Centerpoint Energy Resources 10Q 2012 Q2 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 JUNE 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 July 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 JUNE 30, 2012

TABLE OF CONTENTS



PART I.	FINANCIAL INFORMATION
		Page
Item 1.	Financial Statements	1

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

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

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

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

	Notes to Unaudited Condensed Consolidated Financial Statements	6

Item 2.	Management’s Narrative Analysis of Results of Operations	18

Item 4.	Controls and Procedures	27

PART II.	OTHER INFORMATION

Item 1.	Legal Proceedings	28

Item 1A.	Risk Factors	28

Item 5.	Other Information	28

Item 6.	Exhibits	29

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

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

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

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


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


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


•	timely and appropriate rate actions 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, 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;


•	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 June 30,						Six Months Ended June 30,
	2011			2012			2011			2012

Revenues	$	1,228		$	846		$	3,323		$	2,396

Expenses:
Natural gas	778			409			2,254			1,378
Operation and maintenance	237			228			477			467
Depreciation and amortization	65			70			131			139
Taxes other than income taxes	34			33			87			77
Total	1,114			740			2,949			2,061
Operating Income	114			106			374			335

Other Income (Expense):
Interest and other finance charges	(45		)	(44		)	(94		)	(89		)
Equity in earnings of unconsolidated affiliates	8			8			14			17
Other, net	1			—			2			—
Total	(36		)	(36		)	(78		)	(72		)
Income Before Income Taxes	78			70			296			263
Income tax expense	31			28			116			103
Net Income	$	47		$	42		$	180		$	160

See Notes to the Interim Condensed Consolidated Financial Statements

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				Six Months Ended
	June 30,				June 30,
	2011		2012		2011		2012

Net income	$	47	$	42	$	180	$	160
Other comprehensive income, net of tax:
Adjustment to pension and other postretirement plans (net of tax)	—		—		—		—
Other comprehensive income	—		—		—		—
Comprehensive income	$	47	$	42	$	180	$	160

See Notes to the Interim Condensed Consolidated Financial Statements

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		June 30, 2012
Current Assets:
Cash and cash equivalents	$	1	$	2
Accounts receivable, net	542		354
Accrued unbilled revenue	253		66
Accounts and notes receivable — affiliated companies	17		9
Materials and supplies	86		88
Inventory	187		93
Non-trading derivative assets	87		67
Taxes receivable	1		2
Deferred income tax assets	8		7
Prepaid expenses and other current assets	122		166
Total current assets	1,304		854

Property, Plant and Equipment:
Property, plant and equipment	8,519		8,831
Less accumulated depreciation and amortization	1,489		1,596
Property, plant and equipment, net	7,030		7,235

Other Assets:
Goodwill	1,696		1,696
Non-trading derivative assets	20		22
Investment in unconsolidated affiliates	472		476
Other	165		184
Total other assets	2,353		2,378

Total Assets	$	10,687	$	10,467

See Notes to the Interim Condensed Consolidated Financial Statements

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			June 30, 2012
Current Liabilities:
Short-term borrowings	$	62		$	30
Current portion of long-term debt	—			365
Accounts payable	427			227
Accounts and notes payable — affiliated companies	419			447
Taxes accrued	82			80
Interest accrued	48			48
Customer deposits	74			76
Non-trading derivative liabilities	46			27
Other	157			128
Total current liabilities	1,315			1,428

Other Liabilities:
Accumulated deferred income taxes, net	1,420			1,548
Non-trading derivative liabilities	6			14
Benefit obligations	108			108
Regulatory liabilities	597			618
Other	232			227
Total other liabilities	2,363			2,515

Long-Term Debt	2,919			2,272

Commitments and Contingencies (Note 9)

Stockholder’s Equity:
Common stock	—			—
Paid-in capital	2,416			2,418
Retained earnings	1,681			1,841
Accumulated other comprehensive loss	(7		)	(7		)
Total stockholder’s equity	4,090			4,252

Total Liabilities And Stockholder’s Equity	$	10,687		$	10,467

See Notes to the Interim Condensed Consolidated Financial Statements

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)



	Six Months Ended June 30,
	2011			2012
Cash Flows from Operating Activities:
Net income	$	180		$	160
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	131			139
Amortization of deferred financing costs	6			7
Deferred income taxes	75			95
Write-down of natural gas inventory	—			4
Equity in earnings of unconsolidated affiliates, net of distributions	1			—
Changes in other assets and liabilities:
Accounts receivable and unbilled revenues, net	305			367
Accounts receivable/payable, affiliates	(6		)	5
Inventory	68			88
Taxes receivable	61			(1		)
Accounts payable	(213		)	(197		)
Fuel cost recovery	(19		)	(63		)
Interest and taxes accrued	(2		)	(4		)
Non-trading derivatives, net	—			8
Margin deposits, net	48			36
Other current assets	19			(18		)
Other current liabilities	(28		)	(17		)
Other assets	4			—
Other liabilities	7			6
Other, net	1			2
Net cash provided by operating activities	638			617
Cash Flows from Investing Activities:
Capital expenditures, net of acquisitions	(318		)	(232		)
Acquisitions	—			(89		)
Investment in unconsolidated affiliates	(7		)	(4		)
Other, net	1			(9		)
Net cash used in investing activities	(324		)	(334		)
Cash Flows from Financing Activities:
Decrease in short-term borrowings, net	(14		)	(32		)
Payments of commercial paper, net	(113		)	(285		)
Proceeds from long-term debt	550			—
Payments of long-term debt	(606		)	—
Cash paid for debt exchange	(58		)	—
Debt issuance costs	(9		)	—
Increase (decrease) in notes payable to affiliates	(60		)	31
Other, net	—			4
Net cash used in financing activities	(310		)	(282		)

Net Increase in Cash and Cash Equivalents	4			1
Cash and Cash Equivalents at Beginning of Period	1			1
Cash and Cash Equivalents at End of Period	$	5		$	2

Supplemental Disclosure of Cash Flow Information:
Cash Payments:
Interest, net of capitalized interest	$	90		$	82
Income taxes (refunds), net	(19		)	1
Non-cash transactions:
Accounts payable related to capital expenditures	$	47		$	50

See Notes to the Interim Condensed Consolidated Financial Statements

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 11.

(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				Six Months Ended
	June 30,				June 30,
	2011		2012		2011		2012
	(in millions)
Interest cost on accumulated benefit obligation	2		2		3		3
Amortization of prior service cost	—		—		1		1
Amortization of loss	—		1		—		1
Net periodic cost	$	2	$	3	$	4	$	5

CERC expects to contribute approximately $9 million to its postretirement benefit plan in 2012, of which $4 million has been contributed as of June 30, 2012.

(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 June 30, 2011, CERC recorded decreased natural gas revenues from unrealized net losses of $2 million and decreased natural gas expense from unrealized net gains of $6 million, resulting in a net unrealized gain of $4 million. During the three months ended June 30, 2012, CERC recorded decreased natural gas revenues from unrealized net losses of $41 million and decreased natural gas expense from unrealized net gains of $37 million, resulting in a net unrealized loss of $4 million. During the six months ended June 30, 2011, CERC recorded decreased natural gas revenues from unrealized net losses of $19 million and decreased natural gas expense from unrealized net gains of $21 million, resulting in a net unrealized gain of $2 million. During the six months ended June 30, 2012, CERC recorded decreased natural gas revenues from unrealized net losses of $46 million and decreased natural gas expense from unrealized net gains of $41 million, resulting in a net unrealized loss of $5 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 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 six months ended June 30, 2011, CERC recognized losses of $1 million and $6 million, respectively, related to these swaps. During the three and six months ended June 30, 2012, CERC recognized gains of $-0- and $6 million, related to these swaps. Weather hedge gains and losses are included in revenues in the Condensed Statements of Consolidated Income.

(b) Derivative Fair Values and Income Statement Impacts

The following tables present information about 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 June 30, 2012, while the last table provides a breakdown of the related income statement impacts for the three and six months ended June 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
		June 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	$	68	$	1
Natural gas derivatives (1)	Other Assets	22		—
Natural gas derivatives (1)	Current Liabilities	12		56
Natural gas derivatives (1)	Other Liabilities	1		18
Total		$	103	$	75

________________


(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 785 Bcf or a net 114 Bcf long position. Of the net long position, basis swaps constitute 71 Bcf.


(3)	The net of total non-trading derivative assets and liabilities is a $48 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 $20 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

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



Income Statement Impact of Derivative Activity
		Three Months Ended June 30,
Total derivatives not designated as hedging instruments	Income Statement Location	2011			2012
		(in millions)
Natural gas derivatives	Gains (Losses) in Revenue	$	9		$	(8	)
Natural gas derivatives (1)	Gains (Losses) in Expense: Natural Gas	(12		)	13
Total		$	(3	)	$	5

________________

(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 June 30, 2012.



Income Statement Impact of Derivative Activity
		Six Months Ended June 30,
Total derivatives not designated as hedging instruments	Income Statement Location	2011			2012
		(in millions)
Natural gas derivatives	Gains (Losses) in Revenue	$	14		$	43
Natural gas derivatives (1)	Gains (Losses) in Expense: Natural Gas	(49		)	(68		)
Total		$	(35	)	$	(25	)

________________


(1)	The Gains (Losses) in Expense: Natural Gas includes $(62) 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.

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 June 30, 2012 was $39 million and $11 million, respectively. The aggregate fair value of assets that were posted as collateral was less than $1 million at both December 31, 2011 and June 30, 2012. If all derivative contracts (in a net liability position) containing credit risk contingent features were triggered at December 31, 2011 and June 30, 2012, $38 million and $10 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

cash flow model which includes illiquid forward price curve locations (ranging from $2.52-$4.64 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 0-90%) 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. 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 June 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 June 30, 2012
	(in millions)
Assets
Corporate equities	$	1	$	—	$	—	$	—		$	1
Investments, including money market funds (2)	11		—		—		—			11
Natural gas derivatives	3		71		29		(14		)	89
Total assets	$	15	$	71	$	29	$	(14	)	$	101
Liabilities
Natural gas derivatives	$	11	$	38	$	26	$	(34	)	$	41
Total liabilities	$	11	$	38	$	26	$	(34	)	$	41

________________


(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 $20 million posted with the same counterparties.


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

The following tables present 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 June 30,
	2011			2012
	(in millions)
Beginning balance	$	6		$	3
Total unrealized gains ⁽¹⁾	1			2
Total settlements ⁽¹⁾	(2		)	(2		)
Transfers out of Level 3	—			—
Ending balance ⁽²⁾	$	5		$	3
The amount of total gains for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the reporting date	$	1		$	1



	Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Derivative Assets and Liabilities, net
	Six Months Ended June 30,
	2011			2012
	(in millions)
Beginning balance	$	3		$	6
Total unrealized gains ⁽¹⁾	4			4
Total settlements ⁽¹⁾	(2		)	(6		)
Transfers out of Level 3	—			(1		)
Ending balance ⁽²⁾	$	5		$	3
The amount of total gains for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the reporting date	$	3		$	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 six months ended June 30, 2011 or 2012.


(2)	During both the three and six months ended June 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				June 30, 2012
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in millions)
Financial liabilities:
Long-term debt	$	2,919	$	3,272	$	2,637	$	2,981

(6) Goodwill

Goodwill by reportable business segment as of both December 31, 2011 and June 30, 2012 is as follows (in millions):



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

(7) 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 $414 million at December 31, 2011 and June 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 six months ended June 30, 2011, and $1 million and $2 million, respectively, for the three and six months ended June 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 $42 million and $41 million for the three months ended June 30, 2011 and 2012, respectively, and $81 million for both the six months ended June 30, 2011 and 2012, and are included primarily in operation and maintenance expenses.

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

(a)Short-term Borrowings

Inventory Financing. Gas Operations has 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 $30 million as of December 31, 2011 and June 30, 2012, respectively.


(b)	Long-term Debt

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



		December 31, 2011						June 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.

(9) 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 June 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 June 30, 2012, minimum payment obligations for natural gas supply commitments are approximately $185 million for the remaining six months in 2012, $428 million in 2013, $339 million in 2014, $210 million in 2015, $148 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.

Legal Matters

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

A large number of lawsuits were filed against numerous gas market participants in a number of federal and western state courts in connection with the operation of the natural gas markets in 2000-2002. CenterPoint Energy’s former affiliate, RRI, was a participant in gas trading in the California and Western markets. These lawsuits, many of which have been filed as class actions, allege violations of state and federal antitrust laws. Plaintiffs in these lawsuits are seeking a variety of forms of relief, including, among others, recovery of compensatory damages (in some cases in excess of $1 billion), a trebling of compensatory damages, full consideration damages and attorneys’ fees. CenterPoint Energy and/or Reliant Energy were named in approximately 30 of these lawsuits, which were instituted between 2003 and 2009. CenterPoint Energy and its affiliates have been released or dismissed from all but two of such cases. CenterPoint Energy Services, Inc. (CES), a subsidiary of CERC Corp., is a defendant in a case now pending in federal court in Nevada alleging a conspiracy to inflate Wisconsin natural gas prices in 2000-2002. In July 2011, the court issued an order dismissing the plaintiffs’ claims against the other defendants in the case, each of whom had demonstrated 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. 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 June 30, 2012, CERC had accrued $13 million for remediation of these Minnesota sites and the estimated range of possible remediation costs for these sites was $6 million to $41 million based on remediation continuing for 30 to 50 years. The cost estimates are based on studies of a site or industry average costs for remediation of sites of similar size. The actual remediation costs will be dependent upon the number of sites to be remediated, the participation of other potentially responsible parties (PRPs), if any, and the remediation methods used. The Minnesota Public Utilities Commission includes approximately $285,000 annually in rates to fund normal on-going remediation costs. As of June 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 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 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 $82 million as of June 30, 2012. Market conditions in the fourth quarters of 2010 and 2011 required posting of security under the agreement, and GenOn has posted approximately $28 million of collateral as of June 30, 2012. 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.

(10) Income Taxes

During the three and six months ended June 30, 2012, the effective tax rate was 40% and 39%, respectively. The effective tax rate for 2012 was consistent with the same periods in 2011.

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



	December 31, 2011			June 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 amount of unrecognized tax benefits to change materially over the 12 months ending June 30, 2013.

CenterPoint Energy has a tentative settlement with the Internal Revenue Service (IRS) for tax years 2008 and 2009 that is under review by the Joint Committee on Taxation. In May 2012, the IRS commenced its examination of CenterPoint Energy’s 2010 consolidated income tax return.

(11) 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.

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



	For the Three Months Ended June 30, 2011
	Revenues from External Customers		Inter-segment Revenues			Operating Income (Loss)
Natural Gas Distribution	$	448	$	4		$	13
Competitive Natural Gas Sales and Services	581		5			3
Interstate Pipelines	111		31			60
Field Services	88		10			39
Other	—		—			(1		)
Reconciling Eliminations	—		(50		)	—
Consolidated	$	1,228	$	—		$	114

	For the Three Months Ended June 30, 2012
	Revenues from External Customers		Inter-segment Revenues			Operating Income (Loss)
Natural Gas Distribution	$	360	$	6		$	9
Competitive Natural Gas Sales and Services	302		6			(4		)
Interstate Pipelines	88		37			52
Field Services	96		8			51
Other	—		—			(2		)
Reconciling Eliminations	—		(57		)	—
Consolidated	$	846	$	—		$	106

	For the Six Months Ended June 30, 2011
	Revenues from External Customers		Inter-segment Revenues			Operating Income (Loss)			Total Assets as of December 31, 2011
Natural Gas Distribution	$	1,655	$	9		$	155		$	4,636
Competitive Natural Gas Sales and Services	1,278		14			13			1,089
Interstate Pipelines	224		65			136			3,867
Field Services	166		22			75			1,894
Other	—		—			(5		)	660
Reconciling Eliminations	—		(110		)	—			(1,459		)
Consolidated	$	3,323	$	—		$	374		$	10,687

	For the Six Months Ended June 30, 2012
	Revenues from External Customers		Inter-segment Revenues			Operating Income (Loss)			Total Assets as of June 30, 2012
Natural Gas Distribution	$	1,209	$	11		$	130		$	4,503
Competitive Natural Gas Sales and Services	822		11			(3		)	1,023
Interstate Pipelines	170		82			112			3,935
Field Services	195		14			98			1,976
Other	—		—			(2		)	363
Reconciling Eliminations	—		(118		)	—			(1,333		)
Consolidated	$	2,396	$	—		$	335		$	10,467

(12) Other Current Assets and Liabilities

Included in other current assets on the Condensed Consolidated Balance Sheets at both December 31, 2011 and June 30, 2012 were $17 million of margin deposits and $63 million and $102 million of under-recovered gas cost at December 31, 2011 and June 30, 2012, respectively. Included in other current liabilities on the Condensed Consolidated Balance Sheets at December 31, 2011 and June 30, 2012 were $14 million and $11 million, respectively, of over-recovered gas cost.

(13) Subsequent Events

As of June 30, 2012, CERC owned a 50% interest in Waskom Gas Processing Company (Waskom), a Texas general partnership, which owns and operates a natural gas processing plant and natural gas gathering assets. This investment is accounted for under the equity method as CERC exercises significant influence over Waskom. On July 31, 2012, CERC purchased the remaining 50% interest in Waskom as well as other gathering assets from a third-party for approximately $275 million. The amount of the purchase price allocated to the acquisition of the remaining 50% interest in Waskom was approximately $200 million, with the remaining purchase price allocated to the other gathering assets, based on a discounted cash flow methodology. The purchase of the remaining 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 $130 million on July 31, 2012, which is the result of remeasuring CERC's original 50% interest in Waskom to fair value.

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 six months ended June 30, 2011 and the three and six months ended June 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

Midstream Acquisitions

In May 2012, CenterPoint Energy Field Services, LLC (CEFS) purchased the Amoruso gathering system located in east Texas and related assets from a subsidiary of Encana Corporation (Encana) for approximately $89 million. In connection with this acquisition, CEFS entered into a 15-year gathering agreement with Encana to gather and treat its natural gas production from the Amoruso and Hilltop fields located in Robertson and Leon counties in east Texas. The gathering agreement includes volume commitments and an acreage dedication. The Amoruso gathering system currently has more than 200 million cubic feet per day of natural gas throughput primarily from the Deep Bossier and Cotton Valley Lime formations.

As of June 30, 2012, we owned a 50% interest in Waskom Gas Processing Company (Waskom), a Texas general partnership, which owns and operates a natural gas processing plant and natural gas gathering assets. This investment is accounted for under the equity method as we exercise significant influence over Waskom. On July 31, 2012, we purchased the remaining 50% interest in Waskom as well as other gathering and related assets from a third-party for approximately $275 million. The amount of the purchase price allocated to the acquisition of the remaining 50% interest in Waskom was approximately $200 million, with the remaining purchase price allocated to the other gathering assets, based on a discounted cash flow methodology. The purchase of the remaining 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 $130 million on July 31, 2012, which is the result of remeasuring our original 50% interest in Waskom to fair value.

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 six months ended June 30, 2011 and 2012, followed by a discussion of our consolidated results of operations.



	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2012			2011			2012
	(in millions)
Revenues	$	1,228		$	846		$	3,323		$	2,396
Expenses:
Natural gas	778			409			2,254			1,378
Operation and maintenance	237			228			477			467
Depreciation and amortization	65			70			131			139
Taxes other than income taxes	34			33			87			77
Total	1,114			740			2,949			2,061
Operating Income	114			106			374			335
Interest and other finance charges	(45		)	(44		)	(94		)	(89		)
Equity in earnings of unconsolidated affiliates	8			8			14			17
Other income, net	1			—			2			—
Income Before Income Taxes	78			70			296			263
Income tax expense	31			28			116			103
Net Income	$	47		$	42		$	180		$	160

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

We reported net income of $42 million for the three months ended June 30, 2012 compared to $47 million for the same period in 2011. The decrease in net income of $5 million was primarily due to a $8 million decrease in operating income from our business segments as discussed below, which was partially offset by a $3 million decrease in income tax expense and a $1 million decrease in interest and other finance charges.

Six months ended June 30, 2012 compared to six months ended June 30, 2011

We reported net income of $160 million for the six months ended June 30, 2012 compared to $180 million for the same period in 2011. The decrease in net income of $20 million was primarily due to a $39 million decrease in operating income from our business segments as discussed below, which was partially offset by a $13 million decrease in income tax expense, a $5 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 six months ended June 30, 2012, our effective tax rate was 40% and 39%, respectively. Our effective tax rate in 2012 was consistent with the same periods in 2011.

RESULTS OF OPERATIONS BY BUSINESS SEGMENT

The following table presents operating income (loss) for each of our business segments for the three and six months ended June 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 June 30,						Six Months Ended June 30,
	2011			2012			2011			2012
	(in millions)
Natural Gas Distribution	$	13		$	9		$	155		$	130
Competitive Natural Gas Sales and Services	3			(4		)	13			(3		)
Interstate Pipelines	60			52			136			112
Field Services	39			51			75			98
Other Operations	(1		)	(2		)	(5		)	(2		)
Total Consolidated Operating Income	$	114		$	106		$	374		$	335

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 six months ended June 30, 2011 and 2012 (in millions, except throughput and customer data):



	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2012		2011		2012
Revenues	$	452	$	366	$	1,664	$	1,220
Expenses:
Natural gas	218		136		1,036		629
Operation and maintenance	157		156		325		319
Depreciation and amortization	41		43		83		86
Taxes other than income taxes	23		22		65		56
Total expenses	439		357		1,509		1,090
Operating Income	$	13	$	9	$	155	$	130
Throughput (in billion cubic feet (Bcf)):
Residential	20		16		110		78
Commercial and industrial	51		52		139		126
Total Throughput	71		68		249		204
Number of customers at end of period:
Residential	3,000,665		3,020,913		3,000,665		3,020,913
Commercial and industrial	243,629		243,262		243,629		243,262
Total	3,244,294		3,264,175		3,244,294		3,264,175

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

Our Natural Gas Distribution business segment reported operating income of $9 million for the three months ended June 30, 2012 compared to $13 million for the three months ended June 30, 2011. Operating income decreased $4 million primarily as a result of decreased throughput primarily due to the impacts of warmer weather partially mitigated by weather hedges and weather normalization adjustments ($5 million) and increased depreciation and amortization ($2 million). Adverse impacts were partially offset by rate increases ($3 million) and the addition of over 19,000 customers ($1 million). Decreased expense related to energy efficiency programs ($2 million) and decreased expense related to lower gross receipt taxes ($2 million) were offset by the related revenues.

Six months ended June 30, 2012 compared to six months ended June 30, 2011

Our Natural Gas Distribution business segment reported operating income of $130 million for the six months ended June 30, 2012 compared to $155 million for the six months ended June 30, 2011. Operating income decreased $25 million primarily as a result of decreased throughput primarily due to the impacts of warmer weather partially mitigated by weather hedges and weather normalization adjustments ($29 million), decreased other miscellaneous revenues ($2 million), increased depreciation and amortization ($3 million) and increased other expenses ($4 million). Adverse impacts were partially offset by the addition of over 19,000 customers ($2 million), lower bad debt expense ($6 million) and rate increases ($7 million). Decreased expense related to energy efficiency programs ($4 million) and decreased expense related to lower gross receipt taxes ($10 million) were offset by the related revenues.

Competitive Natural Gas Sales and Services

For information regarding factors that may affect the future results of operations of our Competitive Natural Gas Sales and Services business segment, please read “Risk Factors ─ Risk Factors Affecting Our 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 six months ended June 30, 2011 and 2012 (in millions, except throughput and customer data):



	Three Months Ended June 30,					Six Months Ended June 30,
	2011		2012			2011		2012
Revenues	$	586	$	308		$	1,292	$	833
Expenses:
Natural gas	571		300			1,256		811
Operation and maintenance	11		10			21		22
Depreciation and amortization	1		1			2		2
Taxes other than income taxes	—		1			—		1
Total expenses	583		312			1,279		836
Operating Income (Loss)	$	3	$	(4	)	$	13	$	(3	)
Throughput (in Bcf)	126		127			281		288
Number of customers at end of period	12,152		15,567			12,152		15,567

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

Our Competitive Natural Gas Sales and Services business segment reported an operating loss of $4 million for the three months ended June 30, 2012 compared to operating income of $3 million for the three months ended June 30, 2011. The decrease in operating income of $7 million is primarily due to charges of $4 million for the three months ended June 30, 2012 compared to gains of $4 million for the same period in 2011 related to mark-to-market accounting for derivatives associated with certain forward natural gas purchases and sales used to lock in economic margins.

Six months ended June 30, 2012 compared to six months ended June 30, 2011

Our Competitive Natural Gas Sales and Services business segment reported an operating loss of $3 million for the six months ended June 30, 2012 compared to operating income of $13 million for the six months ended June 30, 2011. The decrease in operating income of $16 million is primarily due to warmer weather and compressed margins (revenues less natural gas costs) of $3 million, higher operation and maintenance expenses of $1 million and a $4 million write-down of natural gas inventory to the lower of cost or market. The first half of 2012 also included charges of $5 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 $2 million benefit for the same period of 2011. Throughput volumes and the number of customers increased in the first two quarters of 2012 compared to the first two quarters of 2011 as a result of continued growth in this segment's commercial business.

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 six months ended June 30, 2011 and 2012 (in millions, except throughput data):



	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2012		2011		2012

Revenues	$	142	$	125	$	289	$	252
Expenses:
Natural gas	21		14		39		21
Operation and maintenance	39		36		70		74
Depreciation and amortization	14		14		27		28
Taxes other than income taxes	8		9		17		17
Total expenses	82		73		153		140
Operating Income	$	60	$	52	$	136	$	112

Equity in earnings of unconsolidated affiliates	$	5	$	6	$	9	$	12

Transportation throughput (in Bcf)	396		346		852		724

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

Our Interstate Pipeline business segment reported operating income of $52 million for the three months ended June 30, 2012 compared to $60 million for the three months ended June 30, 2011. Margins decreased $10 million primarily due to a backhaul contract that expired in 2011 ($4 million), as well as the associated reduction in compressor efficiency ($4 million), lower off-system transportation revenues ($1 million) and lower other transportation and ancillary services ($2 million), which were partially offset by the effects of the restructured 10-year agreement with our natural gas distribution affiliate ($1 million). Lower operations and maintenance expenses ($3 million) were partially offset by higher taxes other than income ($1 million).

Equity Earnings. In addition, this business segment recorded equity income of $5 million and $6 million for the three months ended June 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.

Six months ended June 30, 2012 compared to six months ended June 30, 2011

Our Interstate Pipeline business segment reported operating income of $112 million for the six months ended June 30, 2012 compared to $136 million for the six months ended June 30, 2011. Margins decreased $19 million primarily due to a backhaul contract that expired in 2011 ($14 million), as well as the associated reduction in compressor efficiency ($7 million), and lower off-system transportation revenues ($4 million), which were partially offset by the effects of the restructured 10-year agreement with our natural gas distribution affiliate ($5 million) and other transportation and ancillary services ($1 million). Operation and maintenance expenses increased ($4 million) due to a non-recurring 2011 insurance settlement related to a damaged compressor station. Depreciation and amortization expenses increased ($1 million) due to asset additions.

Equity Earnings. In addition, this business segment recorded equity income of $9 million and $12 million for the six months ended June 30, 2011 and 2012, respectively, from its 50% interest in SESH. These higher earnings primarily resulted from restructuring and extending a long-term agreement with an anchor shipper at the end of 2011. These amounts are included in Equity in Earnings of Unconsolidated Affiliates under the Other Income (Expense) caption.

Field Services

For information regarding factors that may affect the future results of operations of our Field Services business segment, please read “Risk Factors ─ Risk Factors Affecting Our 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 six months ended June 30, 2011 and 2012 (in millions, except throughput data):



	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2012		2011		2012

Revenues	$	98	$	104	$	188	$	209
Expenses:
Natural gas	18		15		33		33
Operation and maintenance	29		26		58		53
Depreciation and amortization	10		11		19		22
Taxes other than income taxes	2		1		3		3
Total expenses	59		53		113		111
Operating Income	$	39	$	51	$	75	$	98

Equity in earnings of unconsolidated affiliates	$	3	$	2	$	5	$	5

Gathering throughput (in Bcf)	197		233		380		470

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

Our Field Services business segment reported operating income of $51 million for the three months ended June 30, 2012 compared to $39 million for the three months ended June 30, 2011. Margins increased by $9 million primarily due to higher throughput from gathering projects in the Haynesville and Fayetteville shales and growth in core gathering services, including revenues from annual contracted volume commitments ($19 million), partially offset by lower commodity prices ($10 million) from sales of retained natural gas. Lower operation and maintenance expenses ($3 million) and taxes other than income taxes ($1 million) were partially offset by higher depreciation expense ($1 million) related to new assets placed in service.

Equity Earnings. In addition, this business segment recorded equity income of $3 million and $2 million in the three months ended June 30, 2011 and 2012, respectively, from its 50% general partnership interest in Waskom. The decline is primarily attributable to customer disruptions impacting volumes as well as lower commodity pricing. These amounts are included in Equity in Earnings of Unconsolidated Affiliates under the Other Income (Expense) caption.

Six months ended June 30, 2012 compared to six months ended June 30, 2011

Our Field Services business segment reported operating income of $98 million for the six months ended June 30, 2012 compared to $75 million for the six months ended June 30, 2011. Margins increased by $21 million primarily due to higher throughput from gathering projects in the Haynesville and Fayetteville shales and growth in core gathering services, including revenues from annual contracted volume commitments ($37 million) partially offset by lower commodity prices ($16 million) from sales of retained natural gas. Lower operation and maintenance expenses ($5 million) were partially offset by higher depreciation expense ($3 million) related to new assets placed in service.

Equity Earnings. In addition, this business segment recorded equity income of $5 million in both the six months ended June 30, 2011 and 2012 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.

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 six months of 2012 include approximately $375 million of capital expenditures and the acquisition of the remaining 50% interest in Waskom and other gathering assets for approximately $275 million in July 2012.

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 six 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 $82 million as of June 30, 2012. Market conditions in the fourth quarters of 2010 and 2011 required posting of security under the agreement, and GenOn has posted approximately $28 million of collateral as of June 30, 2012. 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.

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. The municipalities and the Railroad Commission may suspend rates for up to 90 days and up to 150 days, respectively. New base rates for the Beaumont/East Texas Division 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, as approved by the MPSC, are expected to take effect in the fourth 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. The impact of the lower rates implemented in these two cities is approximately $173,000 per month.

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 July 16, 2012, we had the following revolving credit facility (in millions):



Date Executed	Size of Facility		Amount Utilized at July 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 July 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 second 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.

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 July 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 July 16, 2012, we had borrowings of $357 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 July 26, 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 June 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 June 30, 2012, the amount posted as collateral aggregated approximately $37 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 June 30, 2012, unsecured credit limits extended to CES by counterparties aggregate $358 million and $12 million of such amount was utilized.

Pipeline tariffs and contracts typically provide that if the credit ratings of a shipper or the shipper’s guarantor drop below a threshold level, which is generally investment grade ratings from both Moody’s and S&P, cash or other collateral may be demanded from the shipper in an amount equal to the sum of three months’ charges for pipeline services plus the unrecouped cost of any lateral built for such shipper. If the credit ratings of CERC Corp. decline below the applicable threshold levels, we might need to provide cash or other collateral of as much as $172 million as of June 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 June 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.

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 June 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 June 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 9(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 six months ended June 30, 2011 and 2012 was 3.24 and 3.76, respectively. We do not believe that the ratios for these six-month periods are necessarily indicative of the ratios for the twelve-month periods due to the seasonal nature of our business. The ratios were calculated pursuant to applicable rules of the Securities and Exchange Commission.

Item 6. EXHIBITS

The following exhibits are filed herewith:

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

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: August 10, 2012

Index to Exhibits

The following exhibits are filed herewith:

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



Exhibit Number	Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference
3.1.1	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.

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Litigous
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Centerpoint Energy Resources 10-Q2012 Q2 Quarterly report

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