment recorded equity income of $34 million and $2 million for the nine months ended September 30, 2008 and 2009, respectively, from its 50 percent interest in SESH. Approximately $33 million of the income in the nine months ended September 30, 2008 was pre-operating allowance for funds used during construction in 2008. The 2009 results include a non-cash pre-tax charge of $16 million

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to reflect SESH’s decision to discontinue the use of guidance for accounting for regulated operations and the receipt of a one-time payment related to the construction of the pipeline and a reduction in estimated property taxes, of which our 50 percent share was $5 million. These amounts are included in Equity in Earnings of Unconsolidated Affiliates under the Other Income (Expense) caption.

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 II of this Form 10-Q.

The following table provides summary data of our Field Services business segment for the three and nine months ended September 30, 2008 and 2009 (in millions, except throughput data):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2008		2009		2008		2009
Revenues	$	71	$	63	$	191	$	176
Expenses:
Natural gas		5		18		11		36
Operation and maintenance		19		17		48		54
Depreciation and amortization		3		4		9		11
Taxes other than income taxes		-		1		2		3
Total expenses		27		40		70		104
Operating Income	$	44	$	23	$	121	$	72

Gathering throughput (in Bcf) :		109		106		311		312

Three months ended September 30, 2009 compared to three months ended September 30, 2008

Our Field Services business segment reported operating income of $23 million for the three months ended September 30, 2009 compared to $44 million for the three months ended September 30, 2008. Operating income from new projects and core gathering services increased approximately $4 million for three months ended September 30, 2009 when compared to the same period in 2008 primarily due to continued development in the shale plays. This increase was offset primarily by the effect of a decline in commodity prices from the significantly higher levels in 2008 of approximately $20 million. In addition, operating income decreased from the prior year quarter associated with gains from system imbalances ($3 million).

Equity Earnings. In addition, this business segment recorded equity income of $4 million and $2 million in the three months ended September 30, 2008 and 2009, respectively, from its 50 percent interest in a jointly-owned gas processing plant. The decrease is driven by a decrease in natural gas liquids prices. These amounts are included in Equity in Earnings of Unconsolidated Affiliates under the Other Income (Expense) caption.

Nine months ended September 30, 2009 compared to nine months ended September 30, 2008

Our Field Services business segment reported operating income of $72 million for the nine months ended September 30, 2009 compared to $121 million for the nine months ended September 30, 2008. Operating income from new projects and core gathering services increased approximately $16 million for the nine months ended September 30, 2009 when compared to the same period in 2008 primarily due to continued development in the shale plays. This increase was offset primarily by the effect of a decline in commodity prices of approximately $43 million from the significantly higher prices experienced in 2008. Operating income for the nine months ended September 30, 2009 also included higher costs associated with incremental facilities and increased pension costs ($5 million). The nine month period September 30, 2008 benefited from a one-time gain ($11 million) related to a settlement and contract buyout of one of our customers and a one-time gain ($6 million) related to the sale of assets.

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Equity Earnings. In addition, this business segment recorded equity income of $12 million and $6 million in the nine months ended September 30, 2008 and 2009, respectively, from its 50 percent interest in a jointly-owned gas processing plant. The decrease is driven by a decrease in natural gas liquids prices. These amounts are included in Equity in Earnings of Unconsolidated Affiliates under the Other Income (Expense) caption.

Other Operations

The following table shows the operating income of our Other Operations business segment for the three and nine months ended September 30, 2008 and 2009 (in millions):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2008			2009			2008			2009
Revenues	$	3		$	3		$	8		$	9
Expenses		(4	)		(2	)		(2	)		5
Operating Income	$	7		$	5		$	10		$	4

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, "Risk Factors" in Item 1A of Part II of this Form 10-Q and "Cautionary Statement Regarding Forward-Looking Information."

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, 2008 and 2009:

	Nine Months Ended September 30,
	2008			2009
	(in millions)
Cash provided by (used in):
Operating activities	$	724		$	1,437
Investing activities		(991	)		(582	)
Financing activities		222			(961	)

Cash Provided by Operating Activities

Net cash provided by operating activities in the first nine months of 2009 increased $713 million compared to the same period in 2008 primarily due to decreased gas storage inventory ($425 million), decreased net margin deposits ($185 million), decreased tax payments ($131 million) and decreased net regulatory assets and liabilities ($67 million), which was partially offset by decreased net accounts receivable/payable ($53 million).

Cash Used in Investing Activities

Net cash used in investing activities in the first nine months of 2009 decreased $409 million compared to the same period in 2008 due to decreased investment in unconsolidated affiliates of $96 million, decreased notes receivable from unconsolidated affiliates of $498 million and decreased restricted cash of transition bond companies of $11 million, offset by increased capital expenditures of $177 million primarily related to our Electric Transmission & Distribution and Field Services business segments.

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Cash Used in Financing Activities

Net cash used in financing activities in the first nine months of 2009 increased $1.2 billion compared to the same period in 2008 primarily due to decreased borrowings under revolving credit facilities ($2.2 billion), decreased proceeds from the issuance of long-term debt ($588 million) and decreased short-term borrowings ($31 million), which were partially offset by decreased repayments of long-term debt ($1.2 billion), increased proceeds from the issuance of common stock ($444 million) and increased proceeds from commercial paper ($15 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 2009 include the following:

•

approximately $383 million of capital expenditures; and

•

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

We anticipate receiving an income tax refund of approximately $137 million in the fourth quarter of 2009.

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

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 RRI Energy, Inc. (RRI) (formerly known as Reliant Energy, Inc. and Reliant Resources, Inc.) to our shareholders, CERC had guaranteed certain contractual obligations of what became RRI’s trading subsidiary. When the companies separated, RRI agreed to secure CERC against obligations under the guaranties RRI had been unable to extinguish by the time of separation. Pursuant to such agreement, as amended in December 2007, RRI has agreed to provide to CERC cash or letters of credit as security against CERC’s obligations under its remaining guaranties for demand charges under certain gas purchase and transportation agreements if and to the extent changes in market conditions expose CERC to a risk of loss on those guaranties. As of September 30, 2009, RRI was not required to provide security to CERC. If RRI should fail to perform the contractual obligations, CERC could have to honor its guarantee and, in such event, collateral provided as security may be insufficient to satisfy CERC’s obligations.

Equity Transactions. During the three months ended September 30, 2009, we received proceeds of approximately $11 million from the sale of approximately 0.9 million common shares to our defined contribution plan and proceeds of approximately $4 million from the sale of approximately 0.3 million common shares to participants in our enhanced dividend reinvestment plan. During the nine months ended September 30, 2009, we received proceeds of approximately $47 million from the sale of approximately 4.1 million common shares to our defined contribution plan and proceeds of approximately $11 million from the sale of approximately 1.0 million common shares to participants in our enhanced dividend reinvestment plan.

We received net proceeds of $148 million from the issuance of 14.3 million shares of our common stock through a continuous offering program during the nine months ended September 30, 2009.

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Credit and Receivables Facilities. On October 6, 2009, CenterPoint Houston terminated its $600 million 364-day secured credit facility which had been arranged in November 2008 following Hurricane Ike.

On October 7, 2009, the size of the CERC Corp. revolving credit facility was reduced from $950 million to $915 million through removal of Lehman as a lender. Prior to its removal, Lehman had a $35 million commitment to lend. All credit facility loans to CERC Corp. that were funded by Lehman were repaid in September 2009.

As of October 19, 2009, we had the following facilities (in millions):

Date Executed

Company

Type of

Facility

Size of

Facility

Amount

Utilized at

October

19, 2009

Termination Date

June 29, 2007

CenterPoint Energy

Revolver

1,156

(1)

June 29, 2012

June 29, 2007

CenterPoint Houston

Revolver

289

(1)

June 29, 2012

June 29, 2007

CERC Corp.

Revolver

915

June 29, 2012

October 9, 2009

CERC

Receivables

150

October 8, 2010

___________

(1)

Represents 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 and other securitization bonds) to earnings before interest, taxes, depreciation and amortization (EBITDA) covenant, which was modified (i) in August 2008 so that the permitted ratio of debt to EBITDA would continue at its then-current level for the remaining term of the facility and (ii) in November 2008 so that the permitted ratio of debt to EBITDA would be temporarily increased until the earlier of December 31, 2009 or CenterPoint Houston’s issuance of bonds to securitize the costs incurred as a result of Hurricane Ike, after which time the permitted ratio would revert to the level that existed prior to the November 2008 modification. Non-recourse securitization bonds are not included within the definition of debt for purposes of this covenant.

CERC Corp.’s $915 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 our $1.2 billion credit facility, CenterPoint Houston’s $289 million credit facility and CERC Corp’s $915 million credit facility, an additional utilization fee of 5 basis points applies to borrowings any time more than 50% of the facility is utilized. The spread to LIBOR and the utilization fee fluctuate based on 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 as disclosed above.

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 $915 million CERC Corp. credit facility backstops a $915 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.

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(Moody’s), "A-3" 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-3" 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 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.

Temporary Investments. As of October 19, 2009, 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 our revolving credit facility or the sale of our commercial paper.

Impact on Liquidity of a Downgrade in Credit Ratings. As of October 19, 2009, 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-

Negative

BBB-

Stable

CenterPoint Houston Senior Secured

Debt

Baa1

Positive

BBB+

Negative

A-

Stable

CERC Corp. Senior Unsecured Debt

Baa3

Stable

BBB

Negative

BBB

Stable

__________

(1)

A Moody’s rating outlook is an opinion regarding the likely direction of a rating over the medium term.

(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.

A decline in credit ratings could increase borrowing costs under our $1.2 billion credit facility, CenterPoint Houston’s $289 million credit facility and CERC Corp.’s $915 million credit facility. If our credit ratings or those of CenterPoint Houston or CERC had been downgraded one notch by each of the three principal credit rating agencies from the ratings that existed at September 30, 2009, the impact on the borrowing costs under our bank credit facilities would have been immaterial. 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.

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.

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

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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, 2009, the amount posted as collateral aggregated approximately $140 million ($94 million of which is associated with price stabilization activities of our Natural Gas Distribution business segment). Should the credit ratings of CERC Corp. (as the credit support provider for CES) fall below certain levels, CES would be required to provide additional collateral up to the amount of its previously unsecured credit limit. We estimate that as of September 30, 2009, unsecured credit limits extended to CES by counterparties aggregate $241 million; however, utilized credit capacity was $73 million.

Pipeline tariffs and contracts typically provide that if the credit ratings of a shipper or the shipper’s guarantor drop below a threshold level, which is generally investment grade ratings from both Moody’s and S&P, cash or other collateral may be demanded from the shipper in an amount equal to the sum of three months’ charges for pipeline services plus the unrecouped cost of any lateral built for such shipper. If the credit ratings of CERC Corp. decline below the applicable threshold levels, CERC Corp. might need to provide cash or other collateral of as much as $180 million as of September 30, 2009. The amount of collateral will depend on seasonal variations in transportation levels.

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 at September 30, 2009. Each ZENS note was originally 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 such note. The number and identity of the reference shares attributable to each ZENS note are adjusted for certain corporate events. As of September 30, 2009, the reference shares for each ZENS note consisted of 0.5 share of TW Common and 0.125505 share of Time Warner Cable Inc. common stock (TWC Common), which reflects adjustments resulting from the March 2009 distribution by Time Warner Inc. of shares of TWC Common and Time Warner Inc.’s March 2009 reverse stock split. 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 and TWC Common that we own or from other sources. We own shares of TW Common and TWC Common equal to approximately 100% of the reference shares used to calculate our obligation to the holders of the ZENS notes. ZENS note exchanges result in a cash outflow because tax deferrals related to the ZENS notes and TW Common and TWC Common shares would typically cease when ZENS notes are exchanged or otherwise retired and TW Common and TWC Common shares are sold. The ultimate tax liability 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. The American Recovery and Reinvestment Act of 2009 allows us to defer until 2014 taxes due as a result of the retirement of ZENS notes that would have otherwise been payable in 2009 or 2010 and pay such taxes over the period from 2014 through 2018. Accordingly, if on September 30, 2009, all ZENS notes had been exchanged for cash, we could have deferred taxes of approximately $375 million that would have otherwise been payable in 2009. In May 2009, Time Warner Inc. announced plans for the complete legal and structural separation of AOL LLC. In July 2009, Time Warner Inc. announced that the transaction, which it aims to complete at the end of 2009, involves the conversion of AOL LLC into a corporation and a distribution of its shares to TW Common shareholders. The newly distributed shares will also become reference shares.

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, 2009, 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

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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.

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

•

cash collateral requirements that could exist in connection with certain contracts, including gas purchases, gas price and weather 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;

•

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;

•

increased capital expenditures required for new gas pipeline or field services projects;

•

the ability of RRI and its subsidiaries to satisfy their obligations 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;

•

the ability of NRG Retail, LLC, the successor to RRI’s retail electric provider and the largest customer of CenterPoint Houston, to satisfy its obligations to us and our subsidiaries;

•

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 this Form 10-Q.

Certain Contractual Limits on Our Ability to Issue Securities and Borrow Money. CenterPoint Houston’s credit facilities limit CenterPoint Houston’s debt (excluding transition and other securitization 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. Such covenant was modified twice in 2008 to provide additional debt capacity. The second modification was to provide debt capacity for the financing of system restoration costs following Hurricane Ike. That modification terminates upon the earlier of December 31, 2009 or CenterPoint Houston’s issuance of bonds to securitize the costs incurred as a result of Hurricane Ike. Non-recourse securitization bonds are not included within the definition of debt for purposes of this covenant. Additionally, CenterPoint Houston has contractually agreed that it will not issue additional first mortgage bonds, subject to certain exceptions.

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NEW ACCOUNTING PRONOUNCEMENTS

See Note 2 to our Interim Condensed Consolidated 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, 2009, the recorded fair value of our non-trading energy derivatives was a net liability of $138 million (before collateral). The net liability consisted of a net liability of $158 million associated with price stabilization activities of our Natural Gas Distribution business segment and a net asset of $20 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, 2009 levels would have increased the fair value of our non-trading energy derivatives net liability by $32 million. However, the consolidated income statement impact of this same 10% decrease in market prices would be an increase in income of $9 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, 2009, we had outstanding long-term debt, bank loans, lease obligations and our obligations under our ZENS that subject us to the risk of loss associated with movements in market interest rates.

Our floating-rate obligations aggregated $1.5 billion and $65 million at December 31, 2008 and September 30, 2009, respectively. If the floating interest rates were to increase by 10% from September 30, 2009 rates, our combined interest expense would increase by less than $1 million annually.

At December 31, 2008 and September 30, 2009, we had outstanding fixed-rate debt (excluding indexed debt securities) aggregating $9.0 billion and $9.2 billion, respectively, in principal amount and having a fair value of $8.5 billion and $9.7 billion, respectively. Because these instruments are fixed-rate, they do not expose us to the risk of loss in earnings due to changes in market interest rates (please read Note 10 to our consolidated financial statements). However, the fair value of these instruments would increase by approximately $249 million if interest rates were to decline by 10% from their levels at September 30, 2009. 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.

The ZENS obligation was bifurcated into a debt component and a derivative component. The debt component of $120 million at September 30, 2009 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 $20 million if interest rates were to decline by 10% from levels at September 30, 2009. Changes in the fair value of the derivative component, a $187 million recorded liability at September 30, 2009, are recorded in our Condensed 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

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to increase by 10% from September 30, 2009 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 Condensed Statements of Consolidated Income.

Equity Market Value Risk

We are exposed to equity market value risk through our ownership of 7.2 million shares of TW Common and 1.8 million shares of TWC Common, which we hold to facilitate our ability to meet our obligations under the ZENS. A decrease of 10% from the September 30, 2009 aggregate market value of TW Common and TWC Common would result in a net loss of approximately $5 million, which would be recorded as an unrealized loss in our Condensed 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, 2009 to provide assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms and such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding disclosure.

There has been no change in our internal controls over financial reporting that occurred during the three months ended September 30, 2009 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 11 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 2008 Form 10-K.

Item 1A. RISK FACTORS

The following risk factors are provided to supplement and update the risk factors contained in the reports we file with the SEC, including the risk factors contained in Item 1A of Part I of our 2008 Form 10-K.

We are a holding company that conducts all of our business operations through subsidiaries, primarily CenterPoint Houston and CERC. The following information about risks, along with any additional legal proceedings identified or referenced in Part II, Item 1 “Legal Proceedings” of this Form 10-Q and in “Legal Proceedings” in Item 3 of our 2008 Form 10-K, summarize 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.

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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.

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

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

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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:

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

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

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

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

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appeal or with respect to the ultimate decision by the Texas Utility Commission on the tax normalization issue described below.

If the Texas Utility Commission’s order relating to the ADITC reduction is not reversed or otherwise modified on remand so as to eliminate the normalization violation, the IRS could require CenterPoint Energy to pay an amount equal to 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 CenterPoint Energy’s results of operations, financial condition and cash flows in addition to any potential loss resulting from final resolution of the True-Up Order. In its opinion, the court of appeals ordered that this issue be remanded to the Texas Utility Commission, as that commission requested. No party, in the petitions for review or briefs filed with the Texas Supreme Court, has challenged that order by the court of appeals although the Texas Supreme Court has the authority to consider all aspects of the rulings above, not just those challenged specifically by the appellants. CenterPoint Energy and CenterPoint Houston will continue to pursue a favorable resolution of this issue through the appellate and administrative process. Although the Texas Utility Commission has not previously required a company subject to its jurisdiction to take action that would result in a normalization violation, no prediction can be made as to the ultimate action the Texas Utility Commission may take on this issue on remand.

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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 REPs that supply the electricity CenterPoint Houston distributes to their customers. As of September 30, 2009, CenterPoint Houston did business with 80 REPs. Adverse economic conditions, structural problems in the market served by ERCOT or financial difficulties of one or more REPs could impair the ability of these REPs to pay for CenterPoint Houston’s services or could cause them to delay such payments. In 2008, seven REPs selling power within CenterPoint Houston’s service territory ceased to operate, and their customers were transferred to the provider of last resort or to other REPs. 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 REP cannot make timely payments. Applicable Texas Utility Commission regulations significantly limit the extent to which CenterPoint Houston can apply normal commercial terms or otherwise seek credit protection from firms desiring to provide retail electric service in its service territory, and thus remains at risk for payments not made prior to the shift to the provider of last resort. Although the Texas Utility Commission revised its regulations in 2009 to (i) increase the financial qualifications from REPs that began selling power after January 1, 2009, and (ii) authorize utilities to defer bad debts resulting from defaults by REPs for recovery in a future rate case, significant bad debts may be realized and unpaid amounts may not be timely recovered. A subsidiary of NRG Energy, Inc. is the successor to the retail electric sales business of RRI and has become the largest REP in CenterPoint Houston’s service territory. Approximately 43% of CenterPoint Houston’s $196 million in billed receivables from REPs at September 30, 2009 was owed by the NRG Energy, Inc. subsidiary. Any delay or default in payment by REPs such as the NRG Energy, Inc. subsidiary could adversely affect CenterPoint Houston’s cash flows, financial condition and results of operations. If any of these REPs were unable to meet its obligations, it could consider, among various options, restructuring under the bankruptcy laws, in which event any such REP might seek to avoid honoring its obligations and claims might be made by creditors involving payments CenterPoint Houston had received from such REP.

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

CenterPoint Houston’s rates are regulated by certain municipalities and the Texas Utility Commission based on an analysis of its invested capital and its expenses in a test year. Thus, the rates that CenterPoint Houston is allowed to charge may not match its expenses at any given time. The regulatory process by which rates are determined may not always result in rates that will produce full recovery of CenterPoint Houston’s costs and enable CenterPoint Houston to earn a reasonable return on its invested capital.

In this regard, pursuant to the Stipulation and Settlement Agreement approved by the Texas Utility Commission in September 2006, until June 30, 2010 CenterPoint Houston is limited in its ability to request retail rate relief. For more information on the Stipulation and Settlement Agreement, please read “Business — Regulation — State and Local Regulation — Electric Transmission & Distribution — CenterPoint Houston Rate Agreement” in Item 1 of the 2008 Form 10-K.

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

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

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

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

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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 natural gas distribution business (Gas Operations) are regulated by certain municipalities and state commissions, and for its interstate pipelines by the Federal Energy Regulatory Commission, 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 alternate energy sources, which could result in CERC marketing less natural gas, and its interstate pipelines and field services businesses must compete directly with others in the transportation, storage, gathering, treating and processing of natural gas, which could lead to lower prices and reduced volumes, either of which could have an adverse impact on CERC’s results of operations, financial condition and cash flows.

CERC competes primarily with alternate energy sources such as electricity and other fuel sources. In some areas, intrastate pipelines, other natural gas distributors and marketers also compete directly with CERC for natural gas sales to end-users. In addition, as a result of federal regulatory changes affecting interstate pipelines, natural gas marketers operating on these pipelines may be able to bypass CERC’s facilities and market, sell and/or transport natural gas directly to commercial and industrial customers. Any reduction in the amount of natural gas marketed, sold or transported by CERC as a result of competition may have an adverse impact on CERC’s results of operations, financial condition and cash flows.

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

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

CERC is subject to risk associated with changes in the price of natural gas. Increases in natural gas prices might affect CERC’s ability to collect balances due from its customers and, for Gas Operations, could create the potential for uncollectible accounts expense to exceed the recoverable levels built into CERC’s tariff rates. In addition, a sustained period of high natural gas prices could (i) apply downward demand pressure on natural gas consumption in the areas in which CERC operates thereby resulting in decreased sales volumes and revenues and (ii) increase the risk that CERC’s suppliers or customers fail or are unable to meet their obligations. An increase in natural gas prices would also increase CERC’s working capital requirements by increasing the investment that must be made in order to maintain natural gas inventory levels. Additionally, a decrease in natural gas prices could increase the amount of collateral that CERC must provide under its hedging arrangements.

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

If CERC’s credit rating were to decline, it might be required to post cash collateral in order to purchase natural gas or under its shipping or hedging arrangements. If a credit rating downgrade and the resultant cash collateral requirement were to occur at a time when CERC was experiencing significant working capital requirements or

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otherwise lacked liquidity, CERC’s results of operations, financial condition and cash flows could be adversely affected.

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

CERC’s interstate pipelines and field services businesses largely rely on natural gas sourced in the various supply basins located in the Mid-continent region of the United States. The level of drilling and production activity in these regions is dependent on economic and business factors beyond our control. The primary factor affecting both the level of drilling activity and production volumes is natural gas pricing. A sustained decline in natural gas prices could result in a decrease in exploration and development activities in the regions served by our gathering and pipeline transportation systems and our natural gas treating and processing activities. A sustained decline could also lead producers to shut in production from their existing wells. Other factors that impact production decisions include the level of production costs relative to other available production, producers’ access to needed capital and the cost of that capital, the ability of producers to obtain necessary drilling and other governmental permits, access to drilling rigs and regulatory changes. Because of these factors, even if new natural gas reserves are discovered in areas served by our assets, producers may choose not to develop those reserves or to shut in production from existing reserves. To the extent the availability of this supply is substantially reduced, it could have an adverse effect on CERC’s results of operations, financial condition and cash flows.

CERC’s revenues from these businesses are also affected by the prices of natural gas and natural gas liquids (NGL). NGL prices generally fluctuate on a basis that correlates to fluctuations in crude oil prices. In the past, the prices of natural gas and crude oil have been extremely volatile, and we expect this volatility to continue. The markets and prices for natural gas, NGLs and crude oil depend upon factors beyond our control. These factors include supply of and demand for these commodities, which fluctuate with changes in market and economic conditions and other factors.

CERC’s revenues and results of operations are seasonal.

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

The actual cost of pipelines under construction, future pipeline, gathering and treating systems and related compression facilities may be significantly higher than CERC had planned.

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

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

The Public Utility Holding Company Act of 1935, to which we and our subsidiaries were subject prior to its repeal in the Energy Policy Act of 2005, provided a comprehensive regulatory structure governing the organization,

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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 September 30, 2009, we had $9.4 billion of outstanding indebtedness on a consolidated basis, which includes $2.4 billion of non-recourse transition bonds. As of September 30, 2009, approximately $822 million principal amount of this debt is required to be paid through 2011. This amount excludes principal repayments of approximately $461 million on transition bonds, for which a dedicated revenue stream exists. Our future financing activities may be significantly affected by, among other things:

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

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general economic and capital market conditions;

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credit availability from financial institutions and other lenders;

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

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maintenance of acceptable credit ratings;

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market expectations regarding our future earnings and cash flows;

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

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

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provisions of relevant tax and securities laws.

As of September 30, 2009, CenterPoint Houston had outstanding approximately $3.1 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, $600 million securing borrowings under a credit facility which was retired following the October 2009 termination of the facility 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 $1.5 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 September 30, 2009. However, CenterPoint Houston has contractually agreed that it will not issue additional first mortgage bonds, subject to certain exceptions.

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Our current credit ratings are discussed in “Management’s Discussion and Analysis of Financial Condition and Results of Operations of CenterPoint Energy, Inc. and Subsidiaries — Liquidity and Capital Resources — Future Sources and Uses of Cash — Impact on Liquidity of a Downgrade in Credit Ratings” in Item 2 of Part I of this Form 10-Q. These credit ratings may not remain in effect for any given period of time and one or more of these ratings may be lowered or withdrawn entirely by a rating agency. We note that these credit ratings are not recommendations to buy, sell or hold our securities. Each rating should be evaluated independently of any other rating. Any future reduction or withdrawal of one or more of our credit ratings could have a material adverse impact on our ability to access capital on acceptable terms.

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

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

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

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

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

Risks Common to Our Businesses and Other Risks

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

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

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restricting the way we can handle or dispose of wastes;

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

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

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

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

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construct or acquire new equipment;

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acquire permits for facility operations;

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modify or replace existing and proposed equipment; and

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

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

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

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

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

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

Under some circumstances, we, CenterPoint Houston and CERC could incur liabilities associated with assets and businesses we, CenterPoint Houston and CERC no longer own. These assets and businesses were previously owned by Reliant Energy, Incorporated (Reliant Energy), a predecessor of CenterPoint Houston, directly or through subsidiaries and include:

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merchant energy, energy trading and REP businesses transferred to RRI or its subsidiaries in connection with the organization and capitalization of RRI prior to its initial public offering in 2001; and

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Texas electric generating facilities transferred to Texas Genco Holdings, Inc. (Texas Genco) in 2004 and early 2005.

In connection with the organization and capitalization of RRI, RRI and its subsidiaries assumed liabilities associated with various assets and businesses Reliant Energy transferred to them. RRI also agreed to indemnify, and cause the applicable transferee subsidiaries to indemnify, us and our subsidiaries, including CenterPoint Houston and CERC, with respect to liabilities associated with the transferred assets and businesses. These indemnity provisions were intended to place sole financial responsibility on RRI and its subsidiaries for all liabilities associated

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with the current and historical businesses and operations of RRI, regardless of the time those liabilities arose. If RRI were unable to satisfy a liability that has been so assumed in circumstances in which Reliant Energy and its subsidiaries were not released from the liability in connection with the transfer, we, CenterPoint Houston or CERC could be responsible for satisfying the liability.

Prior to the distribution of our ownership in RRI to our shareholders, CERC had guaranteed certain contractual obligations of what became RRI’s trading subsidiary. When the companies separated, RRI agreed to secure CERC against obligations under the guaranties RRI had been unable to extinguish by the time of separation. Pursuant to such agreement, as amended in December 2007, RRI has agreed to provide to CERC cash or letters of credit as security against CERC’s obligations under its remaining guaranties if and to the extent changes in market conditions expose CERC to a risk of loss on those guaranties. As of September 30, 2009, RRI was not required to provide security to CERC. If RRI should fail to perform the contractual obligations, CERC could have to honor its guarantee and, in such event, collateral provided as security may be insufficient to satisfy CERC’s obligations.

The potential exposure to CERC under the guaranties relates to payment of demand charges related to transportation contracts. The present value of the demand charges under these transportation contracts, which will be effective until 2018, was approximately $99 million as of September 30, 2009. RRI continues to meet its obligations under the contracts, and on the basis of market conditions, we and CERC have not required additional security. 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 our exposure to the counterparty under the guaranty.

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

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

Reliant Energy and RRI are named as defendants in a number of lawsuits arising out of 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, CenterPoint Houston or CERC could incur liability if claims in one or more of these lawsuits were successfully asserted against us, CenterPoint Houston or CERC and indemnification from RRI were determined to be unavailable or if RRI were unable to satisfy indemnification obligations owed with respect to those claims.

In connection with the organization and capitalization of Texas Genco, 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 NRG Texas LP (previously named 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 NRG Texas LP. In addition, under the amended separation agreement, Texas Genco is no longer liable for, and we have assumed and agreed to indemnify NRG Texas LP against, liabilities that Texas Genco originally assumed in

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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 NRG Texas LP were unable to satisfy a liability that had been so assumed or indemnified against, and provided Reliant Energy had not been released from the liability in connection with the transfer, 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 number of individuals who claim injury due to exposure to asbestos. Some of the claimants have worked at locations owned by us, but most existing claims relate to facilities previously owned by our subsidiaries but currently owned by NRG Texas LP. We anticipate that additional claims like those received may be asserted in the future. Under the terms of the arrangements regarding separation of the generating business from us and its sale to NRG Texas LP, ultimate financial responsibility for uninsured losses from claims relating to the generating business has been assumed by NRG Texas LP, but we have agreed to continue to defend such claims to the extent they are covered by insurance maintained by us, subject to reimbursement of the costs of such defense by NRG Texas LP.

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

The continued credit crisis and related turmoil in the global financial system may have an impact on our business, liquidity and our financial condition. Our ability to access the capital markets may be severely restricted at a time when we would like, or need, to access those markets, which could have an impact on our liquidity and flexibility to react to changing economic and business conditions. In addition, the cost of debt financing and the proceeds of equity financing may be materially adversely impacted by these market conditions. Defaults of lenders in our credit facilities should they occur could adversely affect our liquidity. Capital market turmoil was also reflected in significant reductions in equity market valuations in 2008, which significantly reduced the value of assets of our pension plan. These reductions are expected to result in increased non-cash pension expense in 2009, which will impact 2009 results of operations and may impact liquidity if contributions are made to offset reduced asset values.

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

Item 5. OTHER INFORMATION

The ratio of earnings to fixed charges for the nine months ended September 30, 2008 and 2009 was 2.10 and 1.77, respectively. We do not believe that the ratios for these nine-month periods are necessarily indicative 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.

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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.

Agreements included as exhibits are included only to provide information to investors regarding their terms. Agreements listed below may contain representations, warranties and other provisions that were made, among other things, to provide the parties thereto with specified rights and obligations and to allocate risk among them, and no such agreement should be relied upon as constituting or providing any factual disclosures about CenterPoint Energy, Inc., any other persons, any state of affairs or other matters.

Exhibit Number		Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference
3.1	─	Amended and Restated Articles of Incorporation of CenterPoint Energy	CenterPoint Energy’s Form 8-K dated July 24, 2008	1-31447	3.1
3.2	─	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	─	$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
4.3.2	─	First Amendment to Exhibit 4.3.1, dated as of August 20, 2008, among CenterPoint Energy, as Borrower, and the banks named therein	CenterPoint Energy’s Form 10-Q for the quarter ended September 30, 2008	1-31447	4.4
4.3.3	─	Second Amendment to Exhibit 4.3.1, dated as of November 18, 2008, among CenterPoint Energy, as Borrower, and the banks named therein	CenterPoint Energy’s Form 8-K dated November 18, 2008	1-31447	4.1
4.4.1	─	$300,000,000 Second Amended and Restated Credit Agreement, dated as of June 29, 2007, among CenterPoint Houston, as Borrower, and the banks named therein	CenterPoint Energy’s Form 10-Q for the quarter ended June 30, 2007	1-31447	4.4
4.4.2	─	First Amendment to Exhibit 4.4.1, dated as of November 18, 2008, among CenterPoint Houston, as Borrower, and the banks named therein	CenterPoint Energy’s Form 8-K dated November 18, 2008	1-31447	4.2
4.5	─	$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

Table of Contents

Exhibit Number		Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference
+12	─	Computation of Ratios of Earnings to Fixed Charges
+31.1	─	Rule 13a-14(a)/15d-14(a) Certification of David M. McClanahan
+31.2	─	Rule 13a-14(a)/15d-14(a) Certification of Gary L. Whitlock
+32.1	─	Section 1350 Certification of David M. McClanahan
+32.2	─	Section 1350 Certification of Gary L. Whitlock
+101.INS	─	XBRL Instance Document (1)
+101.SCH	─	XBRL Taxonomy Extension Schema Document (1)
+101.CAL	─	XBRL Taxonomy Extension Calculation Linkbase Document (1)
+101.LAB	─	XBRL Taxonomy Extension Labels Linkbase Document (1)
+101.PRE	─	XBRL Taxonomy Extension Presentation Linkbase Document (1)

(1)

Furnished, not filed.

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: October 28, 2009

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	─	Amended and Restated Articles of Incorporation of CenterPoint Energy	CenterPoint Energy’s Form 8-K dated July 24, 2008	1-31447	3.1
3.2	─	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	─	$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
4.3.2	─	First Amendment to Exhibit 4.3.1, dated as of August 20, 2008, among CenterPoint Energy, as Borrower, and the banks named therein	CenterPoint Energy’s Form 10-Q for the quarter ended September 30, 2008	1-31447	4.4
4.3.3	─	Second Amendment to Exhibit 4.3.1, dated as of November 18, 2008, among CenterPoint Energy, as Borrower, and the banks named therein	CenterPoint Energy’s Form 8-K dated November 18, 2008	1-31447	4.1
4.4.1	─	$300,000,000 Second Amended and Restated Credit Agreement, dated as of June 29, 2007, among CenterPoint Houston, as Borrower, and the banks named therein	CenterPoint Energy’s Form 10-Q for the quarter ended June 30, 2007	1-31447	4.4
4.4.2	─	First Amendment to Exhibit 4.4.1, dated as of November 18, 2008, among CenterPoint Houston, as Borrower, and the banks named therein	CenterPoint Energy’s Form 8-K dated November 18, 2008	1-31447	4.2
4.5	─	$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

Table of Contents

Exhibit Number		Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference
+12	─	Computation of Ratios of Earnings to Fixed Charges
+31.1	─	Rule 13a-14(a)/15d-14(a) Certification of David M. McClanahan
+31.2	─	Rule 13a-14(a)/15d-14(a) Certification of Gary L. Whitlock
+32.1	─	Section 1350 Certification of David M. McClanahan
+32.2	─	Section 1350 Certification of Gary L. Whitlock
+101.INS	─	XBRL Instance Document (1)
+101.SCH	─	XBRL Taxonomy Extension Schema Document (1)
+101.CAL	─	XBRL Taxonomy Extension Calculation Linkbase Document (1)
+101.LAB	─	XBRL Taxonomy Extension Labels Linkbase Document (1)
+101.PRE	─	XBRL Taxonomy Extension Presentation Linkbase Document (1)

(1)

Furnished, not filed.

ex12.htm

Exhibit 12

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES

(Millions of Dollars)

	Nine Months Ended September 30,
	2008 (1)			2009 (1)

Net Income	$	359		$	267
Equity in earnings of unconsolidated affiliates		(46	)		(8	)
Income taxes		212			129
Capitalized interest		(10	)		(5	)
		515			383

Fixed charges, as defined:

Interest		448			482
Capitalized interest		10			5
Interest component of rentals charged to operating expense		11			8
Total fixed charges		469			495

Earnings, as defined		984			878

Ratio of earnings to fixed charges		2.10			1.77

________

(1)

Excluded from the computation of fixed charges for the nine months ended September 30, 2008 and 2009 is interest expense of $8 million and interest income of $3 million, respectively, which is included in income tax expense.

ex31-1.htm

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: October 28, 2009

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

ex31-2.htm

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: October 28, 2009

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

ex32-1.htm

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, 2009 (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
October 28, 2009

ex32-2.htm

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, 2009 (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
October 28, 2009