Centerpoint Energy Resources 10-Q 2012 Q3 Quarterly report

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

Commission File Number 1-13265

______________________

CENTERPOINT ENERGY RESOURCES CORP.

(Exact name of registrant as specified in its charter)

Delaware	76-0511406
(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)

______________________

CenterPoint Energy Resources Corp. meets the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and is therefore filing this Form 10-Q with the reduced disclosure format.

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 o	Accelerated filer o	Non-accelerated filer þ	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 by Rule 12b-2 of the Exchange Act).Yes o  No þ

As of October 16, 2012, all 1,000 shares of CenterPoint Energy Resources Corp. common stock were held by Utility Holding, LLC, a wholly owned subsidiary of CenterPoint Energy, Inc.

CENTERPOINT ENERGY RESOURCES CORP.

QUARTERLY REPORT ON FORM 10-Q

FOR THE QUARTER ENDED SEPTEMBER 30, 2012

TABLE OF CONTENTS

PART I.	FINANCIAL INFORMATION
		Page
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 Narrative Analysis of Results of Operations	19
Item 4.	Controls and Procedures	30
PART II.	OTHER INFORMATION
Item 1.	Legal Proceedings	30
Item 1A.	Risk Factors	30
Item 5.	Other Information	30
Item 6.	Exhibits	31

i

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;

• 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;

ii

• 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 outcome of litigation brought by or against us;

• our ability to control costs;

• the investment performance of CenterPoint Energy, Inc.’s 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

PART I. FINANCIAL INFORMATION

Item 1.  FINANCIAL STATEMENTS

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES

(AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.)

CONDENSED STATEMENTS OF CONSOLIDATED INCOME

(Millions of Dollars)

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2012			2011			2012
Revenues	$	1,171		$	954		$	4,494		$	3,350
Expenses:
Natural gas	735			520			2,989			1,898
Operation and maintenance	227			231			704			698
Depreciation and amortization	65			72			196			211
Taxes other than income taxes	33			31			120			108
Goodwill impairment	—			252			—			252
Total	1,060			1,106			4,009			3,167
Operating Income (Loss)	111			(152		)	485			183
Other Income (Expense):
Interest and other finance charges	(48		)	(44		)	(142		)	(133		)
Equity in earnings of unconsolidated affiliates	8			8			22			25
Step acquisition gain	—			136			—			136
Other, net	(1		)	—			1			—
Total	(41		)	100			(119		)	28
Income (Loss) Before Income Taxes	70			(52		)	366			211
Income tax expense	27			75			143			178
Net Income (Loss)	$	43		$	(127	)	$	223		$	33

See Notes to the Interim Condensed Consolidated Financial Statements

1

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES

(AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.)

CONDENSED STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME

(Millions of Dollars)

(Unaudited)

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2011		2012			2011		2012
Net income (loss)	$	43	$	(127	)	$	223	$	33
Other comprehensive income, net of tax:
Adjustment to pension and other postretirement plans (net of tax)	—		—			—		—
Other comprehensive income	—		—			—		—
Comprehensive income (loss)	$	43	$	(127	)	$	223	$	33

See Notes to the Interim Condensed Consolidated Financial Statements

2

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES

(AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.)

CONDENSED CONSOLIDATED BALANCE SHEETS

(Millions of Dollars)

(Unaudited)

ASSETS

	December 31, 2011		September 30, 2012
Current Assets:
Cash and cash equivalents	$	1	$	7
Accounts receivable, net	542		389
Accrued unbilled revenue	253		78
Accounts and notes receivable — affiliated companies	17		15
Materials and supplies	86		91
Inventory	187		170
Non-trading derivative assets	87		41
Taxes receivable	1		2
Deferred income tax assets	8		7
Prepaid expenses and other current assets	122		168
Total current assets	1,304		968
Property, Plant and Equipment:
Property, plant and equipment	8,519		9,420
Less accumulated depreciation and amortization	1,489		1,657
Property, plant and equipment, net	7,030		7,763
Other Assets:
Goodwill	1,696		1,468
Non-trading derivative assets	20		10
Investment in unconsolidated affiliates	472		408
Other	165		185
Total other assets	2,353		2,071
Total Assets	$	10,687	$	10,802

See Notes to the Interim Condensed Consolidated Financial Statements

3

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES

(AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.)

CONDENSED CONSOLIDATED BALANCE SHEETS

(Millions of Dollars)

(Unaudited)

LIABILITIES AND STOCKHOLDER'S EQUITY

	December 31, 2011			September 30, 2012
Current Liabilities:
Short-term borrowings	$	62		$	53
Current portion of long-term debt	—			365
Accounts payable	427			272
Accounts and notes payable — affiliated companies	419			725
Taxes accrued	82			96
Interest accrued	48			57
Customer deposits	74			77
Non-trading derivative liabilities	46			20
Other	157			142
Total current liabilities	1,315			1,807
Other Liabilities:
Accumulated deferred income taxes, net	1,420			1,621
Non-trading derivative liabilities	6			6
Benefit obligations	108			108
Regulatory liabilities	597			622
Other	232			241
Total other liabilities	2,363			2,598
Long-Term Debt	2,919			2,274
Commitments and Contingencies (Note 10)
Stockholder’s Equity:
Common stock	—			—
Paid-in capital	2,416			2,416
Retained earnings	1,681			1,714
Accumulated other comprehensive loss	(7		)	(7		)
Total stockholder’s equity	4,090			4,123
Total Liabilities And Stockholder’s Equity	$	10,687		$	10,802

See Notes to the Interim Condensed Consolidated Financial Statements

4

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES

(AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.)

CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS

(Millions of Dollars)

(Unaudited)

	Nine Months Ended September 30,
	2011			2012
Cash Flows from Operating Activities:
Net income	$	223		$	33
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	196			211
Amortization of deferred financing costs	10			10
Deferred income taxes	102			166
Goodwill impairment	—			252
Step acquisition gain	—			(136		)
Write-down of natural gas inventory	7			4
Equity in earnings of unconsolidated affiliates, net of distributions	3			(6		)
Changes in other assets and liabilities:
Accounts receivable and unbilled revenues, net	356			349
Accounts receivable/payable, affiliates	(12		)	(2		)
Inventory	(46		)	8
Taxes receivable	61			(1		)
Accounts payable	(218		)	(164		)
Fuel cost recovery	(52		)	(72		)
Interest and taxes accrued	22			22
Non-trading derivatives, net	(8		)	16
Margin deposits, net	61			49
Other current assets	18			(16		)
Other current liabilities	(33		)	(16		)
Other assets	5			2
Other liabilities	3			16
Other, net	2			4
Net cash provided by operating activities	700			729
Cash Flows from Investing Activities:
Capital expenditures, net of acquisitions	(483		)	(368		)
Acquisitions, net of cash acquired	—			(360		)
Distributions from (investment in) unconsolidated affiliates	(9		)	6
Other, net	10			(17		)
Net cash used in investing activities	(482		)	(739		)
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			—
Payments of long-term debt	(606		)	—
Cash paid for debt exchange	(58		)	—
Debt issuance costs	(14		)	—
Increase (decrease) in notes payable to affiliates	(81		)	310
Net cash provided by (used in) financing activities	(219		)	16
Net Increase (Decrease) in Cash and Cash Equivalents	(1		)	6
Cash and Cash Equivalents at Beginning of Period	1			1
Cash and Cash Equivalents at End of Period	$	—		$	7
Supplemental Disclosure of Cash Flow Information:
Cash Payments:
Interest, net of capitalized interest	$	123		$	113
Income taxes (refunds), net	(18		)	3
Non-cash transactions:
Accounts payable related to capital expenditures	$	61		$	55

See Notes to the Interim Condensed Consolidated Financial Statements

5

CENTERPOINT ENERGY RESOURCES CORP. 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 Resources Corp. (CERC Corp.) are the condensed consolidated interim financial statements and notes (Interim Condensed Financial Statements) of CenterPoint Energy Resources Corp. and its subsidiaries (collectively, CERC).  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 CERC Corp. for the year ended December 31, 2011.

Background. CERC 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.

CERC Corp. is an indirect wholly owned subsidiary of CenterPoint Energy, Inc. (CenterPoint Energy), a public utility holding company.

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.

CERC’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 CERC’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 CERC’s reportable business segments, see Note 12.

(2)       New Accounting Pronouncements

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

(3)       Employee Benefit Plans

CERC’s employees participate in CenterPoint Energy’s postretirement benefit plan. CERC’s net periodic cost includes the following components relating to postretirement benefits:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2011			2012			2011			2012
	(in millions)
Service Cost	—			1			—			1
Interest cost on accumulated benefit obligation	1			1			4			4
Expected return on plan assets	(1		)	(1		)	(1		)	(1		)
Amortization of prior service cost	1			1			2			2
Amortization of loss	1			—			1			1
Net periodic cost	$	2		$	2		$	6		$	7

CERC expects to contribute approximately $9 million to its postretirement benefit plan in 2012, of which $6 million has been contributed as of September 30, 2012.

6

(4)       Derivative Instruments

CERC is exposed to various market risks. These risks arise from transactions entered into in the normal course of business.  CERC 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 CERC’s Consolidated Balance Sheets at their fair value unless CERC elects the normal purchase and sales exemption for qualified physical transactions. A derivative may be designated as a normal purchase or normal 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 CERC’s marketing, risk management services and hedging activities. The committee’s duties are to establish CERC’s commodity risk policies, allocate board-approved commercial risk limits, approve use of new products and commodities, monitor positions and ensure compliance with CERC’s risk management policies and procedures and limits established by CenterPoint Energy’s board of directors.

CERC’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. CERC 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, CERC 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, CERC 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, CERC 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, CERC 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. CERC 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. CERC 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, CERC recognized losses of $-0- and $6 million, respectively, related to these swaps. During the three and nine months ended September 30, 2012, CERC 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.

7

(b) Derivative Fair Values and Income Statement Impacts

The following tables present information about CERC’s derivative instruments and hedging activities. The first two tables provide a balance sheet overview of CERC’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
Total		$	123	$	124

________________

(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 CERC’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
Total		$	67	$	48

________________

(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 CERC’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.

For CERC’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

8

expense for financial natural gas derivatives and other physical natural gas derivatives.

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
Total		$	(3	)	$	3

 ________________

(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		)
Total		$	(38	)	$	(22	)

 ________________

(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

CERC enters into financial derivative contracts containing material adverse change provisions.  These provisions could require CERC to post additional collateral if the Standard & Poor’s Ratings Services or Moody’s Investors Service, Inc. credit ratings of CERC 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.

(5)       Fair Value Measurements

Assets and liabilities that are recorded at fair value in the Condensed Consolidated Balance Sheets are categorized based upon the level of judgment associated with the inputs used to measure their value. Hierarchical levels, as defined below and directly related to the amount of subjectivity associated with the inputs to fair valuations of these assets and liabilities, are as follows:

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

Level 2: Inputs, other than quoted prices included in Level 1, are observable for the asset or liability, either directly or indirectly. Level 2 inputs include quoted prices for similar instruments in active markets, and inputs other than quoted prices that are observable for the asset or liability. Fair value assets and liabilities that are generally included in this category are derivatives with fair values based on inputs from actively quoted markets.  A market approach is utilized to value CERC’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 CERC’s judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. CERC develops these inputs based on the best information available, including CERC’s own data. A market approach is utilized to value CERC’s Level 3 assets or liabilities. Currently, CERC’s Level 3 assets and liabilities are comprised of physical forward contracts and options. Level 3 physical forward contracts are valued using a discounted

9

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.  CERC’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, CERC’s long forwards lose value whereas its short forwards gain in value.  If volatility decreases, CERC’s long options lose value whereas its short options gain in value.

CERC 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. CERC 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 CERC’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 CERC 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
	(in millions)
Assets
Corporate equities	$	1	$	—	$	—	$	—		$	1
Investments, including money market funds (2)	11		—		—		—			11
Natural gas derivatives	1		112		10		(16		)	107
Total assets	$	13	$	112	$	10	$	(16	)	$	119
Liabilities
Natural gas derivatives	$	19	$	101	$	4	$	(72	)	$	52
Total liabilities	$	19	$	101	$	4	$	(72	)	$	52

________________

(1) Amounts represent the impact of legally enforceable master netting agreements that allow CERC 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.

	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
	(in millions)
Assets
Corporate equities	$	1	$	—	$	—	$	—		$	1
Investments, including money market funds (2)	11		—		—		—			11
Natural gas derivatives	5		49		13		(16		)	51
Total assets	$	17	$	49	$	13	$	(16	)	$	63
Liabilities
Natural gas derivatives	$	8	$	28	$	12	$	(22	)	$	26
Total liabilities	$	8	$	28	$	12	$	(22	)	$	26

________________

(1) Amounts represent the impact of legally enforceable master netting agreements that allow CERC 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.

10

The following table presents additional information about assets or liabilities, including derivatives that are measured at fair value on a recurring basis for which CERC 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 gains (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) CERC did not have Level 3 unrealized gain (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, CERC did not have Level 3 purchases, sales or significant transfers into Level 3.

Estimated Fair Value of Financial Instruments

The fair values of cash and cash equivalents and short-term borrowings are estimated to be approximately equivalent to carrying amounts and have been excluded from the table below. Non-trading derivative assets and liabilities 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	$	2,919	$	3,272	$	2,639	$	3,075

(6)       Acquisition

On July 31, 2012, CERC 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 CERC recorded a pre-tax gain of approximately $136 million on July 31, 2012, which is the result of remeasuring CERC's original 50% interest in Waskom to fair value. As a result of the purchase, CERC 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.

11

(7)       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

CERC 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.

CERC 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. CERC also determined that no impairment charge was required for any other reportable segment.

CERC 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 cash flows 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 CERC’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.

(8)       Related Party Transactions

CERC participates in a “money pool” through which it can borrow or invest on a short-term basis. Funding needs are aggregated and external borrowing or investing is based on the net cash position. The net funding requirements of the money pool are expected to be met with borrowings under CenterPoint Energy’s revolving credit facility or the sale of CenterPoint Energy’s commercial paper. CERC had money pool borrowings of $383 million and $692 million at December 31, 2011 and September 30, 2012, respectively, which are included in accounts and notes payable —affiliated companies in the Condensed Consolidated Balance Sheets.  

CERC had net interest expense related to affiliate borrowings of less than $1 million for both the three and nine months ended September 30, 2011, and net interest expense of $1 million and $3 million, respectively, for the three and nine months ended September 30, 2012.

CenterPoint Energy provides some corporate services to CERC. The costs of services have been charged directly to CERC using methods that management believes are reasonable. These methods include negotiated usage rates, dedicated asset assignment and proportionate corporate formulas based on operating expenses, assets, gross margin, employees and a composite of assets, gross margin and employees. These charges are not necessarily indicative of what would have been incurred had CERC not been an affiliate of CenterPoint Energy. Amounts charged to CERC for these services were $38 million and $37 million for the three months ended

12

September 30, 2011 and 2012, respectively, and $119 million and $118 million for the nine months ended September 30, 2011 and 2012, respectively, and are included primarily in operation and maintenance expenses.

(9)           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

Revolving Credit Facility.   As of December 31, 2011 and September 30, 2012, CERC had the following revolving credit facility and utilization of such facility (in millions):

		December 31, 2011						September 30, 2012
Size of Facility		Loans		Letters of Credit		Commercial Paper		Loans		Letters of Credit		Commercial Paper
$	950	$	—	$	—	$	285	$	—	$	—	$	—

CERC Corp.’s $950 million credit facility, which is scheduled to terminate September 9, 2016, can be drawn at the London Interbank Offered Rate 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 its total capitalization.

(10)           Commitments and Contingencies

(a) Natural Gas Supply Commitments

Natural gas supply commitments include natural gas contracts related to CERC’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 CERC’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), a subsidiary of CERC Corp., 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 Energy Houston Electric, LLC (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

13

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. 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 Federal Energy Regulatory Commission 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, and in October 2012, the plaintiffs filed a 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 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 does not expect the ultimate outcome of the lawsuits to have a material impact on its financial condition, results of operations or cash flows.

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

14

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 does not expect the ultimate outcome of these investigations will have a material adverse impact on its financial condition, results of operations or cash flows.

Asbestos.  Some facilities owned by CERC’s predecessors contain or have contained asbestos insulation and other asbestos-containing materials. CERC or its predecessor companies 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 CERC, but most existing claims relate to facilities previously owned by CERC’s subsidiaries. CERC anticipates that additional claims like those received may be asserted in the future.  Although their ultimate outcome cannot be predicted at this time, CERC 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 its financial condition, results of operations or cash flows.

Other Environmental.  From time to time CERC identifies the presence of environmental contaminants on property where it conducts or has conducted operations. Other such sites involving contaminants may be identified in the future.  CERC has and expects to continue to remediate identified sites consistent with its legal obligations. From time to time CERC 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, CERC 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, CERC does not expect, based on its experience to date, these matters, either individually or in the aggregate, to have a material adverse effect on its financial condition, results of operations or cash flows.

Other Proceedings

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

(f) 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, collateral provided as security may be insufficient to satisfy CERC’s obligations.

(11)           Income Taxes

The effective tax rate for the three and nine months ended September 30, 2012 was (144)% and 84%, respectively, compared to 38% and 39%, respectively, for the three and nine months ended September 30, 2011. The change 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.

15

The following table summarizes CERC’s unrecognized tax benefits at December 31, 2011 and September 30, 2012:

	December 31, 2011			September 30,  2012
	(in millions)
Unrecognized tax benefits (expense)	$	8		$	(11	)
Portion of unrecognized tax benefits that, if recognized, would reduce the effective income tax rate	6			6
Interest accrued on unrecognized tax benefits	(4		)	(7		)

CERC 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 CERC.

CenterPoint Energy’s settlement with the Internal Revenue Service (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.

(12)           Reportable Business Segments

Because CERC is an indirect wholly owned subsidiary of CenterPoint Energy, CERC’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. CERC uses operating income as the measure of profit or loss for its business segments.

CERC’s reportable business segments include the following: Natural Gas Distribution, Competitive Natural Gas Sales and Services, Interstate Pipelines, Field Services and Other Operations.  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 CERC’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. The Other Operations business segment includes unallocated corporate costs and inter-segment eliminations.

16

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

	For the Three Months Ended September 30, 2011
	Revenues from External Customers		Inter-segment Revenues			Operating Income (Loss)
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	—		—			2
Reconciling Eliminations	—		(49		)	—
Consolidated	$	1,171	$	—		$	111
	For the Three Months Ended September 30, 2012
	Revenues from External Customers		Inter-segment Revenues			Operating Income (Loss)
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	—		—			(1		)
Reconciling Eliminations	—		(53		)	—
Consolidated	$	954	$	—		$	(152	)
	For the Nine Months Ended September 30, 2011
	Revenues from External Customers		Inter-segment Revenues			Operating Income (Loss)			Total Assets as of  December 31, 2011
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	—		—			(3		)	660
Reconciling Eliminations	—		(159		)	—			(1,459		)
Consolidated	$	4,494	$	—		$	485		$	10,687
	For the Nine Months Ended September 30, 2012
	Revenues from External Customers		Inter-segment Revenues			Operating Income (Loss)			Total Assets as of  September 30, 2012
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	—		—			(3		)	496
Reconciling Eliminations	—		(171		)	—			(1,463		)
Consolidated	$	3,350	$	—		$	183		$	10,802

17

(13)           Other Current Assets and Liabilities

Included in other current assets on the Condensed Consolidated Balance Sheets at December 31, 2011 and September 30, 2012 were $17 million and $18 million, respectively, of margin deposits and $63 million and $107 million, respectively, of under-recovered gas cost. Included in other current liabilities on the Condensed Consolidated Balance Sheets at December 31, 2011 and September 30, 2012 were $14 million and $5 million, respectively, of over-recovered gas cost.

18

Item 2.  MANAGEMENT’S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS

The following narrative analysis should be read in combination with our Interim Condensed Financial Statements contained in Item 1 of this report and our Annual Report on Form 10-K for the year ended December 31, 2011 (2011 Form 10-K).

We meet the conditions specified in General Instruction H(1)(a) and (b) to Form 10-Q and are therefore permitted to use the reduced disclosure format for wholly owned subsidiaries of reporting companies. Accordingly, we have omitted from this report the information called for by Item 2 (Management’s Discussion and Analysis of Financial Condition and Results of Operations) and Item 3 (Quantitative and Qualitative Disclosures About Market Risk) of Part I and the following Part II items of Form 10-Q: Item 2 (Unregistered Sales of Equity Securities and Use of Proceeds), Item 3 (Defaults Upon Senior Securities) and Item 4 (Submission of Matters to a Vote of Security Holders). The following discussion explains material changes in our revenue and expense items between the three and nine months ended September 30, 2011 and the three and nine months ended September 30, 2012. Reference is made to “Management's Narrative Analysis of Results of Operations” in Item 7 of our 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 our Competitive Natural Gas Sales and Services reportable segment. We also determined that no impairment charge was required for all other reportable segments.

We estimated the value of our 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 cash flows 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.

Our 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.

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 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

19

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

Our results of operations are affected by seasonal fluctuations in the demand for natural gas and price movements of energy commodities as well as natural gas basis differentials. Our results of operations are also affected by, among other things, the actions of various federal, state and local governmental authorities having jurisdiction over rates we charge, competition in our various business operations, the effectiveness of our risk management activities, debt service costs and income tax expense. For more information regarding factors that may affect the future results of operations of our business, please read “Risk Factors” in Item 1A of Part I of our 2011 Form 10-K.

The following table sets forth our consolidated results of operations for the three and nine months ended September 30, 2011 and 2012, followed by a discussion of our consolidated results of operations.

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2012			2011			2012
	(in millions)
Revenues	$	1,171		$	954		$	4,494		$	3,350
Expenses:
Natural gas	735			520			2,989			1,898
Operation and maintenance	227			231			704			698
Depreciation and amortization	65			72			196			211
Taxes other than income taxes	33			31			120			108
Goodwill impairment	—			252			—			252
Total	1,060			1,106			4,009			3,167
Operating Income (Loss)	111			(152		)	485			183
Interest and other finance charges	(48		)	(44		)	(142		)	(133		)
Equity in earnings of unconsolidated affiliates	8			8			22			25
Step acquisition gain	—			136			—			136
Other income (expense), net	(1		)	—			1			—
Income (Loss) Before Income Taxes	70			(52		)	366			211
Income tax expense	27			75			143			178
Net Income (Loss)	$	43		$	(127	)	$	223		$	33

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

We reported a net loss of $127 million for the three months ended September 30, 2012 compared to net income of $43 million for the same period in 2011.  The decrease in net income of $170 million was primarily due to a $263 million decrease in operating income from our business segments as discussed below, including a $252 million non-cash goodwill impairment charge, and a $48 million increase in income tax expense, which were partially offset by a $136 million step acquisition gain related to the acquisition of an additional 50% interest in Waskom and a $4 million decrease in interest and other finance charges.

20

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

We reported net income of $33 million for the nine months ended September 30, 2012 compared to $223 million for the same period in 2011.  The decrease in net income of $190 million was primarily due to a $302 million decrease in operating income from our business segments as discussed below, including a $252 million non-cash goodwill impairment charge, and a $35 million increase in income tax expense, which were partially offset by a $136 million step acquisition gain related to the acquisition of an additional 50% interest in Waskom, a $9 million decrease in interest and other finance charges and a $3 million increase in equity in earnings of unconsolidated affiliates.

Income Tax Expense. During the three and nine months ended September 30, 2012, our effective tax rate was (144)% and 84%, respectively, compared to 38% and 39%, respectively, for the three and nine months ended September 30, 2011. The change 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.

RESULTS OF OPERATIONS BY BUSINESS SEGMENT

The following table presents operating income (loss) for each of our business segments for the three and nine months ended September 30, 2011 and 2012, followed by a discussion of the results of operations by business segment based on operating income. 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
	(in millions)
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	2			(1		)	(3		)	(3		)
Total Consolidated Operating Income (Loss)	$	111		$	(152	)	$	485		$	183

21

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 Businesses,” “─ Risk Factors Associated with Our Consolidated Financial Condition” 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 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.

22

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 Businesses,” “─ Risk Factors Associated with Our Consolidated Financial Condition” 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.

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 the estimate of the fair value of goodwill associated with this reporting unit.

23

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 Businesses,” “─ Risk Factors Associated with Our Consolidated Financial Condition” 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 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.

24

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 Businesses,” “─ Risk Factors Associated with Our Consolidated Financial Condition” 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 on 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 on 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 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).

25

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.

CERTAIN FACTORS AFFECTING FUTURE EARNINGS

For information on other developments, factors and trends that may have an impact on our future earnings, please read “Risk Factors” in Item 1A of Part I of our 2011 Form 10-K and “Management’s Narrative Analysis of Results of Operations - Certain Factors Affecting Future Earnings” in Item 7 of Part II of our 2011 Form 10-K and “Cautionary Statement Regarding Forward-Looking Information” in this Form 10-Q.

LIQUIDITY AND CAPITAL RESOURCES

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 natural gas transmission, distribution and gathering operations. These capital expenditures relate to reliability and safety and system expansions. Our principal anticipated cash requirements for the remaining three months of 2012 include approximately $318 million of capital expenditures.

We expect that proceeds from sales of commercial paper, borrowings under our credit facility, anticipated cash flows from operations and borrowings from affiliates 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 debt securities in the capital markets or the arrangement of additional credit facilities. Issuances of 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 discussed below and operating leases, we have no off-balance sheet arrangements.

Prior to the distribution of CenterPoint Energy Inc.’s ownership in Reliant Resources, Inc. (RRI) to its shareholders, we had guaranteed certain contractual obligations of what became RRI’s trading subsidiary.  When the companies separated, RRI agreed to secure us 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 us cash or letters of credit as security against our obligations under its remaining guaranties for demand charges under certain gas transportation agreements if and to the extent changes in market conditions expose us 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, we could have to honor our guarantee and, in such event, collateral provided as security may be insufficient to satisfy our 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.

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

26

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.

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

Date Executed	Size of Facility		Amount Utilized at October 16, 2012	Termination Date
September 9, 2011	$	950	—	September 9, 2016

CERC Corp.’s $950 million 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 to total capitalization covenant which limits debt to 65% of our total capitalization.

Borrowings under the facility are subject to customary terms and conditions. However, there is no requirement that we make representations prior to borrowings as to the absence of material adverse changes or litigation that could be expected to have a material adverse effect. Borrowings under the credit facility are subject to acceleration upon the occurrence of events of default that we consider customary. The facility provides for customary fees, including commitment fees, administrative agent fees, fees in respect of letters of credit and other fees. The LIBOR borrowing spread and the commitment fees fluctuate based on our credit rating. We are currently in compliance with the various business and financial covenants in our revolving credit facility.

CERC Corp.’s $950 million credit facility backstops a $915 million commercial paper program. As of October 16, 2012, CERC Corp. had no outstanding commercial paper. As a result of the credit ratings on our commercial paper program, we do not expect to be able to rely on the sale of commercial paper to fund all of our short-term borrowing requirements.

During the third quarter of 2012, we met substantially all of our liquidity requirements with borrowings from the money pool described below under “—Money Pool”. We currently expect that we may be required to access financing sources in addition to money pool borrowings in order to satisfy our liquidity requirements for the remainder of 2012.  These sources could include commercial paper proceeds or borrowings under our revolving credit facility.

27

Securities Registered with the SEC.  We have filed a shelf registration statement with the SEC registering an indeterminate principal amount of our senior debt securities.

Temporary Investments.  As of October 16, 2012, we had no external temporary investments.

Money Pool.  We participate in a money pool through which we and certain of our affiliates can borrow or invest on a short-term basis. Funding needs are aggregated and external borrowing or investing is based on the net cash position. The net funding requirements of the money pool are expected to be met with borrowings by CenterPoint Energy under its revolving credit facility or the sale by CenterPoint Energy of its commercial paper. At October 16, 2012, we had borrowings of $650 million from the money pool.  The money pool may not provide sufficient funds to meet our cash needs.

Impact on Liquidity of a Downgrade in Credit Ratings.  The interest on borrowings under our credit facility is based on our credit rating. As of October 16, 2012, Moody’s Investors Service, Inc. (Moody’s), Standard & Poor’s Rating Services (S&P), a division of The McGraw-Hill Companies, and Fitch, Inc. (Fitch) had assigned the following credit ratings to our senior unsecured debt:

Moody’s		S&P		Fitch
Rating	Outlook (1)	Rating	Outlook (2)	Rating	Outlook (3)
Baa2	Stable	BBB+	Stable	BBB	Stable

_______________

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

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

(3) A 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 these credit ratings could increase borrowing costs under our $950 million credit facility. If our credit ratings 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 credit facility 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 markets. Additionally, a decline in credit ratings could increase cash collateral requirements and reduce earnings of our Natural Gas Distribution and Competitive Natural Gas Sales and Services business segments.

We and our subsidiaries purchase natural gas from one of our 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, we 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), our wholly owned subsidiary operating in our Competitive Natural Gas Sales and Services business segment, provides comprehensive natural gas sales and services primarily to commercial and industrial customers and electric and gas utilities throughout the central and eastern United States. In order to economically hedge its exposure to natural gas prices, CES uses derivatives with provisions standard for the industry, including those pertaining to credit thresholds. Typically, the credit threshold negotiated with each counterparty defines the amount of unsecured credit that such counterparty will extend to CES. To the extent that the credit exposure that a counterparty has to CES at a particular time does not exceed that credit threshold, CES is not obligated to provide collateral. Mark-to-market exposure in excess of the credit threshold is routinely collateralized by CES. As of September 30, 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.

28

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, we 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.

Cross Defaults. Under CenterPoint Energy’s revolving credit facility, a payment default on, or a non-payment default that permits acceleration of, any indebtedness exceeding $75 million by us will cause a default. In addition, three outstanding series of CenterPoint Energy’s senior notes, aggregating $750 million in principal amount as of September 30, 2012, provide that a payment default by us in respect of, or an acceleration of, borrowed money and certain other specified types of obligations, in the aggregate principal amount of $50 million, will cause a default. A default by CenterPoint Energy would not trigger a default under our debt instruments or bank credit facility.

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 issuances. Debt financing may not, however, be available to us at that time due to a variety of events, including, among others, maintenance of our credit ratings, industry conditions, general economic conditions, market conditions and market perceptions.

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

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

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

• increased costs related to the acquisition of natural gas;

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

• various legislative or  regulatory actions;

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

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

• 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. Our revolving credit facility limits our debt as a percentage of our total capitalization to 65%.

Relationship with CenterPoint Energy. We are an indirect wholly owned subsidiary of CenterPoint Energy. As a result of this relationship, the financial condition and liquidity of our parent company could affect our access to capital, our credit standing and our financial condition.

29

NEW ACCOUNTING PRONOUNCEMENTS

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

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.

PART II. OTHER INFORMATION

Item 1.LEGAL PROCEEDINGS

For a discussion of material legal and regulatory proceedings affecting us, please read Note 10(c) to our Interim Condensed Financial Statements, each of which is incorporated herein by reference. See also “Business - Regulation” and “- Environmental Matters” in Item 1 and “Legal Proceedings” in Item 3 of our 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

Our ratio of earnings to fixed charges for the nine months ended September 30, 2011 and 2012 was 3.37 and 2.44, 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.

30

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 as indicated.

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 Resources Corp., any other persons, any state of affairs or other matters.

Exhibit Number	Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference
3.1.1	Certificate of Incorporation of RERC Corp.	Form 10-K for the year ended December 31, 1997	1-13265	3(a)(1)
3.1.2	Certificate of Merger merging former NorAm Energy Corp. with and into HI Merger, Inc. dated August 6, 1997	Form 10-K for the year ended December 31, 1997	1-13265	3(a)(2)
3.1.3	Certificate of Amendment changing the name to Reliant Energy Resources Corp.	Form 10-K for the year ended December 31, 1998	1-13265	3(a)(3)
3.1.4	Certificate of Amendment changing the name to CenterPoint Energy Resources Corp.	Form 10-Q for the quarter ended June 30, 2003	1-13265	3(a)(4)
3.2	Bylaws of RERC Corp.	Form 10-K for the year ended December 31, 1997	1-13265	3(b)
4.1	$950,000,000 Credit Agreement, dated as of September 9, 2011, among CERC Corp., as Borrower, and the banks named therein	Form 8-K dated September 9, 2011	1-13265	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 (1)
+101.SCH	XBRL Taxonomy Extension Schema Document (1)
+101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document (1)
+101.LAB	XBRL Taxonomy Extension Labels Linkbase Document (1)
+101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document (1)

(1)     Furnished, not filed.

31

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

Date: November 13, 2012

32

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.

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 Resources Corp., any other persons, any state of affairs or other matters.

Exhibit Number	Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference
3.1.1	Certificate of Incorporation of RERC Corp.	Form 10-K for the year ended December 31, 1997	1-13265	3(a)(1)
3.1.2	Certificate of Merger merging former NorAm Energy Corp. with and into HI Merger, Inc. dated August 6, 1997	Form 10-K for the year ended December 31, 1997	1-13265	3(a)(2)
3.1.3	Certificate of Amendment changing the name to Reliant Energy Resources Corp.	Form 10-K for the year ended December 31, 1998	1-13265	3(a)(3)
3.1.4	Certificate of Amendment changing the name to CenterPoint Energy Resources Corp.	Form 10-Q for the quarter ended June 30, 2003	1-13265	3(a)(4)
3.2	Bylaws of RERC Corp.	Form 10-K for the year ended December 31, 1997	1-13265	3(b)
4.1	$950,000,000 Credit Agreement, dated as of September 9, 2011, among CERC Corp., as Borrower, and the banks named therein	Form 8-K dated September 9, 2011	1-13265	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 (1)
+101.SCH	XBRL Taxonomy Extension Schema Document (1)
+101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document (1)
+101.LAB	XBRL Taxonomy Extension Labels Linkbase Document (1)
+101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document (1)

(1)     Furnished, not filed.

33