Edgar Filing: CENTERPOINT ENERGY INC

CNP_10Q_9.30.2011

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

__________________

FORM 10-Q



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

	FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2011



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

	FOR THE TRANSITION PERIOD FROM __________________ TO __________________

Commission file number 1-31447

_____________________________________

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 þ No o

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 þ No o

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 o No þ

As of October 14, 2011, CenterPoint Energy, Inc. had 425,932,721 shares of common stock outstanding, excluding 166 shares held as treasury stock.

CENTERPOINT ENERGY, INC.

QUARTERLY REPORT ON FORM 10-Q

FOR THE QUARTER ENDED SEPTEMBER 30, 2011

TABLE OF CONTENTS



PART I.	FINANCIAL INFORMATION

Item 1.	Financial Statements	1

	Condensed Statements of Consolidated Income
	Three and Nine Months Ended September 30, 2010 and 2011 (unaudited)	1

	Condensed Consolidated Balance Sheets
	December 31, 2010 and September 30, 2011 (unaudited)	2

	Condensed Statements of Consolidated Cash Flows
	Nine Months Ended September 30, 2010 and 2011 (unaudited)	4

	Notes to Unaudited Condensed Consolidated Financial Statements	5

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	24

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	38

Item 4.	Controls and Procedures	39

PART II.	OTHER INFORMATION

Item 1.	Legal Proceedings	39

Item 1A.	Risk Factors	39

Item 5.	Other Information	40

Item 6.	Exhibits	40

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:


•	state and federal legislative and regulatory actions or developments affecting various aspects of our business, including, among others, energy deregulation or re-regulation, pipeline integrity and safety, health care reform, financial reform and tax legislation;


•	state and federal legislative and regulatory actions or developments relating to the environment, including those related to global climate change;


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


•	factors that may impact the timing and completion of our anticipated transition bond offering to recover our true-up balance, including actions by the Public Utility Commission of Texas (Texas Utility Commission), any appeals of the financing order issued by the Texas Utility Commission authorizing the issuance of such transition bonds, and future market conditions;


•	the timing and outcome of any audits, disputes and other proceedings related to taxes;


•	problems with construction, implementation of necessary technology or other issues with respect to major capital projects that result in delays or in cost overruns that cannot be recouped in rates;


•	industrial, commercial and residential growth in our service territory and changes in market demand, including the effects of energy efficiency measures and demographic patterns;


•	the timing and extent of changes in commodity prices, particularly natural gas and natural gas liquids, and the effects of geographic and seasonal commodity price differentials, including the effects of these circumstances on re-contracting available capacity on our interstate pipelines;


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


•	weather variations and other natural phenomena;


•	the direct or indirect effects on our facilities, operations and financial condition resulting from terrorism, cyber attacks, data security breaches or other attempts to disrupt our businesses or the businesses of third parties, or other catastrophic events;


•	the impact of unplanned facility outages;


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


•	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 credit 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 GenOn Energy, Inc. (GenOn) (formerly known as RRI Energy, Inc., Reliant Energy, Inc. and Reliant Resources, Inc.) and its subsidiaries to satisfy their obligations to us, including indemnity obligations, or obligations in connection with the contractual arrangements pursuant to which we are their guarantor;


•	the ability of retail electric providers (REPs), including REP affiliates of NRG Energy, Inc. and REP affiliates of Energy Future Holdings Corp., which are CenterPoint Houston’s two largest customers, to satisfy their 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 pension and postretirement benefit plans;


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


•	acquisition and merger activities involving us or our competitors; and


•	other factors we discuss in “Risk Factors” in Item 1A of Part I of our Annual Report on Form 10-K for the year ended December 31, 2010 and in Item 1A of Part II of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2011, each of which is incorporated herein by reference, and other reports we file from time to time with the Securities and Exchange Commission.

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

iii

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PART I. FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

CONDENSED STATEMENTS OF CONSOLIDATED INCOME

(In Millions, Except Per Share Amounts)

(Unaudited)



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2011			2010			2011

Revenues	$	1,908		$	1,881		$	6,687		$	6,305

Expenses:
Natural gas	808			735			3,521			2,989
Operation and maintenance	444			448			1,268			1,333
Depreciation and amortization	243			253			660			677
Taxes other than income taxes	86			88			291			282
Total	1,581			1,524			5,740			5,281
Operating Income	327			357			947			1,024

Other Income (Expense):
Gain (loss) on marketable securities	19			(80		)	35			(30		)
Gain (loss) on indexed debt securities	(5		)	88			—			65
Interest and other finance charges	(121		)	(114		)	(364		)	(341		)
Interest on transition and system restoration bonds	(34		)	(31		)	(106		)	(96		)
Equity in earnings of unconsolidated affiliates	10			8			22			22
Return on true-up balance	—			352			—			352
Other, net	3			10			7			19
Total	(128		)	233			(406		)	(9		)

Income Before Income Taxes and Extraordinary Item	199			590			541			1,015
Income tax expense	76			204			223			362
Income Before Extraordinary Item	123			386			318			653
Extraordinary Item, net of tax	—			587			—			587
Net Income	$	123		$	973		$	318		$	1,240

Basic Earnings Per Share:
Income Before Extraordinary Item	$	0.29		$	0.90		$	0.79		$	1.53
Extraordinary Item, net of tax	—			1.38			—			1.38
Net Income	$	0.29		$	2.28		$	0.79		$	2.91

Diluted Earnings Per Share:
Income Before Extraordinary Item	$	0.29		$	0.90		$	0.78		$	1.52
Extraordinary Item, net of tax	—			1.37			—			1.37
Net Income	$	0.29		$	2.27		$	0.78		$	2.89

Dividends Declared Per Share	$	0.195		$	0.1975		$	0.585		$	0.5925

Weighted Average Shares Outstanding, Basic	422			426			405			426

Weighted Average Shares Outstanding, Diluted	425			429			408			428

See Notes to Interim Condensed Consolidated Financial Statements

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CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(In Millions)

(Unaudited)

ASSETS



	December 31, 2010		September 30, 2011
Current Assets:
Cash and cash equivalents ($198 and $103 related to VIEs at December 31, 2010 and September 30, 2011, respectively)	$	199	$	103
Investment in marketable securities	367		337
Accounts receivable, net ($49 and $73 related to VIEs at December 31, 2010 and September 30, 2011, respectively)	835		722
Accrued unbilled revenues	340		160
Natural gas inventory	211		250
Materials and supplies	164		168
Non-trading derivative assets	54		52
Taxes receivable	138		—
Prepaid expenses and other current assets ($39 and $41 related to VIEs at December 31, 2010 and September 30, 2011, respectively)	274		190
Total current assets	2,582		1,982

Property, Plant and Equipment:
Property, plant and equipment	16,005		16,591
Less accumulated depreciation and amortization	4,273		4,433
Property, plant and equipment, net	11,732		12,158

Other Assets:
Goodwill	1,696		1,696
Regulatory assets ($2,597 and $2,352 related to VIEs at December 31, 2010 and September 30, 2011, respectively)	3,446		4,475
Non-trading derivative assets	15		12
Investment in unconsolidated affiliates	468		474
Other	172		154
Total other assets	5,797		6,811

Total Assets	$	20,111	$	20,951

See Notes to Interim Condensed Consolidated Financial Statements

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CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS – (continued)

(In Millions)

(Unaudited)

LIABILITIES AND SHAREHOLDERS’ EQUITY



	December 31, 2010			September 30, 2011
Current Liabilities:
Short-term borrowings	$	53		$	84
Current portion of VIE transition and system restoration bonds long-term debt	283			307
Current portion of indexed debt	126			130
Current portion of other long-term debt	19			46
Indexed debt securities derivative	232			167
Accounts payable	667			417
Taxes accrued	156			184
Interest accrued	171			118
Non-trading derivative liabilities	68			53
Accumulated deferred income taxes, net	407			494
Other	438			319
Total current liabilities	2,620			2,319


Other Liabilities:
Accumulated deferred income taxes, net	2,934			3,814
Non-trading derivative liabilities	16			3
Benefit obligations	906			842
Regulatory liabilities	989			1,033
Other	447			236
Total other liabilities	5,292			5,928

Long-term Debt:
VIE transition and system restoration bonds	2,522			2,215
Other	6,479			6,282
Total long-term debt	9,001			8,497

Commitments and Contingencies (Note 12)

Shareholders’ Equity:
Common stock (424,746,177 shares and 425,919,192 shares outstanding at December 31, 2010 and September 30, 2011, respectively)	4			4
Additional paid-in capital	4,100			4,114
Retained earnings (accumulated deficit)	(789		)	199
Accumulated other comprehensive loss	(117		)	(110		)
Total shareholders’ equity	3,198			4,207

Total Liabilities and Shareholders’ Equity	$	20,111		$	20,951

See Notes to Interim Condensed Consolidated Financial Statements

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CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS

(In Millions)

(Unaudited)



	Nine Months Ended September 30,
	2010			2011
Cash Flows from Operating Activities:
Net income	$	318		$	1,240
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	660			677
Amortization of deferred financing costs	21			22
Deferred income taxes	112			404
Extraordinary item, net of tax	—			(587		)
Return on true-up balance	—			(352		)
Unrealized loss (gain) on marketable securities	(35		)	30
Unrealized gain on indexed debt securities	—			(65		)
Write-down of natural gas inventory	6			7
Equity in earnings of unconsolidated affiliates, net of distributions	4			3
Changes in other assets and liabilities:
Accounts receivable and unbilled revenues, net	434			245
Inventory	(83		)	(50		)
Taxes receivable	(113		)	138
Accounts payable	(283		)	(215		)
Fuel cost over (under) recovery	43			(52		)
Non-trading derivatives, net	(16		)	(10		)
Margin deposits, net	(38		)	61
Interest and taxes accrued	(56		)	(25		)
Net regulatory assets and liabilities	23			22
Other current assets	17			14
Other current liabilities	(38		)	(23		)
Other assets	(8		)	(1		)
Other liabilities	2			(49		)
Other, net	13			15
Net cash provided by operating activities	983			1,449

Cash Flows from Investing Activities:
Capital expenditures	(1,053		)	(960		)
Increase in restricted cash of transition and system restoration bond companies	(1		)	(2		)
Investment in unconsolidated affiliates	(21		)	(9		)
Cash received from U.S Department of Energy grant	58			110
Other, net	3			13
Net cash used in investing activities	(1,014		)	(848		)

Cash Flows from Financing Activities:
Increase in short-term borrowings, net	18			31
Proceeds from commercial paper, net	—			(41		)
Proceeds from long-term debt	—			550
Payments of long-term debt	(783		)	(909		)
Cash paid for debt exchange	—			(58		)
Debt issuance costs	(2		)	(23		)
Payment of common stock dividends	(236		)	(252		)
Proceeds from issuance of common stock, net	392			5
Other, net	1			—
Net cash used in financing activities	(610		)	(697		)

Net Decrease in Cash and Cash Equivalents	(641		)	(96		)
Cash and Cash Equivalents at Beginning of Period	740			199
Cash and Cash Equivalents at End of Period	$	99		$	103

Supplemental Disclosure of Cash Flow Information:
Cash Payments:
Interest, net of capitalized interest	$	505		$	470
Income taxes (refunds), net	210			(204		)
Non-cash transactions:
Accounts payable related to capital expenditures	104			101

See Notes to 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, 2010 (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, 2011, 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 the Texas Gulf Coast area that includes the city of Houston; and

•

CenterPoint Energy Resources Corp. (CERC Corp. and, together with its subsidiaries, CERC), which owns and operates natural gas distribution systems. 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 (U.S. 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, see Note 14.


(2)	New Accounting Pronouncements

In January 2010, the Financial Accounting Standards Board (FASB) issued new accounting guidance to require additional fair value related disclosures. It also clarified existing fair value disclosure guidance about the level of disaggregation, inputs and valuation techniques. This new guidance was effective for the first reporting period beginning after December 15, 2009 except for certain disclosure requirements effective for the first reporting period beginning after December 15, 2010. 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 6 for the required disclosures.

In May 2011, the FASB issued new accounting guidance to achieve common fair value measurements and disclosure requirements in U.S. GAAP and International Financial Reporting Standards (IFRS). Some of the provisions of the new accounting guidance include requiring (1) that only nonfinancial assets should be valued based on a determination of their best use, (2) disclosure of quantitative information about unobservable inputs used in Level 3 fair value measurements and (3) disclosure of the level within the fair value hierarchy for each class of assets or liabilities not measured at fair value in the statement of financial position but for which the fair value is disclosed. This new guidance is effective for interim and annual periods beginning after December 15, 2011. 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 2011, the FASB issued new accounting guidance on the presentation of comprehensive income. The new guidance is intended to improve the overall quality of financial reporting by increasing the prominence of items reported in other comprehensive

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income and aligning the presentation of other comprehensive income in financial statements prepared in accordance with U.S. GAAP with those prepared in accordance with IFRS. The new guidance requires an entity to present the total of comprehensive income, the components of net income, and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. This new guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. 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 September 2011, the FASB issued new accounting guidance that is intended to simplify how entities test goodwill for impairment. The new accounting guidance permits an entity to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test. If, after performing the qualitative assessment, it is determined that the fair value of a reporting unit is more likely than not less than its carrying value, then the quantitative two-step goodwill impairment test that exists under current GAAP must be performed; otherwise, goodwill is deemed to not be impaired and no further testing is required. An entity has the unconditional option to bypass the qualitative assessment and proceed directly to the quantitative assessment. This new guidance is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011, with early adoption permitted. CenterPoint Energy did not elect early adoption, but expects that the adoption of this new guidance will not have a material 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.


(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,
	2010						2011
	Pension Benefits ⁽¹⁾			Postretirement Benefits			Pension Benefits ⁽¹⁾			Postretirement Benefits
	(in millions)
Service cost	$	8		$	—		$	8		$	—
Interest cost	26			7			25			5
Expected return on plan assets	(27		)	(2		)	(29		)	(2		)
Amortization of prior service credit	—			—			1			1
Amortization of net loss	15			—			14			—
Amortization of transition obligation	—			2			—			2
Net periodic cost	$	22		$	7		$	19		$	6



	Nine Months Ended September 30,
	2010						2011
	Pension Benefits ⁽¹⁾			Postretirement Benefits			Pension Benefits ⁽¹⁾			Postretirement Benefits
	(in millions)
Service cost	$	24		$	1		$	25		$	1
Interest cost	77			19			75			17
Expected return on plan assets	(82		)	(7		)	(87		)	(7		)
Amortization of prior service credit	2			2			3			3
Amortization of net loss	44			—			42			1
Amortization of transition obligation	—			5			—			5
Net periodic cost	$	65		$	20		$	58		$	20

________________

(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 in excess of amounts authorized for recovery in base rates is being deferred for rate making purposes. CenterPoint Houston deferred as a regulatory asset $6 million and $2 million, respectively, in pension expense during the three months

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ended September 30, 2010 and 2011, and $18 million and $13 million, respectively, in pension expense during the nine months ended September 30, 2010 and 2011.

CenterPoint Energy expects to contribute approximately $75 million to its pension plans in 2011, of which approximately $69 million and $72 million, respectively, were contributed during the three and nine months ended September 30, 2011.

CenterPoint Energy expects to contribute approximately $18 million to its postretirement benefits plan in 2011, of which approximately $0 and $11 million, respectively, were contributed during the three and nine months ended September 30, 2011.


(4)	Regulatory Matters


(a)	Resolution of True-Up Appeal

In March 2004, CenterPoint Houston filed a true-up application with the Public Utility Commission of Texas (Texas Utility Commission), requesting recovery of $3.7 billion, excluding interest, as allowed under the Texas Electric Choice Plan. 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 returned to customers after August 31, 2004 and certain other adjustments. 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.

Various parties, including CenterPoint Houston, appealed the True-Up Order. These appeals were heard first by a district court in Travis County, Texas, then by the Texas Third Court of Appeals and finally by the Texas Supreme Court. On March 18, 2011, the Texas Supreme Court issued a unanimous ruling on such appeals in which it affirmed in part and reversed in part the decision of the Texas Utility Commission . In June 2011, the Texas Supreme Court denied all motions for rehearing and issued a final mandate remanding the case to the Texas Utility Commission for further proceedings (the Remand Proceeding).

In September 2011, CenterPoint Houston reached an agreement in principle with the staff of the Texas Utility Commission and certain intervenors to settle the issues in the Remand Proceeding (the Settlement) and requested that the Texas Utility Commission abate the procedural schedule for the Remand Proceeding and reserve ruling on pending motions or issues until the Texas Utility Commission reviewed the Settlement. At its open meeting on October 13, 2011, the Texas Utility Commission voted to approve a final order (the Final Order) in the Remand Proceeding. The Final Order provides that (i) CenterPoint Houston is entitled to recover an additional true-up balance of $1.695 billion (the Recoverable True-Up Balance) in the Remand Proceeding, (ii) no further interest will accrue on the Recoverable True-Up Balance, and (iii) CenterPoint Houston will reimburse certain parties for their reasonable rate case expenses. The Final Order is consistent with the terms of the Settlement, which resolved all matters in the Remand Proceeding. The Final Order was issued by the Texas Utility Commission on October 19, 2011. Any party may appeal the Final Order by filing a motion for rehearing within 20 days from the date the party received notice of the Final Order.

On October 27, 2011, the Texas Utility Commission issued a financing order (the Financing Order) that authorizes the issuance of transition bonds by CenterPoint Houston to securitize the Recoverable True-Up Balance. The Financing Order is subject to appeal within 15 days from the date it was issued. The timing and completion of any transition bond offering will ultimately depend on a number of factors, including actions by the Texas Utility Commission, any appeals of the Financing Order, and future market conditions.

As a result of the Final Order, CenterPoint Houston recorded a pre-tax extraordinary gain of $921 million ($587 million after-tax of $334 million) and $352 million ($224 million after-tax) of Other Income related to a portion of interest on the appealed amount. An additional $405 million ($258 million after-tax) will be recorded as an equity return over the life of the transition bonds.

As of September 30, 2011, CenterPoint Energy has not recognized an allowed equity return of $165 million on the portion of CenterPoint Houston’s true-up balance that had previously been securitized because such return will be recognized as it is recovered in rates. During the three months ended September 30, 2010 and 2011, CenterPoint Houston recognized approximately $5 million and $6 million, respectively, of the allowed equity return not previously recognized. During the nine months ended September 30, 2010 and 2011, CenterPoint Houston recognized approximately $12 million and $13 million, respectively, of the allowed equity return not previously recognized.

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(b)	Rate Proceedings

CenterPoint Houston

June 2010 Rate Proceeding. As required under the final order in its 2006 rate proceeding, in June 2010 CenterPoint Houston filed an application to change rates with the Texas Utility Commission and the cities in its service area.

Following hearings in the fall of 2010, the Texas Utility Commission issued its order on May 12, 2011. In response to motions filed by several parties, including CenterPoint Houston, on June 23, 2011, the Texas Utility Commission issued an order on rehearing, which addressed certain errors and inconsistencies identified in its prior decision. CenterPoint Houston implemented revised rates on September 1, 2011 based on the order on rehearing. The order on rehearing has been appealed to the Texas courts by various parties; however, a procedural schedule has not been established.

The order on rehearing provides for a base rate increase for CenterPoint Houston of approximately $14.7 million per year for delivery charges to the REPs and a decrease to charges to wholesale transmission customers of $12.3 million per year. Further, the order adopts a mechanism to track amounts for uncertain tax positions and provide for ultimate recovery of those costs. The order authorizes a return on equity for CenterPoint Houston of 10%, a cost of debt of 6.74%, a capital structure comprised of 55% debt and 45% common equity, and an overall rate of return of 8.21%. The decision also implements CenterPoint Houston’s request to reconcile costs incurred for the advanced metering system (AMS) project and to shorten the period for collecting the AMS surcharge from twelve to six years for residential customers in order to reflect the funds received from the U.S. Department of Energy. As a result of the Texas Utility Commission’s order, CenterPoint Houston anticipates that normalized annual operating income will be reduced by approximately $30 million.

Other. In May 2009, CenterPoint Houston filed an application at the Texas Utility Commission seeking approval of certain estimated 2010 energy efficiency program costs, an energy efficiency performance bonus for 2008 programs, and carrying costs totaling approximately $10 million. The application sought to begin recovery of these costs through a surcharge effective July 1, 2010. In October 2009, the Texas Utility Commission issued its order approving recovery of the 2010 energy efficiency program costs and a partial performance bonus of approximately $8 million, plus carrying costs, but disallowed recovery of a performance bonus of $2 million on approximately $10 million in 2008 energy efficiency costs expended pursuant to the terms of a settlement agreement in a prior rate case. CenterPoint Houston began collecting the approved amounts in July 2010. CenterPoint Houston appealed the denial of the full 2008 performance bonus to the 98th district court in Travis County, Texas. In October 2010, the district court upheld the Texas Utility Commission’s decision. In February 2011, CenterPoint Houston appealed the district court’s judgment to the Texas Third Court of Appeals at Austin, Texas. Oral arguments were heard in October 2011, and the case remains pending.

In April 2010, CenterPoint Houston filed an application with the Texas Utility Commission seeking approval of the recovery of $14.4 million related to estimated 2011 energy efficiency programs, an energy efficiency performance bonus for 2009 programs, and recovery of revenue losses related to the implementation of the 2009 energy efficiency program. The application sought to begin recovery of these costs through a surcharge beginning in January 2011. In November 2010, the Texas Utility Commission issued its order approving recovery of approximately $11 million of the 2011 energy efficiency program costs and a performance bonus, but disallowed recovery of a performance bonus of $2 million on the 2009 energy efficiency costs expended pursuant to the terms of the settlement agreement referenced above. The Texas Utility Commission further concluded that it does not have statutory authority to permit recovery of the approximately $1.4 million in lost revenue associated with 2009 energy efficiency programs. CenterPoint Houston began collecting the approved amounts in January 2011, but has appealed the denial of the full 2009 performance bonus and lost revenue to the 201st district court in Travis County, Texas, where the case remains pending.

In April 2011, CenterPoint Houston filed an application with the Texas Utility Commission seeking approval of the recovery in 2012 of approximately $44.3 million consisting of: (1) estimated 2012 energy efficiency program costs of approximately $35.8 million; (2) an energy efficiency performance bonus based on CenterPoint Houston’s 2010 program achievements of approximately $5.8 million; (3) the amount of lost revenues due to verified and reported 2010 energy savings of approximately $2.2 million; and (4) approximately $0.5 million for under-recovery of 2010 program costs. In the preliminary order in this proceeding, the Texas Utility Commission has excluded approximately $2.1 million of the requested performance bonus for the 2010 programs and has concluded that it does not have the statutory authority to permit recovery of the requested $2.2 million of lost revenues associated with the 2010 programs. In August 2011, CenterPoint Houston and the parties agreed to forego a hearing and admit evidence supporting the recovery of (1) the estimated 2012 energy efficiency costs of approximately $35.8 million, (2) an energy efficiency performance bonus of approximately $3.6 million, and (3) approximately $0.5 million for under-recovery of 2010 program costs. CenterPoint Houston has filed notification that it reserves its right to appeal the denial of the full 2010 performance bonus and lost revenues. The proposed rate adjustments are expected to take effect with the commencement of CenterPoint Houston’s January

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2012 billing month.

In August 2011, CenterPoint Houston filed a Transmission Cost of Service application with the Texas Utility Commission seeking an increase in annual revenue of approximately $3.4 million. In September 2011, the Texas Utility Commission approved the application and the rates became effective at that time.

In September 2011, a new rule of the Texas Utility Commission relating to a Distribution Cost Recovery Factor (DCRF) became effective. The new rule permits an electric utility such as CenterPoint Houston to file each year to recover through a separate DCRF a return on changes to certain distribution-related capital investments, net of any changes in distribution-related accumulated deferred income taxes, as well as related changes to depreciation expense and taxes. The utility is allowed to request one DCRF annually unless in the previous year it was found to have earned in excess of its authorized return on equity as calculated in its annual earnings monitoring report on a weather-adjusted basis, in which case the DCRF is not available. The utility is limited to four DCRF filings and then must seek a full rate proceeding before it can request a subsequent DCRF. The rule expires January 1, 2017.

In October 2011, CenterPoint Houston and certain other parties filed a non-unanimous stipulation (Transmission Stipulation) with the Texas Utility Commission to resolve claims related to the “transition mechanism” component of certain invalidated transmission pricing rules. The Transmission Stipulation resolves all remaining claims that arose from or relate to wholesale transmission service and charges within the Electric Reliability Council of Texas, Inc. (ERCOT) for the period from September 1, 1999 to December 31, 1999 during which the Texas Utility Commission had continued to utilize the “transition mechanism” component of the invalidated transmission pricing rules in setting ERCOT transmission rates. The Transmission Stipulation was filed by all parties to the proceeding, except CPS Energy. Under the Transmission Stipulation, CenterPoint Houston's payment of $5.6 million is to be made within 30 days after issuance of a final appealable order. It is expected that a final appealable order will be issued in early 2012. CenterPoint Houston will seek recovery of the payment through its Transmission Cost Recovery Factor mechanism.

Gas Operations

Texas. In March 2008, the natural gas distribution business 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, the Railroad Commission approved the implementation of rates increasing annual revenues by approximately $3.5 million. The approved rates were contested by a coalition of nine cities in an appeal to the 353rd district court in Travis County, Texas. In January 2010, that court reversed the Railroad Commission’s order in part and remanded the matter to the Railroad Commission. In its final judgment, the court ruled that the Railroad Commission lacked authority to impose the approved cost of service adjustment mechanism in both those nine cities and in those areas in which the Railroad Commission has original jurisdiction. The Railroad Commission and Gas Operations appealed the court’s ruling on the cost of service adjustment mechanism to the Texas Third Court of Appeals in Austin, Texas. Oral arguments were held in February 2011. In October 2011, the Texas Third Court of Appeals reversed the district court's ruling. Parties opposed to the decision may request the Texas Third Court of Appeals to reconsider or appeal to the Texas Supreme Court. CenterPoint Energy does not expect the outcome of this matter to have a material adverse impact on its financial condition, results of operations or cash flows. The cost of service adjustment was initially effective for three successive years ending in calendar year 2010, but would automatically renew for successive three-year periods unless Gas Operations or the regulatory authority having original jurisdiction gave written notice to discontinue the adjustment mechanism by February 1, 2011. Certain cities that agreed to the initial implementation notified Gas Operations by February 1, 2011 of their desire to discontinue the adjustment mechanism. In July 2011, Gas Operations requested that the Railroad Commission waive the notice date of February 1, 2011 in order to allow Gas Operations to discontinue the cost of service adjustment mechanism for the remaining areas, which request was granted in July 2011.

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 sought to establish uniform rates, charges and terms and conditions of service for the cities and environs of the Houston service territory. As finally submitted to the Railroad Commission and the cities, the proposed new rates would have resulted in an overall increase in annual revenue of $20.4 million, excluding carrying costs of approximately $2 million on its gas inventory. In February 2010, the Railroad Commission issued its decision authorizing a revenue increase of $5.1 million annually, reflecting reduced depreciation rates as well as adjustments to pension and other employee benefits, accumulated deferred income taxes and other items. The Railroad Commission also approved a surcharge of $0.9 million per year to recover costs associated with damage caused by Hurricane Ike over three years. These rates went into effect in March 2010. Gas Operations and other parties are seeking judicial review of the Railroad Commission’s decision in the 261st district court in Travis County, Texas.

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(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.

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 the 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.


(a)	Non-Trading Activities

Derivative Instruments. CenterPoint Energy enters into certain derivative instruments to manage physical commodity price risks and does not engage in proprietary or speculative commodity trading. These financial instruments do not qualify or are not designated as cash flow or fair value hedges.

During the three months ended September 30, 2010, CenterPoint Energy recorded increased natural gas revenues from unrealized net gains of $28 million and increased natural gas expense from unrealized net losses of $9 million, resulting in a net unrealized gain of $19 million. During the three months ended September 30, 2011, CenterPoint Energy recorded increased natural gas revenues from unrealized net gains of $18 million and increased natural gas expense from unrealized net losses of $12 million, resulting in a net unrealized gain of $6 million. During the nine months ended September 30, 2010, CenterPoint Energy recorded increased natural gas revenues from unrealized net gains of $45 million and increased natural gas expense from unrealized net losses of $31 million, resulting in a net unrealized gain of $14 million. During the nine months ended September 30, 2011, CenterPoint Energy recorded decreased natural gas revenues from unrealized net losses of $1 million and decreased natural gas expense from unrealized net gains of $9 million, resulting in a net unrealized gain of $8 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 Gas Operations’ results in the remaining jurisdictions and in CenterPoint Houston’s service territory.

CenterPoint Energy enters into heating-degree day swaps to mitigate the effect of fluctuations from normal weather on its results of operations and cash flows for the winter heating season. The swaps are based on ten-year normal weather. During the three and nine months ended September 30, 2010, CenterPoint Energy recognized losses of $0 and $5 million, respectively, related to these swaps. During the three and nine months ended September 30, 2011, CenterPoint Energy recognized losses of $0 and $6 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 two tables provide a balance sheet overview of CenterPoint Energy’s Derivative Assets and Liabilities as of December 31, 2010 and September 30, 2011, while the last table provides a breakdown of the related income statement impacts for the three and nine months ended September 30, 2010 and 2011.

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Fair Value of Derivative Instruments
		December 31, 2010
Total derivatives not designated as hedging instruments	Balance Sheet Location	Derivative Assets Fair Value (2) (3)		Derivative Liabilities Fair Value (2) (3)
		(in millions)
Natural gas contracts (1)	Current Assets	$	55	$	1
Natural gas contracts (1)	Other Assets	15		—
Natural gas contracts (1)	Current Liabilities	10		143
Natural gas contracts (1)	Other Liabilities	—		35
Indexed debt securities derivative	Current Liabilities	—		232
Total		$	80	$	411

________________


(1)	Natural gas 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.


(2)	The fair value shown for natural gas contracts is comprised of derivative gross volumes totaling 626 billion cubic feet (Bcf) or a net 72 Bcf long position. Of the net long position, basis swaps constitute 63 Bcf and volumes associated with price stabilization activities of the Natural Gas Distribution business segment constitute 26 Bcf.


(3)	The net of total non-trading derivative assets and liabilities is a $15 million liability as shown on CenterPoint Energy’s Condensed Consolidated Balance Sheets, and is comprised of the natural gas contracts derivative assets and liabilities separately shown above offset by collateral netting of $84 million.



Fair Value of Derivative Instruments
		September 30, 2011
Total derivatives not designated as hedging instruments	Balance Sheet Location	Derivative Assets Fair Value (2) (3)		Derivative Liabilities Fair Value (2) (3)
		(in millions)
Natural gas contracts (1)	Current Assets	$	52	$	—
Natural gas contracts (1)	Other Assets	12		—
Natural gas contracts (1)	Current Liabilities	22		104
Natural gas contracts (1)	Other Liabilities	1		7
Indexed debt securities derivative	Current Liabilities	—		167
Total		$	87	$	278

________________


(1)	Natural gas 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.


(2)	The fair value shown for natural gas contracts is comprised of derivative gross volumes totaling 585 Bcf or a net 69 Bcf long position. Of the net long position, basis swaps constitute 69 Bcf and volumes associated with price stabilization activities of the Natural Gas Distribution business segment constitute 10 Bcf.


(3)	The net of total non-trading derivative assets and liabilities is an $8 million asset as shown on CenterPoint Energy’s Condensed Consolidated Balance Sheets, and is comprised of the natural gas contracts derivative assets and liabilities separately shown above offset by collateral netting of $32 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 these contracts are recorded as net regulatory assets. Realized and unrealized gains and losses on other derivatives are recognized in the Condensed Statements of Consolidated Income as revenue for retail sales derivative contracts and as natural gas expense for financial natural gas derivatives and non-retail related physical natural gas derivatives. Unrealized gains and losses on indexed debt securities are recorded as Other Income (Expense) in the Condensed Statements of Consolidated Income.

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Income Statement Impact of Derivative Activity
		Three Months Ended September 30,
Total derivatives not designated as hedging instruments	Income Statement Location	2010			2011
		(in millions)
Natural gas contracts	Gains (Losses) in Revenue	$	41		$	27
Natural gas contracts (1)	Gains (Losses) in Expense: Natural Gas	(41		)	(30		)
Indexed debt securities derivative	Gains (Losses) in Other Income (Expense)	(5		)	88
Total		$	(5	)	$	85

________________


(1)	The Gains (Losses) in Expense: Natural Gas includes $(24) million and $(17) million of costs in 2010 and 2011, respectively, 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
		Nine Months Ended September 30,
Total derivatives not designated as hedging instruments	Income Statement Location	2010			2011
		(in millions)
Natural gas contracts	Gains (Losses) in Revenue	$	90		$	41
Natural gas contracts (1)	Gains (Losses) in Expense: Natural Gas	(133		)	(79		)
Indexed debt securities derivative	Gains (Losses) in Other Income (Expense)	—			65
Total		$	(43	)	$	27

________________


(1)	The Gains (Losses) in Expense: Natural Gas includes $(74) million and $(79) million of costs in 2010 and 2011, respectively, associated with price stabilization activities of the Natural Gas Distribution business segment that will be ultimately recovered through purchased gas adjustments.


(c)	Credit Risk Contingent Features

CenterPoint Energy enters into financial derivative contracts containing material adverse change provisions. These provisions could require CenterPoint Energy to post additional collateral if the Standard & Poor’s Ratings Services or Moody’s Investors Service, Inc. credit ratings of CenterPoint Energy, Inc. or its subsidiaries are downgraded. The total fair value of the derivative instruments that contain credit risk contingent features that are in a net liability position at December 31, 2010 and September 30, 2011 was $107 million and $51 million, respectively. The aggregate fair value of assets that are already posted as collateral was $31 million and $2 million, respectively, at December 31, 2010 and September 30, 2011. If all derivative contracts (in a net liability position) containing credit risk contingent features were triggered at December 31, 2010 and September 30, 2011, $76 million and $48 million, respectively, of additional assets would be required to be posted as collateral.


(6)	Fair Value Measurements

Assets and liabilities that are 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 below 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 exchange-traded derivatives and equity securities.

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. A market approach is utilized to value CenterPoint Energy’s Level 2 assets or liabilities.

Level 3: Inputs are unobservable for the asset or liability, and include situations where there is little, if any, market activity

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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. A market approach is utilized to value CenterPoint Energy’s Level 3 assets or liabilities.

CenterPoint Energy determines the appropriate level for each financial asset and liability on a quarterly basis and recognizes any transfers at the end of the reporting period. For the quarter ended September 30, 2011, there were no significant transfers between levels.

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, 2010 and September 30, 2011, 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
			Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Netting Adjustments ⁽¹⁾			December 31, 2010
	(in millions)
Assets
Corporate equities	$	368	$	—	$	—	$	—		$	368
Investments, including money market funds	54		—		—		—			54
Natural gas derivatives	—		73		7		(11		)	69
Total assets	$	422	$	73	$	7	$	(11	)	$	491
Liabilities
Indexed debt securities derivative	$	—	$	232	$	—	$	—		$	232
Natural gas derivatives	8		167		4		(95		)	84
Total liabilities	$	8	$	399	$	4	$	(95	)	$	316

________________


(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 of $84 million posted with the same counterparties.



	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
			Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Netting Adjustments ⁽¹⁾			September 30, 2011
	(in millions)
Assets
Corporate equities	$	339	$	—	$	—	$	—		$	339
Investments, including money market funds	54		—		—		—			54
Natural gas derivatives	8		72		7		(23		)	64
Total assets	$	401	$	72	$	7	$	(23	)	$	457
Liabilities
Indexed debt securities derivative	$	—	$	167	$	—	$	—		$	167
Natural gas derivatives	11		96		4		(55		)	56
Total liabilities	$	11	$	263	$	4	$	(55	)	$	223

________________


(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 of $32 million posted with the same counterparties.

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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,
	2010			2011
	(in millions)
Beginning balance	$	5		$	5
Total unrealized losses:
Included in earnings	—			(1		)
Total settlements, gross ⁽¹⁾:
Included in earnings	(2		)	(1		)
Ending balance	$	3		$	3
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	$	1		$	(1	)

________________


(1)	During both the three months ended September 30, 2010 and 2011, CenterPoint Energy did not have Level 3 purchases or sales.



	Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Derivative assets and liabilities, net
	Nine Months Ended September 30,
	2010			2011
	(in millions)
Beginning balance	$	(6	)	$	3
Total unrealized gains (losses):
Included in earnings	2			3
Included in regulatory assets	(1		)	—
Total settlements, gross ⁽¹⁾:
Included in earnings	(1		)	(3		)
Included in regulatory assets	9			—
Ending balance	$	3		$	3
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		$	2

________________


(1)	During both the nine months ended September 30, 2010 and 2011, CenterPoint Energy did not have Level 3 purchases or sales.

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 and CenterPoint Energy’s 2.00% Zero-Premium Exchangeable Subordinated Notes due 2029 indexed debt securities derivative 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.

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	December 31, 2010				September 30, 2011
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in millions)
Financial liabilities:
Long-term debt	$	9,303	$	10,071	$	8,850	$	9,870


(7)	Goodwill

Goodwill by reportable business segment as of both December 31, 2010 and September 30, 2011 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 as of July 1, 2011, its annual impairment testing date, and determined that no impairment existed.


(8)	Comprehensive Income

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



	For the Three Months Ended				For the Nine Months Ended
	September 30,				September 30,
	2010		2011		2010		2011
	(in millions)
Net income	$	123	$	973	$	318	$	1,240
Other comprehensive income:
Adjustment related to pension and other postretirement plans (net of tax of $2, $2, $5 and $5)	2		2		7		7
Reclassification of deferred loss from cash flow hedges realized in net income (net of tax of $-0-, $-0-, $-0- and $-0-)	1		—		1		—
Total	3		2		8		7
Comprehensive income	$	126	$	975	$	326	$	1,247

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



	December 31, 2010			September 30, 2011
	(in millions)
Adjustment related to pension and postretirement plans	$	(114	)	$	(107	)
Net deferred loss from cash flow hedges	(3		)	(3		)
Total accumulated other comprehensive loss	$	(117	)	$	(110	)


(9)	Capital Stock

CenterPoint Energy, Inc. 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, 2010, 424,746,343 shares of CenterPoint Energy common stock were issued and 424,746,177 shares were outstanding. At September 30, 2011, 425,919,358 shares of CenterPoint Energy common stock were issued and 425,919,192 shares were outstanding. Outstanding common shares exclude 166 treasury shares at both December 31, 2010 and September 30, 2011.


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


(a)	Short-term Borrowings

Receivables Facility. CERC’s receivables facility terminated pursuant to its terms on September 14, 2011. As of December 31, 2010, the facility size was $160 million and there were no advances under the facility.

Inventory Financing. In October 2009, Gas Operations entered into asset management agreements associated with its utility distribution service in Arkansas, north Louisiana and Oklahoma that extend through March 31, 2012. Pursuant to the provisions of the agreements, Gas Operations sells natural gas and agrees to repurchase an equivalent amount of natural gas during the winter heating seasons at the same cost, plus a financing charge. These transactions are accounted for as a financing and they had an associated principal obligation of $53 million and $84 million as of December 31, 2010 and September 30, 2011, respectively.


(b)	Long-term Debt

Revolving Credit Facilities. In the third quarter of 2011, the revolving credit facilities of CenterPoint Energy, CenterPoint Houston and CERC Corp. were replaced with five-year revolving credit facilities of similar borrowing capacity. As of December 31, 2010 and September 30, 2011, CenterPoint Energy, CenterPoint Houston and CERC Corp. had the following revolving credit facilities and utilization of such facilities (in millions):



	December 31, 2010								September 30, 2011
	Size of Facility		Loans		Letters of Credit		Commercial Paper		Size of Facility		Loans		Letters of Credit		Commercial Paper
CenterPoint Energy	$	1,156	$	—	$	20	$	—	$	1,200	$	—	$	16	$	—
CenterPoint Houston	289		—		4		—		300		—		4		—
CERC Corp.	915		—		—		183		950		—		—		142
Total	$	2,360	$	—	$	24	$	183	$	2,450	$	—	$	20	$	142

CenterPoint Energy’s $1.2 billion credit facility, which is scheduled to terminate September 9, 2016, can be drawn at the London Interbank Offered Rate (LIBOR) plus 175 basis points based on CenterPoint Energy’s current credit ratings. The facility contains a debt (excluding transition and system restoration bonds) to earnings before interest, taxes, depreciation and amortization (EBITDA) covenant (as those terms are defined in the facility). The facility allows for a temporary increase of the permitted ratio in the financial covenant from 5 times to 5.5 times if CenterPoint Houston experiences damage from a natural disaster in its service territory and CenterPoint Energy certifies to the administrative agent that CenterPoint Houston has incurred system restoration costs reasonably likely to exceed $100 million in a consecutive twelve-month period, all or part of which CenterPoint Houston intends to seek to recover through securitization financing. Such temporary increase in the financial covenant would be in effect from the date CenterPoint Energy delivers its certification until the earliest to occur of (i) the completion of the securitization financing, (ii) the first anniversary of CenterPoint Energy’s certification or (iii) the revocation of such certification.

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CenterPoint Houston’s $300 million credit facility, which is scheduled to terminate September 9, 2016, can be drawn at LIBOR plus 150 basis points based on CenterPoint Houston's current credit ratings. The facility contains a debt (excluding transition and system restoration bonds) to total capitalization covenant which limits debt to 65% of the borrower's total capitalization.

CERC Corp.’s $950 million credit facility, which is scheduled to terminate September 9, 2016, can be drawn at LIBOR plus 150 basis points based on CERC Corp.’s current credit ratings. The facility contains a debt to total capitalization covenant which limits debt to 65% of CERC's total capitalization.

CERC Corp. Senior Notes. In January 2011, CERC Corp. issued $250 million aggregate principal amount of senior notes due 2021 with an interest rate of 4.50% and $300 million aggregate principal amount of senior notes due 2041 with an interest rate of 5.85%. The proceeds from the issuance of the notes were used for the repayment of $550 million of CERC Corp.’s 7.75% senior notes at their maturity in February 2011. Accordingly, the $550 million senior notes due in February 2011 are reflected as long-term debt as of December 31, 2010.

CERC Corp. Exchange Offer. Also in January 2011, CERC Corp. issued an additional $343 million aggregate principal amount of 4.50% senior notes due 2021 and provided cash consideration of $114 million in exchange for $397 million aggregate principal amount of its 7.875% senior notes due 2013. The premium of $58 million paid on exchanged notes has been deferred and will be amortized to interest expense over the life of the 4.50% senior notes due 2021.


(11)	Income Taxes

During the three and nine months ended September 30, 2010, the effective tax rate was 38% and 41%, respectively. During the three and nine months ended September 30, 2011, the effective tax rate was 35% and 36%, respectively. The most significant items affecting the comparability of the effective tax rate for the nine months ended September 30, 2010 and 2011 are a non-cash, $21 million increase in the 2010 income tax expense as a result of a change in tax law and a $9 million decrease in the 2011 income tax expense related to a decrease in accrued interest for tax reserves related to the potential normalization violation.

The change in tax law, which becomes effective for tax years beginning after December 31, 2012, eliminates the tax deductibility of the portion of retiree health care costs that are reimbursed by Medicare Part D subsidies. Based upon the actuarially determined net present value of lost future retiree health care deductions related to the subsidies, CenterPoint Energy reduced its deferred tax asset by approximately $32 million as of March 31, 2010. The portion of the reduction that CenterPoint Energy believes will be recovered through the regulatory process, or approximately $11 million, was recorded as an adjustment to regulatory assets. The remaining $21 million of the reduction in CenterPoint Energy’s deferred tax asset was reflected as a charge to income tax expense.

The following table summarizes CenterPoint Energy’s unrecognized tax benefits at December 31, 2010 and September 30, 2011:



	December 31, 2010		September 30, 2011
	(in millions)
Unrecognized tax benefits	$	252	$	52
Portion of unrecognized tax benefits that, if recognized, would reduce the effective income tax rate	17		20
Interest accrued on unrecognized tax benefits	12		—

The decrease of $200 million in unrecognized tax benefits from December 31, 2010 is primarily related to the remeasurement of unrecognized tax benefits for the potential normalization violation. As a result of the Settlement, discussed in Note 4(a), CenterPoint Houston has determined that the potential normalization violation has been prevented and consequently, recorded a reduction to the liability for unrecognized income tax benefits by $279 million during the three months ended September 30, 2011 of which $211 million was related to the balance as of December 31, 2010 with the remaining $68 million related to the six months ended June 30, 2011. The unrecognized tax benefit for the normalization issue was a temporary difference and, therefore, the decrease in the balance thereto resulted in an increase to the deferred tax liability of $268 million and a decrease in income tax expense of $11 million for the release of accrued interest expense.

It is reasonably possible that the total amount of unrecognized tax benefits could decrease in the range of $16 million to $35 million over the next 12 months, depending on the result of CenterPoint Energy’s administrative appeal relating to the Internal Revenue Service's (IRS) disallowance of CenterPoint Energy’s casualty loss deduction associated with the damage caused by

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Hurricane Ike. Additionally, the casualty loss deduction is a temporary difference and, therefore, any increase or decrease in the balance of unrecognized tax benefits related thereto would not affect the effective tax rate.

In January 2011, the IRS commenced its examination of CenterPoint Energy’s 2008 and 2009 consolidated federal income tax returns.


(12)	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, 2010 and September 30, 2011 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, 2011, minimum payment obligations for natural gas supply commitments are approximately $181 million for the remaining three months in 2011, $499 million in 2012, $498 million in 2013, $388 million in 2014, $235 million in 2015 and $410 million after 2015.


(b)	Capital Commitments

Long-Term Gas Gathering and Treating Agreements

Magnolia Gathering System. In September 2009, CenterPoint Energy Field Services, LLC (CEFS) 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 certain Haynesville Shale and Bossier Shale formations in Louisiana. Pursuant to these agreements, CEFS acquired jointly-owned gathering facilities (the Magnolia Gathering System) from Encana and Shell in northwest Louisiana. Each of the agreements includes acreage dedication and volume commitments for which CEFS has exclusive rights to gather Shell’s and Encana’s natural gas production.

During the fourth quarter of 2010, CEFS substantially completed the construction and initial expansion of the Magnolia Gathering System in order to permit the system to gather and treat up to 700 million cubic feet (MMcf) per day of natural gas, with only well connects remaining. CEFS spent approximately $320 million on the original project scope, including the purchase of the original facilities and is in the second year of the 10-year, 700 MMcf per day volume commitment made by Shell and Encana which commenced in September 2009.

Pursuant to an expansion election made by Encana and Shell in March 2010, CEFS expanded the Magnolia Gathering System to increase its gathering and treating capacity by an additional 200 MMcf per day, increasing the aggregate capacity of the system to 900 MMcf per day. The expansion was completed and placed into service in February 2011 at a total cost of approximately $52 million. The 200 MMcf per day incremental volume commitment made by Shell and Encana began contemporaneously with the completion of the expansion.

Under the long-term agreements, Encana or Shell may elect to require CEFS to expand the capacity of the Magnolia Gathering System by up to an additional 800 MMcf per day, bringing the total system capacity to 1.7 Bcf per day. CEFS estimates that the cost to expand the capacity of the Magnolia Gathering System by an additional 800 MMcf per day would be as much as $240 million. Encana and Shell would provide incremental volume commitments in connection with an election to expand the system’s capacity.

Olympia Gathering System. In April 2010, CEFS entered into additional long-term agreements with Encana and Shell to provide gathering and treating services for their natural gas production from certain Haynesville Shale and Bossier Shale formations in Texas and Louisiana. Pursuant to these agreements, CEFS acquired jointly-owned gathering facilities (the Olympia Gathering System) from Encana and Shell in northwest Louisiana.

Under the terms of the agreements, CEFS is expanding the Olympia Gathering System in order to permit the system to gather and treat up to 600 MMcf per day of natural gas. As of September 30, 2011, CEFS had spent approximately $390 million on the 600 MMcf per day project, including the purchase of the original facilities, and expects to incur up to an additional $35 million to complete the remaining contractual milestones and well connects for this expansion. CEFS is in the second year of the 10-year, 600 MMcf per day volume commitment made by Shell and Encana which commenced in April 2010.

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Under the long-term agreements, Encana and Shell may elect to require CEFS to expand the capacity of the Olympia Gathering System by up to an additional 520 MMcf per day, bringing the total system capacity to 1.1 Bcf per day. CEFS estimates that the cost to expand the capacity of the Olympia Gathering System by an additional 520 MMcf per day would be as much as $200 million. Encana and Shell would provide incremental volume commitments in connection with an election to expand the system’s capacity.


(c)	Legal, Environmental and Other Regulatory Matters

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 certain lawsuits described below. Under a master separation agreement between CenterPoint Energy and a former subsidiary, RRI Energy, Inc. (RRI), CenterPoint Energy and its subsidiaries are entitled to be indemnified by RRI and its successors for any losses, including attorneys’ fees and other costs, arising out of these lawsuits. In May 2009, RRI sold its Texas retail business to a subsidiary of NRG Energy, Inc. (NRG) and changed its name to RRI Energy, Inc. In December 2010, Mirant Corporation merged with and became a wholly owned subsidiary of RRI Energy, Inc., and RRI Energy, Inc. changed its name to GenOn Energy, Inc. (GenOn). Neither the sale of the retail business nor the merger with Mirant Corporation alters RRI’s (now GenOn’s) contractual obligations to indemnify CenterPoint Energy and its subsidiaries, including CenterPoint Houston, for certain liabilities, including their indemnification obligations regarding the gas market manipulation litigation, nor does it affect the terms of existing guaranty arrangements for certain GenOn gas transportation contracts discussed below.

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. In July 2011, the court issued an order dismissing the plaintiffs' claims against the other defendants in the case, each of whom had demonstrated FERC jurisdictional sales for resale during the relevant period, based on federal preemption. The plaintiffs have appealed this ruling to the United States Court of Appeals for the Ninth Circuit. Additionally, CenterPoint Energy was a defendant in a lawsuit filed in state court in Nevada that was dismissed in 2007, but in March 2010 the plaintiffs appealed the dismissal to the Nevada Supreme Court. 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.

Natural Gas Measurement Lawsuits. CERC Corp. and certain of its subsidiaries are defendants in two mismeasurement lawsuits brought against approximately 245 pipeline companies and their affiliates pending in state court in Stevens County, Kansas. In one case (originally filed in May 1999 and amended four times), the plaintiffs purport to represent a class of royalty owners who allege that the defendants have engaged in systematic mismeasurement of the volume of natural gas for more than 25 years. The plaintiffs amended their petition in this suit in July 2003 in response to an order from the judge denying certification of the plaintiffs’ alleged class. In the amendment, the plaintiffs dismissed their claims against certain defendants (including two CERC Corp. subsidiaries), limited the scope of the class of plaintiffs they purport to represent and eliminated previously asserted claims based on mismeasurement of the British thermal unit (Btu) content of the gas. The same plaintiffs then filed a second lawsuit, again as representatives of a putative class of royalty owners in which they assert their claims that the defendants have engaged in systematic mismeasurement of the Btu content of natural gas for more than 25 years. In both lawsuits, the plaintiffs seek compensatory damages, along with statutory penalties, treble damages, interest, costs and fees. In September 2009, the district court in Stevens County, Kansas, denied plaintiffs’ request for class certification of their case and, in March 2010, denied the plaintiffs’ request for reconsideration of that order. The time for seeking further review of the district court’s decision has now passed.

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.

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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, 2011, CERC had accrued $13 million for remediation of these Minnesota sites and the estimated range of possible remediation costs for these sites was $6 million to $41 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 (PRPs), if any, and the remediation methods used. The Minnesota Public Utility Commission has provided for the inclusion in rates of approximately $285,000 annually to fund normal on-going remediation costs. As of September 30, 2011, CERC had collected $5.4 million from insurance companies to be used for future environmental remediation.

In addition to the Minnesota sites, the United States Environmental Protection Agency and other regulators have investigated MGP sites that were owned or operated by CERC or may have been owned by one of its former affiliates. CERC has been named as a defendant in a lawsuit filed in the United States District Court, District of Maine, under which contribution is sought by private parties for the cost to remediate former MGP sites based on the previous ownership of such sites by former affiliates of CERC or its divisions. CERC has also been identified as a PRP by the State of Maine for a site that is a 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 would be required to determine if other potentially responsible parties, including CERC, would have to contribute to that remediation. In September 2009, the federal district court granted CERC’s motion for summary judgment in the proceeding and, in July 2011, the plaintiff appealed the federal district court’s decision to the United States Court of Appeals for the First Circuit. On September 12, 2011, the First Circuit Court of Appeals dismissed the plaintiff's appeal with respect to CERC.

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.

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 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 the distribution of CenterPoint Energy’s ownership in RRI to its shareholders, CERC had guaranteed certain contractual

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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 (now GenOn) 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 transportation agreements if and to the extent changes in market conditions expose CERC to a risk of loss on those guaranties based on an annual calculation, with any required collateral to be posted each December. The undiscounted maximum potential payout of the demand charges under these transportation contracts, which will be in effect until 2018, was approximately $100 million as of September 30, 2011. Market conditions in the fourth quarter of 2010 required posting of security under the agreement, and GenOn posted approximately $7 million in collateral in December 2010. As a result of market conditions in the fourth quarter of 2011, CERC has provided notice to GenOn of its obligation to post additional security in December 2011. If GenOn 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.


(13)	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,
	2010		2011		2010		2011
	(in millions, except share and per share amounts)
Basic earnings per share calculation:
Income before extraordinary item	$	123	$	386	$	318	$	653
Extraordinary item, net of tax	—		587		—		587
Net income	$	123	$	973	$	318	$	1,240

Weighted average shares outstanding	422,178,000		425,885,000		404,957,000		425,517,000

Basic earnings per share:
Income before extraordinary item	$	0.29	$	0.90	$	0.79	$	1.53
Extraordinary item, net of tax	—		1.38		—		1.38
Net income	$	0.29	$	2.28	$	0.79	$	2.91

Diluted earnings per share calculation:
Net income	$	123	$	973	$	318	$	1,240

Weighted average shares outstanding	422,178,000		425,885,000		404,957,000		425,517,000
Plus: Incremental shares from assumed conversions:
Stock options ⁽¹⁾	548,000		399,000		529,000		377,000
Restricted stock	2,242,000		2,558,000		2,242,000		2,558,000
Weighted average shares assuming dilution	424,968,000		428,842,000		407,728,000		428,452,000

Diluted earnings per share:
Income before extraordinary item	$	0.29	$	0.90	$	0.78	$	1.52
Extraordinary item, net of tax	—		1.37		—		1.37
Net income	$	0.29	$	2.27	$	0.78	$	2.89

________________


(1)	Options to purchase 1,522,444 shares were outstanding for both the three and nine months ended September 30, 2010, 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.

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(14)	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. 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 the following 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 non-rate regulated natural gas gathering, processing and treating operations. Other Operations consists primarily of other corporate operations which support all of CenterPoint Energy’s business operations.

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



	For the Three Months Ended September 30, 2010
	Revenues from External Customers			Net Intersegment Revenues			Operating Income (Loss)
Electric Transmission & Distribution	$	655	⁽¹⁾	$	—		$	212
Natural Gas Distribution	395			3			(4		)
Competitive Natural Gas Sales and Services	638			9			7
Interstate Pipelines	136			34			68
Field Services	81			13			40
Other Operations	3			—			4
Eliminations	—			(59		)	—
Consolidated	$	1,908		$	—		$	327



	For the Three Months Ended September 30, 2011
	Revenues from External Customers			Net Intersegment Revenues			Operating Income (Loss)
Electric Transmission & Distribution	$	707	⁽¹⁾	$	—		$	244
Natural Gas Distribution	379			5			(2		)
Competitive Natural Gas Sales and Services	580			4			(10		)
Interstate Pipelines	104			31			60
Field Services	108			9			61
Other Operations	3			—			4
Eliminations	—			(49		)	—
Consolidated	$	1,881		$	—		$	357

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	For the Nine Months Ended September 30, 2010
	Revenues from External Customers			Net Intersegment Revenues			Operating Income		Total Assets as of December 31, 2010
Electric Transmission & Distribution	$	1,699	⁽¹⁾	$	—		$	477	$	9,817
Natural Gas Distribution	2,390			10			145		4,575
Competitive Natural Gas Sales and Services	2,032			27			16		1,190
Interstate Pipelines	352			104			207		3,672
Field Services	205			37			94		1,803
Other Operations	9			—			8		2,184			⁽²⁾
Eliminations	—			(178		)	—		(3,130		)
Consolidated	$	6,687		$	—		$	947	$	20,111



	For the Nine Months Ended September 30, 2011
	Revenues from External Customers			Net Intersegment Revenues			Operating Income		Total Assets as of September 30, 2011
Electric Transmission & Distribution	$	1,802	⁽¹⁾	$	—		$	530	$	11,084
Natural Gas Distribution	2,034			14			153		4,379
Competitive Natural Gas Sales and Services	1,858			18			3		1,108
Interstate Pipelines	328			96			196		3,826
Field Services	274			31			136		1,862
Other Operations	9			—			6		1,897			⁽²⁾
Eliminations	—			(159		)	—		(3,205		)
Consolidated	$	6,305		$	—		$	1,024	$	20,951

________________

(1)

Sales to affiliates of NRG in the three months ended September 30, 2010 and 2011 represented approximately $179 million and $188 million, respectively, of CenterPoint Houston’s transmission and distribution revenues. Sales to affiliates of Energy Future Holdings Corp. (Energy Future Holdings) in the three months ended September 30, 2010 and 2011 represented approximately $57 million and $58 million, respectively, of CenterPoint Houston’s transmission and distribution revenues. Sales to affiliates of NRG in the nine months ended September 30, 2010 and 2011 represented approximately $447 million and $448 million, respectively, of CenterPoint Houston’s transmission and distribution revenues. Sales to affiliates of Energy Future Holdings in the nine months ended September 30, 2010 and 2011 represented approximately $141 million and $139 million, respectively, of CenterPoint Houston’s transmission and distribution revenues.


(2)	Included in total assets of Other Operations as of December 31, 2010 and September 30, 2011 are pension and other postemployment related regulatory assets of $704 million and $668 million, respectively.


(15)	Subsequent Events

On October 26, 2011, CenterPoint Energy’s board of directors declared a regular quarterly cash dividend of $0.1975 per share of common stock payable on December 9, 2011, to shareholders of record as of the close of business on November 16, 2011.

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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, 2010 (2010 Form 10-K).

EXECUTIVE SUMMARY

Recent Events

Resolution of True-Up Appeal

In March 2004, CenterPoint Houston filed a true-up application with the Public Utility Commission of Texas (Texas Utility Commission), requesting recovery of $3.7 billion, excluding interest, as allowed under the Texas Electric Choice Plan. 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 returned to customers after August 31, 2004 and certain other adjustments. To reflect the impact of the True-Up Order, in 2004 and 2005, we recorded a net after-tax extraordinary loss of $947 million.

Olympia Gathering System

In April 2010, CenterPoint Energy Field Services, LLC (CEFS) 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 certain Haynesville Shale and Bossier Shale formations in Texas and Louisiana. Pursuant to these agreements, CEFS acquired jointly-owned gathering facilities (the Olympia Gathering System) from Encana and Shell in northwest Louisiana.

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to complete the remaining contractual milestones and well connects for this expansion. CEFS is in the second year of the 10-year, 600 MMcf per day volume commitment made by Shell and Encana which commenced in April 2010.

Under the long-term agreements, Encana and Shell may elect to require CEFS to expand the capacity of the Olympia Gathering System by up to an additional 520 MMcf per day, bringing the total system capacity to 1.1 billion cubic feet (Bcf) per day. CEFS estimates that the cost to expand the capacity of the Olympia Gathering System by an additional 520 MMcf per day would be as much as $200 million. Encana and Shell would provide incremental volume commitments in connection with an election to expand the system’s capacity.

Advanced Metering System and Distribution Grid Automation (Intelligent Grid)

In October 2009, the U.S. Department of Energy (DOE) selected CenterPoint Houston for a $200 million grant for its advanced metering system (AMS) and intelligent grid (IG) projects. In March 2010, CenterPoint Houston and the DOE completed negotiations and finalized the agreement. Under the terms of agreement, the DOE has agreed to reimburse CenterPoint Houston for 50% of its eligible costs until the total amount of the grant has been paid. Through September 30, 2011, CenterPoint Houston has received the entire $200 million of grant funding from the DOE. CenterPoint Houston estimates that capital expenditures of approximately $645 million for the installation of the advanced meters and corresponding communication and data management systems will be incurred over the deployment period. CenterPoint Houston is using $150 million of the grant funding to accelerate completion of its deployment of advanced meters to 2012, instead of 2014 as originally scheduled. CenterPoint Houston will use the other $50 million from the grant for an initial deployment of an IG in a portion of its service territory to be completed in 2013. It is expected that the portion of the IG project subject to funding by the DOE will cost approximately $115 million. CenterPoint Houston believes the IG has the potential to provide an improvement in grid planning, operations, maintenance and customer service for its distribution system.

In March 2010, the Internal Revenue Service (IRS) announced through the issuance of Revenue Procedure 2010-20 that it was providing a safe harbor to corporations that receive a Smart Grid Investment Grant. The IRS stated that it would not challenge a corporation’s treatment of the grant as a non-taxable non-shareholder contribution to capital as long as the corporation properly reduced the tax basis of specified property.

CenterPoint Houston 2010 Rate Case

As required under the final order in its 2006 rate proceeding, in June 2010 CenterPoint Houston filed an application to change rates with the Texas Utility Commission and the cities in its service area.

The order on rehearing provides for a base rate increase for CenterPoint Houston of approximately $14.7 million per year for delivery charges to the REPs and a decrease to charges to wholesale transmission customers of $12.3 million per year. Further, the order adopts a mechanism to track amounts for uncertain tax positions and provide for ultimate recovery of those costs. The order authorizes a return on equity for CenterPoint Houston of 10%, a cost of debt of 6.74%, a capital structure comprised of 55% debt and 45% common equity, and an overall rate of return of 8.21%. The decision also implements CenterPoint Houston’s request to reconcile costs incurred for the AMS project and to shorten the period for collecting the AMS surcharge from twelve to six years for residential customers in order to reflect the funds received from the DOE. As a result of the Texas Utility Commission’s order, CenterPoint Houston anticipates that normalized annual operating income will be reduced by approximately $30 million.

Financial Reform Legislation

On July 21, 2010, the President signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank), which makes substantial changes to regulatory oversight regarding banks and financial institutions. Many provisions of Dodd-Frank will also affect non-financial businesses such as those conducted by us and our subsidiaries. It is not possible at this time to predict the ultimate impacts this legislation may have on us and our subsidiaries since most of the provisions in the law require extensive rulemaking by various regulatory agencies and authorities, including, among others, the Securities and Exchange Commission (SEC), the Commodities Futures Trading Commission (CFTC) and the New York Stock Exchange (NYSE). Nevertheless, in a number of areas, the resulting rules are expected to have direct or indirect impacts on our businesses.

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Dodd-Frank provisions will increase required disclosures regarding executive compensation, and rules adopted by the SEC in January 2011 required an advisory vote at our 2011 annual meeting by shareholders on executive compensation (“say-on-pay”) and required an advisory vote by shareholders on the frequency that such say-on-pay votes will be submitted in future years. New rules adopted by the SEC were intended to provide shareholders with access to the director nomination process, but those rules have been vacated on procedural grounds by a federal appellate court in response to legal challenges. In September 2011, the SEC announced that it would not seek a rehearing of the appellate court's decision.

Although Dodd-Frank includes significant new provisions regarding the regulation of derivatives, the impact of those requirements will not be known definitively until regulations have been adopted by the SEC and the CFTC. The SEC and certain federal banking agencies are charged with adopting new regulations regarding asset-backed securities transactions such as the asset-backed securitizations CenterPoint Houston has sponsored for recovery of transition and storm restoration costs. The new regulations will include rules to implement the Dodd-Frank requirement that securitizers retain a portion of the credit risk of asset-backed securities sold to third parties. We expect that our anticipated transition bond offering to securitize the $1.695 billion Recoverable True-Up Balance will be completed before the new risk retention rules are in effect.

Dodd-Frank also makes substantial changes to the regulatory oversight of the credit rating agencies that are typically engaged to rate our securities and those of our subsidiaries. It is presently unknown what effect implementation of these new provisions ultimately will have on the activities or costs associated with the credit rating process.

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,
	2010			2011			2010			2011
Revenues	$	1,908		$	1,881		$	6,687		$	6,305
Expenses	1,581			1,524			5,740			5,281
Operating Income	327			357			947			1,024
Interest and Other Finance Charges	(121		)	(114		)	(364		)	(341		)
Interest on Transition and System Restoration Bonds	(34		)	(31		)	(106		)	(96		)
Equity in Earnings of Unconsolidated Affiliates	10			8			22			22
Return on True-Up Balance	—			352			—			352
Other Income, net	17			18			42			54
Income Before Income Taxes and Extraordinary Item	199			590			541			1,015
Income Tax Expense	76			204			223			362
Income Before Extraordinary Item	123			386			318			653
Extraordinary Item, net of tax	—			587			—			587
Net Income	$	123		$	973		$	318		$	1,240

Basic Earnings Per Share:
Income Before Extraordinary Item	$	0.29		$	0.90		$	0.79		$	1.53
Extraordinary Item, net of tax	—			1.38			—			1.38
Net Income	$	0.29		$	2.28		$	0.79		$	2.91

Diluted Earnings Per Share:
Income Before Extraordinary Item	$	0.29		$	0.90		$	0.78		$	1.52
Extraordinary Item, net of tax	—			1.37			—			1.37
Net Income	$	0.29		$	2.27		$	0.78		$	2.89

Three months ended September 30, 2011 compared to three months ended September 30, 2010

We reported consolidated net income of $973 million ($2.27 per diluted share) for the three months ended September 30, 2011 compared to $123 million ($0.29 per diluted share) for the same period in 2010. The increase in net income of $850 million was primarily due to the resolution of the true-up appeal resulting in an after-tax extraordinary gain of $587 million and a $352

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million return on the true-up balance, a $93 million increase in the gain on our indexed debt securities, a $30 million increase in operating income (discussed by segment below), and a $10 million decrease in interest expense due to lower levels of debt, which were partially offset by a $128 million increase in income tax expense and a $99 million decrease in the gain on our marketable securities.

Nine months ended September 30, 2011 compared to nine months ended September 30, 2010

We reported consolidated net income of $1.24 billion ($2.89 per diluted share) for the nine months ended September 30, 2011 compared to $318 million ($0.78 per diluted share) for the same period in 2010. The increase in net income of $922 million was primarily due to the resolution of the true-up appeal resulting in an after-tax extraordinary gain of $587 million and a $352 million return on the true-up balance, a $77 million increase in operating income (discussed by segment below), a $65 million increase in the gain on our indexed debt securities and a $33 million decrease in interest expense due to lower levels of debt, which were partially offset by a $139 million increase in income tax expense and a $65 million decrease in the gain on our marketable securities.

Income Tax Expense

During the three and nine months ended September 30, 2010, the effective tax rate was 38% and 41%, respectively. During the three and nine months ended September 30, 2011, the effective tax rate was 35% and 36%, respectively. The most significant item affecting the comparability of the effective tax rate for the nine months ended September 30, 2010 and 2011 is a non-cash, $21 million increase in the 2010 income tax expense as a result of a change in tax law and a $9 million decrease in the 2011 income tax expense related to a decrease in accrued interest for tax reserves related to the potential normalization violation.

The change in tax law, which becomes effective for tax years beginning after December 31, 2012, eliminates the tax deductibility of the portion of retiree health care costs that are reimbursed by Medicare Part D subsidies. Based upon the actuarially determined net present value of lost future retiree health care deductions related to the subsidies, we reduced our deferred tax asset by approximately $32 million as of March 31, 2010. The portion of the reduction that we believe will be recovered through the regulatory process, or approximately $11 million, was recorded as an adjustment to regulatory assets. The remaining $21 million of the reduction in our deferred tax asset was reflected as a charge to income tax expense.

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, 2010 and 2011. Included in revenues are intersegment sales. We account for intersegment sales as if the sales were to third parties, that is, at current market prices.



	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2011			2010		2011
Electric Transmission & Distribution	$	212		$	244		$	477	$	530
Natural Gas Distribution	(4		)	(2		)	145		153
Competitive Natural Gas Sales and Services	7			(10		)	16		3
Interstate Pipelines	68			60			207		196
Field Services	40			61			94		136
Other Operations	4			4			8		6
Total Consolidated Operating Income	$	327		$	357		$	947	$	1,024

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 Businesses and Other Risks” in Item 1A of Part I of our 2010 Form 10-K and Item 1A of Part II of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2011 (First Quarter Form 10-Q).

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The following tables provide summary data of our Electric Transmission & Distribution business segment for the three and nine months ended September 30, 2010 and 2011 (in millions, except throughput and customer data):



	Three Months Ended September 30,				Nine Months Ended September 30,
	2010		2011		2010		2011
Revenues:
Electric transmission and distribution utility	$	520	$	565	$	1,355	$	1,454
Transition and system restoration bond companies	135		142		344		348
Total revenues	655		707		1,699		1,802
Expenses:
Operation and maintenance, excluding transition and system restoration bond companies	215		228		609		655
Depreciation and amortization, excluding transition and system restoration bond companies	75		70		219		207
Taxes other than income taxes	52		54		156		158
Transition and system restoration bond companies	101		111		238		252
Total expenses	443		463		1,222		1,272
Operating Income	$	212	$	244	$	477	$	530

Operating Income:
Electric transmission and distribution utility	$	178	$	213	$	371	$	434
Transition and system restoration bond companies (1)	34		31		106		96
Total segment operating income	$	212	$	244	$	477	$	530

Throughput (in gigawatt-hours (GWh)):
Residential	9,262		10,682		21,499		23,338
Total	23,342		24,957		59,952		62,802

Number of metered customers at end of period:
Residential	1,868,421		1,899,479		1,868,421		1,899,479
Total	2,115,595		2,150,731		2,115,595		2,150,731

________________


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

Three months ended September 30, 2011 compared to three months ended September 30, 2010

Our Electric Transmission & Distribution business segment reported operating income of $244 million for the three months ended September 30, 2011, consisting of $213 million from the regulated electric transmission and distribution utility (TDU) and $31 million related to transition and system restoration bond companies. For the three months ended September 30, 2010, operating income totaled $212 million, consisting of $178 million from the TDU and $34 million related to transition and system restoration bond companies. TDU revenues increased $45 million due to increased usage ($36 million), primarily due to favorable weather, and higher revenues due to customer growth ($6 million) from the addition of over 35,000 new customers. Operation and maintenance expenses increased $13 million due to higher transmission costs billed by transmission providers ($7 million) and increased labor and benefit costs ($7 million). Depreciation expense decreased by $5 million primarily due to lower depreciation rates implemented in September 2011 as a result of the 2010 rate case.

Nine months ended September 30, 2011 compared to nine months ended September 30, 2010

Our Electric Transmission & Distribution business segment reported operating income of $530 million for the nine months ended September 30, 2011, consisting of $434 million from the TDU and $96 million related to transition and system restoration bond companies. For the nine months ended September 30, 2010, operating income totaled $477 million, consisting of $371 million from the TDU and $106 million related to transition and system restoration bond companies. TDU revenues increased $99 million due to increased usage ($51 million), primarily due to favorable weather, higher transmission-related revenues ($25 million) and

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higher revenues due to customer growth ($13 million) from the addition of over 35,000 new customers. Operation and maintenance expenses increased $46 million due to higher transmission costs billed by transmission providers ($24 million), increased labor and benefit costs ($10 million), increased contracts and services ($5 million) and other operating expense increases ($6 million). Depreciation expense decreased by $12 million in part due to lower depreciation rates implemented in September 2011 as a result of the 2010 rate case.

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 Businesses and Other Risks” in Item 1A of Part I of our 2010 Form 10-K.

The following table provides summary data of our Natural Gas Distribution business segment for the three and nine months ended September 30, 2010 and 2011 (in millions, except throughput and customer data):



	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2011			2010		2011
Revenues	$	398		$	384		$	2,400	$	2,048
Expenses:
Natural gas	180			167			1,563		1,203
Operation and maintenance	160			156			471		481
Depreciation and amortization	40			41			124		124
Taxes other than income taxes	22			22			97		87
Total expenses	402			386			2,255		1,895
Operating Income (Loss)	$	(4	)	$	(2	)	$	145	$	153

Throughput (in Bcf):
Residential	13			12			125		122
Commercial and industrial	46			48			182		187
Total Throughput	59			60			307		309

Number of customers at period end:
Residential	2,969,452			2,990,934			2,969,452		2,990,934
Commercial and industrial	242,032			241,838			242,032		241,838
Total	3,211,484			3,232,772			3,211,484		3,232,772

Three months ended September 30, 2011 compared to three months ended September 30, 2010

Our Natural Gas Distribution business segment reported an operating loss of $2 million for the three months ended September 30, 2011 compared to $4 million for the three months ended September 30, 2010. Operating loss decreased $2 million primarily as a result of lower operation and maintenance expenses ($4 million) in part due to lower bad debt expense. Increased operation and maintenance expenses related to energy efficiency programs ($2 million) were offset by the related revenues.

Nine months ended September 30, 2011 compared to nine months ended September 30, 2010

Our Natural Gas Distribution business segment reported operating income of $153 million for the nine months ended September 30, 2011 compared to $145 million for the nine months ended September 30, 2010. Operating income increased $8 million primarily as a result of increased throughput to large-volume customers ($6 million), the addition of 21,000 customers ($6 million), lower bad debt expense ($5 million) and rate increases ($4 million), partially offset by lower miscellaneous revenues ($6 million) and higher other operating expense ($6 million). Increased expense related to energy efficiency programs ($17 million) and decreased expense related to lower gross receipt taxes ($11 million) were offset by the related revenues.

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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 Businesses and Other Risks” in Item 1A of Part I of our 2010 Form 10-K.

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, 2010 and 2011 (in millions, except throughput and customer data):



	Three Months Ended September 30,					Nine Months Ended September 30,
	2010		2011			2010		2011
Revenues	$	647	$	584		$	2,059	$	1,876
Expenses:
Natural gas	629		582			2,009		1,838
Operation and maintenance	10		10			29		31
Depreciation and amortization	1		1			3		3
Taxes other than income taxes	—		1			2		1
Total expenses	640		594			2,043		1,873
Operating Income (Loss)	$	7	$	(10	)	$	16	$	3

Throughput (in Bcf)	135		126			404		407

Number of customers at period end	11,883		12,650			11,883		12,650

Three months ended September 30, 2011 compared to three months ended September 30, 2010

Our Competitive Natural Gas Sales and Services business segment reported an operating loss of $10 million for the three months ended September 30, 2011 compared to operating income of $7 million for the three months ended September 30, 2010. The decrease in operating income of $17 million is largely due to an unfavorable $13 million change in the mark-to-market valuation for non-trading financial derivatives for the third quarter of 2011 versus the same period in 2010. An additional $1 million decrease resulted from a $7 million write-down of natural gas inventory in the current quarter compared to a $6 million write-down for the same quarter last year. Basis spreads on pipeline transportation opportunities remain depressed and continue to negatively impact this segment's results.

Nine months ended September 30, 2011 compared to nine months ended September 30, 2010

Our Competitive Natural Gas Sales and Services business segment reported operating income of $3 million for the nine months ended September 30, 2011 compared to $16 million for the nine months ended September 30, 2010. The decrease in operating income of $13 million is primarily due to an unfavorable $6 million change in the mark-to-market valuation for non-trading financial derivatives for the first nine months of 2011 as compared to the same period in 2010. Adding to this decrease in operating income is a $6 million decrease in margin attributable to reduced basis spreads on pipeline transport opportunities and decreased seasonal storage spreads. The remaining $1 million decrease resulted from a $7 million write-down of natural gas inventory to the lower of cost or market for the nine-month period ending September 30, 2011 as compared to a $6 million write-down in the prior year period.

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 Businesses and Other Risks” in Item 1A of Part I of our 2010 Form 10-K.

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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, 2010 and 2011 (in millions, except throughput data):



	Three Months Ended September 30,				Nine Months Ended September 30,
	2010		2011		2010		2011
Revenues	$	170	$	135	$	456	$	424
Expenses:
Natural gas	38		15		72		54
Operation and maintenance	42		39		112		109
Depreciation and amortization	13		13		39		40
Taxes other than income taxes	9		8		26		25
Total expenses	102		75		249		228
Operating Income	$	68	$	60	$	207	$	196

Equity in earnings of unconsolidated affiliates	$	8	$	6	$	15	$	15

Transportation throughput (in Bcf)	422		356		1,260		1,208

Three months ended September 30, 2011 compared to three months ended September 30, 2010

Our Interstate Pipeline business segment reported operating income of $60 million for the three months ended September 30, 2011 compared to $68 million for the three months ended September 30, 2010. Margins (revenues less natural gas costs) decreased $12 million primarily due to an expiring backhaul contract ($10 million), lower off-system transportation revenues ($4 million) and the effects of the restructured 10-year agreement with our natural gas distribution affiliate ($6 million), which were partially offset by increased ancillary services ($8 million). We estimate that the expiration of the backhaul contract will adversely impact our 2011 revenues by approximately $20 million. Operating income for the quarter benefited from lower operation and maintenance expenses ($3 million) and lower taxes other than income ($1 million).

Equity Earnings. In addition, this business segment recorded equity income of $8 million and $6 million for the three months ended September 30, 2010 and 2011, respectively, from its 50% interest in the Southeast Supply Header (SESH), a jointly-owned pipeline. These amounts are included in Equity in Earnings of Unconsolidated Affiliates under the Other Income (Expense) caption.

Nine months ended September 30, 2011 compared to nine months ended September 30, 2010

Our Interstate Pipeline business segment reported operating income of $196 million for the nine months ended September 30, 2011 compared to $207 million for the nine months ended September 30, 2010. Margins (revenues less natural gas costs) decreased $14 million primarily due to the effects of the restructured 10-year agreement with our natural gas distribution affiliate ($9 million), lower off-system revenues ($7 million) and lower revenues ($12 million) related to an expiring backhaul contract partially offset by new firm transportation contract revenues. Partially offsetting these declines were increased margins from ancillary service ($12 million), new power plant transportation contracts ($1 million) and industrial customers ($1 million). Operation and maintenance expenses benefited from a $5 million favorable insurance settlement related to a damaged compressor station. Depreciation expense increased ($1 million) due to asset additions, offset by lower taxes other than income attributable to a reduction in franchise taxes ($1 million).

Equity Earnings. In addition, this business segment recorded equity income of $15 million for both the nine months ended September 30, 2010 and 2011 from its 50% interest in SESH. 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 Businesses and Other Risks” in Item 1A of Part I of our 2010 Form 10-K.

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The following table provides summary data of our Field Services business segment for the three and nine months ended September 30, 2010 and 2011 (in millions, except throughput data):



	Three Months Ended September 30,				Nine Months Ended September 30,
	2010		2011		2010		2011
Revenues	$	94	$	117	$	242	$	305
Expenses:
Natural gas	19		19		53		52
Operation and maintenance	29		25		75		83
Depreciation and amortization	6		9		17		28
Taxes other than income taxes	—		3		3		6
Total expenses	54		56		148		169
Operating Income	$	40	$	61	$	94	$	136

Equity in earnings of unconsolidated affiliates	$	3	$	2	$	8	$	7

Gathering throughput (in Bcf)	180		206		464		586

Three months ended September 30, 2011 compared to three months ended September 30, 2010

Our Field Services business segment reported operating income of $61 million for the three months ended September 30, 2011 compared to $40 million for the three months ended September 30, 2010. Margins increased primarily due to higher throughput from gathering projects in the Haynesville and Fayetteville shales and growth in core gathering services, including revenues from annual contracted volume commitments ($25 million), partially offset by lower commodity prices ($2 million). Operation and maintenance expenses decreased primarily due to a reduction in leased treating facilities ($4 million). Increases in depreciation expense ($3 million) and taxes other than income ($3 million) resulted from the expansion of the Magnolia and Olympia gathering systems in North Louisiana.

Equity Earnings. In addition, this business segment recorded equity income of $3 million and $2 million in the three months ended September 30, 2010 and 2011, respectively, from its 50% general partnership interest in Waskom Gas Processing Company (Waskom). These amounts are included in Equity in Earnings of Unconsolidated Affiliates under the Other Income (Expense) caption.

Nine months ended September 30, 2011 compared to nine months ended September 30, 2010

Our Field Services business segment reported operating income of $136 million for the nine months ended September 30, 2011 compared to $94 million for the nine months ended September 30, 2010. Margins increased primarily due to higher throughput from gathering projects in the Haynesville and Fayetteville shales and growth in core gathering services, including revenues from annual contracted volume commitments ($75 million), partially offset by lower commodity prices ($8 million) and reduced processing margins ($2 million). Increases in operation and maintenance expenses ($8 million), depreciation expense ($11 million) and taxes other than income ($3 million) resulted from the expansion of the Magnolia and Olympia gathering systems in North Louisiana.

Equity Earnings. In addition, this business segment recorded equity income of $8 million and $7 million in the nine months ended September 30, 2010 and 2011, respectively, from its 50% general partnership interest in Waskom. These amounts are included in Equity in Earnings of Unconsolidated Affiliates under the Other Income (Expense) caption.

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Other Operations

The following table shows the operating income of our Other Operations business segment for the three and nine months ended September 30, 2010 and 2011 (in millions):



	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2011			2010		2011
Revenues	$	3		$	3		$	9	$	9
Expenses	(1		)	(1		)	1		3
Operating Income	$	4		$	4		$	8	$	6

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 of our 2010 Form 10-K, “Risk Factors” in Item 1A of Part I of our 2010 Form 10-K and in Item 1A of Part II of our First Quarter Form 10-Q, and “Cautionary Statement Regarding Forward-Looking Information” in this Form 10-Q.

LIQUIDITY AND CAPITAL RESOURCES

Historical Cash Flows

The following table summarizes the net cash provided by (used in) operating, investing and financing activities for the nine months ended September 30, 2010 and 2011:



	Nine Months Ended September 30,
	2010			2011
	(in millions)
Cash provided by (used in):
Operating activities	$	983		$	1,449
Investing activities	(1,014		)	(848		)
Financing activities	(610		)	(697		)

Cash Provided by Operating Activities

Net cash provided by operating activities in the first nine months of 2011 increased $466 million compared to the same period in 2010 due to increased tax refunds ($414 million), decreased net margin deposits ($99 million) and increased cash related to gas storage ($13 million), which were partially offset by decreased cash provided by net accounts receivable/payable ($121 million) and decreased cash provided by fuel cost recovery ($95 million).

Cash Used in Investing Activities

Net cash used in investing activities in the first nine months of 2011 decreased $166 million compared to the same period in 2010 due to decreased capital expenditures ($93 million), increased cash received from the DOE grant ($52 million) and decreased investment in unconsolidated affiliates ($12 million).

Cash Used in Financing Activities

Net cash used in financing activities in the first nine months of 2011 increased $87 million compared to the same period in 2010 due to decreased proceeds from the issuance of common stock ($387 million), increased payments of long-term debt ($126 million), increased cash paid for debt exchange ($58 million), decreased proceeds from commercial paper ($41 million), increased debt issuance costs ($21 million) and increased common stock dividend payments ($16 million), which were partially offset by increased proceeds from long-term debt ($550 million) and increased short-term borrowings ($13 million).

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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 capital expenditures are expected to be used for investment in infrastructure for our electric transmission and distribution operations, and our natural gas transmission, distribution and gathering operations. These capital expenditures are anticipated to both maintain reliability and safety as well as to expand our systems through value-added projects. Our principal cash requirements for the remaining three months of 2011 include the following:


•	capital expenditures of approximately $500 million; and


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

We expect that proceeds from sales of commercial paper, 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 2011. 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, funds raised in the commercial paper markets and additional credit facilities may not, however, be available to us on acceptable terms.

In the fourth quarter of 2011 or the first quarter of 2012, we expect to receive proceeds of $1.695 billion, less issuance costs, from the securitization of the Recoverable True-Up Balance.

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

Prior to the distribution of our ownership in RRI Energy, Inc. (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 (now named GenOn Energy, Inc. (GenOn)) 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 transportation agreements if and to the extent changes in market conditions expose CERC to a risk of loss on those guaranties based on an annual calculation, with any required collateral to be posted each December. The undiscounted maximum potential payout of the demand charges under these transportation contracts, which will be in effect until 2018, was approximately $100 million as of September 30, 2011. Market conditions in the fourth quarter of 2010 required posting of security under the agreement, and GenOn posted approximately $7 million in collateral in December 2010. As a result of market conditions in the fourth quarter of 2011, CERC has provided notice to GenOn of its obligation to post additional security in December 2011. If GenOn 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.

In May 2009, RRI sold its Texas retail business to a subsidiary of NRG Energy, Inc. (NRG). In December 2010, Mirant Corporation merged with and became a wholly owned subsidiary of RRI and RRI changed its name from RRI Energy, Inc. to GenOn Energy, Inc. Neither the sale of the retail business nor the merger with Mirant Corporation alters GenOn’s contractual obligations to indemnify us and our subsidiaries, including CenterPoint Houston, for certain liabilities, including their indemnification obligations regarding certain litigation, nor does it affect the terms of existing guaranty arrangements for certain GenOn gas transportation contracts as discussed above.

Debt Financing Transactions. In January 2011, CERC Corp. issued $250 million aggregate principal amount of senior notes due 2021 with an interest rate of 4.50% and $300 million aggregate principal amount of senior notes due 2041 with an interest rate of 5.85%. The proceeds from the issuance of the notes were used for the repayment of $550 million of CERC Corp.’s 7.75% senior notes at their maturity in February 2011.

Also in January 2011, CERC Corp. issued an additional $343 million aggregate principal amount of 4.50% senior notes due 2021 and provided cash consideration of $114 million in exchange for $397 million aggregate principal amount of its 7.875% senior notes due 2013. The premium of $58 million paid on exchanged notes has been deferred and will be amortized to interest expense over the life of the 4.50% senior notes due 2021.

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Credit Facilities. In the third quarter of 2011, the CERC Corp. receivables facility terminated in accordance with its terms and the revolving credit facilities of CenterPoint Energy, CenterPoint Houston and CERC Corp. were replaced with five-year revolving credit facilities of similar borrowing capacity. As of October 14, 2011, we had the following revolving credit facilities (in millions):

Date Executed

Company

Size of

Facility

Amount

Utilized at

October 14, 2011 ⁽¹⁾

Termination Date

September 9, 2011

CenterPoint Energy

1,200

⁽²⁾

September 9, 2016

September 9, 2011

CenterPoint Houston

300

⁽²⁾

September 9, 2016

September 9, 2011

CERC Corp.

950

101

⁽³⁾

September 9, 2016

________________


(1)	Based on the debt (excluding transition and system restoration bonds) to earnings before interest, taxes, depreciation and amortization (EBITDA) covenant in our $1.2 billion credit facility, we would have been permitted to utilize the full capacity of our revolving credit facilities aggregating $2.5 billion at September 30, 2011.


(2)	Represents outstanding letters of credit.


(3)	Represents commercial paper that is backstopped by CERC Corp.’s revolving credit facility.

Our $1.2 billion credit facility can be drawn at the London Interbank Offered Rate (LIBOR) plus 175 basis points based on our current credit ratings. The facility contains a debt (excluding transition and system restoration bonds) to EBITDA covenant (as those terms are defined in the facility). The facility allows for a temporary increase of the permitted ratio in the financial covenant from 5 times to 5.5 times if CenterPoint Houston experiences damage from a natural disaster in its service territory and we certify to the administrative agent that CenterPoint Houston has incurred system restoration costs reasonably likely to exceed $100 million in a consecutive twelve-month period, all or part of which CenterPoint Houston intends to seek to recover through securitization financing. Such temporary increase in the financial covenant would be in effect from the date we deliver our certification until the earliest to occur of (i) the completion of the securitization financing, (ii) the first anniversary of our certification or (iii) the revocation of such certification.

CenterPoint Houston's $300 million credit facility can be drawn at LIBOR plus 150 basis points based on CenterPoint Houston's current credit ratings. The facility contains a debt (excluding transition and system restoration bonds) to total capitalization covenant which limits debt to 65% of the borrower's total capitalization.

CERC Corp.'s $950 million credit facility can be drawn at LIBOR plus 150 basis points based on CERC Corp.'s current credit ratings. The facility contains a debt to total capitalization covenant which limits debt to 65% of CERC's total capitalization.

Borrowings under each of the facilities are subject to customary terms and conditions. However, there is no requirement that the borrower 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 consider customary. The facilities also provide for customary fees, including commitment fees, administrative agent fees, fees in respect of letters of credit and other fees. In each of the three revolving credit facilities, the spread to LIBOR and the commitment fees fluctuate based on the borrower's credit rating. The borrowers are currently in compliance with the various business and financial covenants in the three revolving credit facilities.

Our $1.2 billion credit facility backstops our $1.0 billion commercial paper program. The $950 million CERC Corp. credit facility backstops a $915 million commercial paper program. As of September 30, 2011, CERC Corp. had $142 million of outstanding commercial paper. We expect that CERC Corp. will continue to issue commercial paper during the fourth quarter of 2011 and may draw on its revolving credit facility if access to the commercial paper market is limited or uneconomic due to CERC Corp.'s credit ratings or other factors.

Securities Registered with the SEC. CenterPoint Energy, CenterPoint Houston and CERC Corp. have filed a joint shelf registration statement with the SEC registering indeterminate principal amounts of CenterPoint Houston’s general mortgage bonds, CERC Corp.’s senior debt securities and CenterPoint Energy’s senior debt securities and junior subordinated debt securities and an indeterminate number of CenterPoint Energy’s shares of common stock, shares of preferred stock, as well as stock purchase contracts and equity units.

Temporary Investments. As of October 14, 2011, we had no external temporary investments.

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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. The interest on borrowings under our credit facilities is based on our credit rating. As of October 14, 2011, Moody’s Investors Service, Inc. (Moody’s), Standard & Poor’s Ratings Services (S&P), a division of The McGraw-Hill Companies, and Fitch, Inc. (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

Baa3

Stable

BBB-

Positive

BBB-

Positive

CenterPoint Houston Senior

Secured Debt

Stable

BBB+

Positive

A-

Positive

CERC Corp. Senior Unsecured

Debt

Baa2

Stable

BBB

Positive

BBB

Stable

________________


(1)	A Moody’s rating outlook is an opinion regarding the likely direction of an issuer’s 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 Fitch rating outlook encompasses a one- to two-year horizon as to the likely ratings direction.

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

A decline in credit ratings could increase borrowing costs under our $1.2 billion credit facility, CenterPoint Houston’s $300 million credit facility and CERC Corp.’s $950 million credit facility. If our credit ratings or those of CenterPoint Houston or CERC Corp. had been downgraded one notch by each of the three principal credit rating agencies from the ratings that existed at September 30, 2011, 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 and to access the commercial paper market.

CERC Corp. and its subsidiaries purchase natural gas from one of their suppliers under supply agreements that contain an aggregate credit threshold of $120 million based on CERC Corp.’s S&P senior unsecured long-term debt rating of BBB. Under these agreements, CERC may need to provide collateral if the aggregate threshold is exceeded. 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 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, 2011, the amount posted as collateral aggregated approximately $47 million ($18 million of which is associated with price stabilization activities performed for 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, 2011, unsecured credit limits extended to CES by counterparties aggregate $294 million and $44 million of

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such amount was utilized.

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 $171 million as of September 30, 2011. The amount of collateral will depend on seasonal variations in transportation levels.

In September 1999, we issued Zero-Premium Exchangeable Subordinated Notes due 2029 (ZENS) having an original principal amount of $1.0 billion of which $840 million remains outstanding at September 30, 2011. 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, 2011, the reference shares for each ZENS note consisted of 0.5 share of TW Common, 0.125505 share of Time Warner Cable Inc. common stock (TWC Common) and 0.045455 share of AOL Inc. common stock (AOL Common). 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, TWC Common and AOL Common that we own or from other sources. We own shares of TW Common, TWC Common and AOL 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, TWC Common and AOL Common shares would typically cease when ZENS notes are exchanged or otherwise retired and TW Common, TWC Common and AOL 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. If all ZENS notes had been exchanged for cash on September 30, 2011, deferred taxes of approximately $424 million would have been payable in 2011.

Cross Defaults. Under our revolving credit facility, a payment default on, or a non-payment default that permits acceleration of, any indebtedness exceeding $75 million by us or any of our significant subsidiaries will cause a default. In addition, three outstanding series of our senior notes, aggregating $750 million in principal amount as of September 30, 2011, provide that a payment default by us, CERC Corp. or CenterPoint Houston in respect of, or an acceleration of, borrowed money and certain other specified types of obligations, in the aggregate principal amount of $50 million, will cause a default. A default by CenterPoint Energy would not trigger a default under our subsidiaries’ debt instruments or bank credit facilities.

Possible Acquisitions, Divestitures and Joint Ventures. From time to time, we consider the acquisition or the disposition of assets or businesses or possible joint ventures or other joint ownership arrangements with respect to assets or businesses. Any determination to take 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 Affect Cash Requirements. In addition to the above factors, our liquidity and capital resources could be affected by:


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


•	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 legislative or regulatory actions;


•	incremental collateral, if any, that may be required due to regulation of derivatives;

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•	the ability of GenOn and its subsidiaries to satisfy their obligations in respect of GenOn’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 REPs, including REP affiliates of NRG and REP affiliates of Energy Future Holdings Corp., which are CenterPoint Houston’s two largest customers, to satisfy their 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 pension and postretirement benefit plans;


•	restoration costs and revenue losses resulting from future 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 Part I of our 2010 Form 10-K and Item 1A of Part II of our First Quarter 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 system restoration bonds) as a percentage of its total capitalization to 65%. CERC Corp.’s bank facility limits CERC’s debt as a percentage of its total capitalization to 65%. Our $1.2 billion credit facility contains a debt, excluding transition and system restoration bonds, to EBITDA covenant which will temporarily increase if CenterPoint Houston experiences damage from a natural disaster in its service territory that meets certain criteria. Additionally, CenterPoint Houston has contractually agreed that it will not issue additional first mortgage bonds, subject to certain exceptions.

NEW ACCOUNTING PRONOUNCEMENTS

See Note 2 to our Interim Condensed 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, 2011, the recorded fair value of our non-trading energy derivatives was a net liability of $24 million (before collateral). The net liability consisted of a net liability of $56 million associated with price stabilization activities of our Natural Gas Distribution business segment and a net asset of $32 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. An increase of 10% in the market prices of energy commodities from their September 30, 2011 levels would have increased the fair value of our non-trading energy derivatives net liability by $7 million. This increase in net liabilities consists of a $4 million decrease to net liabilities associated with price stabilization activities of our Natural Gas Distribution business segment and an $11 million increase to net liabilities related to our Competitive Natural Gas Sales and Services business segment.

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 non-derivative 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.

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Interest Rate Risk

As of September 30, 2011, we had outstanding long-term debt, bank loans, lease obligations and obligations under our ZENS (indexed debt securities) that subject us to the risk of loss associated with movements in market interest rates.

We have no material floating-rate obligations.

At December 31, 2010 and September 30, 2011, we had outstanding fixed-rate debt (excluding indexed debt securities) aggregating $9.1 billion and $8.9 billion, respectively, in carrying amount and having a fair value of $9.9 billion and $9.9 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. However, the fair value of these instruments would increase by approximately $235 million if interest rates were to decline by 10% from their levels at September 30, 2011. 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 is bifurcated into a debt component and a derivative component. The debt component of $130 million at September 30, 2011 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 $22 million if interest rates were to decline by 10% from levels at September 30, 2011. Changes in the fair value of the derivative component, a $167 million recorded liability at September 30, 2011, 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 to increase by 10% from September 30, 2011 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, 1.8 million shares of TWC Common and 0.7 million shares of AOL Common, which we hold to facilitate our ability to meet our obligations under the ZENS. A decrease of 10% from the September 30, 2011 aggregate market value of these shares would result in a net loss of approximately $10 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, 2011 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, 2011 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 12(c) 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 2010 Form 10-K.


Item 1A.	RISK FACTORS

There have been no material changes from the risk factors disclosed in our 2010 Form 10-K and First Quarter Form 10-Q.

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Item 5.	OTHER INFORMATION

The ratio of earnings to fixed charges for the nine months ended September 30, 2010 and 2011 was 2.09 and 3.24, 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.


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	Restated Articles of Incorporation of CenterPoint Energy	CenterPoint Energy’s Form 8-K dated July 24, 2008	1-31447	3.2
3.2	Amended and Restated Bylaws of CenterPoint Energy	CenterPoint Energy’s Form 10-K for the year ended December 31, 2010	1-31447	3(b)
4.1	Form of CenterPoint Energy Stock Certificate	CenterPoint Energy’s Registration Statement on Form S-4	3-69502	4.1
4.2	Rights Agreement dated January 1, 2002, between CenterPoint Energy and JPMorgan Chase Bank, as Rights Agent	CenterPoint Energy’s Form 10-K for the year ended December 31, 2001	1-31447	4.2
4.3	$1,200,000,000 Credit Agreement, dated as of September 9, 2011, among CenterPoint Energy, as Borrower, and the banks named therein	CenterPoint Energy's Form 8-K dated September 9, 2011	1-31447	4.1
4.4	$300,000,000 Credit Agreement, dated as of September 9, 2011, among CenterPoint Houston, as Borrower, and the banks named therein	CenterPoint Energy's Form 8-K dated September 9, 2011	1-31447	4.2
4.5	$950,000,000 Credit Agreement, dated as of September 9, 2011, among CERC Corp., as Borrower, and the banks named therein	CenterPoint Energy's Form 8-K dated September 9, 2011	1-31447	4.3
+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
+101.SCH	XBRL Taxonomy Extension Schema Document
+101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
+101.DEF	XBRL Taxonomy Extension Definition Linkbase Document
+101.LAB	XBRL Taxonomy Extension Labels Linkbase Document
+101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.



	CENTERPOINT ENERGY, INC.


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

Date: November 2, 2011

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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	Restated Articles of Incorporation of CenterPoint Energy	CenterPoint Energy’s Form 8-K dated July 24, 2008	1-31447	3.2
3.2	Amended and Restated Bylaws of CenterPoint Energy	CenterPoint Energy’s Form 10-K for the year ended December 31, 2010	1-31447	3(b)
4.1	Form of CenterPoint Energy Stock Certificate	CenterPoint Energy’s Registration Statement on Form S-4	3-69502	4.1
4.2	Rights Agreement dated January 1, 2002, between CenterPoint Energy and JPMorgan Chase Bank, as Rights Agent	CenterPoint Energy’s Form 10-K for the year ended December 31, 2001	1-31447	4.2
4.3	$1,200,000,000 Credit Agreement, dated as of September 9, 2011, among CenterPoint Energy, as Borrower, and the banks named therein	CenterPoint Energy's Form 8-K dated September 9, 2011	1-31447	4.1
4.4	$300,000,000 Credit Agreement, dated as of September 9, 2011, among CenterPoint Houston, as Borrower, and the banks named therein	CenterPoint Energy's Form 8-K dated September 9, 2011	1-31447	4.2
4.5	$950,000,000 Credit Agreement, dated as of September 9, 2011, among CERC Corp., as Borrower, and the banks named therein	CenterPoint Energy's Form 8-K dated September 9, 2011	1-31447	4.3
+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
+101.SCH	XBRL Taxonomy Extension Schema Document
+101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
+101.DEF	XBRL Taxonomy Extension Definition Linkbase Document
+101.LAB	XBRL Taxonomy Extension Labels Linkbase Document
+101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document