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CERC Q2 2013 10-Q

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, 2013
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 in Rule 12b-2 of the Exchange Act).Yes o No þ

As of July 18, 2013, 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, 2013

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, 2012 and 2013 (unaudited)	1

	Condensed Statements of Consolidated Comprehensive Income
	Three and Six Months Ended June 30, 2012 and 2013 (unaudited)	2

	Condensed Consolidated Balance Sheets
	December 31, 2012 and June 30, 2013 (unaudited)	3

	Condensed Statements of Consolidated Cash Flows
	Six Months Ended June 30, 2012 and 2013 (unaudited)	5

	Notes to Unaudited Condensed Consolidated Financial Statements	6

Item 2.	Management’s Narrative Analysis of Results of Operations	21

Item 4.	Controls and Procedures	33

PART II.	OTHER INFORMATION

Item 1.	Legal Proceedings	33

Item 1A.	Risk Factors	33

Item 5.	Other Information	35

Item 6.	Exhibits	36

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

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

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

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

•

state and federal legislative and regulatory actions or developments affecting various aspects of our businesses (including the businesses of Enable Midstream Partners, LP (Midstream Partnership), our midstream partnership with OGE Energy Corp. (OGE) and affiliates of ArcLight Capital Partners, LLC (ArcLight)), including, among others, energy deregulation or re-regulation, pipeline integrity and safety, health care reform, financial reform, tax legislation and actions regarding the rates charged by our regulated businesses;


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


•	timely and appropriate rate actions that allow recovery of costs and a reasonable return on investment;


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


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


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


•	the timing and extent of changes in commodity prices, particularly natural gas and natural gas liquids (NGLs), and the effects of geographic and seasonal commodity price differentials;


•	weather variations and other natural phenomena, including the impact of severe weather events on operations and capital;


•	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.), a wholly owned subsidiary of NRG Energy, 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, joint ventures and 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;


•	future economic conditions in regional and national markets and their effect on sales, prices and costs;


•	the performance of Midstream Partnership, the amount of cash distributions we receive from Midstream Partnership, and the value of our interest in Midstream Partnership, and factors that may have a material impact on such performance, cash distributions and value, including certain of the factors specified above and:


◦	the integration of the operations of the businesses we contributed to Midstream Partnership with those contributed by OGE and ArcLight;


◦	the achievement of anticipated operational and commercial synergies and expected growth opportunities, and the successful implementation of its business plan;


◦	competitive conditions in the midstream industry, and actions taken by Midstream Partnership's customers and competitors, including the extent and timing of the entry of additional competition in the markets served by Midstream Partnership;

◦

the timing and extent of changes in commodity prices, particularly natural gas and NGLs, the competitive effects of the available pipeline capacity in the regions served by Midstream Partnership, and the effects of geographic and seasonal commodity price differentials, including the effects of these circumstances on re-contracting available capacity on Midstream Partnership's interstate pipelines;


◦	the demand for natural gas, NGLs and transportation and storage services;


◦	changes in tax status;


◦	access to growth capital;


◦	the availability and prices of raw materials for current and future construction projects; 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, 2012, which is incorporated herein by reference, in Item 1A of Part II of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2013, in Item 1A of Part II of this Quarterly Report on Form 10-Q and other reports we file from time to time with the Securities and Exchange Commission.

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

iii

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,
	2012			2013			2012			2013

Revenues	$	846		$	1,235		$	2,396		$	3,088

Expenses:
Natural gas	409			852			1,378			2,076
Natural gas-affiliates	—			28			—			28
Operation and maintenance	228			209			467			460
Depreciation and amortization	70			56			139			133
Taxes other than income taxes	33			34			77			85
Total	740			1,179			2,061			2,782
Operating Income	106			56			335			306

Other Income (Expense):
Interest and other finance charges	(44		)	(37		)	(89		)	(82		)
Equity in earnings of unconsolidated affiliates, net	8			37			17			42
Other, net	—			(5		)	—			(5		)
Total	(36		)	(5		)	(72		)	(45		)
Income Before Income Taxes	70			51			263			261
Income tax expense	28			213			103			295
Net Income (Loss)	$	42		$	(162	)	$	160		$	(34	)

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,
	2012		2013			2012		2013

Net income (loss)	$	42	$	(162	)	$	160	$	(34	)
Other comprehensive income, net of tax:
Adjustment to pension and other postretirement plans (net of tax)	—		—			—		—
Other comprehensive income	—		—			—		—
Comprehensive income (loss)	$	42	$	(162	)	$	160	$	(34	)

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, 2012		June 30, 2013
Current Assets:
Cash and cash equivalents	$	1	$	7
Accounts receivable, net	544		391
Accrued unbilled revenue	258		81
Accounts and notes receivable — affiliated companies	15		39
Materials and supplies	83		32
Natural gas inventory	145		139
Non-trading derivative assets	36		27
Prepaid expenses and other current assets	133		39
Total current assets	1,215		755

Property, Plant and Equipment:
Property, plant and equipment	9,615		4,624
Less accumulated depreciation and amortization	1,714		1,316
Property, plant and equipment, net	7,901		3,308

Other Assets:
Goodwill	1,468		840
Non-trading derivative assets	6		7
Investment in unconsolidated affiliates	405		4,485
Notes receivable from unconsolidated affiliates	—		363
Other	195		187
Total other assets	2,074		5,882

Total Assets	$	11,190	$	9,945

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, 2012			June 30, 2013
Current Liabilities:
Short-term borrowings	$	38		$	37
Current portion of long-term debt	365			—
Accounts payable	443			288
Accounts and notes payable — affiliated companies	818			63
Taxes accrued	72			48
Interest accrued	48			36
Customer deposits	79			78
Non-trading derivative liabilities	14			12
Other	177			146
Total current liabilities	2,054			708

Other Liabilities:
Accumulated deferred income taxes, net	1,676			1,976
Non-trading derivative liabilities	2			1
Benefit obligations	122			122
Regulatory liabilities	619			633
Other	208			188
Total other liabilities	2,627			2,920

Long-Term Debt	2,276			2,118

Commitments and Contingencies (Note 10)

Stockholder’s Equity:
Common stock	—			—
Paid-in capital	2,416			2,416
Retained earnings	1,818			1,784
Accumulated other comprehensive loss	(1		)	(1		)
Total stockholder’s equity	4,233			4,199

Total Liabilities and Stockholder’s Equity	$	11,190		$	9,945

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,
	2012			2013
Cash Flows from Operating Activities:
Net income (loss)	$	160		$	(34	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	139			133
Amortization of deferred financing costs	7			6
Deferred income taxes	95			289
Write-down of natural gas inventory	4			3
Equity in earnings of unconsolidated affiliates, net of distributions	—			(25		)
Changes in other assets and liabilities:
Accounts receivable and unbilled revenues, net	367			168
Accounts receivable/payable - affiliated companies	5			(10		)
Inventory	88			(1		)
Taxes receivable	(1		)	—
Accounts payable	(197		)	(109		)
Fuel cost recovery	(63		)	116
Interest and taxes accrued	(4		)	(22		)
Non-trading derivatives, net	8			—
Margin deposits, net	36			7
Other current assets	(18		)	15
Other current liabilities	(17		)	(17		)
Other assets	—			(7		)
Other liabilities	6			14
Other, net	2			1
Net cash provided by operating activities	617			527
Cash Flows from Investing Activities:
Capital expenditures, net of acquisitions	(232		)	(239		)
Acquisitions, net of cash acquired	(89		)	—
Investment in unconsolidated affiliates	(4		)	—
Cash contribution to Midstream Partnership	—			(38		)
Other, net	(9		)	—
Net cash used in investing activities	(334		)	(277		)
Cash Flows from Financing Activities:
Decrease in short-term borrowings, net	(32		)	(1		)
Payments of commercial paper, net	(285		)	—
Proceeds from long-term debt	—			1,050
Payments of long-term debt	—			(525		)
Increase (decrease) in notes payable - affiliated companies	31			(768		)
Other, net	4			—
Net cash used in financing activities	(282		)	(244		)

Net Increase in Cash and Cash Equivalents	1			6
Cash and Cash Equivalents at Beginning of Period	1			1
Cash and Cash Equivalents at End of Period	$	2		$	7

Supplemental Disclosure of Cash Flow Information:
Cash Payments:
Interest, net of capitalized interest	$	82		$	85
Income taxes, net	1			1
Non-cash transactions:
Accounts payable related to capital expenditures	$	50		$	33

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, 2012.

Background. CERC owns and operates natural gas distribution systems (Gas Operations) and owns an interest in a midstream partnership (Midstream Partnership) as described below. 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. also owns approximately 58.3% of the limited partner interests in Midstream Partnership, which owns and operates interstate pipelines and natural gas gathering, processing and treating facilities.

On March 14, 2013, CenterPoint Energy, Inc. (CenterPoint Energy) entered into a Master Formation Agreement (MFA) with OGE Energy Corp. (OGE) and affiliates of ArcLight Capital Partners, LLC (ArcLight), pursuant to which CenterPoint Energy, OGE and ArcLight agreed to form Midstream Partnership as a private limited partnership. On May 1, 2013, the parties closed on the formation of Midstream Partnership. In connection with the closing (i) CERC Corp. converted its direct wholly owned subsidiary, CenterPoint Energy Field Services, LLC, a Delaware limited liability company (CEFS), into a Delaware limited partnership that became Midstream Partnership and was subsequently renamed Enable Midstream Partners, LP, (ii) CERC Corp. contributed to Midstream Partnership its equity interests in each of CenterPoint Energy Gas Transmission Company, LLC (CEGT), CenterPoint Energy - Mississippi River Transmission, LLC (MRT), certain of its other midstream subsidiaries (Other CNP Midstream Subsidiaries), and a 24.95% interest in Southeast Supply Header, LLC (SESH and, collectively with CEFS, CEGT, MRT and Other CNP Midstream Subsidiaries, CenterPoint Midstream), and (iii) OGE and ArcLight indirectly contributed 100% of the equity interests in Enogex LLC to Midstream Partnership.

CERC Corp. holds approximately 58.3% of the limited partner interests in Midstream Partnership and OGE and ArcLight hold approximately 28.5% and 13.2%, respectively, of the limited partner interests. Midstream Partnership is equally controlled by CERC Corp. and OGE; each own 50% of the management rights in the general partner of Midstream Partnership. CERC Corp. and OGE will also own a 40% and 60% interest, respectively, in any incentive distribution rights to be held by the general partner of Midstream Partnership following an initial public offering of Midstream Partnership. The general partner of Midstream Partnership is governed by a board made up of an equal number of representatives designated by each of CERC Corp. and OGE. See Note 6 for further discussion on the formation of Midstream Partnership.

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

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

CERC’s Interim Condensed Financial Statements reflect all normal recurring adjustments that are, in the opinion of management, necessary to present fairly the financial position, results of operations and cash flows for the respective periods. Amounts reported in CERC’s Condensed Statements of Consolidated Income are not necessarily indicative of amounts expected for a full-year period due to the effects of, among other things, (a) seasonal fluctuations in demand for energy and energy services, (b) changes in energy commodity prices, (c) timing of maintenance and other expenditures and (d) acquisitions and dispositions of businesses, assets and other interests.

For a description of CERC’s reportable business segments, see Note 12.

(2) New Accounting Pronouncements

Management believes that recently issued accounting 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,
	2012		2013		2012		2013
	(in millions)
Interest cost on accumulated benefit obligation	2		1		3		2
Amortization of prior service cost	—		—		1		1
Amortization of loss	1		1		1		1
Net periodic cost	$	3	$	2	$	5	$	4

CERC expects to contribute approximately $8 million to its postretirement benefit plan in 2013, of which $2 million and $4 million, respectively, was contributed during the three and six months ended June 30, 2013.

(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 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 the 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.

Weather Hedges. CERC has weather normalization or other rate mechanisms that mitigate the impact of weather on its gas operations in Arkansas, Louisiana, Mississippi and Oklahoma. Gas Operations in Texas and Minnesota 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 these jurisdictions. CERC enters into heating-degree day swaps for these Gas Operations jurisdictions to mitigate the effect of fluctuations from normal weather on its results of operations and cash flows for the winter heating season. The swaps are based on ten-year normal weather. During the three months ended June 30, 2012 and 2013, CERC recognized gains of $-0- and losses of $3 million, respectively, related to these swaps. During the six months ended June 30, 2012 and 2013, CERC recognized gains of $6 million and losses of $6 million, respectively, 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 four tables provide a balance sheet overview of CERC’s Derivative Assets and Liabilities as of December 31, 2012 and June 30, 2013, while the last two tables provide a breakdown of the related income statement impacts for the three and six months ended June 30, 2012 and 2013.



Fair Value of Derivative Instruments
		December 31, 2012
Total derivatives not designated as hedging instruments	Balance Sheet Location	Derivative Assets Fair Value		Derivative Liabilities Fair Value
		(in millions)
Natural gas derivatives (1) (2)	Current Assets: Non-trading derivative assets	$	37	$	1
Natural gas derivatives (1) (2)	Other Assets: Non-trading derivative assets	6		—
Natural gas derivatives (1) (2)	Current Liabilities: Non-trading derivative liabilities	5		27
Natural gas derivatives (1) (2)	Other Liabilities: Non-trading derivative liabilities	1		4
Total		$	49	$	32

________________


(1)	The fair value shown for natural gas contracts is comprised of derivative gross volumes totaling 489 billion cubic feet (Bcf) or a net 101 Bcf long position. Of the net long position, basis swaps constitute 73 Bcf.

(2)

Natural gas contracts are presented on a net basis in the Condensed Consolidated Balance Sheets. Natural gas contracts are subject to master netting arrangements. This netting applies to all undisputed amounts due or past due and causes derivative assets (liabilities) to be ultimately presented net in a liability (asset) account within the Condensed Consolidated Balance Sheets. The net of total non-trading derivative assets and liabilities was a $26 million asset as shown on CERC’s Condensed Consolidated Balance Sheets (and as detailed in the table below), and was comprised of the natural gas contracts derivative assets and liabilities separately shown above offset by collateral netting of $9 million:



Offsetting of Natural Gas Derivative Assets and Liabilities
	December 31, 2012
	Gross Amounts Recognized (1)			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amount Presented in the Consolidated Balance Sheets (2)
	(in millions)
Current Assets: Non-trading derivative assets	$	42		$	(6	)	$	36
Other Assets: Non-trading derivative assets	7			(1		)	6
Current Liabilities: Non-trading derivative liabilities	(28		)	14			(14		)
Other Liabilities: Non-trading derivative liabilities	(4		)	2			(2		)
Total	$	17		$	9		$	26

________________


(1)	Gross Amounts Recognized include some derivative assets and liabilities that are not subject to master netting arrangements.


(2)	The derivative assets and liabilities on the Consolidated Balance Sheets exclude accounts receivable or accounts payable that, should they exist, could be used as offsets to these balances in the event of a default.



Fair Value of Derivative Instruments
		June 30, 2013
Total derivatives not designated as hedging instruments	Balance Sheet Location	Derivative Assets Fair Value		Derivative Liabilities Fair Value
		(in millions)
Natural gas derivatives (1) (3)	Current Assets: Non-trading derivative assets	$	27	$	—
Natural gas derivatives (1) (3)	Other Assets: Non-trading derivative assets	7		—
Natural gas derivatives (1) (2) (3)	Current Liabilities: Non-trading derivative liabilities	27		41
Natural gas derivatives (1) (3)	Other Liabilities: Non-trading derivative liabilities	4		7
Total		$	65	$	48

________________


(1)	The fair value shown for natural gas contracts is comprised of derivative gross volumes totaling 695 Bcf or a net 76 Bcf long position. Of the net long position, basis swaps constitute 63 Bcf.


(2)	The $41 million Derivative Current Liability includes $3 million related to physical forwards purchased from Midstream Partnership.

(3)

Natural gas contracts are presented on a net basis in the Condensed Consolidated Balance Sheets. Natural gas contracts are subject to master netting arrangements. This netting applies to all undisputed amounts due or past due and causes derivative assets (liabilities) to be ultimately presented net in a liability (asset) account within the Condensed Consolidated Balance Sheets. The net of total non-trading derivative assets and liabilities was a $21 million asset as shown on CERC’s Condensed Consolidated Balance Sheets (and as detailed in the table below), and was comprised of the natural gas contracts derivative assets and liabilities separately shown above offset by collateral netting of $4 million:



Offsetting of Natural Gas Derivative Assets and Liabilities
	June 30, 2013
	Gross Amounts Recognized (1)			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amount Presented in the Consolidated Balance Sheets (2)
	(in millions)
Current Assets: Non-trading derivative assets	$	38		$	(11	)	$	27
Other Assets: Non-trading derivative assets	7			—			7
Current Liabilities: Non-trading derivative liabilities	(25		)	13			(12		)
Other Liabilities: Non-trading derivative liabilities	(3		)	2			(1		)
Total	$	17		$	4		$	21

________________


(1)	Gross Amounts Recognized include some derivative assets and liabilities that are not subject to master netting arrangements.


(2)	The derivative assets and liabilities on the Consolidated Balance Sheets exclude accounts receivable or accounts payable that, should they exist, could be used as offsets to these balances in the event of a default.

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	2012			2013
		(in millions)
Natural gas derivatives	Gains (Losses) in Revenue	$	(8	)	$	27
Natural gas derivatives (1)	Gains (Losses) in Expense: Natural Gas	13			(18		)
Total		$	5		$	9



Income Statement Impact of Derivative Activity
		Six Months Ended June 30,
Total derivatives not designated as hedging instruments	Income Statement Location	2012			2013
		(in millions)
Natural gas derivatives	Gains (Losses) in Revenue	$	43		$	13
Natural gas derivatives (1) (2)	Gains (Losses) in Expense: Natural Gas	(68		)	(2		)
Total		$	(25	)	$	11

________________


(1)	The Gains (Losses) in Expense: Natural Gas includes $(3) million during both the three months and six months ended June 30, 2013 related to physical forwards purchased from Midstream Partnership.


(2)	The Gains (Losses) in Expense: Natural Gas includes $(38) million and $-0- of costs during the six months ended June 30, 2012 and 2013, 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, 2012 and June 30, 2013 was $5 million and $3 million, respectively. The aggregate fair value of assets that were posted as collateral was less than $1 million at both December 31, 2012 and June 30, 2013. If all derivative contracts (in a net liability position) containing credit risk contingent features were triggered at December 31, 2012 and June 30, 2013, $5 million and $3 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 $2.89 to $4.57 per one million British thermal units (Btu)) as an unobservable input. Level 3 options are valued through Black-Scholes (including forward start) option models which include option volatilities (ranging from 0 to 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. For the six months ended June 30, 2013, there were no transfers between Level 1 and 2 with regard to Natural Gas derivatives. CERC also recognizes purchases of Level 3 financial assets and liabilities at their fair market value at the end of the reporting period.

The following tables present information about CERC’s assets and liabilities (including derivatives that are presented net) measured at fair value on a recurring basis as of December 31, 2012 and June 30, 2013, 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, 2012
	(in millions)
Assets
Corporate equities	$	1	$	—	$	—	$	—		$	1
Investments, including money market funds	11		—		—		—			11
Natural gas derivatives	1		40		7		(6		)	42
Total assets	$	13	$	40	$	7	$	(6	)	$	54
Liabilities
Natural gas derivatives	$	5	$	21	$	5	$	(15	)	$	16
Total liabilities	$	5	$	21	$	5	$	(15	)	$	16

________________


(1)	Amounts represent the impact of legally enforceable master netting arrangements that allow CERC to settle positive and negative positions and also include cash collateral of $9 million posted with the same counterparties.



	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Netting Adjustments ⁽¹⁾			Balance as of June 30, 2013
	(in millions)
Assets
Corporate equities	$	2	$	—	$	—	$	—		$	2
Investments, including money market funds	10		—		—		—			10
Natural gas derivatives	5		33		7		(11		)	34
Total assets	$	17	$	33	$	7	$	(11	)	$	46
Liabilities
Natural gas derivatives (2)	$	6	$	19	$	3	$	(15	)	$	13
Total liabilities	$	6	$	19	$	3	$	(15	)	$	13

________________


(1)	Amounts represent the impact of legally enforceable master netting arrangements that allow CERC to settle positive and negative positions and also include cash collateral of $4 million posted with the same counterparties.


(2)	The (Level 2) Natural gas derivative liability of $19 million includes $3 million related to physical forwards purchased from Midstream Partnership.

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



	Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Derivative Assets and Liabilities, net
	Three Months Ended June 30,					Six Months Ended June 30,
	2012			2013		2012			2013
	(in millions)
Beginning balance	$	3		$	3	$	6		$	2
Total gains ⁽¹⁾	2			1		4			3
Total settlements ⁽¹⁾	(2		)	—		(6		)	(1		)
Transfers out of Level 3	—			—		(1		)	—
Ending balance ⁽²⁾	$	3		$	4	$	3		$	4
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		$	2	$	2		$	3

____________


(1)	CERC did not have Level 3 unrealized gains (losses) or settlements related to price stabilization activities of the Natural Gas Distribution business segment during either the three or six months ended June 30, 2012 or 2013.


(2)	CERC did not have significant Level 3 purchases, sales or transfers into Level 3 during either the three or six months ended June 30, 2012 or 2013.

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, 2012				June 30, 2013
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in millions)
Financial assets:
Notes receivable - affiliated companies	$	—	$	—	$	363	$	360
Financial liabilities:
Long-term debt	$	2,641	$	3,094	$	2,118	$	2,374

(6) Unconsolidated Affiliates

As discussed in Note 1, on May 1, 2013 (the Closing Date) CERC Corp., OGE and ArcLight closed on the formation of Midstream Partnership. Midstream Partnership owns CenterPoint Midstream, which consists of substantially all of CERC Corp.’s former Interstate Pipelines and Field Services business segments. As a result, CERC no longer has Interstate Pipelines and Field Services business segments. Equity earnings associated with CERC's interest in Midstream Partnership and equity earnings associated with its retained 25.05% interest in SESH will be reported under a new Midstream Investments segment. For a further description of CERC's reportable business segments, see Note 12.

The formation of Midstream Partnership by CERC has been considered a contribution of in-substance real estate to a limited partnership. CERC considers the CenterPoint Midstream assets to be in-substance real estate as the businesses are composed of, and reliant upon, substantial real estate assets and integral equipment. Real estate assets and integral equipment primarily includes gas transmission pipelines, compressor station equipment, rights of way, storage and processing assets, and long-term customer

contracts. Accordingly, CERC did not recognize a gain or loss upon contribution and recorded its investment in Midstream Partnership using the equity method of accounting based on the historical cost of the contributed assets and liabilities as of the Closing Date. Approximately $5.8 billion of assets and $1.5 billion of liabilities (which includes the Term Loan and the indebtedness owed to CERC, both discussed below, of $1.05 billion and $363 million, respectively) were contributed by CERC Corp. CERC has the ability to significantly influence the operating and financial policies of Midstream Partnership and, accordingly, recorded an equity method investment of $4.3 billion in Midstream Partnership on the Closing Date. Pursuant to the MFA, CERC retained certain assets and liabilities historically held by CenterPoint Midstream such as balances relating to federal income taxes and benefit plan obligations.

Effective on the Closing Date, CenterPoint Energy and Midstream Partnership entered into a Services Agreement, Employee Transition Agreement, Transitional Services Agreement and other agreements (collectively, Transition Agreements) whereby CERC agreed to provide certain support services to Midstream Partnership such as accounting, legal, risk management and treasury functions. Additionally, to support the operations of Midstream Partnership, CERC provides seconded employees to Midstream Partnership. CERC does not anticipate extending the services provided to Midstream Partnership, including providing seconded employees, beyond December 31, 2014. CERC did not transfer any employees to Midstream Partnership at formation of the partnership or during the three months ended June 30, 2013. CERC billed Midstream Partnership for reimbursement of transitional services, including the costs of seconded employees, during the period from the Closing Date to June 30, 2013 of $28 million under the Transition Agreements. The reimbursement of the transitional services costs are recorded net against the actual expenses incurred in the Condensed Statements of Consolidated Income.

Midstream Partnership, at its discretion, has the right to select and offer employment to seconded employees from CenterPoint Energy. As of June 30, 2013, CERC determined it cannot reasonably estimate the impact of the costs associated with the termination of employees related to the formation of Midstream Partnership or transfer of employees from CERC to Midstream Partnership, including the impact of the changes to the actuarial determination of employee benefit plan obligations. Pursuant to the Transition Agreements, Midstream Partnership has agreed to reimburse CERC for severance and terminations costs related to the termination of CERC's seconded employees, including any potential benefit-related costs, regardless of whether such seconded employees are offered employment by Midstream Partnership.

On the Closing Date, Midstream Partnership entered into a $1.05 billion three-year senior unsecured term loan facility (the Term Loan) with third parties and repaid $1.05 billion of affiliated notes payable (Affiliated Notes Payable) owed to CERC. CERC provided a guarantee of Midstream Partnership's obligations under the Term Loan. The guarantee is subordinated to all senior debt of CERC. Certain of the entities contributed to Midstream Partnership by CERC are obligated on approximately $363 million of indebtedness owed to CERC bearing interest at an annual rate of 2.10% to 2.45% that is scheduled to mature in 2017.

CERC has certain put rights, and Midstream Partnership has certain call rights, exercisable with respect to the 25.05% interest in SESH retained by CERC, under which CERC would contribute to Midstream Partnership CERC's retained interest in SESH, in exchange for a specified number of limited partnership units in Midstream Partnership and a cash payment, payable either from CERC to Midstream Partnership or from Midstream Partnership to CERC for changes in the value of SESH.

As of June 30, 2013, CERC held an approximate 58.3% interest in Midstream Partnership and a 25.05% interest in SESH.

Investment in Unconsolidated Affiliates:



	December 31, 2012		June 30, 2013
	(in millions)
Midstream Partnership	$	—	$	4,285
SESH	404		200
Other	1		—
Total	$	405	$	4,485

Equity in Earnings of Unconsolidated Affiliates, net:



	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2013		2012		2013
	(in millions)
Midstream Partnership	$	—	$	33	$	—	$	33
SESH	6		4		12		9
Other	2		—		5		—
	$	8	$	37	$	17	$	42

Summarized income information for Midstream Partnership from formation on May 1, 2013 through June 30, 2013, based on the contributed assets recorded at historical costs on the Closing Date, is as follows (in millions):



Operating Revenues	$	502
Gross Margin	207
Operating Income	75
Net Income	65

Reconciliation of Equity in Earnings, net
CenterPoint Energy's 58.3% interest	$	38
Amortization of basis difference	(5		)
CenterPoint Energy's equity in earnings, net	$	33

Midstream Partnership concluded that the formation of Midstream Partnership is considered a business combination, and CenterPoint Midstream is the acquirer for accounting purposes. Under this method, the fair value of the consideration paid by CenterPoint Midstream for Enogex is allocated to the assets acquired and liabilities assumed on the Closing Date based on their fair value. Enogex's assets, liabilities and equity will accordingly be adjusted to estimated fair value as of May 1, 2013. Determining the fair value of certain assets and liabilities assumed is judgmental in nature and often involves the use of significant estimates and assumptions. Midstream Partnership is using appraisers to assist in the determination of fair value of certain assets. Midstream Partnership's valuation is expected to be finalized in the third quarter of 2013, and the estimated fair value of the assets as of June 30, 2013, and the related depreciation and amortization for the two month period ended June 30, 2013, may be significantly different from its initial estimate. CERC does not expect that its equity in earnings, net, of Midstream Partnership in the second quarter of 2013 will be materially different as a result of the fair value determination.

As such, CERC has estimated its 58.3% interest in the net income for Midstream Partnership for the period May 1, 2013 through June 30, 2013 to be approximately $33 million. CERC expects additional depreciation and amortization to be incurred by Midstream Partnership on the step-up of Enogex's assets which will inversely affect CERC's recognition of the basis difference between its equity method investment and its proportionate share of the interest in the equity of Midstream Partnership on the Closing Date.

(7) Goodwill

Goodwill by reportable business segment as of December 31, 2012 and changes in the carrying amount of goodwill as of June 30, 2013 are as follows (in millions):



	December 31, 2012		Contributed to Midstream Partnership		June 30, 2013
Natural Gas Distribution	$	746	$	—	$	746
Interstate Pipelines	579		579		—
Competitive Natural Gas Sales and Services	83		—		83
Field Services	49		49		—
Other Operations	11		—		11
Total	$	1,468	$	628	$	840

(8) Related Party Transactions

CERC participates in a “money pool” through which it can borrow or invest on a short-term basis. Funding needs are aggregated and external borrowing or investing is based on the net cash position. The net funding requirements of the money pool are expected to be met with borrowings under CenterPoint Energy’s revolving credit facility or the sale of CenterPoint Energy’s commercial paper. CERC had money pool borrowings of $779 million and $11 million at December 31, 2012 and June 30, 2013, 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 $1 million and $2 million for the three and six months ended June 30, 2012, respectively, and net interest expense of less than $1 million and $1 million for the three and six months ended June 30, 2013, respectively.

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 $41 million and $23 million for the three months ended June 30, 2012 and 2013, respectively, and $81 million and $60 million for the six months ended June 30, 2012 and 2013, respectively, and are included primarily in operation and maintenance expenses.

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

(a)Short-term Borrowings

Inventory Financing. Gas Operations has asset management agreements associated with its utility distribution service in Arkansas, north Louisiana and Oklahoma that extend through 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 had an associated principal obligation of $38 million and $37 million as of December 31, 2012 and June 30, 2013, respectively.


(b)	Long-term Debt

Debt Repayments. In April 2013, CERC Corp. retired approximately $365 million aggregate principal amount of its 7.875% senior notes at their maturity. The retirement of senior notes was financed by CERC Corp. with the issuance of commercial paper. In May 2013, CERC Corp. applied proceeds from Midstream Partnership's May 1, 2013 debt repayment of $1.05 billion to the repayment of $357 million aggregate principal amount of its commercial paper and to the May 31, 2013 redemption of $160 million aggregate principal amount of its 5.95% senior notes due January 15, 2014 at 103.419% of their aggregate principal amount.

Revolving Credit Facility. As of December 31, 2012 and June 30, 2013, CERC had the following revolving credit facility and utilization of such facility (in millions):



		December 31, 2012						June 30, 2013
Size of Facility		Loans		Letters of Credit		Commercial Paper		Loans		Letters of Credit		Commercial Paper
$	950	$	—	$	—	$	—	$	—	$	—	$	—

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

(10) Commitments and Contingencies

(a) Natural Gas Supply Commitments

Natural gas supply commitments include natural gas contracts related to CERC’s Natural Gas Distribution and Competitive Natural Gas Sales and Services business segments, which have various quantity requirements and durations, that are not classified as non-trading derivative assets and liabilities in CERC’s Condensed Consolidated Balance Sheets as of December 31, 2012 and June 30, 2013 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, 2013, minimum payment obligations for natural gas supply commitments are approximately $134 million for the remaining six months in 2013, $277 million in 2014, $214 million in 2015, $150 million in 2016, $99 million in 2017 and $162 million after 2017.

(b) Legal, Environmental and Other Regulatory Matters

Legal Matters

Gas Market Manipulation Cases. CenterPoint Energy, CenterPoint Houston or their predecessor, Reliant Energy, Incorporated (Reliant Energy), and certain of their former subsidiaries have been named as defendants in certain lawsuits described below. Under a master separation agreement between CenterPoint Energy and a former subsidiary, Reliant Resources, Inc. (RRI), CenterPoint Energy and its subsidiaries are entitled to be indemnified by RRI and its successors for any losses, including certain attorneys’ fees and other costs, arising out of these lawsuits. In May 2009, RRI sold its Texas retail business to a subsidiary of NRG Energy, Inc. (NRG) and RRI changed its name to RRI Energy, Inc. In December 2010, Mirant Corporation merged with and became a wholly owned subsidiary of RRI, and RRI changed its name to GenOn Energy, Inc. (GenOn). In December 2012, NRG acquired GenOn through a merger in which GenOn became a wholly owned subsidiary of NRG. None of the sale of the retail business, the merger with Mirant Corporation, or the acquisition of GenOn by NRG alters RRI’s (now GenOn’s) contractual obligations to indemnify CenterPoint Energy and its subsidiaries, including CenterPoint Houston, for certain liabilities, including their indemnification obligations regarding the gas market manipulation litigation, nor does it affect the terms of existing guaranty arrangements for certain GenOn gas transportation contracts discussed below.

A large number of lawsuits were filed against numerous gas market participants in a number of federal and western state courts in connection with the operation of the natural gas markets in 2000-2002. CenterPoint Energy’s former affiliate, RRI, was a participant in gas trading in the California and Western markets. These lawsuits, many of which were filed as class actions, allege violations of state and federal antitrust laws. Plaintiffs in these lawsuits are seeking a variety of forms of relief, including, among others, recovery of compensatory damages (in some cases in excess of $1 billion), a trebling of compensatory damages, full consideration damages and attorneys’ fees. CenterPoint Energy and/or Reliant Energy were named in approximately 30 of these lawsuits, which were instituted between 2003 and 2009. CenterPoint Energy and its affiliates have since been released or dismissed from all but one such case. 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 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 appealed this ruling to the United States Court of Appeals for the Ninth Circuit, which reversed the trial court's dismissal of the plaintiffs' claims. The other defendants may seek further review by filing a writ of certiorari with the U.S. Supreme Court. CenterPoint Energy believes that CES is not a proper defendant in this case and will continue to pursue a dismissal. CERC does not expect the ultimate outcome of this matter to have a material impact on its financial condition, results of operations or cash flows. Additionally, CenterPoint Energy was a defendant in a lawsuit filed in state court in Nevada that was dismissed in 2007. In September 2012, the Nevada Supreme Court affirmed the dismissal. In June 2013, the Supreme Court of the United States denied plaintiffs’ petition for writ of certiorari and this matter is now concluded.

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, 2013, CERC had recorded a liability of $13 million for remediation of these Minnesota sites. The estimated range of possible remediation costs for the sites for which CERC believes it may have responsibility 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 ongoing remediation costs. As of June 30, 2013, CERC had collected $6 million from insurance companies to be used for future environmental remediation.

In addition to the Minnesota sites, the United States Environmental Protection Agency and other regulators have investigated MGP sites that were owned or operated by CERC or may have been owned by one of its former affiliates. CERC and CenterPoint

Energy do not expect the ultimate outcome of these investigations will have a material adverse impact on the financial condition, results of operations or cash flows of either CenterPoint Energy or CERC.

Asbestos. Some facilities owned by CERC's predecessors contain or have contained asbestos insulation and other asbestos-containing materials. CERC or its predecessor companies have been named, along with numerous others, as a defendant in lawsuits filed by a number of individuals who claim injury due to exposure to asbestos. Some of the claimants have worked at locations owned by CERC, but most existing claims relate to facilities previously owned by CERC's subsidiaries. CERC anticipates that additional claims like those received may be asserted in the future. Although their ultimate outcome cannot be predicted at this time, CERC intends to continue vigorously contesting claims that it does not consider to have merit and, based on its experience to date, does not expect these matters, either individually or in the aggregate, to have a material adverse effect on its financial condition, results of operations or cash flows.

Other Environmental. From time to time CERC identifies the presence of environmental contaminants on property where it conducts or has conducted operations. Other such sites involving contaminants may be identified in the future. CERC has remediated 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.

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 $66 million as of June 30, 2013. Based on market conditions in the fourth quarter of 2012 at the time the most recent annual calculation was made under the agreement, GenOn was not obligated to post any security. If GenOn should fail to perform the contractual obligations, CERC could have to honor its guarantee and, in such event, any collateral then provided as security may be insufficient to satisfy CERC’s obligations.

CenterPoint Energy, Inc. has provided guarantees (CenterPoint Midstream Guarantees) with respect to the performance of certain obligations of Midstream Partnership under long-term gas gathering and treating agreements with an indirect wholly owned subsidiary of Encana Corporation and an indirect wholly owned subsidiary of Royal Dutch Shell plc. As of June 30, 2013, CenterPoint Energy, Inc. had guaranteed Midstream Partnership's obligations up to an aggregate amount of $100 million under these agreements. CERC Corp. has provided guarantees (CERC Midstream Guarantees) with respect to the performance of certain obligations of Midstream Partnership, CEGT and MRT under certain contractual arrangements with third parties, which guarantees are scheduled to expire between July 2013 and December 2018. The maximum aggregate amount payable by CERC Corp. under these guarantees is $157.2 million. The aggregate dollar amount of the obligations covered by the CERC Midstream Guarantees varies over time. The obligations supported by the CERC Midstream Guarantees for the months of June and July 2013 totaled less than $1 million. Under the terms of the omnibus agreement entered into in connection with the closing of the formation of Midstream Partnership, Midstream Partnership and CenterPoint Energy, Inc. have agreed to use commercially reasonable efforts and cooperate with each other to terminate the CenterPoint Midstream Guarantees and the CERC Midstream Guarantees, and to release CenterPoint Energy, Inc. or CERC Corp. from such guarantees on or prior to October 28, 2013 by causing Midstream Partnership or one of its subsidiaries to enter into substitute guarantees or to assume the CenterPoint Midstream Guarantees or CERC Midstream Guarantees, as applicable.

CERC Corp. has also provided a guarantee of collection of Midstream Partnership's obligations under its $1.05 billion three-year unsecured term loan facility, which guarantee is subordinated to all senior debt of CERC Corp.

(11) Income Taxes

The effective tax rate for the three and six months ended June 30, 2013 was 418% and 113%, respectively, compared to 40% and 39% for the same period in 2012. The higher effective tax rate for the three and six months ended June 30, 2013 was primarily associated with the formation of Midstream Partnership. As a result of the formation of Midstream Partnership, a deferred tax liability of $225 million was recorded for the book-to-tax basis differences in CERC's investment resulting from the goodwill that was contributed by CERC. In addition, CERC recognized a tax benefit of $27 million associated with the remeasurement of state deferred taxes related to Midstream Partnership formation.

The following table summarizes CERC’s unrecognized tax benefits (expenses) at December 31, 2012 and June 30, 2013:



	December 31, 2012			June 30, 2013
	(in millions)
Unrecognized tax expenses	$	(20	)	$	(21	)
Portion of unrecognized tax expenses that, if recognized, would increase the effective income tax rate	—			—
Interest accrued on unrecognized tax expenses	(7		)	(7		)

CERC does not expect the change to the amount of unrecognized tax expenses over the twelve months ending June 30, 2014 to materially impact the financial position of CERC.

CenterPoint Energy's consolidated federal income tax returns have been audited by the Internal Revenue Service (IRS) and settled through the 2009 tax year. CenterPoint Energy has filed claims for income tax refunds that are pending review by the IRS for tax years 2002, 2003 and 2004. CenterPoint Energy is currently under examination by the IRS for tax years 2010 and 2011. CERC has considered the effects of these examinations in its accrual for settled issues and liability for uncertain income tax positions as of June 30, 2013.

On July 9, 2013 CenterPoint Energy received notification that the Joint Committee of Taxation had approved its outstanding tax claims related to the 2002 and 2003 audit cycles. CenterPoint Energy will record the effects of the settlement in the third quarter of 2013.

(12) Reportable Business Segments

Because CERC is an indirect wholly owned subsidiary of CenterPoint Energy, CERC’s determination of reportable business segments considers the strategic operating units under which CenterPoint Energy manages sales, allocates resources and assesses performance of various products and services to wholesale or retail customers in differing regulatory environments. CERC uses operating income as the measure of profit or loss for its business segments.

CERC’s reportable business segments include the following: Natural Gas Distribution, Competitive Natural Gas Sales and Services, Midstream Investments 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. Midstream Investments consists primarily of CERC’s investment in Midstream Partnership and its retained interest in SESH. The Other Operations business segment includes unallocated corporate costs and inter-segment eliminations.

Prior to May 1, 2013, CERC also reported an Interstate Pipelines business segment, which included CERC’s interstate natural gas pipeline operations, and a Field Services business segment, which included CERC’s non-rate regulated natural gas gathering, processing and treating operations. As previously announced, the formation of CERC’s midstream partnership with OGE and ArcLight closed on May 1, 2013. Midstream Partnership now owns CERC’s former Interstate Pipelines and Field Services business segments, except the retained interest in SESH. As a result, effective May 1, 2013, CERC reports equity earnings associated with its interest in Midstream Partnership and equity earnings associated with its retained interest in SESH under a new Midstream Investments segment, and no longer has Interstate Pipelines and Field Services reporting segments prospectively.

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



	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 Three Months Ended June 30, 2013
	Revenues from External Customers			Inter-segment Revenues				Operating Income (Loss)
Natural Gas Distribution	$	524		$	5			$	25
Competitive Natural Gas Sales and Services	622			6				3
Interstate Pipelines	41		⁽¹⁾	13			⁽¹⁾	20			⁽¹⁾
Field Services	48		⁽¹⁾	7			⁽¹⁾	20			⁽¹⁾
Midstream Investments	—			—				—			⁽²⁾
Other	—			—				(12		)
Reconciling Eliminations	—			(31		)		—
Consolidated	$	1,235		$	—			$	56

	For the Six Months Ended June 30, 2012
	Revenues from External Customers			Inter-segment Revenues				Operating Income (Loss)				Total Assets as of December 31, 2012
Natural Gas Distribution	$	1,209		$	11			$	130			$	4,775
Competitive Natural Gas Sales and Services	822			11				(3		)		839
Interstate Pipelines	170			82				112				4,004
Field Services	195			14				98				2,453
Other	—			—				(2		)		647
Reconciling Eliminations	—			(118		)		—				(1,528		)
Consolidated	$	2,396		$	—			$	335			$	11,190

	For the Six Months Ended June 30, 2013
	Revenues from External Customers			Inter-segment Revenues				Operating Income (Loss)				Total Assets as of June 30, 2013
Natural Gas Distribution	$	1,567		$	13			$	164			$	4,685
Competitive Natural Gas Sales and Services	1,210			15				10				831
Interstate Pipelines	133		⁽¹⁾	53			⁽¹⁾	72			⁽¹⁾	—
Field Services	178		⁽¹⁾	18			⁽¹⁾	73			⁽¹⁾	—
Midstream Investments	—			—				—				4,485			⁽²⁾
Other	—			—				(13		)		899
Reconciling Eliminations	—			(99		)		—				(955		)
Consolidated	$	3,088		$	—			$	306			$	9,945


(1)	Results reflected in the three months ended June 30, 2013 represent only the month of April 2013. Results reflected in the six months ended June 30, 2013 represent only January 2013 through April 2013.

(2)

Midstream Investments reported equity earnings of $33 million from Midstream Partnership and $2 million of equity earnings from CenterPoint Energy’s retained interest in SESH for the months of May and June 2013. Included in total assets of Midstream Investments as of June 30, 2013 is $4,285 million related to CenterPoint Energy’s investment in Midstream Partnership and $200 million related to CenterPoint Energy’s retained interest in SESH.

(13) Other Current Assets and Liabilities

Included in other current assets on the Condensed Consolidated Balance Sheets at December 31, 2012 and June 30, 2013 were $12 million and $9 million, respectively, of margin deposits and $86 million and $23 million, respectively, of under-recovered gas cost. Included in other current liabilities on the Condensed Consolidated Balance Sheets at December 31, 2012 and June 30, 2013 were $6 million and $53 million, respectively, of over-recovered gas cost.

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, 2012 (2012 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, 2012 and the three and six months ended June 30, 2013. Reference is made to “Management's Narrative Analysis of Results of Operations” in Item 7 of our 2012 Form 10-K.

EXECUTIVE SUMMARY

Recent Events

Midstream Partnership. As previously disclosed, on March 14, 2013, CenterPoint Energy, Inc. (CenterPoint Energy) entered into a Master Formation Agreement (MFA) with OGE Energy Corp. (OGE) and affiliates of ArcLight Capital Partners, LLC (ArcLight), pursuant to which CenterPoint Energy, OGE and ArcLight agreed to form a midstream partnership (Midstream Partnership) as a private limited partnership. On May 1, 2013, the parties closed on the formation of Midstream Partnership pursuant to the terms of the MFA. In connection with the closing (i) CenterPoint Energy Resources Corp. (CERC Corp.) converted its direct wholly owned subsidiary, CenterPoint Energy Field Services, LLC, a Delaware limited liability company (CEFS), into a Delaware limited partnership that became Midstream Partnership and was subsequently renamed Enable Midstream Partners, LP, (ii) we contributed to Midstream Partnership our equity interests in each of CenterPoint Energy Gas Transmission Company, LLC (CEGT), CenterPoint Energy - Mississippi River Transmission, LLC (MRT), certain of our other midstream subsidiaries, and a 24.95% interest in Southeast Supply Header, LLC (SESH), and (iii) OGE and ArcLight indirectly contributed 100% of the equity interests in Enogex LLC to Midstream Partnership. Midstream Partnership owns substantially all of our former Interstate Pipelines and Field Services business segments, except for our retained 25.05% interest in SESH.

CERC Corp. holds approximately 58.3% of the limited partner interests, OGE holds approximately 28.5% of the limited partner interests, and ArcLight holds approximately 13.2% of the limited partner interests in Midstream Partnership. Midstream Partnership is equally controlled by CERC Corp. and OGE; each own 50% of the management rights in the general partner of Midstream Partnership. CERC Corp. and OGE will also own a 40% and 60% interest, respectively, in any incentive distribution rights to be held by the general partner of Midstream Partnership following an initial public offering of Midstream Partnership. The general partner of Midstream Partnership is governed by a board made up of an equal number of representatives designated by each of CERC Corp. and OGE.

In connection with the closing, Midstream Partnership (i) entered into a $1.05 billion three-year senior unsecured term loan facility, (ii) repaid $1.05 billion of indebtedness owed to CERC, and (iii) entered into a $1.4 billion senior unsecured revolving credit facility.

As a result of the formation of Midstream Partnership, we no longer report Interstate Pipelines and Field Services business segments. Equity earnings associated with the our interest in Midstream Partnership and equity earnings associated with our retained 25.05% interest in SESH are reported under a new Midstream Investments segment. For a further description of our reportable business segments, see Note 12 to our Interim Condensed Consolidated Financial Statements.

In August 2012, CenterPoint Energy-Mississippi River Transmission, LLC (MRT), a subsidiary of Midstream Partnership and an interstate pipeline that provides natural gas transportation, natural gas storage and pipeline services to customers principally in Arkansas, Illinois and Missouri, made a rate filing with the Federal Energy Regulatory Commission (FERC) pursuant to Section 4 of the Natural Gas Act. In its filing, MRT requested an annual cost of service of $103.8 million (an increase of approximately $47.3 million above the annual cost of service underlying the current FERC approved maximum rates for MRT's pipeline), new depreciation rates, an overall rate of return of 10.813% (based on a return on equity of 13.62%), a regulatory compliance cost (RCC) surcharge with a true-up mechanism to recover safety, environmental, and security costs associated with mandated requirements and billing determinants reflecting no adjustments for MRT's conversion of a portion of CEGT's firm capacity to a lease. In August 2012, a number of parties filed protests in response to MRT's rate filing. In September 2012, the FERC issued an order accepting MRT's filing, suspending the filed tariff rates for the full statutorily permitted five month suspension period and setting certain issues for

hearing. Following continued negotiations with its customers, on July 25, 2013, MRT filed a motion to suspend the procedural schedule for the proceeding, which motion was granted on July 26, 2013. On July 30, 2013, MRT filed with the FERC an uncontested Stipulation and Agreement and Offer of Settlement, resolving all issues in the rate case. In particular, MRT withdrew its proposed RCC surcharge. The settlement specifies few particulars, other than setting an annual overall cost-of-service for MRT of $84.0 million and increasing the depreciation rates for certain asset classes. MRT expects FERC approval of the settlement either late in the third quarter or early in the fourth quarter of 2013, with the settlement rates going into effect thereafter. MRT will be making refunds to certain of its customers for amounts collected between the requested $103.8 million cost of service and the $84.0 million settlement cost of service.

Debt Matters. In April 2013, we retired approximately $365 million aggregate principal amount of our 7.875% senior notes at their maturity. The retirement of senior notes was financed with the issuance of commercial paper.

In May 2013, we applied proceeds from Midstream Partnership's May 1, 2013 debt repayment of $1.05 billion to the repayment of $357 million aggregate principal amount of our commercial paper and to the May 31, 2013 redemption of $160 million aggregate principal amount of our 5.95% senior notes due January 15, 2014 at 103.419% of their aggregate principal amount.

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 2012 Form 10-K, in Item 1A of Part II of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2013 (First Quarter Form 10-Q) and in Item 1A of Part II of this Form 10-Q.

The following table sets forth our consolidated results of operations for the three and six months ended June 30, 2012 and 2013, followed by a discussion of our consolidated results of operations.



	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2013			2012			2013
	(in millions)
Revenues	$	846		$	1,235		$	2,396		$	3,088
Expenses:
Natural gas	409			852			1,378			2,076
Natural gas-affiliates	—			28			—			28
Operation and maintenance	228			209			467			460
Depreciation and amortization	70			56			139			133
Taxes other than income taxes	33			34			77			85
Total	740			1,179			2,061			2,782
Operating Income	106			56			335			306
Interest and other finance charges	(44		)	(37		)	(89		)	(82		)
Equity in earnings of unconsolidated affiliates	8			37			17			42
Other expense, net	—			(5		)	—			(5		)
Income Before Income Taxes	70			51			263			261
Income tax expense	28			213			103			295
Net Income (Loss)	$	42		$	(162	)	$	160		$	(34	)

Three months ended June 30, 2013 compared to three months ended June 30, 2012

We reported a net loss of $162 million for the three months ended June 30, 2013 compared to net income of $42 million for the same period in 2012. The decrease in net income of $204 million was primarily due to a $185 million increase in income tax expense as further discussed below, a $50 million decrease in operating income (discussed below by segment) and a $5 million increase in other expense, which were partially offset by a $29 million increase in equity earnings of unconsolidated affiliates and a $7 million decrease in interest expense.

Six months ended June 30, 2013 compared to six months ended June 30, 2012

We reported a net loss of $34 million for the six months ended June 30, 2013 compared to net income of $160 million for the same period in 2012. The decrease in net income of $194 million was primarily due to a $192 million increase in income tax expense as further discussed below, a $29 million decrease in operating income (discussed below by segment) and a $5 million increase in other expense, which were partially offset by a $25 million increase in equity earnings of unconsolidated affiliates and a $7 million decrease in interest expense.

Income Tax Expense. Our effective tax rate for the three and six months ended June 30, 2013 was 418% and 113%, compared to 40% and 39% for the same periods in 2012. The higher effective tax rate for the three and six months ended June 30, 2013 was primarily associated with the formation of Midstream Partnership. As a result of the formation of Midstream Partnership, a deferred tax liability of $225 million was recorded for the book-to-tax basis difference in our investment resulting from the goodwill that we contributed.

In addition, we recognized a tax benefit of $27 million associated with the remeasurement of state deferred taxes related to Midstream Partnership formation.

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, 2012 and 2013, 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,
	2012			2013				2012			2013
	(in millions)
Natural Gas Distribution	$	9		$	25			$	130		$	164
Competitive Natural Gas Sales and Services	(4		)	3				(3		)	10
Interstate Pipelines	52			20			⁽¹⁾	112			72			⁽²⁾
Field Services	51			20			⁽¹⁾	98			73			⁽²⁾
Other Operations	(2		)	(12		)		(2		)	(13		)
Total Consolidated Operating Income	$	106		$	56			$	335		$	306

_______________


(1)	Represents April 2013 results only.


(2)	Represents January 2013 through April 2013 results only.

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 2012 Form 10-K and in Item 1A of Part II of our First Quarter Form 10-Q.

The following table provides summary data of our Natural Gas Distribution business segment for the three and six months ended June 30, 2012 and 2013 (in millions, except throughput and customer data):



	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2013		2012		2013
Revenues	$	366	$	529	$	1,220	$	1,580
Expenses:
Natural gas	136		268		629		924
Operation and maintenance	156		160		319		330
Depreciation and amortization	43		46		86		91
Taxes other than income taxes	22		30		56		71
Total expenses	357		504		1,090		1,416
Operating Income	$	9	$	25	$	130	$	164
Throughput (in billion cubic feet (Bcf)):
Residential	16		25		78		105
Commercial and industrial	52		56		126		142
Total Throughput	68		81		204		247
Number of customers at end of period:
Residential	3,020,913		3,051,621		3,020,913		3,051,621
Commercial and industrial	243,262		244,215		243,262		244,215
Total	3,264,175		3,295,836		3,264,175		3,295,836

Three months ended June 30, 2013 compared to three months ended June 30, 2012

Our Natural Gas Distribution business segment reported operating income of $25 million for the three months ended June 30, 2013 compared to $9 million for the three months ended June 30, 2012. Operating income increased $16 million due to increased usage primarily due to colder weather as compared to the prior year period, partially mitigated by weather hedges and weather normalization adjustments ($12 million), rate increases ($4 million) and increased economic activity across our footprint including the addition of approximately 32,000 customers ($3 million). These increases were partially offset by an increase in depreciation ($3 million) and an increase in property taxes ($2 million). Operation and maintenance expenses were essentially flat excluding increased expenses related to energy efficiency programs ($4 million), which were offset by related revenues. Increased expenses related to higher gross receipt taxes ($6 million) were also offset by the related revenues.

Six months ended June 30, 2013 compared to six months ended June 30, 2012

Our Natural Gas Distribution business segment reported operating income of $164 million for the six months ended June 30, 2013 compared to $130 million for the six months ended June 30, 2012. Operating income increased $34 million due to increased usage primarily due to colder weather as compared to the prior year period, partially mitigated by weather hedges and weather normalization adjustments ($29 million), rate increases ($6 million), and increased economic activity across our footprint, including the addition of approximately 32,000 customers ($5 million). These increases were partially offset by an increase in depreciation ($5 million) and an increase in property taxes ($2 million). Operation and maintenance expenses were essentially flat excluding increased expenses related to energy efficiency programs ($11 million), which were offset by related revenues. Increased expenses related to higher gross receipt taxes ($14 million) were also 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 2012 Form 10-K and in Item 1A of Part II of our First Quarter Form 10-Q.

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, 2012 and 2013 (in millions, except throughput and customer data):



	Three Months Ended June 30,					Six Months Ended June 30,
	2012			2013		2012			2013
Revenues	$	308		$	628	$	833		$	1,225
Expenses:
Natural gas	300			612		811			1,190
Operation and maintenance	10			11		22			22
Depreciation and amortization	1			1		2			2
Taxes other than income taxes	1			1		1			1
Total expenses	312			625		836			1,215
Operating Income (Loss)	$	(4	)	$	3	$	(3	)	$	10
Throughput (in Bcf)	127			137		288			299
Number of customers at end of period	15,567			17,190		15,567			17,190

Three months ended June 30, 2013 compared to three months ended June 30, 2012

Our Competitive Natural Gas Sales and Services business segment reported operating income of $3 million for the three months ended June 30, 2013 compared to an operating loss of $4 million for the three months ended June 30, 2012. The increase in operating income of $7 million is primarily due to a $10 million improvement from mark-to-market accounting offset by a $3 million inventory write down to the lower of cost or market and a $1 million increase in operation and maintenance expenses. Specifically, the mark-to-market accounting impact for derivatives associated with certain forward natural gas purchases and sales used to lock in economic margins was a positive $6 million for the second quarter of 2013 compared to a $4 million charge for the same period of 2012.

Six months ended June 30, 2013 compared to six months ended June 30, 2012

Our Competitive Natural Gas Sales and Services business segment reported operating income of $10 million for the six months ended June 30, 2013 compared to an operating loss of $3 million for the six months ended June 30, 2012. The increase in operating income of $13 million is primarily due to a $7 million increase generated from higher margins and lower fixed costs from the expiration of uneconomic transportation and storage contracts and a $6 million improvement from mark-to-market accounting. The first half of 2013 included a $1 million benefit 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 charges of $5 million for the same period of 2012. Write-downs of natural gas inventory to the lower of cost or market were $3 million for the first half of 2013 and $4 million for the first half of 2012. Throughput volumes and the number of customers increased in the first two quarters of 2013 compared to the first two quarters of 2012 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 2012 Form 10-K, in Item 1A of Part II of our First Quarter Form 10-Q and in Item 1A of Part II of this Form 10-Q.

The following table provides summary data of our Interstate Pipelines business segment for the three and six months ended June 30, 2012 and 2013 (in millions, except throughput data):



	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2013 (1)		2012		2013 (2)

Revenues	$	125	$	54	$	252	$	186
Expenses:
Natural gas	14		15		21		35
Operation and maintenance	36		13		74		51
Depreciation and amortization	14		5		28		20
Taxes other than income taxes	9		1		17		8
Total expenses	73		34		140		114
Operating Income	$	52	$	20	$	112	$	72

Equity in earnings of unconsolidated affiliates	$	6	$	2	$	12	$	7

Transportation throughput (in Bcf)	346		117		724		482

______________


(1)	Represents April 2013 results only.


(2)	Represents January 2013 through April 2013 results only.

Three months ended June 30, 2013 compared to three months ended June 30, 2012

Our Interstate Pipeline business segment reported operating income of $20 million for the three months ended June 30, 2013 compared to $52 million for the three months ended June 30, 2012. Substantially all of this segment was contributed to Midstream Partnership on May 1, 2013, so results for the three months ended June 30, 2013 are not comparable to the same period in the prior year. Effective May 1, 2013, our equity method investment and related equity income in Midstream Partnership are included in our Midstream Investments segment.

Equity Earnings. In addition, this business segment recorded equity income from its ownership in the Southeast Supply Header (SESH), a jointly owned pipeline, of $6 million and $2 million for the three months ended June 30, 2012 and 2013, respectively. The decrease was primarily due to the contribution of a 24.95% interest in SESH to Midstream Partnership. Second quarter of 2013 equity earnings includes $2 million from our 50% interest in SESH for the month of April 2013. Beginning May 1, 2013, equity earnings related to the transferred interest in SESH as well as our remaining 25.05% interest are reported as components of Midstream Investments equity income.

Six months ended June 30, 2013 compared to six months ended June 30, 2012

Our Interstate Pipeline business segment reported operating income of $72 million for the six months ended June 30, 2013 compared to $112 million for the six months ended June 30, 2012. Substantially all of this segment was contributed to Midstream Partnership on May 1, 2013, so results for the six months ended June 30, 2013 are not comparable to the same period in the prior year. Effective May 1, 2013, our equity method investment and related equity income in Midstream Partnership are included in our Midstream Investments segment.

Equity Earnings. In addition, this business segment recorded equity income from its ownership in SESH, a jointly owned pipeline, of $12 million and $7 million for the six months ended June 30, 2012 and 2013, respectively. The decrease was primarily due to the contribution of a 24.95% interest in SESH to Midstream Partnership as discussed above.

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 2012 Form 10-K, in Item 1A of Part II of our First Quarter Form 10-Q and in Item 1A of Part II of this Form 10-Q.

The following table provides summary data of our Field Services business segment for the three and six months ended June 30, 2012 and 2013 (in millions, except throughput data):



	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2013 (1)		2012		2013 (2)

Revenues	$	104	$	55	$	209	$	196
Expenses:
Natural gas	15		16		33		54
Operation and maintenance	26		13		53		45
Depreciation and amortization	11		5		22		20
Taxes other than income taxes	1		1		3		4
Total expenses	53		35		111		123
Operating Income	$	51	$	20	$	98	$	73

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

Gathering throughput (in Bcf)	233		62		470		252

______________


(1)	Represents April 2013 results only.


(2)	Represents January 2013 through April 2013 results only.

Three months ended June 30, 2013 compared to three months ended June 30, 2012

Our Field Services business segment reported operating income of $20 million for the three months ended June 30, 2013 compared to $51 million for the three months ended June 30, 2012. Substantially all of this segment was contributed to Midstream Partnership on May 1, 2013, so results for the three months ended June 30, 2013 are not comparable to the same period in the prior year. Effective May 1, 2013, our equity method investment and related equity income in Midstream Partnership are included in our Midstream Investments segment.

Equity Earnings. In addition, this business segment recorded equity income of $2 million for the three months ended June 30, 2012 from its 50% general partnership interest in Waskom Gas Processing Company (Waskom) and is included in Equity in Earnings under the Other Income (Expense) caption. From August 1, 2012 through April 30, 2013, financial results for Waskom are included in operating income. On May 1, 2013, our 100% investment in Waskom was contributed to Midstream Partnership.

Six months ended June 30, 2013 compared to six months ended June 30, 2012

Our Field Services business segment reported operating income of $73 million for the six months ended June 30, 2013 compared to $98 million for the six months ended June 30, 2012. Substantially all of this segment was contributed to Midstream Partnership on May 1, 2013, so results for the six months ended June 30, 2013 are not comparable to the same period in the prior year. Effective May 1, 2013, our equity method investment and related equity income in Midstream Partnership are included in our Midstream Investments segment.

Equity Earnings. In addition, this business segment recorded equity income of $5 million for the six months ended June 30, 2012 from its 50% general partnership interest in Waskom and is included in Equity in Earnings under the Other Income (Expense) caption. From August 1, 2012 through April 30, 2013, financial results for Waskom are included in operating income. On May 1, 2013, our 100% investment in Waskom was contributed to Midstream Partnership.

Midstream Investments

For information regarding factors that may affect the future results of operations of our Midstream Investments business segment, please read “Risk Factors ─ Risk Factors Affecting Our Natural Gas Distribution, Competitive Natural Gas Sales and Services, Interstate Pipelines and Field Services Businesses,” “─ Risk Factors Associated with Our Consolidated Financial Condition” and “─ Risks Common to Our Businesses and Other Risks” in Item 1A of Part I of our 2012 Form 10-K, Item 1A of Part II of our First Quarter Form 10-Q and Item 1A of Part II of this Form 10-Q.

In the second quarter of 2013, we reported pre-tax equity income of $33 million from our 58.3% limited partner interest in Midstream Partnership that was formed on May 1, 2013. Additionally, we reported $2 million of pre-tax equity income from our 25.05% interest in SESH for the months of May and June 2013. Midstream Partnership results for the two months ended June 30, 2013, were consistent with management's expectations in light of lower natural gas liquids prices and low seasonal and geographic price differentials. Midstream Partnership continued to increase gathering and processing capacity through system expansions. Transportation throughput was impacted by system integrity projects and slightly lower demand.

Midstream Partnership Operating Data during the two months ended June 30, 2013



		Two Months Ended June 30, 2013
Natural gas gathered volumes - Trillion British Thermal Units per day (TBtu/d)		3.56
Natural gas transportation volumes - TBtu/d		5.19
Natural gas processed volumes - TBtu/d		1.44

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 2012 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 2012 Form 10-K, “Risk Factors” in Item 1A in Part II of our First Quarter Form 10-Q and in Item 1A of Part II of this Form 10-Q 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 and distribution operations. These capital expenditures relate to reliability, safety and system expansions. Our principal cash requirements for the remaining six months of 2013 include approximately $249 million of capital expenditures.

We expect that borrowings under our credit facility, proceeds from commercial paper, anticipated cash flows from operations, intercompany borrowings and distributions from Midstream Partnership will be sufficient to meet our anticipated cash needs for the remaining six months of 2013.

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 described 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 $66 million as of June 30, 2013. Based on

market conditions in the fourth quarter of 2012 at the time the most recent annual calculation was made under the agreement, GenOn was not obligated to post any security. If GenOn should fail to perform the contractual obligations, we could have to honor our guarantee and, in such event, any collateral provided as security may be insufficient to satisfy our obligations.

Regulatory Matters. Significant regulatory developments that have occurred since our First Quarter Form 10-Q was filed with the Securities and Exchange Commission (SEC) are discussed below.

Gas Operations

Houston and South Texas Gas Reliability Infrastructure Programs (GRIP). The natural gas distribution business of CERC’s (Gas Operations) Houston and South Texas Divisions each submitted annual GRIP filings on March 28, 2013. For the Houston Division, the filing was to recover costs related to $55.8 million in incremental capital expenditures that were incurred in 2012. The increase in revenue requirements for this filing period is $10.7 million annually based on an authorized rate of return of 8.65%. For the South Texas Division, the filing was to recover costs related to $17.5 million in incremental capital expenditures that were incurred in 2012. The increase in revenue requirements for this filing period is $2.9 million annually based on an authorized rate of return of 8.75%. Rates were completely implemented by July 2013.

Arkansas Billing Determinant Rate Adjustment Tariff (BDA) Filing. Gas Operations’ Arkansas Division made its annual BDA filing with the Arkansas Public Service Commission (APSC) on March 27, 2013 to request recovery of a calendar year 2012 shortfall of $6.77 million. No exceptions were noted by the APSC staff and the revised rates went into effect on June 1, 2013.

Mississippi Rate Regulation Adjustment Rider (RRA). Gas Operations’ Mississippi Division submitted an annual RRA filing with the Mississippi Public Service Commission (MPSC) on May 1, 2013 to request recovery of calendar year 2012 earnings shortfall of approximately $3.2 million. The MPSC approved approximately $2.9 million and the revised rates went into effect in July 2013.

Cost of Service Adjustment (COSA) Rate Adjustments. In March 2008, Gas Operations filed a request to change its rates with the Railroad Commission of Texas (Railroad Commission) and the 47 cities in its Texas Coast service territory. In 2008, the Railroad Commission approved the implementation of rates increasing annual revenues from the Texas Coast service territory by approximately $3.5 million. The approved rates were contested by a coalition of nine cities in an appeal to the 353rd district court in Travis County, Texas. In January 2010, that court reversed the Railroad Commission's order in part and remanded the matter to the Railroad Commission. In its final judgment, the court ruled that the Railroad Commission lacked authority to impose the approved COSA mechanism both in those nine cities and in those areas in which the Railroad Commission has original jurisdiction. The Railroad Commission and Gas Operations appealed the court's ruling on the COSA mechanism to the Texas Third Court of Appeals in Austin, Texas. In October 2011, the Texas Third Court of Appeals reversed the district court's ruling. In December 2011, the Texas Third Court of Appeals denied a motion for rehearing. In February 2012, parties opposed to the Third Court's decision appealed to the Texas Supreme Court. In February 2013, the Texas Supreme Court granted the petitions for review. Oral arguments have been scheduled for September 2013. The issues on appeal are limited to the validity of the COSA rate adjustments made for the 2008 to 2010 calendar years. If the Texas Supreme Court were to determine that the Railroad Commission lacked authority to approve these rate adjustments, Gas Operations could have a potential refund liability of revenues billed during the applicable periods plus interest.

Minneapolis Franchise. Gas Operations currently provides natural gas distribution services to approximately 124,000 customers in Minneapolis, Minnesota under a franchise that is due to expire at the end of 2014. In June 2013, the Minneapolis City Council voted to hold public hearings on August 1, 2013 to consider (i) authorizing the establishment of a municipal electric utility and authorizing the City to own, operate, construct and extend electric facilities and acquire the property of any existing electric public utility operating within Minneapolis, and (ii) authorizing the establishment of a municipal gas utility and authorizing the City to own, operate, construct and extend gas and similar facilities and acquire the property of any existing gas public utility operating within Minneapolis. Should the City Council vote to pursue either such activity, a ballot initiative would need to be placed before the electorate of Minneapolis authorizing a change to the City's charter to provide the City with authority to own and operate an electric and/or gas utility, as applicable. If the City was authorized to acquire existing gas public utility assets, the City Council would then need to take affirmative steps to do so and the City would need to make payment for the acquisition of such assets.

Minnesota Rate Case. On August 2, 2013, Gas Operations filed an application with the Minnesota Public Utilities Commission (MPUC) to increase its rates for utility distribution service. If approved by the MPUC, the proposed new rates would result in an overall increase in annual revenue of approximately $44 million. Interim rates, if approved by the MPUC, are expected to go into effect on October 1 and remain in place until a final decision is made by the MPUC. If final rates are determined to be lower than interim rates, Gas Operations would refund customers the difference including interest.

Credit Facility. As of July 18, 2013, we had the following revolving credit facility (in millions):



Date Executed	Size of Facility		Amount Utilized at July 18, 2013		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.

On April 11, 2013, we amended our $950 million credit facility to add an exception to the covenants which restrict (i) the consolidation, merger or disposal of assets and (ii) the sale of stock in certain significant subsidiaries, in each case to permit the transactions contemplated by our previously announced Midstream Partnership.

CERC Corp.’s $950 million credit facility backstops a $915 million commercial paper program. As of June 30, 2013, CERC Corp. had no outstanding commercial paper.

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 18, 2013, we had external temporary investments of approximately $54 million.

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 18, 2013, we had no borrowings from or investments in 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 18, 2013, Moody’s Investors Service, Inc. (Moody’s), Standard & Poor’s Ratings Services (S&P), a division of The McGraw-Hill Companies, and Fitch, Inc. (Fitch) had assigned the following credit ratings to our senior unsecured debt:



Moody’s		S&P		Fitch
Rating	Outlook (1)	Rating	Outlook (2)	Rating	Outlook (3)
Baa2	Stable	A-	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 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, 2013, 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 market. 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 their suppliers under supply agreements that contain an aggregate credit threshold of $140 million based on CERC Corp.'s S&P senior unsecured long-term debt rating of A-. Under these agreements, we may need to provide collateral if the aggregate threshold is exceeded or if the S&P senior unsecured long-term debt rating is downgraded below BBB+.

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, 2013, the amount posted as collateral aggregated approximately $13 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, 2013, unsecured credit limits extended to CES by counterparties aggregate $289 million and $3 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 $180 million as of June 30, 2013. 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, 2013, 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.

Midstream Partnership. In connection with its formation on May 1, 2013, Midstream Partnership (i) entered into a $1.05 billion three-year senior unsecured term loan facility, (ii) repaid $1.05 billion of indebtedness owed to CERC Corp., and (iii) entered into a $1.4 billion senior unsecured revolving credit facility.

The sponsors of Midstream Partnership, including CenterPoint Energy, may from time to time determine to provide funds to Midstream Partnership through loans and/or capital contributions in addition to funds that Midstream Partnership may obtain from time to time under its revolving credit facility or from other sources, which loans or capital contributions could be substantial.

Certain of the entities contributed to Midstream Partnership by us are obligated on approximately $363 million of indebtedness owed to a wholly owned subsidiary of CERC Corp. that is scheduled to mature in 2017.

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 2012 Form 10-K, in Item 1A of Part II of our First Quarter Form 10-Q and in Item 1A of Part II of this Form 10-Q.

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, 2013 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. We have investments in certain unconsolidated affiliates. As we do not control these affiliates, our disclosure controls and procedures with respect to such affiliates are substantially more limited than those we maintain with respect to our consolidated subsidiaries.

There has been no change in our internal controls over financial reporting that occurred during the three months ended June 30, 2013 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

PART II. OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

For a description of certain legal and regulatory proceedings affecting us, please read Note 10(b) 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 2012 Form 10-K.

Item 1A. RISK FACTORS

Other than with respect to the updated risk factors and the addition of the other risk factors set forth below, there have been no material changes from the risk factors disclosed in our 2012 Form 10-K and First Quarter Form 10-Q.

The revenues and results of operations of Midstream Partnership are subject to fluctuations in the supply and price of natural gas and natural gas liquids and regulatory and other issues impacting its customers' production decisions.

Midstream Partnership largely relies on natural gas sourced in the various supply basins located in the Mid-continent region of the United States. The level of drilling and production activity in these regions is dependent on economic and business factors beyond our and its control. The primary factor affecting both the level of drilling activity and production volumes is natural gas pricing. A sustained decline in natural gas prices could result in a decrease in exploration and development activities in the regions served by Midstream Partnership's gathering and pipeline transportation systems and its natural gas treating and processing activities. A sustained decline could also lead producers to shut in production from their existing wells. Other factors that impact production decisions include the level of production costs relative to other available production, producers' access to needed capital and the cost of that capital, access to drilling rigs, the ability of producers to obtain necessary drilling and other governmental permits, levels of reserves, geological considerations and regulatory changes. Regulatory changes include the potential for more restrictive rules governing the use of hydraulic fracturing, a process used in the extraction of natural gas from shale reservoir formations, and the use of water in that process. Because of these factors, even if new natural gas reserves are discovered in areas served by Midstream Partnership's assets, producers may choose not to develop those reserves or to shut in production from existing reserves. To the extent the availability of this supply is substantially reduced, it could have an adverse effect on Midstream Partnership's results of operations, financial condition and cash flows.

Midstream Partnership's revenues from its businesses are also affected by the prices of natural gas and natural gas liquids (NGLs). Although the gathering revenues from its field services operations are primarily fee-based, a portion of these revenues is related to sales of natural gas that it retains from either a usage component of its contracts or from compressor efficiencies, and a reduction in natural gas prices could adversely impact these revenues. For example, Midstream Partnership's keep-whole natural gas processing arrangements expose it to fluctuations in the pricing spreads between NGLs prices and natural gas prices. Under these arrangements, the processor processes raw natural gas to extract NGLs and pays to the producer the gas equivalent Btu value of raw natural gas received from the producer in the form of either processed gas or its cash equivalent. The processor is generally entitled to retain

the processed NGLs and to sell them for its own account. Accordingly, the processor's margin is a function of the difference between the value of the NGLs produced and the cost of the processed gas used to replace the gas equivalent Btu value of those NGLs. Therefore, if natural gas prices increase and NGLs prices do not increase by a corresponding amount, the processor has to replace the British thermal units of natural gas at higher prices and processing margins are negatively affected.

Likewise, under many of Midstream Partnership's percent-of-proceeds and percent-of-liquids natural gas processing agreements, the processor gathers raw natural gas from producers at the wellhead, transports the gas through its gathering system, processes the gas and sells the processed gas and/or NGLs at prices based on published index prices. The price paid to producers is based on an agreed percentage of the actual proceeds of the sale of processed natural gas, NGLs or both or the expected proceeds based on an index price. These arrangements expose Midstream Partnership to risks associated with the price of natural gas and NGLs.

NGL prices generally fluctuate on a basis that correlates to fluctuations in crude oil prices. In addition, NGLs prices are a function of supply and demand. For example, recently, NGLs supply relative to demand has resulted in NGLs prices trending downward. In the past, the prices of natural gas and crude oil have been extremely volatile, and we expect this volatility to continue. The markets and prices for natural gas, NGLs and crude oil depend upon factors beyond our control. These factors include supply of and demand for these commodities, which fluctuate with changes in market and economic conditions and other factors.

Midstream Partnership depends on two customers for a significant portion of its firm intrastate transportation and storage services. The loss of, or reduction in volumes from, either of these customers could result in a decline in Midstream Partnership's transportation and storage services and its financial condition, results of operations and cash flows.

Midstream Partnership provides firm intrastate transportation and storage services to several customers on its system. Its major intrastate transportation customers are OG&E and Public Service Company of Oklahoma, or PSO, the second largest electric utility in Oklahoma. As part of a no-notice load following contract with OG&E, Midstream Partnership provides natural gas storage services for OG&E. It provides gas transmission delivery services to all of PSO's natural gas-fired electric generation facilities in Oklahoma under a firm intrastate transportation contract.

The PSO contract and the OG&E contract provide for a monthly demand charge plus variable transportation charges including fuel. The stated term of the PSO contract expired January 1, 2013, but the contract remains in effect from year to year thereafter unless either party provides written notice of termination to the other party at least 180 days prior to the commencement of the next succeeding annual period. Because neither party provided notice of termination 180 days prior to January 1, 2013, the PSO contract will remain in effect at least through January 1, 2014. The stated term of the OG&E contract expired April 30, 2009, but the contract remains in effect from year to year thereafter unless either party provides written notice of termination to the other party at least 180 days prior to the commencement of the next succeeding annual period. Because neither party provided notice of termination 180 days prior to May 1, 2013, the OG&E contract will remain in effect at least through April 30, 2014. The loss of all or even a portion of the intrastate transportation and storage services for either of these customers, the failure to extend or replace these contracts or the extension or replacement of these contracts on less favorable terms, as a result of competition or otherwise, could have a material adverse effect on Midstream Partnership's financial condition, results of operations and cash flows.

If third-party pipelines and other facilities interconnected to Midstream Partnership's gathering, processing or transportation facilities become partially or fully unavailable, its financial condition, results of operations and cash flows could be adversely affected.

Midstream Partnership depends upon third-party natural gas pipelines to deliver gas to, and take gas from, its transportation systems. It also depends on third-party facilities to transport and fractionate NGLs that are delivered to the third party at the tailgates of the processing plants. Fractionation is the separation of the heterogeneous mixture of extracted NGLs into individual components for end-use sale. Additionally, Midstream Partnership depends on third parties to provide electricity for compression at many of its facilities. Since it does not own or operate any of these third-party pipelines or other facilities, their continuing operation is not within Midstream Partnership's control. If any of these third-party pipelines or other facilities become partially or fully unavailable, its financial condition, results of operations and cash flows could be adversely affected.

Midstream Partnership's intrastate natural gas transportation and storage operations are subject to regulation by the FERC pursuant to Section 311 of the NGPA.

The rates, terms, and conditions for transporting natural gas in interstate commerce on Midstream Partnership's intrastate pipelines are subject to the jurisdiction of the FERC under Section 311 of the NGPA. The majority of Midstream Partnership's intrastate pipelines that provide interstate transportation under Section 311 of the NGPA are located within Oklahoma with an additional intrastate pipeline located in Illinois. Rates to provide such service must be “fair and equitable” under the NGPA and are subject to

review, refund with interest if found not to be fair and equitable, and approval by the FERC at least once every five years (previously a triennial requirement). The terms and conditions of service set forth in the intrastate pipelines' Statement of Operating Conditions are subject to FERC approval as well. FERC and state regulation may have an adverse impact on Midstream Partnership's ability to establish interstate transportation and storage rates on its intrastate facilities that would allow it to recover the full cost of operating our transportation and storage facilities, including a reasonable return, and could have an adverse effect on its financial condition, results of operations and cash flows.

A change in the jurisdictional characterization of some of Midstream Partnership's assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of its assets, which may cause its revenues to decline and operating expenses to increase.

Midstream Partnership's natural gas gathering and intrastate transportation operations are generally exempt from the jurisdiction of the FERC under the NGA, but FERC regulation may indirectly impact these businesses and the markets for products derived from these businesses. The FERC's policies and practices across the range of its oil and natural gas regulatory activities, including, for example, its policies on interstate open access transportation, ratemaking, capacity release, and market center promotion may indirectly affect intrastate markets. In recent years, the FERC has pursued pro-competitive policies in its regulation of interstate oil and natural gas pipelines. However, we cannot assure you that the FERC will continue to pursue this approach as it considers matters such as pipeline rates and rules and policies that may indirectly affect the intrastate natural gas transportation business. In addition, the distinction between FERC-regulated transmission services and federally unregulated gathering services has been the subject of regular litigation. The classification and regulation of some of Midstream Partnership's gathering facilities and intrastate transportation pipelines may be subject to change based on any reassessment by Midstream Partnership of the jurisdictional status of its facilities or on future determinations by FERC and the courts.

Natural gas gathering may receive greater regulatory scrutiny at the state level; therefore, Midstream Partnership's natural gas gathering operations could be adversely affected should they become subject to the application of state regulation of rates and services. Midstream Partnership's gathering and transportation operations could also be subject to safety and operational regulations relating to the design, construction, testing, operation, replacement and maintenance of such facilities. We cannot predict what effect, if any, such changes might have on Midstream Partnership's operations, but it could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes. Recovery of the costs associated with such changes is not assured, and Midstream Partnership may have to renegotiate contracts or make rate change filings for its transportation businesses to attempt to recover these costs from its customers.

Item 5. OTHER INFORMATION

Ratio of Earnings to Fixed Charges. Our ratio of earnings to fixed charges for the six months ended June 30, 2012 and 2013 was 3.76 and 3.74, 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.

Accounting Standards Update. On January 1, 2013, CERC adopted Financial Accounting Standards Board (FASB) issued Accounting Standards Update No. 2011-11, Balance Sheet: Disclosures about Offsetting Assets and Liabilities (ASU 2011-11). ASU 2011-11 requires an entity to provide enhanced disclosures that will enable users of its financial statements to evaluate the effect or potential effect of netting arrangements on an entity's financial position. In January 2013, the FASB issued Accounting Standards Update No. 2013-01, Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities (ASU 2013-01), clarified that the scope of ASU 2011-11 applies to derivatives accounted for in accordance with FASB ASC Topic 815, Derivative and Hedging, that are either offset in accordance with FASB ASC Section 210-20-45 or Section 815-10-45 or subject to an enforceable master netting arrangement or similar agreement. ASU 2011-11 and ASU 2013-01 are effective for interim and annual reporting periods beginning on or after January 1, 2013 and should be applied retrospectively. The retrospective application did not have an impact on the CERC's consolidated financial statements other than additional disclosures.

CERC presents natural gas contracts on a net basis in the Consolidated Balance Sheets. Natural gas contracts are subject to master netting arrangements. This netting applies to all undisputed amounts due or past due and causes derivative assets (liabilities) to be ultimately presented net in a liability (asset) account within the Consolidated Balance Sheets. The tables below reflect the unaudited retrospective application of ASU 2011-11 and ASU 2013-01 for the years ended December 31, 2012 and 2011, including the location and fair value amounts of all derivative instruments in the Consolidated Balance Sheets, as well as the gross recognized derivative assets, liabilities and amounts offset in the Consolidated Balance Sheets:



Offsetting of Natural Gas Derivative Assets and Liabilities
	December 31, 2012
	Gross Amounts Recognized (1)			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amount Presented in the Consolidated Balance Sheets (2)
	(in millions)
Current Assets: Non-trading derivative assets	$	42		$	(6	)	$	36
Other Assets: Non-trading derivative assets	7			(1		)	6
Current Liabilities: Non-trading derivative liabilities	(28		)	14			(14		)
Other Liabilities: Non-trading derivative liabilities	(4		)	2			(2		)
Total	$	17		$	9		$	26



Offsetting of Natural Gas Derivative Assets and Liabilities
	December 31, 2011
	Gross Amounts Recognized (1)			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amount Presented in the Consolidated Balance Sheets (2)
	(in millions)
Current Assets: Non-trading derivative assets	$	102		$	(15	)	$	87
Other Assets: Non-trading derivative assets	20			—			20
Current Liabilities: Non-trading derivative liabilities	(110		)	64			(46		)
Other Liabilities: Non-trading derivative liabilities	(13		)	7			(6		)
Total	$	(1	)	$	56		$	55

_______________


(1)	Gross Amounts Recognized include some derivative assets and liabilities that are not subject to master netting arrangements.


(2)	The derivative assets and liabilities on the Consolidated Balance Sheets exclude accounts receivable or accounts payable that, should they exist, could be used as offsets to these balances in the event of a default.

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
4.6	First Amendment to Credit Agreement, dated as of April 11, 2013, among CERC Corp., as Borrower, and the banks named therein	Form 8-K dated April 11, 2013	1-13265	4.2
4.7	Subordinated Guaranty of Collection dated as of May 1, 2013 by CenterPoint Energy Resources Corp. (CERC) in favor of Citibank, N.A., as agent	Form 8-K dated May 1, 2013	1-13265	10.7
10.1	First Amended and Restated Agreement of Limited Partnership of CenterPoint Energy Field Services LP (CEFS) dated as of May 1, 2013	Form 8-K dated May 1, 2013	1-13265	10.1
10.2	Amended and Restated Limited Liability Company Agreement of CNP OGE GP LLC dated as of May 1, 2013	Form 8-K dated May 1, 2013	1-13265	10.2
10.3	Registration Rights Agreement dated as of May 1, 2013 by and among CEFS, CERC Corp., OGE Enogex Holdings LLC, and Enogex Holdings LLC	Form 8-K dated May 1, 2013	1-13265	10.3
10.4	Omnibus Agreement dated as of May 1, 2013 among CenterPoint Energy, OGE, Enogex Holdings LLC and CEFS	Form 8-K dated May 1, 2013	1-13265	10.4
+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
99.1	$1,050,000,000 Credit Agreement, dated as of May 1, 2013, among CEFS, as Borrower, and the banks named therein	Form 8-K dated May 1, 2013	1-13265	10.5
99.2	$1,400,000,000 Credit Agreement, dated as of May 1, 2013, among CEFS as Borrower, and the banks named therein	Form 8-K dated May 1, 2013	1-13265	10.6
+101.INS	XBRL Instance Document
+101.SCH	XBRL Taxonomy Extension Schema Document
+101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
+101.DEF	XBRL Taxonomy Extension Definition Linkbase Document
+101.LAB	XBRL Taxonomy Extension Labels Linkbase Document
+101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

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 9, 2013

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
4.6	First Amendment to Credit Agreement, dated as of April 11, 2013, among CERC Corp., as Borrower, and the banks named therein	Form 8-K dated April 11, 2013	1-13265	4.2
4.7	Subordinated Guaranty of Collection dated as of May 1, 2013 by CenterPoint Energy Resources Corp. (CERC) in favor of Citibank, N.A., as agent	Form 8-K dated May 1, 2013	1-13265	10.7
10.1	First Amended and Restated Agreement of Limited Partnership of CenterPoint Energy Field Services LP (CEFS) dated as of May 1, 2013	Form 8-K dated May 1, 2013	1-13265	10.1
10.2	Amended and Restated Limited Liability Company Agreement of CNP OGE GP LLC dated as of May 1, 2013	Form 8-K dated May 1, 2013	1-13265	10.2
10.3	Registration Rights Agreement dated as of May 1, 2013 by and among CEFS, CERC Corp., OGE Enogex Holdings LLC, and Enogex Holdings LLC	Form 8-K dated May 1, 2013	1-13265	10.3
10.4	Omnibus Agreement dated as of May 1, 2013 among CenterPoint Energy, OGE, Enogex Holdings LLC and CEFS	Form 8-K dated May 1, 2013	1-13265	10.4
+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
99.1	$1,050,000,000 Credit Agreement, dated as of May 1, 2013, among CEFS, as Borrower, and the banks named therein	Form 8-K dated May 1, 2013	1-13265	10.5
99.2	$1,400,000,000 Credit Agreement, dated as of May 1, 2013, among CEFS as Borrower, and the banks named therein	Form 8-K dated May 1, 2013	1-13265	10.6



Exhibit Number	Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference
+101.INS	XBRL Instance Document
+101.SCH	XBRL Taxonomy Extension Schema Document
+101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
+101.DEF	XBRL Taxonomy Extension Definition Linkbase Document
+101.LAB	XBRL Taxonomy Extension Labels Linkbase Document
+101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

CERC Exhibit 12_6.30.2013

Exhibit 12

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES

(An Indirect Wholly Owned Subsidiary of CenterPoint Energy, Inc.)

COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES

(Millions of Dollars)



	Six Months Ended June 30,
	2012 (1)			2013 (1)

Net Income (Loss)	$	160		$	(34	)
Equity in earnings of unconsolidated affiliates, net of distributions	—			(25		)
Income taxes	103			295
Capitalized interest	(1		)	—
	262			236

Fixed charges, as defined:

Interest	89			82
Capitalized interest	1			—
Interest component of rentals charged to operating expense	5			4
Total fixed charges	95			86

Earnings, as defined	$	357		$	322

Ratio of earnings to fixed charges	3.76			3.74

___________


(1)	Excluded from the computation of fixed charges for the six months ended June 30, 2012 and 2013 is interest income of $2 million and less than $1 million, respectively, which is included in income tax expense.

CERC Exhibit 31.1_6.30.2013

Exhibit 31.1

CERTIFICATIONS

I, David M. McClanahan, certify that:

1. I have reviewed this quarterly report on Form 10-Q of CenterPoint Energy Resources Corp.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:


(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


(c)	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


(d)	Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):


(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and


(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: August 9, 2013

/s/ David M. McClanahan

David M. McClanahan

President and Chief Executive Officer

CERC Exhibit 31.2 _6.30.2013

Exhibit 31.2

CERTIFICATIONS

I, Gary L. Whitlock, certify that:

1. I have reviewed this quarterly report on Form 10-Q of CenterPoint Energy Resources Corp.;


(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


(c)	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


(d)	Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and


(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and


(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: August 9, 2013

/s/ Gary L. Whitlock

Gary L. Whitlock

Executive Vice President and Chief Financial Officer

CERC Exhibit 32.1_6.30.2013

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of CenterPoint Energy Resources Corp. (the “Company”) on Form 10-Q for the three months ended June 30, 2013 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, David M. McClanahan, Chief Executive Officer, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that:

1. The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ David M. McClanahan

David M. McClanahan

President and Chief Executive Officer

August 9, 2013

CERC Exhibit 32.2_6.30.2013

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of CenterPoint Energy Resources Corp. (the “Company”) on Form 10-Q for the three months ended June 30, 2013 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, Gary L. Whitlock, Chief Financial Officer, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that:

1. The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Gary L. Whitlock

Gary L. Whitlock

Executive Vice President and Chief Financial Officer

August 9, 2013