Edgar Filing: CENTERPOINT ENERGY INC

CNP_10Q_9.30.2012

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, 2012



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 16, 2012, CenterPoint Energy, Inc. had 427,441,738 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, 2012

TABLE OF CONTENTS



PART I.	FINANCIAL INFORMATION

Item 1.	Financial Statements	1

	Condensed Statements of Consolidated Income
	Three and Nine Months Ended September 30, 2011 and 2012 (unaudited)	1

	Condensed Statements of Consolidated Comprehensive Income
	Three and Nine Months Ended September 30, 2011 and 2012 (unaudited)	2

	Condensed Consolidated Balance Sheets
	December 31, 2011 and September 30, 2012 (unaudited)	3

	Condensed Statements of Consolidated Cash Flows
	Nine Months Ended September 30, 2011 and 2012 (unaudited)	5

	Notes to Unaudited Condensed Consolidated Financial Statements	6

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	22

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	36

Item 4.	Controls and Procedures	37

PART II.	OTHER INFORMATION

Item 1.	Legal Proceedings	38

Item 1A.	Risk Factors	38

Item 5.	Other Information	38

Item 6.	Exhibits	39

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 businesses, including, among others, energy deregulation or re-regulation, pipeline integrity and safety, health care reform, financial reform, tax legislation and actions regarding the rates charged by our regulated businesses;


•	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 that allow recovery of costs and a reasonable return on investment;


•	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, the competitive effects of excess pipeline capacity in the regions we serve, 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, particularly supplies available for gathering by our field services business and transporting by our interstate pipelines, including the impact of natural gas and natural gas liquids prices on the level of drilling and production activities in the regions we serve;


•	competition in our mid-continent region footprint for access to natural gas supplies and markets;


•	weather variations and other natural phenomena;


•	any 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. (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 Energy Houston Electric, LLC’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, 2011, 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,
	2011			2012			2011			2012

Revenues	$	1,881		$	1,705		$	6,305		$	5,314

Expenses:
Natural gas	735			520			2,989			1,898
Operation and maintenance	448			458			1,333			1,364
Depreciation and amortization	253			301			677			800
Taxes other than income taxes	88			86			282			272
Goodwill impairment	—			252			—			252
Total	1,524			1,617			5,281			4,586
Operating Income	357			88			1,024			728

Other Income (Expense):
Gain (loss) on marketable securities	(80		)	77			(30		)	136
Gain (loss) on indexed debt securities	88			(52		)	65			(76		)
Interest and other finance charges	(114		)	(104		)	(341		)	(318		)
Interest on transition and system restoration bonds	(31		)	(37		)	(96		)	(112		)
Equity in earnings of unconsolidated affiliates	8			8			22			25
Return on true-up balance	352			—			352			—
Step acquisition gain	—			136			—			136
Other, net	10			12			19			28
Total	233			40			(9		)	(181		)

Income Before Income Taxes and Extraordinary Item	590			128			1,015			547
Income tax expense	204			118			362			264
Income Before Extraordinary Item	386			10			653			283
Extraordinary Item, net of tax	587			—			587			—
Net Income	$	973		$	10		$	1,240		$	283

Basic Earnings Per Share:
Income Before Extraordinary Item	$	0.90		$	0.02		$	1.53		$	0.66
Extraordinary Item, net of tax	1.38			—			1.38			—
Basic Earnings Per Share	$	2.28		$	0.02		$	2.91		$	0.66

Diluted Earnings Per Share:
Income Before Extraordinary Item	$	0.90		$	0.02		$	1.52		$	0.66
Extraordinary Item, net of tax	1.37			—			1.37			—
Diluted Earnings Per Share	$	2.27		$	0.02		$	2.89		$	0.66

Dividends Declared Per Share	$	0.1975		$	0.2025		$	0.5925		$	0.6075

Weighted Average Shares Outstanding, Basic	426			427			426			427

Weighted Average Shares Outstanding, Diluted	429			430			428			430

See Notes to Interim Condensed Consolidated Financial Statements

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CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

CONDENSED STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME

(In Millions)

(Unaudited)



	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2011		2012		2011		2012
Net income	$	973	$	10	$	1,240	$	283
Other comprehensive income:
Adjustment related to pension and other postretirement plans (net of tax of $2, $2, $5 and $6)	2		3		7		8
Total	2		3		7		8
Comprehensive income	$	975	$	13	$	1,247	$	291

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CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(In Millions)

(Unaudited)

ASSETS



	December 31, 2011		September 30, 2012
Current Assets:
Cash and cash equivalents ($220 and $194 related to VIEs at December 31, 2011 and September 30, 2012, respectively)	$	220	$	722
Investment in marketable securities	386		522
Accounts receivable, net ($52 and $104 related to VIEs at December 31, 2011 and September 30, 2012, respectively)	773		698
Accrued unbilled revenues	326		167
Natural gas inventory	187		170
Materials and supplies	166		182
Non-trading derivative assets	87		41
Taxes receivable	—		5
Prepaid expenses and other current assets ($42 and $53 related to VIEs at December 31, 2011 and September 30, 2012, respectively)	192		245
Total current assets	2,337		2,752

Property, Plant and Equipment:
Property, plant and equipment	16,868		18,010
Less accumulated depreciation and amortization	4,466		4,673
Property, plant and equipment, net	12,402		13,337

Other Assets:
Goodwill	1,696		1,468
Regulatory assets ($2,289 and $3,635 related to VIEs at December 31, 2011 and September 30, 2012, respectively)	4,619		4,319
Non-trading derivative assets	20		10
Investment in unconsolidated affiliates	472		408
Other	157		183
Total other assets	6,964		6,388

Total Assets	$	21,703	$	22,477

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, 2011			September 30, 2012
Current Liabilities:
Short-term borrowings	$	62		$	53
Current portion of VIE transition and system restoration bonds long-term debt	307			451
Current portion of indexed debt	131			136
Current portion of other long-term debt	46			815
Indexed debt securities derivative	197			273
Accounts payable	560			371
Taxes accrued	207			171
Interest accrued	164			130
Non-trading derivative liabilities	46			20
Accumulated deferred income taxes, net	507			597
Other	366			347
Total current liabilities	2,593			3,364


Other Liabilities:
Accumulated deferred income taxes, net	3,832			4,070
Non-trading derivative liabilities	6			6
Benefit obligations	1,065			994
Regulatory liabilities	1,039			1,095
Other	305			276
Total other liabilities	6,247			6,441

Long-term Debt:
VIE transition and system restoration bonds	2,215			3,459
Other	6,426			4,956
Total long-term debt	8,641			8,415

Commitments and Contingencies (Note 12)

Shareholders’ Equity:
Common stock (426,030,345 shares and 427,441,738 shares outstanding at December 31, 2011 and September 30, 2012, respectively)	4			4
Additional paid-in capital	4,120			4,123
Retained earnings	231			255
Accumulated other comprehensive loss	(133		)	(125		)
Total shareholders’ equity	4,222			4,257

Total Liabilities and Shareholders’ Equity	$	21,703		$	22,477

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,
	2011			2012
Cash Flows from Operating Activities:
Net income	$	1,240		$	283
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	677			800
Amortization of deferred financing costs	22			23
Deferred income taxes	404			237
Extraordinary item, net of tax	(587		)	—
Return on true-up balance	(352		)	—
Goodwill impairment	—			252
Step acquisition gain	—			(136		)
Unrealized loss (gain) on marketable securities	30			(136		)
Unrealized loss (gain) on indexed debt securities	(65		)	76
Write-down of natural gas inventory	7			4
Equity in earnings of unconsolidated affiliates, net of distributions	3			(6		)
Pension contributions	(72		)	(80		)
Changes in other assets and liabilities:
Accounts receivable and unbilled revenues, net	245			260
Inventory	(50		)	(3		)
Taxes receivable	138			(5		)
Accounts payable	(215		)	(186		)
Fuel cost recovery	(52		)	(72		)
Non-trading derivatives, net	(10		)	16
Margin deposits, net	61			49
Interest and taxes accrued	(25		)	(71		)
Net regulatory assets and liabilities	22			71
Other current assets	14			(12		)
Other current liabilities	(23		)	(23		)
Other assets	(1		)	(4		)
Other liabilities	23			32
Other, net	15			10
Net cash provided by operating activities	1,449			1,379

Cash Flows from Investing Activities:
Capital expenditures, net of acquisitions	(960		)	(818		)
Acquisitions, net of cash acquired	—			(360		)
Increase in restricted cash of transition and system restoration bond companies	(2		)	(12		)
Distributions from (investment in) unconsolidated affiliates	(9		)	6
Cash received from U.S. Department of Energy grant	110			—
Other, net	13			(25		)
Net cash used in investing activities	(848		)	(1,209		)

Cash Flows from Financing Activities:
Increase (decrease) in short-term borrowings, net	31			(9		)
Payments of commercial paper, net	(41		)	(285		)
Proceeds from long-term debt	550			2,495
Payments of long-term debt	(909		)	(1,528		)
Cash paid for debt exchange and debt retirement	(58		)	(69		)
Debt issuance costs	(23		)	(16		)
Payment of common stock dividends	(252		)	(259		)
Proceeds from issuance of common stock, net	5			3
Net cash provided by (used in) financing activities	(697		)	332

Net Increase (Decrease) in Cash and Cash Equivalents	(96		)	502
Cash and Cash Equivalents at Beginning of Period	199			220
Cash and Cash Equivalents at End of Period	$	103		$	722

Supplemental Disclosure of Cash Flow Information:
Cash Payments:
Interest, net of capitalized interest	$	470		$	446
Income taxes (refunds), net	(204		)	46
Non-cash transactions:
Accounts payable related to capital expenditures	101			100

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, 2011 (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, 2012, 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 (Gas Operations). 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.

As of September 30, 2012, CenterPoint Energy had five variable interest entities (VIEs) consisting of transition and system restoration bond companies which it consolidates. The consolidated VIEs are wholly-owned bankruptcy remote special purpose entities that were formed specifically for the purpose of securitizing transition and system restoration related property. Creditors of CenterPoint Energy have no recourse to any assets or revenues of the transition and system restoration bond companies. The bonds issued by these VIEs are payable only from and secured by transition and system restoration property and the bondholders have no recourse to the general credit of CenterPoint Energy.

Basis of Presentation. The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

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

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

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(3)	Employee Benefit Plans

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



	Three Months Ended September 30,
	2011						2012
	Pension Benefits(1)			Postretirement Benefits			Pension Benefits(1)			Postretirement Benefits
	(in millions)
Service cost	$	8		$	—		$	9		$	—
Interest cost	25			5			25			6
Expected return on plan assets	(29		)	(2		)	(30		)	(1		)
Amortization of prior service credit	1			1			2			—
Amortization of net loss	14			—			15			1
Amortization of transition obligation	—			2			—			2
Net periodic cost	$	19		$	6		$	21		$	8



	Nine Months Ended September 30,
	2011						2012
	Pension Benefits(1)			Postretirement Benefits			Pension Benefits(1)			Postretirement Benefits
	(in millions)
Service cost	$	25		$	1		$	27		$	1
Interest cost	75			17			74			18
Expected return on plan assets	(87		)	(7		)	(90		)	(5		)
Amortization of prior service credit	3			3			6			2
Amortization of net loss	42			1			45			3
Amortization of transition obligation	—			5			—			5
Net periodic cost	$	58		$	20		$	62		$	24

________________


(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 Energy expects to contribute a total of approximately $82 million to its pension plans in 2012, of which approximately $33 million and $80 million, respectively, was contributed during the three and nine months ended September 30, 2012.

CenterPoint Energy expects to contribute a total of approximately $18 million to its postretirement benefits plan in 2012, of which approximately $3 million and $12 million, respectively, was contributed during the three and nine months ended September 30, 2012.


(4)	Regulatory Accounting

As of September 30, 2012, CenterPoint Energy has not recognized an allowed equity return of $563 million because such return will be recognized as it is recovered in rates. During the three months ended September 30, 2011 and 2012, CenterPoint Houston recognized approximately $7 million and $16 million, respectively, of the allowed equity return not previously recognized. During the nine months ended September 30, 2011 and 2012, CenterPoint Houston recognized approximately $15 million and $37 million, respectively, of the allowed equity return not previously recognized.

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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, 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 three months ended September 30, 2012, CenterPoint Energy recorded decreased natural gas revenues from unrealized net losses of $30 million and decreased natural gas expense from unrealized net gains of $21 million, resulting in a net unrealized loss of $9 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. During the nine months ended September 30, 2012, CenterPoint Energy recorded decreased natural gas revenues from unrealized net losses of $76 million and decreased natural gas expense from unrealized net gains of $62 million, resulting in a net unrealized loss of $14 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, Mississippi, 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 for these Gas Operations jurisdictions to mitigate the effect of fluctuations from normal weather on its results of operations and cash flows for the winter heating season. The swaps have limits and are based on ten-year normal weather. During the three and nine months ended September 30, 2011, CenterPoint Energy recognized losses of $-0- and $6 million, respectively, related to these swaps. During the three and nine months ended September 30, 2012, CenterPoint Energy recognized gains of $-0- and $6 million, respectively, related to these swaps. Weather hedge gains and losses are included in revenues in the Condensed Statements of Consolidated Income.

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(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, 2011 and September 30, 2012, while the last table provides a breakdown of the related income statement impacts for the three and nine months ended September 30, 2011 and 2012.



Fair Value of Derivative Instruments
		December 31, 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 derivatives (1)	Current Assets	$	88	$	1
Natural gas derivatives (1)	Other Assets	20		—
Natural gas derivatives (1)	Current Liabilities	15		110
Natural gas derivatives (1)	Other Liabilities	—		13
Indexed debt securities derivative	Current Liabilities	—		197
Total		$	123	$	321

________________


(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 633 billion cubic feet (Bcf) or a net 84 Bcf long position. Of the net long position, basis swaps constitute 74 Bcf and volumes associated with price stabilization activities of the Natural Gas Distribution business segment constitute 6 Bcf.


(3)	The net of total non-trading derivative assets and liabilities is a $55 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 $56 million.



Fair Value of Derivative Instruments
		September 30, 2012
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 derivatives (1)	Current Assets	$	43	$	2
Natural gas derivatives (1)	Other Assets	13		2
Natural gas derivatives (1)	Current Liabilities	11		38
Natural gas derivatives (1)	Other Liabilities	—		6
Indexed debt securities derivative	Current Liabilities	—		273
Total		$	67	$	321

________________


(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 566 Bcf or a net 128 Bcf long position. Of the net long position, basis swaps constitute 69 Bcf.


(3)	The net of total non-trading derivative assets and liabilities is a $25 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 $6 million.

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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 physical natural gas sales derivative contracts and as natural gas expense for financial natural gas derivatives and other 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.



Income Statement Impact of Derivative Activity
		Three Months Ended September 30,
Total derivatives not designated as hedging instruments	Income Statement Location	2011			2012
		(in millions)
Natural gas derivatives	Gains (Losses) in Revenue	$	27		$	(21	)
Natural gas derivatives (1)	Gains (Losses) in Expense: Natural Gas	(30		)	24
Indexed debt securities derivative	Gains (Losses) in Other Income (Expense)	88			(52		)
Total		$	85		$	(49	)

________________

(1)

The Gains (Losses) in Expense: Natural Gas includes $(17) million of costs in 2011 associated with price stabilization activities of the Natural Gas Distribution business segment that will be ultimately recovered through purchased gas adjustments. There are no such costs associated with price stabilization activities of the Natural Gas Distribution business segment in the three months ended September 30, 2012.



Income Statement Impact of Derivative Activity
		Nine Months Ended September 30,
Total derivatives not designated as hedging instruments	Income Statement Location	2011			2012
		(in millions)
Natural gas derivatives	Gains (Losses) in Revenue	$	41		$	22
Natural gas derivatives (1)	Gains (Losses) in Expense: Natural Gas	(79		)	(44		)
Indexed debt securities derivative	Gains (Losses) in Other Income (Expense)	65			(76		)
Total		$	27		$	(98	)

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(1)	The Gains (Losses) in Expense: Natural Gas includes $(79) million and $(38) million of costs in 2011 and 2012, 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, 2011 and September 30, 2012 was $39 million and $7 million, respectively. The aggregate fair value of assets that were posted as collateral was less than $1 million at both December 31, 2011 and September 30, 2012. If all derivative contracts (in a net liability position) containing credit risk contingent features were triggered at December 31, 2011 and September 30, 2012, $38 million and $6 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.

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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 for the asset or liability. 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. Currently, CenterPoint Energy’s Level 3 assets and liabilities are comprised of physical forward contracts and options. Level 3 physical forward contracts are valued using a discounted cash flow model which includes illiquid forward price curve locations (ranging from $2.89-$4.90 per one million British thermal units) as an unobservable input. Level 3 options are valued through Black-Scholes (including forward start) option models which include option volatilities (ranging from 0-67%) as an unobservable input. CenterPoint Energy’s Level 3 derivative assets and liabilities consist of both long and short positions (forwards and options) and their fair value is sensitive to forward prices and volatilities. If forward prices decrease, CenterPoint Energy’s long forwards lose value whereas its short forwards gain in value. If volatility decreases, CenterPoint Energy’s long options lose value whereas its short options gain in value.

CenterPoint Energy determines the appropriate level for each financial asset and liability on a quarterly basis and recognizes transfers between levels at the end of the reporting period. For the nine months ended September 30, 2012, there were no transfers between Level 1 and 2 with regard to Natural Gas derivatives. CenterPoint Energy also recognizes purchases of Level 3 financial assets and liabilities at their fair market value at the end of the reporting period.

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, 2011 and September 30, 2012, and indicate the fair value hierarchy of the valuation techniques utilized by CenterPoint Energy to determine such fair value.



	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Netting Adjustments ⁽¹⁾			Balance as of December 31, 2011
			Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Netting Adjustments ⁽¹⁾			Balance as of December 31, 2011
	(in millions)
Assets
Corporate equities	$	387	$	—	$	—	$	—		$	387
Investments, including money market funds (2)	56		—		—		—			56
Natural gas derivatives	1		112		10		(16		)	107
Total assets	$	444	$	112	$	10	$	(16	)	$	550
Liabilities
Indexed debt securities derivative	$	—	$	197	$	—	$	—		$	197
Natural gas derivatives	19		101		4		(72		)	52
Total liabilities	$	19	$	298	$	4	$	(72	)	$	249

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(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 $56 million posted with the same counterparties.


(2)	Excludes money market fund investments included in Cash and cash equivalents.

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	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Netting Adjustments ⁽¹⁾			Balance as of September 30, 2012
			Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Netting Adjustments ⁽¹⁾			Balance as of September 30, 2012
	(in millions)
Assets
Corporate equities	$	524	$	—	$	—	$	—		$	524
Investments, including money market funds (2)	75		—		—		—			75
Natural gas derivatives	5		49		13		(16		)	51
Total assets	$	604	$	49	$	13	$	(16	)	$	650
Liabilities
Indexed debt securities derivative	$	—	$	273	$	—	$	—		$	273
Natural gas derivatives	8		28		12		(22		)	26
Total liabilities	$	8	$	301	$	12	$	(22	)	$	299

________________


(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 $6 million posted with the same counterparties.


(2)	Excludes money market fund investments included in Cash and cash equivalents.

The following table presents 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,						Nine Months Ended September 30,
	2011			2012			2011			2012
	(in millions)
Beginning balance	$	5		$	3		$	3		$	6
Total unrealized gain (losses) ⁽¹⁾	(1		)	—			3			4
Total settlements ⁽¹⁾	(1		)	(2		)	(3		)	(8		)
Transfers out of Level 3	—			—			—			(1		)
Ending balance ⁽²⁾	$	3		$	1		$	3		$	1
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	)	$	2		$	—

________________


(1)	CenterPoint Energy did not have Level 3 unrealized gains (losses) or settlements related to price stabilization activities of the Natural Gas Distribution business segment for either the three or nine months ended September 30, 2011 or 2012.


(2)	During both the three and nine months ended September 30, 2011 and 2012, CenterPoint Energy did not have material Level 3 purchases, sales or significant transfers into Level 3.

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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. These assets and liabilities, which are not measured at fair value in the Condensed Consolidated Balance Sheets but for which the fair value is disclosed, would be classified as Level 1 in the fair value hierarchy.



	December 31, 2011				September 30, 2012
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in millions)
Financial liabilities:
Long-term debt	$	8,994	$	10,049	$	9,681	$	10,916

(7) Acquisition

On July 31, 2012, CenterPoint Energy purchased the 50% interest that it did not already own in Waskom Gas Processing Company (Waskom), a Texas general partnership, which owns and operates a natural gas processing plant and natural gas gathering assets, as well as other gathering and related assets from a third-party for approximately $273 million. The amount of the purchase price allocated to the acquisition of the 50% interest in Waskom was approximately $201 million, with the remaining purchase price allocated to the other gathering assets, based on a discounted cash flow methodology. The $273 million purchase price was allocated as follows: $253 million to property, plant and equipment; $16 million to goodwill; and the remaining balance to other assets and liabilities. The purchase of the 50% interest in Waskom was determined to be a business combination achieved in stages, and as such CenterPoint Energy recorded a pre-tax gain of approximately $136 million on July 31, 2012, which is the result of remeasuring its original 50% interest in Waskom to fair value. As a result of the purchase, CenterPoint Energy recorded goodwill of $24 million, which includes $17 million related to Waskom (including the re-measurement of its existing 50% interest) and $7 million related to the other gathering and related assets.


(8)	Goodwill

Goodwill by reportable business segment as of September 30, 2012 and changes in the carrying amount of goodwill for the nine months ended September 30, 2012 are as follows (in millions):



	December 31, 2011		Impairment charge		Acquisition		September 30, 2012
Natural Gas Distribution	$	746	$	—	$	—	$	746
Interstate Pipelines	579		—		—		579
Competitive Natural Gas Sales and Services	335		252		—		83
Field Services	25		—		24		49
Other Operations	11		—		—		11
Total	$	1,696	$	252	$	24	$	1,468

CenterPoint Energy performs its goodwill impairment tests at least annually and evaluates goodwill when events or changes in circumstances indicate that its carrying value 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 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.

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CenterPoint Energy performed its annual impairment test in the third quarter of 2012 and determined that a non-cash goodwill impairment charge in the amount of $252 million was required for the Competitive Natural Gas Sales and Services reportable segment. CenterPoint Energy also determined that no impairment charge was required for any other reportable segment.

CenterPoint Energy estimated the value of the Competitive Natural Gas Sales and Services reporting unit using an income approach. Under this approach, the fair value of the reporting unit is determined by using the present value of future expected cash flows, which are based on management projections of revenue growth, gross margin, and overall market conditions. These estimated future cash flows are then discounted using a rate that approximates the weighted average cost of capital of a market participant.

The Competitive Natural Gas Sales and Services reporting unit fair value analysis resulted in an implied fair value of goodwill of $83 million for this reporting unit, and as a result, a non-cash impairment charge in the amount of $252 million was recorded in the third quarter of 2012. The adverse wholesale market conditions facing CenterPoint Energy's energy services business, specifically the prospects for continued low geographic and seasonal price differentials for natural gas, led to a reduction in the estimate of the fair value of goodwill associated with this reporting unit.


(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, 2011, 426,030,511 shares of CenterPoint Energy, Inc. common stock were issued and 426,030,345 shares were outstanding. At September 30, 2012, 427,441,904 shares of CenterPoint Energy, Inc. common stock were issued and 427,441,738 shares were outstanding. Outstanding common shares exclude 166 treasury shares at both December 31, 2011 and September 30, 2012.


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


(a)	Short-term Borrowings

Inventory Financing. Gas Operations has entered into asset management agreements associated with its utility distribution service in Arkansas, north Louisiana and Oklahoma that extend through March 2015. 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 $62 million and $53 million as of December 31, 2011 and September 30, 2012, respectively.


(b)	Long-term Debt

Transition Bonds. In January 2012, CenterPoint Energy Transition Bond Company IV, LLC, a new special purpose subsidiary of CenterPoint Houston, issued $1.695 billion of transition bonds in three tranches with interest rates ranging from 0.9012% to 3.0282% and final maturity dates ranging from April 15, 2018 to October 15, 2025. The transition bonds will be repaid over time through a charge imposed on customers in CenterPoint Houston’s service territory.

Pollution Control Bonds. In February 2012, CenterPoint Energy purchased $275 million aggregate principal amount of pollution control bonds issued on its behalf at 100% of their principal amount plus accrued interest pursuant to the mandatory tender provisions of the bonds. The purchased pollution control bonds will remain outstanding and may be remarketed. Prior to the purchase, the pollution control bonds had fixed interest rates ranging from 5.15% to 5.95%. Additionally, in March 2012, CenterPoint Energy redeemed $100 million aggregate principal amount of pollution control bonds issued on its behalf at 100% of their principal amount plus accrued interest pursuant to the optional redemption provisions of the bonds. The redeemed pollution control bonds had a fixed interest rate of 5.25%.

General Mortgage Bonds. In August 2012, CenterPoint Houston issued $300 million of 2.25% general mortgage bonds due 2022 and $500 million of 3.55% general mortgage bonds due 2042. The net proceeds from the sale of the bonds were used to fund a portion of the redemption of the general mortgage bonds discussed below.

In August 2012, CenterPoint Houston redeemed $300 million principal amount of its 5.75% general mortgage bonds due 2014 at a price of 107.332% of their principal amount and $500 million principal amount of its 7.00% general mortgage bonds due 2014 at a price of 109.397% of their principal amount. Redemption premiums for the two series aggregated approximately $69 million and were deferred as regulatory assets.

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Revolving Credit Facilities. As of December 31, 2011 and September 30, 2012, CenterPoint Energy, CenterPoint Houston and CERC Corp. had the following revolving credit facilities and utilization of such facilities (in millions):



			December 31, 2011						September 30, 2012
	Size of Facility		Loans		Letters of Credit		Commercial Paper		Loans		Letters of Credit		Commercial Paper
CenterPoint Energy	$	1,200	$	—	$	16	$	—	$	—	$	7	$	—
CenterPoint Houston	300		—		4		—		—		4		—
CERC Corp.	950		—		—		285		—		—		—
Total	$	2,450	$	—	$	20	$	285	$	—	$	11	$	—

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 150 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.

CenterPoint Houston’s $300 million credit facility, which is scheduled to terminate September 9, 2016, can be drawn at LIBOR plus 125 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.


(11)	Income Taxes

The effective tax rate for the three and nine months ended September 30, 2012 was 92% and 48%, respectively, compared to 35% and 36% for the same periods in 2011. The increase in the effective tax rate for the three and nine months ended September 30, 2012 was primarily due to the unfavorable tax effect of the impairment of non-tax deductible goodwill of $252 million, partially offset by favorable tax adjustments, including the re-measurement of certain unrecognized tax benefits, of $18 million and $31 million for the three and nine months ended September 30, 2012, respectively, related to CenterPoint Energy’s Internal Revenue Service (IRS) settlement of tax years 2006 through 2009.

The following table summarizes CenterPoint Energy’s unrecognized tax benefits (expense) at December 31, 2011 and September 30, 2012:



	December 31, 2011			September 30, 2012
	(in millions)
Unrecognized tax benefits (expense)	$	51		$	(13	)
Portion of unrecognized tax benefits that, if recognized, would reduce the effective income tax rate	21			4
Interest accrued on unrecognized tax benefits	(1		)	(8		)

CenterPoint Energy does not expect the change to the amount of unrecognized tax benefits over the twelve months ending September 30, 2013 to materially impact the financial position of CenterPoint Energy.

CenterPoint Energy's settlement with the IRS for tax years 2008 and 2009 was approved by the Joint Committee on Taxation during the third quarter of 2012. In September 2012, the IRS commenced its examination of CenterPoint Energy’s 2011 consolidated federal income tax return in conjunction with its review of CenterPoint Energy's 2010 consolidated federal income tax return.

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(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, 2011 and September 30, 2012 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, 2012, minimum payment obligations for natural gas supply commitments are approximately $143 million for the remaining three months in 2012, $437 million in 2013, $352 million in 2014, $216 million in 2015, $150 million in 2016 and $251 million after 2016.


(b)	Long-Term Gas Gathering and Treating Agreements

CenterPoint Energy Field Services, LLC (CEFS) has 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. Under the long-term agreements, Encana or Shell may elect to require CEFS to expand the capacity of its gathering systems by up to an additional 1.3 Bcf per day. CEFS estimates that the cost to expand the capacity of its gathering systems by an additional 1.3 Bcf per day would be as much as $440 million. Encana and Shell would provide incremental volume commitments in connection with an election to expand system 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 have been named as defendants in certain lawsuits described below. Under a master separation agreement between CenterPoint Energy and a former subsidiary, Reliant Resources, 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 RRI changed its name to RRI Energy, Inc. In December 2010, Mirant Corporation merged with and became a wholly owned subsidiary of RRI, and RRI changed its name to GenOn Energy, Inc. (GenOn). In July 2012, GenOn and NRG entered into a definitive merger agreement providing for NRG's acquisition of GenOn, subject to certain conditions. None of the sale of the retail business, the merger with Mirant Corporation, or the pending acquisition of GenOn by NRG 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 were 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 since 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. In September 2012, the Nevada Supreme Court affirmed the dismissal. In October 2012, the Nevada Supreme Court granted the plaintiffs’ motion to stay the dismissal of this case pending the filing and final disposition of their petition for a writ of certiorari to the Supreme Court of the United States. 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

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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. In July 2012, the plaintiffs filed a motion to dismiss certain defendants from both lawsuits, including the remaining CenterPoint Energy defendants.

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.

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, 2012, CERC had accrued $13 million for remediation of these Minnesota sites and the estimated range of possible remediation costs for the sites CERC believes it has responsibility for 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 Utilities Commission includes approximately $285,000 annually in rates to fund normal on-going remediation costs. As of September 30, 2012, CERC had collected $5.7 million from insurance companies to be used to mitigate future environmental costs.

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 and CenterPoint Energy do not expect the ultimate outcome of these investigations will have a material adverse impact on the financial condition, results of operations or cash flows of either CenterPoint Energy or 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 subsidiaries of 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 and early 2005, CenterPoint Energy sold its generating business, to which most of these claims relate, to a company which is now an affiliate of NRG. Under the terms of the arrangements regarding separation of the generating business from CenterPoint Energy and its sale of that business, ultimate financial responsibility for uninsured losses from claims relating to the generating business has been assumed by the NRG affiliate, but CenterPoint Energy has agreed to continue to defend such claims to the extent they are covered by insurance maintained by CenterPoint Energy, subject to reimbursement of the costs of such defense by the NRG affiliate. 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, based on its experience to date, does not expect 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 identifies the presence of environmental contaminants on property where its subsidiaries conduct or have conducted operations. Other such sites involving contaminants may be identified in the future. CenterPoint Energy has and expects to continue to remediate identified sites consistent with its legal obligations. From

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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 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 $77 million as of September 30, 2012. Based on market conditions in the fourth quarter of 2012 at the time the most recent annual calculation was made under the agreement, GenOn was not obligated to post any security. As a result, CenterPoint Energy currently anticipates returning to GenOn in December 2012 the approximately $28 million of aggregate collateral previously posted by GenOn under the agreement. If GenOn should fail to perform the contractual obligations, CERC could have to honor its guarantee and, in such event, any collateral provided as security may be insufficient to satisfy CERC’s obligations.

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(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,
	2011		2012		2011		2012
	(in millions, except share and per share amounts)
Basic earnings per share calculation:
Income before extraordinary item	$	386	$	10	$	653	$	283
Extraordinary item, net of tax	587		—		587		—
Net income	$	973	$	10	$	1,240	$	283

Weighted average shares outstanding	425,885,000		427,406,000		425,517,000		427,086,000

Basic earnings per share:
Income before extraordinary item	$	0.90	$	0.02	$	1.53	$	0.66
Extraordinary item, net of tax	1.38		—		1.38		—
Net income	$	2.28	$	0.02	$	2.91	$	0.66

Diluted earnings per share calculation:
Net income	$	973	$	10	$	1,240	$	283

Weighted average shares outstanding	425,885,000		427,406,000		425,517,000		427,086,000
Plus: Incremental shares from assumed conversions:
Stock options	399,000		230,000		377,000		222,000
Restricted stock	2,558,000		2,347,000		2,558,000		2,347,000
Weighted average shares assuming dilution	428,842,000		429,983,000		428,452,000		429,655,000

Diluted earnings per share:
Income before extraordinary item	$	0.90	$	0.02	$	1.52	$	0.66
Extraordinary item, net of tax	1.37		—		1.37		—
Net income	$	2.27	$	0.02	$	2.89	$	0.66


(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. 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.

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



	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

	For the Three Months Ended September 30, 2012
	Revenues from External Customers			Net Intersegment Revenues			Operating Income (Loss)
Electric Transmission & Distribution	$	748	⁽¹⁾	$	—		$	242
Natural Gas Distribution	351			4			5
Competitive Natural Gas Sales and Services	382			7			(259		)
Interstate Pipelines	92			30			48
Field Services	129			12			55
Other Operations	3			—			(3		)
Eliminations	—			(53		)	—
Consolidated	$	1,705		$	—		$	88



	For the Nine Months Ended September 30, 2011
	Revenues from External Customers			Net Intersegment Revenues			Operating Income			Total Assets as of December 31, 2011
Electric Transmission & Distribution	$	1,802	⁽¹⁾	$	—		$	530		$	11,221
Natural Gas Distribution	2,034			14			153			4,636
Competitive Natural Gas Sales and Services	1,858			18			3			1,089
Interstate Pipelines	328			96			196			3,867
Field Services	274			31			136			1,894
Other Operations	9			—			6			2,318			⁽²⁾
Eliminations	—			(159		)	—			(3,322		)
Consolidated	$	6,305		$	—		$	1,024		$	21,703

	For the Nine Months Ended September 30, 2012
	Revenues from External Customers			Net Intersegment Revenues			Operating Income (Loss)			Total Assets as of September 30, 2012
Electric Transmission & Distribution	$	1,955	⁽¹⁾	$	—		$	540		$	11,051
Natural Gas Distribution	1,560			15			135			4,571
Competitive Natural Gas Sales and Services	1,204			18			(262		)	777
Interstate Pipelines	262			112			160			3,982
Field Services	324			26			153			2,439
Other Operations	9			—			2			2,252			⁽²⁾
Eliminations	—			(171		)	—			(2,595		)
Consolidated	$	5,314		$	—		$	728		$	22,477

________________

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(1)

Sales to affiliates of NRG in the three months ended September 30, 2011 and 2012 represented approximately $188 million and $196 million, respectively, of CenterPoint Houston’s transmission and distribution revenues. Sales to affiliates of Energy Future Holdings Corp. in the three months ended September 30, 2011 and 2012 represented approximately $58 million and $49 million, respectively, of CenterPoint Houston’s transmission and distribution revenues. Sales to affiliates of NRG in the nine months ended September 30, 2011 and 2012 represented approximately $448 million and $488 million, respectively, of CenterPoint Houston’s transmission and distribution revenues. Sales to affiliates of Energy Future Holdings Corp. in the nine months ended September 30, 2011 and 2012 represented approximately $139 million and $123 million, respectively, of CenterPoint Houston’s transmission and distribution revenues.


(2)	Included in total assets of Other Operations as of December 31, 2011 and September 30, 2012 are pension and other postemployment related regulatory assets of $796 million and $756 million, respectively.


(15)	Subsequent Events

On October 24, 2012, CenterPoint Energy’s board of directors declared a regular quarterly cash dividend of $0.2025 per share of common stock payable on December 10, 2012, to shareholders of record as of the close of business on November 16, 2012.

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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, 2011 (2011 Form 10-K).

EXECUTIVE SUMMARY

Recent Events

Acquisition

On July 31, 2012, we purchased the 50% interest that we did not already own in Waskom Gas Processing Company (Waskom), a Texas general partnership, which owns and operates a natural gas processing plant and natural gas gathering assets, as well as other gathering and related assets from a third-party for approximately $273 million. The amount of the purchase price allocated to the acquisition of the 50% interest in Waskom was approximately $201 million, with the remaining purchase price allocated to the other gathering assets, based on a discounted cash flow methodology. The purchase of the 50% interest in Waskom was determined to be a business combination achieved in stages, and as such we recorded a pre-tax gain of approximately $136 million on July 31, 2012, which is the result of remeasuring our original 50% interest in Waskom to fair value. As a result of the purchase, we recorded goodwill of $24 million, which includes $17 million related to Waskom (including the re-measurement of our existing 50% interest) and $7 million related to the other gathering and related assets.

Goodwill Impairment

We performed our annual impairment test in the third quarter of 2012 and determined that a non-cash goodwill impairment charge in the amount of $252 million was required for the Competitive Natural Gas Sales and Services reportable segment. We also determined that no impairment charge was required for our other reportable segments.

We estimated the value of the Competitive Natural Gas Sales and Services reporting unit using an income approach. Under this approach, the fair value of the reporting unit is determined by using the present value of future expected cash flows, which are based on management projections of revenue growth, gross margin, and overall market conditions. These estimated future cash flows are then discounted using a rate that approximates the weighted average cost of capital of a market participant.

The Competitive Natural Gas Sales and Services reporting unit fair value analysis resulted in an implied fair value of goodwill of $83 million for this reporting unit, and as a result, a non-cash impairment charge in the amount of $252 million was recorded in the third quarter of 2012. The adverse wholesale market conditions facing our energy services business, specifically the prospects for continued low geographic and seasonal price differentials for natural gas, led to a reduction in our estimate of the fair value of goodwill associated with this reporting unit.

Debt Financing Transactions

In August 2012, CenterPoint Energy Houston Electric LLC (CenterPoint Houston) issued $300 million of 2.25% general mortgage bonds due 2022 and $500 million of 3.55% general mortgage bonds due 2042. The net proceeds from the sale of the bonds were used to fund a portion of the redemption of the general mortgage bonds discussed below.

CenterPoint Energy-Mississippi River Transmission, LLC Rate Filing

In August 2012, our subsidiary, CenterPoint Energy-Mississippi River Transmission, LLC (MRT), an interstate pipeline that provides natural gas transportation, natural gas storage and pipeline services to customers principally in Arkansas, Illinois and Missouri, filed a rate filing with the Federal Energy Regulatory Commission (FERC) pursuant to Section 4 of the Natural Gas Act. In its filing, MRT requested an annual cost of service of $103.8 million (an increase of approximately $47.3 million above the annual cost of service underlying the current FERC approved maximum rates for MRT's pipeline), new depreciation rates, an overall rate of return of 10.813% (based on a return on equity of 13.62%), a regulatory compliance cost (RCC) surcharge with a true-up mechanism to recover safety, environmental, and security costs associated with mandated requirements and billing

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determinants reflecting no adjustments for MRT's conversion of a portion of CenterPoint Energy Gas Transmission Company, LLC’s firm capacity to a lease. In August 2012, a number of parties filed protests in response to MRT's rate filing. In September 2012, the FERC issued an order accepting MRT's filing, suspending the filed tariff rates for the full statutorily permitted five month suspension period and setting certain issues for hearing. In particular, the FERC limited the scope of the RCC surcharge set for hearing to the recovery of only security costs. MRT filed for rehearing on the scope of costs that could be considered for recovery under the RCC in October 2012. The procedural schedule for the rate filing contemplates a hearing at the FERC in the third quarter of 2013.

CenterPoint Energy Gas Transmission Company, LLC Rate Settlement Proceeding

In an effort to avoid the expense of a rate case, in October 2012 CenterPoint Energy Gas Transmission Company, LLC (CEGT) initiated a settlement process with its customers. Should these discussions fail, CEGT will consider filing for a general rate increase in 2013. CEGT will attempt to reach a mutually agreeable rate solution with its customers to recover its increased costs to maintain a safe and reliable system, but there can be no assurance that it will be successful and will avoid the initiation of a general rate case filing.

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,
	2011			2012			2011			2012
Revenues	$	1,881		$	1,705		$	6,305		$	5,314
Expenses	1,524			1,617			5,281			4,586
Operating Income	357			88			1,024			728
Interest and Other Finance Charges	(114		)	(104		)	(341		)	(318		)
Interest on Transition and System Restoration Bonds	(31		)	(37		)	(96		)	(112		)
Equity in Earnings of Unconsolidated Affiliates	8			8			22			25
Return on True-Up Balance	352			—			352			—
Step acquisition gain	—			136			—			136
Other Income, net	18			37			54			88
Income Before Income Taxes	590			128			1,015			547
Income Tax Expense	204			118			362			264
Income Before Extraordinary Item	386			10			653			283
Extraordinary Item, net of tax	587			—			587			—
Net Income	$	973		$	10		$	1,240		$	283

Basic Earnings Per Share:
Income Before Extraordinary Item	$	0.90		$	0.02		$	1.53		$	0.66
Extraordinary Item, net of tax	1.38			—			1.38			—
Basic Earnings Per Share	$	2.28		$	0.02		$	2.91		$	0.66

Diluted Earnings Per Share:
Income Before Extraordinary Item	$	0.90		$	0.02		$	1.52		$	0.66
Extraordinary Item, net of tax	1.37			—			1.37			—
Diluted Earnings Per Share	$	2.27		$	0.02		$	2.89		$	0.66

Three months ended September 30, 2012 compared to three months ended September 30, 2011

We reported consolidated net income of $10 million ($0.02 per diluted share) for the three months ended September 30, 2012 compared to $973 million ($2.27 per diluted share) for the same period in 2011. The decrease in net income of $963 million was primarily due to the resolution of the true-up appeal in 2011 resulting in an after-tax extraordinary gain of $587 million and a $352 million return on true-up balance, a $269 million decrease in operating income (discussed by segment below), including a $252

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million non-cash goodwill impairment charge, and a $140 million increase in the loss on our indexed debt securities, which were partially offset by a $157 million increase in the gain on our marketable securities, a $136 million step acquisition gain related to the acquisition of an additional 50% interest in Waskom, an $86 million decrease in income tax expense and a $5 million increase in other income related to an indemnification payment from a former affiliate.

Nine months ended September 30, 2012 compared to nine months ended September 30, 2011

We reported consolidated net income of $283 million ($0.66 per diluted share) for the nine months ended September 30, 2012 compared to $1,240 million ($2.89 per diluted share) for the same period in 2011. The decrease in net income of $957 million was primarily due to the resolution of the true-up appeal in 2011 resulting in an after-tax extraordinary gain of $587 million and a $352 million return on true-up balance, a $296 million decrease in operating income (discussed by segment below), including a $252 million non-cash goodwill impairment charge, and a $141 million increase in the loss on our indexed debt securities, which were partially offset by a $166 million increase in the gain on our marketable securities, a $136 million step acquisition gain related to the acquisition of an additional 50% interest in Waskom, a $98 million decrease in income tax expense and a $12 million increase in other income related to an indemnification payment from a former affiliate.

Income Tax Expense

Our effective tax rate for the three and nine months ended September 30, 2012 was 92% and 48%, respectively, compared to 35% and 36% for both of the same periods in 2011. The increase in the effective tax rate for the three and nine months ended September 30, 2012 was primarily due to the unfavorable tax effect of the impairment of non-tax deductible goodwill of $252 million, partially offset by favorable tax adjustments, including the re-measurement of certain unrecognized tax benefits, of $18 million and $31 million for the three and nine months ended September 30, 2012, respectively, related to CenterPoint Energy’s Internal Revenue Service (IRS) settlement of tax years 2006 through 2009.

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, 2011 and 2012. 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,
	2011			2012			2011		2012
Electric Transmission & Distribution	$	244		$	242		$	530	$	540
Natural Gas Distribution	(2		)	5			153		135
Competitive Natural Gas Sales and Services	(10		)	(259		)	3		(262		)
Interstate Pipelines	60			48			196		160
Field Services	61			55			136		153
Other Operations	4			(3		)	6		2
Total Consolidated Operating Income	$	357		$	88		$	1,024	$	728

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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 2011 Form 10-K.

The following tables provide summary data of our Electric Transmission & Distribution business segment for the three and nine months ended September 30, 2011 and 2012 (in millions, except throughput and customer data):



	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2012		2011		2012
Revenues:
Electric transmission and distribution utility	$	565	$	563	$	1,454	$	1,492
Transition and system restoration bond companies	142		185		348		463
Total revenues	707		748		1,802		1,955
Expenses:
Operation and maintenance, excluding transition and system restoration bond companies	228		228		655		680
Depreciation and amortization, excluding transition and system restoration bond companies	70		76		207		224
Taxes other than income taxes	54		54		158		160
Transition and system restoration bond companies	111		148		252		351
Total expenses	463		506		1,272		1,415
Operating Income	$	244	$	242	$	530	$	540

Operating Income:
Electric transmission and distribution utility	$	213	$	205	$	434	$	428
Transition and system restoration bond companies (1)	31		37		96		112
Total segment operating income	$	244	$	242	$	530	$	540

Throughput (in gigawatt-hours (GWh)):
Residential	10,682		9,524		23,338		21,967
Total	24,957		23,753		62,802		61,284

Number of metered customers at end of period:
Residential	1,898,789		1,934,078		1,898,789		1,934,078
Total	2,149,594		2,189,796		2,149,594		2,189,796

________________


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

Three months ended September 30, 2012 compared to three months ended September 30, 2011

Our Electric Transmission & Distribution business segment reported operating income of $242 million for the three months ended September 30, 2012, consisting of $205 million from the regulated electric transmission and distribution utility (TDU) and $37 million related to transition and system restoration bond companies (Bond Companies). For the three months ended September 30, 2011, operating income totaled $244 million, consisting of $213 million from the TDU and $31 million related to Bond Companies. TDU operating income decreased $8 million due to decreased usage ($38 million), primarily due to a return to more normal weather when compared to the weather experienced in 2011, and the impact of the 2010 rate case implemented in September 2011 ($9 million), partially offset by higher transmission-related revenues net of higher costs billed by transmission providers ($13 million), higher equity return ($9 million) primarily related to true-up proceeds, customer growth ($7 million) from the addition of over 40,000 new customers, decreased labor and benefits costs ($6 million) and increased miscellaneous revenues ($5 million), primarily from right-of-way access and easement grants.

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Nine months ended September 30, 2012 compared to nine months ended September 30, 2011

Our Electric Transmission & Distribution business segment reported operating income of $540 million for the nine months ended September 30, 2012, consisting of $428 million from the TDU and $112 million related to Bond Companies. For the nine months ended September 30, 2011, operating income totaled $530 million, consisting of $434 million from the TDU and $96 million related to Bond Companies. TDU operating income decreased $6 million due to decreased usage ($49 million), primarily due to a return to more normal weather when compared to the weather experienced in 2011, and the impact of the 2010 rate case implemented in September 2011 ($36 million), partially offset by increased miscellaneous revenues ($23 million), primarily from right-of-way access and easement grants, higher equity return ($22 million) primarily related to true-up proceeds, customer growth ($19 million) from the addition of over 40,000 new customers, higher transmission-related revenues net of higher costs billed by transmission providers ($10 million) and decreased labor and benefits costs ($6 million).

Natural Gas Distribution

For information regarding factors that may affect the future results of operations of our Natural Gas Distribution business segment, please read “Risk Factors ─ Risk Factors Affecting Our Natural Gas Distribution, Competitive Natural Gas Sales and Services, Interstate Pipelines and Field Services Businesses,” “─ Risk Factors Associated with Our Consolidated Financial Condition” and “─ Risks Common to Our Businesses and Other Risks” in Item 1A of Part I of our 2011 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, 2011 and 2012 (in millions, except throughput and customer data):



	Three Months Ended September 30,					Nine Months Ended September 30,
	2011			2012		2011		2012
Revenues	$	384		$	355	$	2,048	$	1,575
Expenses:
Natural gas	167			134		1,203		763
Operation and maintenance	156			151		481		470
Depreciation and amortization	41			43		124		129
Taxes other than income taxes	22			22		87		78
Total expenses	386			350		1,895		1,440
Operating Income (Loss)	$	(2	)	$	5	$	153	$	135

Throughput (in billion cubic feet (Bcf)):
Residential	12			12		122		90
Commercial and industrial	48			49		187		175
Total Throughput	60			61		309		265

Number of customers at end of period:
Residential	2,990,934			3,022,320		2,990,934		3,022,320
Commercial and industrial	241,838			242,001		241,838		242,001
Total	3,232,772			3,264,321		3,232,772		3,264,321

Three months ended September 30, 2012 compared to three months ended September 30, 2011

Our Natural Gas Distribution business segment reported operating income of $5 million for the three months ended September 30, 2012 compared to an operating loss of $2 million for the three months ended September 30, 2011. Operating income increased $7 million primarily as a result of reduced benefits expense ($3 million), rate increases ($2 million), the addition of over 31,000 customers ($2 million) and increased usage ($2 million). Favorable impacts were partially offset by increased depreciation and amortization expense ($2 million).

Nine months ended September 30, 2012 compared to nine months ended September 30, 2011

Our Natural Gas Distribution business segment reported operating income of $135 million for the nine months ended September 30, 2012 compared to $153 million for the nine months ended September 30, 2011. Operating income decreased $18 million primarily as a result of decreased throughput primarily due to the impacts of warmer winter weather partially mitigated by weather hedges and weather normalization adjustments ($27 million), increased depreciation and amortization expense ($5

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million) and increased insurance expense ($7 million). Adverse impacts were partially offset by reduced labor and benefits expense ($2 million), the addition of over 31,000 customers ($4 million), lower bad debt expense ($6 million), rate increases ($9 million) and reduced other expenses ($5 million). Decreased expense related to energy efficiency programs ($4 million) and decreased expense related to lower gross receipts taxes ($11 million) were offset by a corresponding reduction in the related revenues.

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 2011 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, 2011 and 2012 (in millions, except throughput and customer data):



	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2012			2011		2012
Revenues	$	584		$	389		$	1,876	$	1,222
Expenses:
Natural gas	582			382			1,838		1,193
Operation and maintenance	10			12			31		34
Depreciation and amortization	1			2			3		4
Taxes other than income taxes	1			—			1		1
Goodwill impairment	—			252			—		252
Total expenses	594			648			1,873		1,484
Operating Income (Loss)	$	(10	)	$	(259	)	$	3	$	(262	)
Goodwill impairment	—			252			—		252
Operating Income (Loss), excluding goodwill impairment	$	(10	)	$	(7	)	$	3	$	(10	)

Throughput (in Bcf)	126			129			407		417

Number of customers at end of period	12,650			14,816			12,650		14,816

Three months ended September 30, 2012 compared to three months ended September 30, 2011

Our Competitive Natural Gas Sales and Services business segment reported an operating loss, excluding the goodwill impairment discussed below, of $7 million for the three months ended September 30, 2012 compared to an operating loss of $10 million for the three months ended September 30, 2011. The increase in operating income of $3 million is due to increased operating margins of $13 million created primarily by reductions in fixed transportation and storage costs. In addition, for the three months ended September 30, 2012, there was no write-down of natural gas inventory to the lower of cost or market as compared to a $6 million write-down for the three months ended September 30, 2011. Offsetting these increases in operating income are higher operation and maintenance expenses of $2 million. The three months ended September 30, 2012 also included a charge of $9 million resulting from mark-to-market accounting for derivatives associated with certain forward natural gas purchases and sales used to lock in economic margins compared to a gain of $5 million for the same period of 2011.

Nine months ended September 30, 2012 compared to nine months ended September 30, 2011

Our Competitive Natural Gas Sales and Services business segment reported an operating loss, excluding the goodwill impairment discussed below, of $10 million for the nine months ended September 30, 2012 compared to operating income of $3 million for the nine months ended September 30, 2011. The decrease in operating income of $13 million is primarily due to a $22 million negative impact of mark-to-market accounting for derivatives associated with certain forward natural gas purchases and sales used to lock in economic margins. The first nine months of 2012 included mark-to-market charges of $14 million compared to an $8 million benefit for the same period of 2011. Higher operation and maintenance expenses of $3 million were partially offset by a $2 million reduction in the write-down of natural gas inventory to the lower of cost or market as compared to the prior year period. An $11 million improvement was seen in operating margins primarily as a result of reductions in fixed transportation and storage costs.

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Goodwill Impairment

The third quarter of 2012 includes a non-cash goodwill impairment charge of $252 million for our Competitive Natural Gas Sales and Services business segment. The adverse wholesale market conditions facing our energy services business, specifically the prospects for continued low geographic and seasonal price differentials for natural gas, led to a reduction in our estimate of the fair value of goodwill associated with this reporting unit.

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 2011 Form 10-K.

The following table provides summary data of our Interstate Pipelines business segment for the three and nine months ended September 30, 2011 and 2012 (in millions, except throughput data):



	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2012		2011		2012
Revenues	$	135	$	122	$	424	$	374
Expenses:
Natural gas	15		15		54		36
Operation and maintenance	39		37		109		111
Depreciation and amortization	13		15		40		43
Taxes other than income taxes	8		7		25		24
Total expenses	75		74		228		214
Operating Income	$	60	$	48	$	196	$	160

Equity in earnings of unconsolidated affiliates	$	6	$	8	$	15	$	20

Transportation throughput (in Bcf)	356		306		1,208		1,030

Three months ended September 30, 2012 compared to three months ended September 30, 2011

Our Interstate Pipeline business segment reported operating income of $48 million for the three months ended September 30, 2012 compared to $60 million for the three months ended September 30, 2011. Operating income decreased $12 million primarily due to lower margins from seasonal and market-sensitive transportation contracts ($4 million) and ancillary services ($4 million), and a backhaul contract that expired in 2011 ($1 million) and the associated reduction in compressor efficiency ($2 million) on the Carthage to Perryville pipeline due to lower volumes, and lower off-system transportation revenues ($2 million). Operating income benefited from lower operations and maintenance expenses ($2 million) and taxes other than income ($1 million), partially offset by increased depreciation and amortization due to asset additions ($2 million).

Equity Earnings. In addition, this business segment recorded equity income of $6 million and $8 million for the three months ended September 30, 2011 and 2012, respectively, from its 50% interest in the Southeast Supply Header (SESH), a jointly-owned pipeline. These higher earnings primarily resulted from restructuring and extending a long-term agreement with an anchor shipper at the end of 2011. These amounts are included in Equity in Earnings of Unconsolidated Affiliates under the Other Income (Expense) caption.

Nine months ended September 30, 2012 compared to nine months ended September 30, 2011

Our Interstate Pipeline business segment reported operating income of $160 million for the nine months ended September 30, 2012 compared to $196 million for the nine months ended September 30, 2011. Operating income decreased $36 million due to lower margins of $32 million primarily due to a backhaul contract that expired in 2011 ($12 million), as well as the associated reduction in compressor efficiency ($8 million) on the Carthage to Perryville pipeline due to lower volumes, lower off-system transportation revenues ($6 million), lower seasonal and market-sensitive transportation contracts ($7 million) and ancillary services ($4 million). These margin decreases were partially offset by the effects of the restructured 10-year agreement with our natural gas distribution affiliate ($5 million). Operating income also decreased as a result of higher operations and maintenance expenses ($2 million) due to a non-recurring 2011 insurance settlement related to a damaged compressor station and higher

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depreciation and amortization expenses ($3 million) due to asset additions, partially offset by lower taxes other than income ($1 million).

Equity Earnings. In addition, this business segment recorded equity income of $15 million and $20 million for the nine months ended September 30, 2011 and 2012, respectively, from its 50% interest in SESH. These higher earnings primarily resulted from restructuring and extending a long-term agreement with an anchor shipper at the end of 2011. 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 2011 Form 10-K.

The following table provides summary data of our Field Services business segment for the three and nine months ended September 30, 2011 and 2012 (in millions, except throughput data):



	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2012		2011		2012
Revenues	$	117	$	141	$	305	$	350
Expenses:
Natural gas	19		42		52		75
Operation and maintenance	25		29		83		82
Depreciation and amortization	9		13		28		35
Taxes other than income taxes	3		2		6		5
Total expenses	56		86		169		197
Operating Income	$	61	$	55	$	136	$	153

Equity in earnings of unconsolidated affiliates	$	2	$	—	$	7	$	5

Gathering throughput (in Bcf)	206		221		586		691

Three months ended September 30, 2012 compared to three months ended September 30, 2011

Our Field Services business segment reported operating income of $55 million for the three months ended September 30, 2012 compared to $61 million for the three months ended September 30, 2011. Operating income decreased $6 million primarily from reduced margins due to lower commodity prices ($8 million) from sales of retained natural gas and lower core gathering margins ($6 million) driven by the timing of revenues from throughput guarantees. Operating income benefited from the May 2012 acquisition of the Amoruso gathering system ($5 million) and the acquisition of an additional 50% interest in Waskom and other assets from a third party in July 2012 ($2 million). Operating income also increased ($1 million) due to the classification of earnings from the 50% partnership interest in Waskom which we already owned as operating income for August and September of 2012 instead of equity earnings as reported for prior periods.

Equity Earnings. In addition, this business segment recorded equity income of $2 million and $-0- in the three months ended September 30, 2011 and 2012, respectively, from its 50% general partnership interest in Waskom. These amounts are included in Equity in Earnings under the Other Income (Expense) caption. As discussed above, beginning on August 1, 2012, financial results for Waskom are included in operating income. Equity income from Waskom for the month of July 2012 was less than $1 million.

Nine months ended September 30, 2012 compared to nine months ended September 30, 2011

Our Field Services business segment reported operating income of $153 million for the nine months ended September 30, 2012 compared to $136 million for the nine months ended September 30, 2011. Operating income increased $17 million primarily from increased margins due to gathering projects in the Haynesville and Fayetteville shales and growth in core gathering services, including revenues from throughput guarantees ($30 million), partially offset by lower commodity prices ($24 million) from sales of retained natural gas. Operating income benefited from the May 2012 acquisition of the Amoruso gathering system ($6 million) and the acquisition of an additional 50% interest in Waskom and other assets from a third party in July 2012 ($2 million). Operating

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income also increased ($1 million) due to the classification of earnings from the 50% partnership interest in Waskom which we already owned as operating income for August and September of 2012 instead of equity earnings as reported for prior periods. Higher depreciation expense ($5 million) due to new assets placed in service was offset by lower operation and maintenance expenses ($6 million) and lower taxes other than income ($1 million).

Equity Earnings. In addition, this business segment recorded equity income of $7 million and $5 million in the nine months ended September 30, 2011 and 2012, 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. As discussed above, beginning on August 1, 2012, financial results for Waskom are included in operating income.

Other Operations

The following table shows the operating income (loss) of our Other Operations business segment for the three and nine months ended September 30, 2011 and 2012 (in millions):



	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2012			2011		2012
Revenues	$	3		$	3		$	9	$	9
Expenses	(1		)	6			3		7
Operating Income (Loss)	$	4		$	(3	)	$	6	$	2

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 2011 Form 10-K, “Risk Factors” in Item 1A of Part I of our 2011 Form 10-K, 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, 2011 and 2012:



	Nine Months Ended September 30,
	2011			2012
	(in millions)
Cash provided by (used in):
Operating activities	$	1,449		$	1,379
Investing activities	(848		)	(1,209		)
Financing activities	(697		)	332

Cash Provided by Operating Activities

Net cash provided by operating activities in the first nine months of 2012 decreased $70 million compared to the same period in 2011 due primarily to increased net tax payments ($250 million) and decreased cash provided by fuel cost recovery ($20 million), which were partially offset by increased cash related to gas storage ($59 million), increased cash provided by net regulatory assets and liabilities ($49 million), increased cash provided by net accounts receivable/payable ($44 million) and decreased cash paid for interest ($24 million).

Cash Used in Investing Activities

Net cash used in investing activities in the first nine months of 2012 increased $361 million compared to the same period in 2011 due primarily to increased cash paid for acquisitions ($360 million) and decreased cash received from a grant from the U.S. Department of Energy ($110 million), which were partially offset by decreased capital expenditures ($142 million).

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Cash Provided by (Used in) Financing Activities

Net cash provided by financing activities in the first nine months of 2012 increased $1.029 billion compared to the same period in 2011 due to increased proceeds from long-term debt ($1.945 billion) and decreased debt issuance costs ($7 million), which were partially offset by increased payments of long-term debt ($619 million), increased payments of commercial paper ($244 million), decreased short-term borrowings ($40 million), increased cash paid for debt retirement ($11 million) and increased payments of common stock dividends ($7 million).

Future Sources and Uses of Cash

Our liquidity and capital requirements are affected primarily by our results of operations, capital expenditures, debt service requirements, tax payments and working capital needs. Substantially all of 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 relate to reliability and safety and system expansions. Our principal cash requirements for the remaining three months of 2012 include the following:


•	capital expenditures of approximately $478 million;


•	scheduled principal payments on transition and system restoration bonds of $62 million; and


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

We expect that cash on hand and anticipated cash flows from operations will be sufficient to meet our anticipated cash needs for the remaining three months of 2012.

Longer term cash requirements or discretionary financing or refinancing may result in the issuance of equity or debt securities in the capital markets, borrowing under existing credit facilities, the issuance of commercial paper 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.

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 Reliant Resources, Inc. (RRI) to our shareholders, CenterPoint Energy Resources Corp. (CERC Corp. and, together with its subsidiaries, 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 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 $77 million as of September 30, 2012. Based on market conditions in the fourth quarter of 2012 at the time the most recent annual calculation was made under the agreement, GenOn was not obligated to post any security. As a result, we currently anticipate returning to GenOn in December 2012 the approximately $28 million of aggregate collateral previously posted by GenOn under the agreement. If GenOn should fail to perform the contractual obligations, CERC could have to honor its guarantee and, in such event, any collateral provided as security may be insufficient to satisfy CERC’s obligations.

Regulatory Matters. Regulatory developments that have occurred since our 2011 Form 10-K was filed with the Securities and Exchange Commission (SEC) are discussed below. See “─ Executive Summary - CenterPoint Energy-Mississippi River Transmission, LLC Rate Filing” for regulatory developments related to MRT and “─ Executive Summary - CenterPoint Energy Gas Transmission Company, LLC Rate Settlement Proceeding” for regulatory developments related to CEGT.

CenterPoint Houston

June 2010 Rate Case. The order on rehearing issued by the Public Utility Commission of Texas (Texas Utility Commission) in connection with CenterPoint Houston's 2010 rate case was appealed to the Texas courts by various parties and a trial is scheduled for December 2012.

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Other. In May 2012, CenterPoint Houston filed an application, subsequently modified consistent with the Texas Utility Commission’s preliminary order, requesting approval to recover a total of approximately $47.5 million in 2013 consisting of: (1) estimated 2013 energy efficiency program costs of $42.9 million; (2) a credit of $1.8 million related to the over-recovery of 2011 program costs; (3) a performance incentive for 2011 program achievements of $6.3 million and (4) certain rate case expenses. In October 2012, the Texas Utility Commission approved a settlement agreement filed by the parties to recover a total of $46.2 million. The $1.3 million reduction was attributable to settlement spending from CenterPoint Houston’s 2006 rate settlement included in the 2011 performance incentive calculation. The settlement preserves the right for CenterPoint Houston to appeal the reduction in its requested performance bonus amount. The rates will take effect with the commencement of CenterPoint Houston’s January 2013 billing month.

Gas Operations

Beaumont/East Texas Rate Case. In July 2012, the natural gas distribution business of CERC (Gas Operations) filed a general rate case with the Railroad Commission of Texas (Railroad Commission) and certain municipalities requesting an increase of approximately $8.6 million based on a proposed rate of return of 9.09%, a return on equity (ROE) of 11.00%, and a capital structure of 42% debt to 58% equity. Since our last rate case in this jurisdiction over six years ago, Gas Operations has invested approximately $62 million in capital expenditures, while consumption for the average residential customer has decreased and the average number of customers has declined. Rates went into effect in August 2012 for 24 cities. All other cities suspended the rates for up to 90 days or denied any increase outright. The Railroad Commission suspended the rates for the environs and for the cities that have given up original jurisdiction for up to 150 days. The hearing on the merits is scheduled to begin in December 2012. New base rates for the remaining cities are expected to become effective in the first quarter of 2013.

Mississippi Regulatory Rate Adjustment (RRA). In May 2012, Gas Operations and the Mississippi Public Utility Staff filed a joint stipulation for the revised RRA and initial Weather Normalization Adjustment which the Mississippi Public Service Commission (MPSC) approved in May 2012. In June 2012, Gas Operations requested an annual increase of approximately $2.2 million under the newly revised RRA based on calendar year 2011. New rates reflecting an increase of $1.744 million, as approved by the MPSC, took effect in the third quarter of 2012.

Minnesota Conservation Improvement Program (CIP). In May 2012, Gas Operations filed a request with the Minnesota Public Utilities Commission for a $4.6 million CIP incentive. A decision is expected by the end of 2012.

Oklahoma Performance Based Rate Change (PBRC). In March 2012, Gas Operations filed a PBRC with the Oklahoma Corporation Commission (OCC) showing that it had earnings for 2011 above the prescribed threshold and would refund approximately $1.86 million to customers beginning in July 2012. The OCC issued a final order approving the refund on June 6, 2012.

Houston and South Texas Gas Reliability Infrastructure Programs (GRIP). Gas Operations’ Houston and South Texas Divisions each submitted annual GRIP filings on March 30, 2012. For the Houston division, this filing is to recover costs related to $51.2 million in incremental capital expenditures that were incurred in 2011. The increase in revenue requirements for this filing period is $9.4 million annually based on an authorized rate of return of 8.65%. For the South Texas division, this filing is to recover costs related to $14.5 million in incremental capital expenditures that were incurred since the last rate case. The increase in revenue requirements for this filing period is $2.4 million annually based on an authorized rate of return of 8.75%. In June 2012, the Railroad Commission approved both GRIP applications as filed and the new rates were implemented in July 2012 in the applicable cities, with the exception of Houston and Pasadena. Lower GRIP rates were implemented in July 2012 for these two cities, subject to a pending appeal to the Railroad Commission. In September 2012, the Railroad Commission voted to authorize billing of the original filed GRIP rates in both cities.

City of Houston Gas Utility Rate Inquiry. In July 2012, the City Council of Houston adopted an ordinance to initiate a formal inquiry regarding the reasonableness of the rates charged by Gas Operations in its Houston service territory. A formal schedule for the inquiry has not been established at this time.

Debt Financing Transactions. In January 2012, CenterPoint Energy Transition Bond Company IV, LLC issued $1.695 billion of transition bonds in three tranches with interest rates ranging from 0.9012% to 3.0282% and final maturity dates ranging from April 15, 2018 to October 15, 2025. Through the issuance of these transition bonds, CenterPoint Houston recovered the additional true-up balance of $1.695 billion, less approximately $10.4 million of offering expenses. The transition bonds will be repaid over time through a charge imposed on customers in CenterPoint Houston’s service territory.

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In February 2012, we purchased $275 million aggregate principal amount of pollution control bonds issued on our behalf at 100% of their principal amount plus accrued interest pursuant to the mandatory tender provisions of the bonds. The purchased pollution control bonds will remain outstanding and may be remarketed. Prior to the purchase, the pollution control bonds had fixed interest rates ranging from 5.15% to 5.95%. The purchases reduced temporary investments and leverage while providing us with the flexibility to finance future capital needs in the tax-exempt market through the remarketing of these bonds. Additionally, in March 2012, we redeemed $100 million aggregate principal amount of pollution control bonds issued on our behalf at 100% of their principal amount plus accrued interest pursuant to the optional redemption provisions of the bonds. The redeemed pollution control bonds had a fixed interest rate of 5.25%.

In August 2012, CenterPoint Houston issued $300 million of 2.25% general mortgage bonds due 2022 and $500 million of 3.55% general mortgage bonds due 2042. The net proceeds from the sale of the bonds were used to fund a portion of the redemption of the general mortgage bonds discussed below.

Credit Facilities. As of October 16, 2012, we had the following revolving credit facilities (in millions):

Date Executed

Company

Size of

Facility

Amount

Utilized at

October 16, 2012 ⁽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

—

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, 2012.


(2)	Represents outstanding letters of credit.

Our $1.2 billion credit facility can be drawn at the London Interbank Offered Rate (LIBOR) plus 150 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 125 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 CenterPoint Houston’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.

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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, 2012, we and CERC Corp. had no outstanding commercial paper.

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 16, 2012, we had external temporary investments of $585 million.

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 16, 2012, 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

Positive

BBB

Stable

BBB

Stable

CenterPoint Houston Senior

Secured Debt

Positive

A-

Stable

CERC Corp. Senior Unsecured

Debt

Baa2

Stable

BBB+

Stable

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, 2012, 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

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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, 2012, the amount posted as collateral aggregated approximately $25 million. 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, 2012, unsecured credit limits extended to CES by counterparties aggregate $353 million and $7 million of 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 $175 million as of September 30, 2012. 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, 2012. 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, 2012, 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, 2012, deferred taxes of approximately $401 million would have been payable in 2012.

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, 2012, 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;

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•	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;


•	the ability of GenOn and its subsidiaries to satisfy their obligations in respect of GenOn’s indemnity obligations to us and our subsidiaries;


•	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;


•	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 2011 Form 10-K.

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, 2012, the recorded fair value of our non-trading energy derivatives was a net asset of $19 million (before collateral), all of which is related to our Competitive Natural Gas Sales and Services business segment. A decrease of 10% in the market prices of energy commodities from their September 30, 2012 levels would have decreased the fair value of our non-trading energy derivatives net asset by $3 million.

The above analysis of the non-trading energy derivatives utilized for commodity price risk management purposes does not include the favorable impact that the same hypothetical price movement would have on our 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

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of the portfolio of non-trading energy derivatives held for hedging purposes associated with the hypothetical changes in commodity prices referenced above is expected to be substantially offset by a favorable impact on the underlying hedged physical transactions.

Interest Rate Risk

As of September 30, 2012, 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, 2011 and September 30, 2012, we had outstanding fixed-rate debt (excluding indexed debt securities) aggregating $8.7 billion and $9.7 billion, respectively, in carrying amount and having a fair value of $9.8 billion and $10.9 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 $222 million if interest rates were to decline by 10% from their levels at September 30, 2012. 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 $136 million at September 30, 2012 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 $23 million if interest rates were to decline by 10% from levels at September 30, 2012. Changes in the fair value of the derivative component, a $273 million recorded liability at September 30, 2012, 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, 2012 levels, the fair value of the derivative component liability would increase by approximately $5 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, 2012 aggregate market value of these shares would result in a net loss of approximately $13 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, 2012 to provide assurance that information required to be disclosed in our reports filed or submitted under the Securities Exchange Act of 1934, as amended, 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, 2012 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

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PART II. OTHER INFORMATION


Item 1.	LEGAL PROCEEDINGS

For a description of certain legal and regulatory proceedings affecting CenterPoint Energy, please read Note 12(c) to our Interim Condensed Financial Statements and “Management’s Discussion and Analysis of Financial Condition and Results of Operations ─ Liquidity and Capital Resources ─ Future Sources and Uses of Cash ─ Regulatory Matters”, 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 2011 Form 10-K.


Item 1A.	RISK FACTORS

There have been no material changes from the risk factors disclosed in our 2011 Form 10-K.


Item 5.	OTHER INFORMATION

The ratio of earnings to fixed charges for the nine months ended September 30, 2011 and 2012 was 3.24 and 2.21, respectively. We do not believe that the ratios for these nine-month periods are necessarily indicative of the ratios for the twelve-month periods due to the seasonal nature of our business. The ratios were calculated pursuant to applicable rules of the Securities and Exchange Commission.

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Item 6.	EXHIBITS

The following exhibits are filed herewith:

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

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

Pursuant to Item 601(b)(4)(iii)(A) of Regulation S-K, CenterPoint Energy has not filed as exhibits to this Form 10-Q certain long-term debt instruments, including indentures, under which the total amount of securities authorized does not exceed 10% of the total assets of CenterPoint Energy and its subsidiaries on a consolidated basis. CenterPoint Energy hereby agrees to furnish a copy of any such instrument to the SEC upon request.



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)
3.3	Statement of Resolutions Deleting Shares Designated Series A Preferred Stock of CenterPoint Energy	CenterPoint Energy’s Form 10-K for the year ended December 31, 2011	1-31447	3(c)
4.1	Form of CenterPoint Energy Stock Certificate	CenterPoint Energy’s Registration Statement on Form S-4	3-69502	4.1
4.2	$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
4.3	$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
4.4	$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 7, 2012

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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)
3.3	Statement of Resolutions Deleting Shares Designated Series A Preferred Stock of CenterPoint Energy	CenterPoint Energy’s Form 10-K for the year ended December 31, 2011	1-31447	3(c)
4.1	Form of CenterPoint Energy Stock Certificate	CenterPoint Energy’s Registration Statement on Form S-4	3-69502	4.1
4.2	$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
4.3	$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
4.4	$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