CENTERPOINT ENERGY RESOURCES CORP - FORM 10-Q

Attached files

file	filename
EX-32.1 - EXHIBIT - CENTERPOINT ENERGY RESOURCES CORP	cercexhibit321_9302014.htm
EX-31.2 - EXHIBIT - CENTERPOINT ENERGY RESOURCES CORP	cercexhibit312_9302014.htm
EX-31.1 - EXHIBIT - CENTERPOINT ENERGY RESOURCES CORP	cercexhibit311_9302014.htm
EX-12 - EXHIBIT - CENTERPOINT ENERGY RESOURCES CORP	cercexhibit12_9302014.htm
EXCEL - IDEA: XBRL DOCUMENT - CENTERPOINT ENERGY RESOURCES CORP	Financial_Report.xls
EX-32.2 - EXHIBIT - CENTERPOINT ENERGY RESOURCES CORP	cercexhibit322_9302014.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q



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

	FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2014
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 October 22, 2014, all 1,000 shares of CenterPoint Energy Resources Corp. common stock were held by Utility Holding, LLC, a wholly owned subsidiary of CenterPoint Energy, Inc.

CENTERPOINT ENERGY RESOURCES CORP.

QUARTERLY REPORT ON FORM 10-Q

FOR THE QUARTER ENDED SEPTEMBER 30, 2014

TABLE OF CONTENTS



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

	Condensed Statements of Consolidated Income
	Three and Nine Months Ended September 30, 2014 and 2013 (unaudited)	1

	Condensed Statements of Consolidated Comprehensive Income
	Three and Nine Months Ended September 30, 2014 and 2013 (unaudited)	2

	Condensed Consolidated Balance Sheets
	September 30, 2014 and December 31, 2013 (unaudited)	3

	Condensed Statements of Consolidated Cash Flows
	Nine Months Ended September 30, 2014 and 2013 (unaudited)	5

	Notes to Unaudited Condensed Consolidated Financial Statements	6

Item 2.	Management’s Narrative Analysis of Results of Operations	22

Item 4.	Controls and Procedures	32

PART II.	OTHER INFORMATION

Item 1.	Legal Proceedings	33

Item 1A.	Risk Factors	33

Item 5.	Other Information	33

Item 6.	Exhibits	34

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 (Enable)), 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;


•	local, 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 territories 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 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;


•	our ability to invest planned capital;


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


◦	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 Enable's customers and competitors, including the extent and timing of the entry of additional competition in the markets served by Enable;

◦

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


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


◦	environmental and other governmental regulations, including the availability of drilling permits and the regulation of hydraulic fracturing;


◦	changes in tax status;


◦	access to growth capital; and


◦	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, 2013 and in Item 1A of Part II of the Quarterly Report on Form 10-Q for the quarter ended March 31, 2014, which are incorporated herein by reference, and other reports we file from time to time with the Securities and Exchange Commission.

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

iii

PART I. FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES

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

CONDENSED STATEMENTS OF CONSOLIDATED INCOME

(Millions of Dollars)

(Unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013

Revenues	$	964		$	891		$	4,678		$	3,979

Expenses:
Natural gas	702			637			3,625			2,741
Operation and maintenance	184			172			562			632
Depreciation and amortization	53			49			153			182
Taxes other than income taxes	28			29			114			114
Total	967			887			4,454			3,669
Operating Income (Loss)	(3		)	4			224			310

Other Income (Expense):
Interest and other finance charges	(36		)	(36		)	(105		)	(118		)
Equity in earnings of unconsolidated affiliates, net	79			80			241			122
Other, net	3			2			7			(3		)
Total	46			46			143			1
Income Before Income Taxes	43			50			367			311
Income tax expense	15			18			139			313
Net Income (Loss)	$	28		$	32		$	228		$	(2	)

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				Nine Months Ended
	September 30,				September 30,
	2014		2013		2014		2013

Net income (loss)	$	28	$	32	$	228	$	(2	)
Other comprehensive income, net of tax:
Adjustment to pension and other postretirement plans (net of tax)	—		—		—		—
Other comprehensive income	—		—		—		—
Comprehensive income (loss)	$	28	$	32	$	228	$	(2	)

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



	September 30, 2014		December 31, 2013
Current Assets:
Cash and cash equivalents	$	4	$	1
Accounts receivable, less bad debt reserve of $19 and $25, respectively	345		565
Accrued unbilled revenue	74		311
Accounts and notes receivable — affiliated companies	107		44
Materials and supplies	42		34
Natural gas inventory	253		145
Non-trading derivative assets	34		24
Taxes receivable	—		18
Deferred income tax assets	—		21
Prepaid expenses and other current assets	99		51
Total current assets	958		1,214

Property, Plant and Equipment:
Property, plant and equipment	5,193		4,815
Less: accumulated depreciation and amortization	1,500		1,379
Property, plant and equipment, net	3,693		3,436

Other Assets:
Goodwill	840		840
Non-trading derivative assets	17		10
Investment in unconsolidated affiliates	4,525		4,518
Notes receivable from unconsolidated affiliates	363		363
Other	149		161
Total other assets	5,894		5,892

Total Assets	$	10,545	$	10,542

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



	September 30, 2014		December 31, 2013
Current Liabilities:
Short-term borrowings	$	80	$	43
Accounts payable	279		495
Accounts and notes payable — affiliated companies	52		103
Taxes accrued	55		74
Interest accrued	40		36
Customer deposits	77		78
Non-trading derivative liabilities	11		17
Other	154		163
Total current liabilities	748		1,009

Other Liabilities:
Accumulated deferred income taxes, net	2,189		2,082
Non-trading derivative liabilities	2		4
Benefit obligations	103		102
Regulatory liabilities	692		642
Other	152		160
Total other liabilities	3,138		2,990

Long-Term Debt	2,127		2,240

Commitments and Contingencies (Note 10)

Stockholder’s Equity:
Common stock	—		—
Paid-in capital	2,417		2,416
Retained earnings	2,110		1,882
Accumulated other comprehensive income	5		5
Total stockholder’s equity	4,532		4,303

Total Liabilities and Stockholder’s Equity	$	10,545	$	10,542

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)



	Nine Months Ended September 30,
	2014			2013
Cash Flows from Operating Activities:
Net income (loss)	$	228		$	(2	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	153			182
Amortization of deferred financing costs	7			8
Deferred income taxes	132			307
Write-down of natural gas inventory	2			4
Equity in earnings of unconsolidated affiliates, net of distributions	(6		)	(65		)
Changes in other assets and liabilities:
Accounts receivable and unbilled revenues, net	444			255
Accounts receivable/payable - affiliated companies	7			(6		)
Inventory	(118		)	(103		)
Taxes receivable	18			(8		)
Accounts payable	(220		)	(152		)
Fuel cost recovery	(57		)	105
Interest and taxes accrued	(15		)	2
Non-trading derivatives, net	(25		)	(6		)
Margin deposits, net	(13		)	5
Other current assets	18			19
Other current liabilities	(8		)	(20		)
Other assets	8			(11		)
Other liabilities	22			17
Other, net	5			3
Net cash provided by operating activities	582			534
Cash Flows from Investing Activities:
Capital expenditures	(376		)	(371		)
Increase in notes receivable - affiliated companies	(83		)	—
Cash contribution to Enable	—			(38		)
Other, net	(2		)	1
Net cash used in investing activities	(461		)	(408		)
Cash Flows from Financing Activities:
Increase in short-term borrowings, net	37			32
Payments of commercial paper, net	(118		)	—
Proceeds from long-term debt	—			1,050
Payments of long-term debt	—			(525		)
Decrease in notes payable - affiliated companies	(38		)	(679		)
Other, net	1			(1		)
Net cash used in financing activities	(118		)	(123		)

Net Increase in Cash and Cash Equivalents	3			3
Cash and Cash Equivalents at Beginning of Period	1			1
Cash and Cash Equivalents at End of Period	$	4		$	4

Supplemental Disclosure of Cash Flow Information:
Cash Payments:
Interest, net of capitalized interest	$	91		$	113
Income taxes (refunds), net	(1		)	1
Non-cash transactions:
Accounts payable related to capital expenditures	$	25		$	28
Formation of Enable	—			4,252
Exercise of SESH put to Enable	196			—

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, 2013.

Background. CERC owns and operates natural gas distribution systems (Gas Operations) and owns an interest in Enable Midstream Partners, LP (Enable) as described in Note 6. A wholly owned subsidiary of CERC Corp. offers variable and fixed-price physical natural gas supplies primarily to commercial and industrial customers and electric and gas utilities. As of September 30, 2014, CERC Corp. also owned approximately 55.4% of the limited partner interests in Enable, which owns, operates and develops natural gas and crude oil infrastructure assets.

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

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

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

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

(2) New Accounting Pronouncements

In April 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2014-08 (ASU 2014-08), Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity, which significantly changes the existing accounting guidance on discontinued operations. Under ASU 2014-08, only those disposals of components of an entity that represent a strategic shift that has (or will have) a major effect on an entity's operations and financial results should be reported as a discontinued operation. ASU 2014-08 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2014. ASU 2014-08 should be applied to components classified as held for sale after its effective date. Early adoption is permitted, but only for disposals (or classifications as held for sale) that have not been reported in financial statements previously issued or available for issuance. The adoption is expected to reduce the number of disposals that meet the definition of a discontinued operation.

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) (ASU 2014-09), which supersedes most current revenue recognition guidance. ASU 2014-09 provides a comprehensive new revenue recognition model that requires revenue to be recognized in a manner that depicts the transfer of goods or services to a customer at an amount that reflects the consideration expected to be received in exchange for those goods or services. ASU 2014-09 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016. Early adoption is not permitted, and entities have the option of using either a full retrospective or a modified retrospective adoption approach. Accordingly, CERC will adopt ASU 2014-09 on January 1, 2017, and is currently evaluating the impact that this standard will have on its financial position, results of operations, cash flows and disclosures.

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

(3) Employee Benefit Plans

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



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2014			2013			2014			2013
	(in millions)
Service cost	$	1		$	1		$	1		$	1
Interest cost on accumulated benefit obligation	1			2			4			4
Expected return on plan assets	(1		)	(1		)	(1		)	(1		)
Amortization of prior service cost	—			—			—			1
Amortization of loss	1			1			1			2
Net periodic cost	$	2		$	3		$	5		$	7

CERC expects to contribute approximately $7 million to its postretirement benefit plan in 2014, of which $2 million and $5 million was contributed during the three and nine months ended September 30, 2014, respectively.

(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 Condensed 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 risk 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 entered into heating-degree day swaps for certain 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, which contained a bilateral dollar cap of $15 million in 2012 - 2013, $16 million in 2013 - 2014 and $16 million in 2014 - 2015. The swaps are based on ten-year normal weather. During both the three months ended September 30, 2014 and 2013, CERC recognized losses of $-0- related to these swaps. During the nine months ended September 30, 2014 and 2013, CERC recognized losses of $7 million and $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 September 30, 2014 and December 31, 2013, while the last two tables provide a breakdown of the related income statement impacts for the three and nine months ended September 30, 2014 and 2013.



Fair Value of Derivative Instruments
		September 30, 2014
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	$	45	$	11
Natural gas derivatives (1) (2)	Other Assets: Non-trading derivative assets	17		—
Natural gas derivatives (1) (2)	Current Liabilities: Non-trading derivative liabilities	1		12
Natural gas derivatives (1) (2)	Other Liabilities: Non-trading derivative liabilities	3		5
Total		$	66	$	28

________________


(1)	The fair value shown for natural gas contracts is comprised of derivative gross volumes totaling 811 billion cubic feet (Bcf) or a net 34 Bcf long position. Of the net long position, basis swaps constitute 126 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 $38 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.



Offsetting of Natural Gas Derivative Assets and Liabilities
	September 30, 2014
	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	$	46		$	(12	)	$	34
Other Assets: Non-trading derivative assets	20			(3		)	17
Current Liabilities: Non-trading derivative liabilities	(23		)	12			(11		)
Other Liabilities: Non-trading derivative liabilities	(5		)	3			(2		)
Total	$	38		$	—		$	38

________________


(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 Condensed 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
		December 31, 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) (2) (3)	Current Assets: Non-trading derivative assets	$	28	$	4
Natural gas derivatives (1) (2)	Other Assets: Non-trading derivative assets	10		—
Natural gas derivatives (1) (2)	Current Liabilities: Non-trading derivative liabilities	4		21
Natural gas derivatives (1) (2)	Other Liabilities: Non-trading derivative liabilities	1		5
Total		$	43	$	30

________________


(1)	The fair value shown for natural gas contracts is comprised of derivative gross volumes totaling 607 Bcf or a net 46 Bcf long position. Of the net long position, basis swaps constitute 99 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 $13 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 less than $1 million.


(3)	The $28 million Derivative Current Asset includes $1 million related to physical forwards purchased from Enable.



Offsetting of Natural Gas Derivative Assets and Liabilities
	December 31, 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	$	32		$	(8	)	$	24
Other Assets: Non-trading derivative assets	11			(1		)	10
Current Liabilities: Non-trading derivative liabilities	(25		)	8			(17		)
Other Liabilities: Non-trading derivative liabilities	(5		)	1			(4		)
Total	$	13		$	—		$	13

________________


(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.

Realized and unrealized gains and losses on 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 September 30,
Total derivatives not designated as hedging instruments	Income Statement Location	2014			2013
		(in millions)
Natural gas derivatives	Gains (Losses) in Revenue	$	22		$	11
Natural gas derivatives (1)	Gains (Losses) in Expense: Natural Gas	(4		)	(2		)
Total		$	18		$	9



Income Statement Impact of Derivative Activity
		Nine Months Ended September 30,
Total derivatives not designated as hedging instruments	Income Statement Location	2014			2013
		(in millions)
Natural gas derivatives	Gains (Losses) in Revenue	$	(74	)	$	24
Natural gas derivatives (1)	Gains (Losses) in Expense: Natural Gas	110			(3		)
Total		$	36		$	21

________________


(1)	The Gains (Losses) in Expense: Natural Gas includes $-0- and $2 million during the three and nine months ended September 30, 2014, respectively, related to physical forwards purchased from Enable.

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 both September 30, 2014 and December 31, 2013 was $1 million. The aggregate fair value of assets that were posted as collateral was less than $1 million at both September 30, 2014 and December 31, 2013. If all derivative contracts (in a net liability position) containing credit risk contingent features were triggered at both September 30, 2014 and December 31, 2013, $1 million 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 $2.04 to $4.95 per one million British thermal units) as an unobservable input. Level 3 options are valued through Black-Scholes (including forward start) option models which include option volatilities (ranging from 0 to 81%) as an unobservable input. CERC’s Level 3 derivative assets and liabilities consist of both long and short positions (forwards and options) and their fair value is sensitive to forward prices and volatilities. If forward prices decrease, CERC’s long forwards lose value whereas its short forwards gain in value. If volatility decreases, CERC’s long options lose value whereas its short options gain in value.

CERC determines the appropriate level for each financial asset and liability on a quarterly basis and recognizes transfers between levels at the end of the reporting period. For the nine months ended September 30, 2014, there were no transfers between Level 1 and 2. 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 September 30, 2014 and December 31, 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 September 30, 2014
	(in millions)
Assets
Corporate equities	$	2	$	—	$	—	$	—		$	2
Investments, including money market funds	11		—		—		—			11
Natural gas derivatives	4		51		11		(15		)	51
Total assets	$	17	$	51	$	11	$	(15	)	$	64
Liabilities
Natural gas derivatives	$	3	$	23	$	2	$	(15	)	$	13
Total liabilities	$	3	$	23	$	2	$	(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 $-0- 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 December 31, 2013
	(in millions)
Assets
Corporate equities	$	2	$	—	$	—	$	—		$	2
Investments, including money market funds	11		—		—		—			11
Natural gas derivatives (2)	5		33		5		(9		)	34
Total assets	$	18	$	33	$	5	$	(9	)	$	47
Liabilities
Natural gas derivatives	$	1	$	27	$	2	$	(9	)	$	21
Total liabilities	$	1	$	27	$	2	$	(9	)	$	21

________________


(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 less than $1 million posted with the same counterparties.


(2)	The (Level 2) Natural gas derivative assets of $33 million include $1 million related to physical forwards purchased from Enable.

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



	Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Derivative Assets and Liabilities, net
	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
	(in millions)
Beginning balance	$	4		$	4		$	3		$	2
Total gains	6			2			6			5
Total settlements	(1		)	(1		)	1			(2		)
Transfers into Level 3	—			—			(1		)	—
Ending balance ⁽¹⁾	$	9		$	5		$	9		$	5
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	$	6		$	2		$	7		$	4

____________


(1)	CERC did not have significant Level 3 purchases, sales or transfers out of Level 3 during either the three or nine months ended September 30, 2014 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 or Level 2 in the fair value hierarchy.



	September 30, 2014				December 31, 2013
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in millions)
Financial assets:
Notes receivable from unconsolidated affiliates	$	363	$	366	$	363	$	363
Financial liabilities:
Long-term debt	$	2,127	$	2,442	$	2,240	$	2,466

(6) Unconsolidated Affiliates

On May 1, 2013 (the Closing Date) CERC Corp., OGE Energy Corp. (OGE) and ArcLight Capital Partners, LLC (ArcLight) closed on the formation of Enable. CERC has the ability to significantly influence the operating and financial policies of Enable and, accordingly, accounts for its investment in Enable using the equity method of accounting. Under the equity method, CERC will adjust its investment in Enable each period for contributions made, distributions received, CERC’s share of Enable’s comprehensive income and accretion of basis differences, as appropriate. CERC evaluates its equity method investments for impairment when events or changes in circumstances indicate there is a loss in value of the investment that is other than a temporary decline.

CERC’s investment in Enable is considered to be a variable interest entity (VIE) because the power to direct the activities that most significantly impact Enable’s economic performance does not reside with the holders of equity investment at risk. However, CERC is not considered the primary beneficiary of Enable since it does not have the power to direct the activities of Enable that are considered most significant to the economic performance of Enable. CERC’s maximum exposure to loss related to Enable is limited to its equity investment as presented in the Condensed Consolidated Balance Sheet at September 30, 2014, CERC Corp.’s guarantee of collection of Enable’s $1.1 billion senior notes due 2019 and 2024 (Guaranteed Senior Notes) and other guarantees discussed in Note 10, CERC Corp.’s $363 million notes receivable from Enable and outstanding current accounts receivable from Enable. The $363 million of notes receivable from Enable bears interest at an annual rate of 2.10% to 2.45% and matures in 2017. CERC recorded

interest income of $2 million and $2 million during the three months ended September 30, 2014 and 2013, respectively, and $6 million and $3 million during the nine months ended September 30, 2014 and 2013, respectively, for interest earned on or after the Closing Date and had interest receivable from Enable of $2 million and $4 million as of September 30, 2014 and December 31, 2013, respectively, on its notes receivable from Enable.

Effective on the Closing Date, CenterPoint Energy and Enable 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 Enable such as accounting, legal, risk management and treasury functions for an initial term ending on April 30, 2016. The support services automatically extend year-to-year at the end of the initial term, unless terminated by Enable with at least 90 days’ notice. Enable may terminate the initial support services at any time with 180 days’ notice if approved by the board of Enable's general partner. Additionally, CERC agreed to provide seconded employees to Enable to support its operations for an initial term ending on December 31, 2014, unless revised by mutual agreement with CERC, OGE and Enable prior to that date.

CERC billed Enable for reimbursement of transitional services, including the costs of seconded employees, $36 million and $42 million during the three months ended September 30, 2014 and 2013, respectively, and $118 million and $70 million during the nine months ended September 30, 2014 and 2013, respectively, under the Transition Agreements for transition services incurred on or after the Closing Date. Actual transitional services costs are recorded net of reimbursements received from Enable. Effective April 1, 2014, Enable’s general partner, CERC and OGE agreed to reduce certain governance related costs billed to Enable for transition services. CERC had accounts receivable from Enable of $17 million and $21 million as of September 30, 2014 and December 31, 2013, respectively, for amounts billed for transitional services, including the cost of seconded employees.

Enable, at its discretion, has the right to select and offer employment to seconded employees from CERC. CERC did not transfer any employees to Enable at formation of the partnership or at any time during the period from the Closing Date through September 30, 2014. As of September 30, 2014, CERC determined it cannot reasonably estimate the impact of the costs associated with the termination of employees related to the formation of Enable or transfer of employees from CERC to Enable, including the impact of the changes to the actuarial determination of employee benefit plan obligations. Pursuant to the Transition Agreements, Enable has agreed to reimburse CERC for certain severance and termination costs related to the termination of CERC's seconded employees.

On April 16, 2014, Enable completed its initial public offering (IPO) of 28,750,000 common units, at a price of $20.00 per unit, which included 3,750,000 common units sold by ArcLight pursuant to an over-allotment option that was fully exercised by the underwriters. Enable received $464 million in net proceeds from the sale of the units, after deducting underwriting fees, structuring fees and other offering costs. In connection with Enable’s IPO, a portion of CERC’s common units were converted into subordinated units, as discussed further below. Subsequent to the IPO, Enable continues to be equally controlled by CERC and OGE; each own 50% of the management rights in the general partner of Enable. CERC and OGE also own a 40% and 60% economic interest, respectively, in the incentive distribution rights held by the general partner of Enable.

As a result of Enable’s IPO, CERC’s limited partner interest in Enable was reduced from approximately 58.3% to approximately 54.7%. CERC accounted for the dilution of its investment in Enable as a result of Enable’s IPO as a failed partial sale of in-substance real estate. CERC did not receive any cash from Enable’s IPO and, as such, CERC did not recognize a gain or loss. CERC’s basis difference in Enable was reduced for the impact of the Enable IPO.

In accordance with the Enable formation agreements, CERC had certain put rights, and Enable had certain call rights, exercisable with respect to the 25.05% interest in Southeast Supply Header, LLC (SESH) retained by CERC, under which CERC would contribute its retained interest in SESH, in exchange for a specified number of limited partner units in Enable and a cash payment, payable either from CERC to Enable or from Enable to CERC, to the extent of changes in the value of SESH subject to certain restrictions. Specifically, the rights were and are exercisable with respect to (1) a 24.95% interest in SESH (24.95% Put), which closed on May 30, 2014 as discussed below and (2) a 0.1% interest in SESH, which may be exercised no earlier than June 2015 for 25,341 common units in Enable.

On May 30, 2014, CERC closed its 24.95% Put and contributed to Enable its 24.95% interest in SESH in exchange for 6,322,457 common units of Enable, which increased CERC's limited partner interest in Enable from approximately 54.7% to approximately 55.4%. No cash payment was required to be made pursuant to the Enable formation agreements in connection with CERC's exercise of the 24.95% Put. CERC accounted for the contribution of its 24.95% interest in SESH to Enable in exchange for common units of Enable as a non-monetary transaction of in-substance real estate equity method investments. As such, CERC recorded the 6,322,457 common units at the historical cost of the contributed 24.95% interest in SESH of $196 million and recorded no gain or loss in connection with its exercise of the 24.95% Put. As a result, CERC's basis difference in Enable was reduced for the impact of its exercise of the 24.95% Put.

CERC incurred natural gas expenses, including transportation and storage costs, of $24 million and $42 million, during the three months ended September 30, 2014 and 2013, respectively, and $99 million and $70 million during the nine months ended September 30, 2014 and 2013, respectively, for transactions with Enable occurring on or after the Closing Date. CERC had accounts payable to Enable of $10 million and $22 million at September 30, 2014 and December 31, 2013, respectively, from such transactions.

As of September 30, 2014, CERC held an approximate 55.4% limited partner interest in Enable consisting of 94,126,366 common units and 139,704,916 subordinated units and a 0.1% interest in SESH. The principal difference between Enable common units and subordinated units is that in any quarter during the subordination period, holders of the subordinated units are not entitled to receive any distribution of available cash until the common units have received the minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. If Enable does not pay distributions on its subordinated units, the subordinated units will not accrue arrearages for those unpaid distributions. At the end of the subordination period, CERC’s subordinated units in Enable will be converted to common units in Enable on a one-for-one basis. On September 30, 2014, Enable’s common units closed at $24.64 per unit on the New York Stock Exchange.

Investment in Unconsolidated Affiliates:



	September 30, 2014		December 31, 2013
	(in millions)
Enable	$	4,524	$	4,319
SESH (1)	1		199
Total	$	4,525	$	4,518


(1)	On May 30, 2014, CERC contributed a 24.95% interest in SESH to Enable, leaving CERC with a 0.1% interest in SESH as of September 30, 2014.

Equity in Earnings of Unconsolidated Affiliates, net:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
	(in millions)
Enable (1)	$	79	$	77	$	236	$	110
SESH (2)	—		3		5		12
	$	79	$	80	$	241	$	122


(1)	On May 1, 2013, CERC formed Enable with OGE and ArcLight.


(2)	On each of May 1, 2013 and May 30, 2014, CERC contributed a 24.95% interest in SESH to Enable, leaving CERC with a 0.1% interest in SESH as of September 30, 2014.

Summarized unaudited consolidated income information for Enable is as follows:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013 (1)		2014		2013 (1)
	(in millions)
Operating revenues	$	804	$	796	$	2,632	$	1,298
Cost of sales, excluding depreciation and amortization	439		458		1,550		753
Operating income	151		132		452		207
Net income attributable to Enable	139		123		408		188

CERC's approximate interest	$	76	$	72	$	230	$	110
Basis difference accretion	3		5		6		—
CERC's equity in earnings, net	$	79	$	77	$	236	$	110

(1)

On May 1, 2013, CERC formed Enable with OGE and ArcLight. The amounts included in the table represent the three- and five- month periods ended September 30, 2013. Enable concluded that its formation was considered a business combination, in which the fair value of the consideration paid for Enogex, LLC (Enogex), the businesses contributed by OGE, was allocated to the assets acquired and liabilities assumed by Enable on the Closing Date. In the third quarter of 2013, Enable completed its valuation of Enogex, and Enogex's assets, liabilities and equity, and its related depreciation and amortization for the five-month period ended September 30, 2013, was accordingly adjusted to estimated fair value as of the Closing Date. CERC’s equity in earnings, net of basis difference, in the third quarter of 2013 was not materially different as a result of the final fair value determination.

Summarized unaudited consolidated balance sheet information for Enable is as follows:



	September 30, 2014			December 31, 2013
	(in millions)
Current assets	$	520		$	549
Non-current assets	11,172			10,683
Current liabilities	520			720
Non-current liabilities	2,346			2,331
Non-controlling interest	32			33
Enable partners' capital	8,794			8,148

CERC's ownership interest in Enable's partner capital	$	4,870		$	4,753
CERC's basis difference	(346		)	(434		)
CERC's investment in Enable	$	4,524		$	4,319

Distributions Received from Unconsolidated Affiliates:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
	(in millions)
Enable (1)	$	70	$	36	$	227	$	36
SESH (2)	1		3		8		21
Total	$	71	$	39	$	235	$	57


(1)	On May 1, 2013, CERC formed Enable with OGE and ArcLight.


(2)	On each of May 1, 2013 and May 30, 2014, CERC contributed a 24.95% interest in SESH to Enable, leaving CERC with a 0.1% interest in SESH as of September 30, 2014.

(7) Goodwill

Goodwill by reportable business segment as of both September 30, 2014 and December 31, 2013 is as follows (in millions):



Natural Gas Distribution	$	746
Energy Services	83
Other Operations	11
Total	$	840

CERC performs its goodwill impairment tests at least annually and evaluates goodwill when events or changes in circumstances indicate that its carrying value may not be recoverable. The impairment evaluation for goodwill is performed by using a two-step process. In the first step, the fair value of each reporting unit is compared with the carrying amount of the reporting unit, including goodwill. The estimated fair value of the reporting unit is generally determined on the basis of discounted cash flows. If the estimated fair value of the reporting unit is less than the carrying amount of the reporting unit, then a second step must be completed in order to determine the amount of the goodwill impairment that should be recorded. In the second step, the implied fair value of the reporting unit's goodwill is determined by allocating the reporting unit's fair value to all of its assets and liabilities other than goodwill (including any unrecognized intangible assets) in a manner similar to a purchase price allocation. The resulting implied fair value of the goodwill that results from the application of this second step is then compared to the carrying amount of the goodwill and an impairment charge is recorded for the difference.

CERC performed its annual impairment test in the third quarter of 2014 and determined, based on the results of the first step, that no impairment charge was required for any reportable segment.

(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 investments in the money pool of $83 million and borrowings from the money pool of $38 million at September 30, 2014 and December 31, 2013, respectively, which are included in accounts and notes receivable — affiliated companies and accounts and notes payable — affiliated companies, respectively, in the Condensed Consolidated Balance Sheets.

CERC had affiliate related net interest income of less than $1 million for both the three and nine months ended September 30, 2014, and net interest expense of less than $1 million and $2 million for the three and nine months ended September 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 $34 million and $28 million for the three months ended September 30, 2014 and 2013, respectively, and $93 million and $88 million for the nine months ended September 30, 2014 and 2013, respectively, and are included primarily in operation and maintenance expenses.

See Note 6 for related party transactions with Enable.

(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 March 2015. Pursuant to the provisions of the agreements, Gas Operations sells natural gas and agrees to repurchase an equivalent amount of natural gas during the winter heating seasons at the same cost, plus a financing charge. These transactions are accounted for as a financing and had an associated principal obligation of $80 million and $43 million as of September 30, 2014 and December 31, 2013, respectively.


(b)	Long-term Debt

Revolving Credit Facility. On September 9, 2014, CERC Corp's revolving credit facility was amended to, among other things, extend the maturity date of the commitment from September 9, 2018 to September 9, 2019. The amendment also reduced the swingline and letter of credit sub-facility, with the total commitment remaining unchanged. As of September 30, 2014 and December 31, 2013, CERC had the following revolving credit facility and utilization of such facility (in millions):



		September 30, 2014						December 31, 2013
Size of Facility		Loans		Letters of Credit		Commercial Paper		Loans		Letters of Credit		Commercial Paper
$	600	$	—	$	—	$	—	$	—	$	—	$	118

CERC Corp.’s $600 million revolving credit facility, which is scheduled to terminate on September 9, 2019, can be drawn at the London Interbank Offered Rate plus 1.50% based on CERC Corp.’s current credit ratings. The revolving credit facility contains a financial covenant which limits CERC's consolidated debt to an amount not to exceed 65% of CERC's consolidated capitalization.

CERC Corp. was in compliance with all financial covenants in its revolving credit facility as of September 30, 2014.

(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 Energy 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 September 30, 2014 and December 31, 2013 as these contracts meet an exception as “normal purchases contracts” or do not meet the definition of a derivative. Natural gas supply commitments also include natural gas transportation contracts that do not meet the definition of a derivative. As of September 30, 2014, minimum payment obligations for natural gas supply commitments are approximately $232 million for the remaining three months in 2014, $634 million in 2015, $557 million in 2016, $485 million in 2017, $434 million in 2018 and $180 million after 2018.

(b) Legal, Environmental and Other Regulatory Matters

Legal Matters

Gas Market Manipulation Cases. CenterPoint Energy, CenterPoint Energy Houston Electric, LLC 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 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 guarantee 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 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. In August 2013, the other defendants filed a petition for review with the U.S. Supreme Court, which the court granted on July 1, 2014. The defendants filed an opening brief with the court on September 18, 2014. The plaintiffs’ brief is due on November 21, 2014, and the other defendants' reply brief is due on December 22, 2014. Four amicus briefs favorable to our co-defendants were filed by the United States, Interstate Natural Gas Association of America, et. al., Washington

Legal Foundation and Noble America Corporation, et. al. 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.

Environmental Matters

Manufactured Gas Plant Sites. CERC and its predecessors operated manufactured gas plants (MGPs) in the past. There are seven MGP sites in CERC’s Minnesota service territory. CERC believes it never owned or operated, and therefore has no liability with respect to, two of these sites. With respect to two other sites, CERC has completed state ordered remediation, other than ongoing monitoring and water treatment.

At September 30, 2014, 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 September 30, 2014, CERC had collected $6.5 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 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. From time to time, CERC is also a defendant in legal proceedings with respect to claims brought by various plaintiffs against broad groups of participants in the energy industry. 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 guarantees 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 guarantees 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 guarantees 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 $46 million as of September 30, 2014. Based on market conditions in the fourth quarter of 2014 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.

CERC Corp. has also provided a guarantee of collection of $1.1 billion of Enable's Guaranteed Senior Notes. This guarantee is subordinated to all senior debt of CERC Corp. and is subject to automatic release on May 1, 2016.

The fair value of these guarantees is not material.

(11) Income Taxes

The effective tax rate reported for the three and nine months ended September 30, 2014 was 35% and 38%, respectively, compared to 36% and 101%, respectively, for the same periods in 2013. The higher effective tax rate for the nine months ended September 30, 2013 was primarily associated with the formation of Enable. As a result of the Enable formation, 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 the Enable formation.

CERC reported no uncertain tax liability as of September 30, 2014 and expects no significant change to the uncertain tax liability over the next twelve months. CenterPoint Energy’s consolidated federal income tax returns for the years 2012 and 2013 are currently under audit by the Internal Revenue Service (IRS). Tax years through 2011 have been audited and settled with the IRS. For 2014, CenterPoint Energy is a participant in the IRS’s Compliance Assurance Process.

(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, Energy 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. Energy Services represents CERC’s non-rate regulated gas sales and services operations. Midstream Investments consists primarily of CERC’s investment in Enable 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. The formation of Enable closed on May 1, 2013. Enable now owns substantially all of CERC’s former Interstate Pipelines and Field Services business segments, except for a 0.1% interest in SESH. As a result, effective May 1, 2013, CERC reports equity earnings associated with its interest in Enable and equity earnings associated with its interest in SESH under the Midstream Investments segment, and no longer has Interstate Pipelines and Field Services reporting segments prospectively.

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



	For the Three Months Ended September 30, 2014
	Revenues from External Customers		Inter-segment Revenues			Operating Income (Loss)
Natural Gas Distribution	$	375	$	7		$	(8	)
Energy Services	589		15			6
Midstream Investments (1)	—		—			—
Other	—		—			(1		)
Reconciling Eliminations	—		(22		)	—
Consolidated	$	964	$	—		$	(3	)

	For the Three Months Ended September 30, 2013
	Revenues from External Customers		Inter-segment Revenues			Operating Income (Loss)
Natural Gas Distribution	$	375	$	6		$	5
Energy Services	516		4			2
Midstream Investments (1)	—		—			—
Other	—		—			(3		)
Reconciling Eliminations	—		(10		)	—
Consolidated	$	891	$	—		$	4


	For the Nine Months Ended September 30, 2014
	Revenues from External Customers		Inter-segment Revenues			Operating Income (Loss)			Total Assets as of September 30, 2014
Natural Gas Distribution	$	2,379	$	22		$	184		$	5,059
Energy Services	2,298		66			43			882
Midstream Investments (1)	—		—			—			4,525
Other	1		—			(3		)	769
Reconciling Eliminations	—		(88		)	—			(690		)
Consolidated	$	4,678	$	—		$	224		$	10,545

	For the Nine Months Ended September 30, 2013
	Revenues from External Customers		Inter-segment Revenues			Operating Income (Loss)			Total Assets as of December 31, 2013
Natural Gas Distribution	$	1,942	$	19		$	169		$	4,976
Energy Services	1,726		19			12			895
Interstate Pipelines (2)	133		53			72			—
Field Services (2)	178		18			73			—
Midstream Investments (1)	—		—			—			4,518
Other	—		—			(16		)	1,149
Reconciling Eliminations	—		(109		)	—			(996		)
Consolidated	$	3,979	$	—		$	310		$	10,542

(1)

Midstream Investments reported equity earnings of $79 million from Enable and less than $1 million of equity earnings from CERC’s retained interest in SESH for the three months ended September 30, 2014. Midstream Investments reported equity earnings of $236 million from Enable and $5 million of equity earnings from CERC’s retained interest in SESH for the nine months ended September 30, 2014. Midstream Investments reported equity earnings of $77 million from Enable and $3 million of equity earnings from CERC’s interest in SESH for the three months ended September 30, 2013. Midstream Investments reported equity earnings of $110 million from Enable and $5 million of equity earnings from CERC’s interest in SESH for the five months ended September 30, 2013. Included in total assets of Midstream Investments as of September 30, 2014 and December 31, 2013 is $4,524 million and $4,319 million, respectively, related to CERC’s investment in Enable and $1 million and $199 million, respectively, related to CERC’s interest in SESH.


(2)	Results reflected in the nine months ended September 30, 2013 represent only January 2013 through April 2013.

(13) Other Current Assets and Liabilities

Included in other current assets on the Condensed Consolidated Balance Sheets at September 30, 2014 and December 31, 2013 were $18 million and $4 million, respectively, of margin deposits and $70 million and $22 million, respectively, of under-recovered gas cost. Included in other current liabilities on the Condensed Consolidated Balance Sheets at September 30, 2014 and December 31, 2013 were $47 million and $42 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, 2013 (2013 Form 10-K).

We meet the conditions specified in General Instruction H(1)(a) and (b) to Form 10-Q and are therefore permitted to use the reduced disclosure format for wholly owned subsidiaries of reporting companies. Accordingly, we have omitted from this report the information called for by Item 2 (Management’s Discussion and Analysis of Financial Condition and Results of Operations) and Item 3 (Quantitative and Qualitative Disclosures About Market Risk) of Part I and the following Part II items of Form 10-Q: Item 2 (Unregistered Sales of Equity Securities and Use of Proceeds), Item 3 (Defaults Upon Senior Securities) and Item 4 (Submission of Matters to a Vote of Security Holders). The following discussion explains material changes in our revenue and expense items between the three and nine months ended September 30, 2014 and the three and nine months ended September 30, 2013. Reference is made to “Management's Narrative Analysis of Results of Operations” in Item 7 of our 2013 Form 10-K.

EXECUTIVE SUMMARY

Recent Events

Debt Matters. On September 9, 2014, our revolving credit facility was amended to, among other things, extend the maturity date of the commitment from September 9, 2018 to September 9, 2019. The amendment also reduced the swingline and letter of credit sub-facility, with the total commitment remaining unchanged.

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 2013 Form 10-K and in Item 1A of Part II of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2014 (First Quarter Form 10-Q).

The following table sets forth our consolidated results of operations for the three and nine months ended September 30, 2014 and 2013, followed by a discussion of our consolidated results of operations.



	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
	(in millions)
Revenues	$	964		$	891		$	4,678		$	3,979
Expenses:
Natural gas	702			637			3,625			2,741
Operation and maintenance	184			172			562			632
Depreciation and amortization	53			49			153			182
Taxes other than income taxes	28			29			114			114
Total	967			887			4,454			3,669
Operating Income (Loss)	(3		)	4			224			310
Interest and other finance charges	(36		)	(36		)	(105		)	(118		)
Equity in earnings of unconsolidated affiliates, net	79			80			241			122
Other expense, net	3			2			7			(3		)
Income Before Income Taxes	43			50			367			311
Income tax expense	15			18			139			313
Net Income (Loss)	$	28		$	32		$	228		$	(2	)

Three months ended September 30, 2014 compared to three months ended September 30, 2013

We reported net income of $28 million for the three months ended September 30, 2014 compared to $32 million for the same period in 2013. The decrease in net income of $4 million was primarily due to decreased operating income ($7 million) (discussed by segment below), which was partially offset by decreased income tax expense ($3 million).

Nine months ended September 30, 2014 compared to nine months ended September 30, 2013

We reported net income of $228 million for the nine months ended September 30, 2014 compared to a net loss of $2 million for the same period in 2013. The increase in net income of $230 million was primarily due to decreased income tax expense as discussed below ($174 million), increased equity earnings of unconsolidated affiliates ($119 million) and decreased interest expense ($13 million), which were partially offset by decreased operating income ($86 million) (discussed by segment below).

Income Tax Expense. Our effective tax rate reported for the three and nine months ended September 30, 2014 was 35% and 38%, respectively, compared to 36% and 101% for the same periods in 2013. The higher effective tax rate for the nine months ended September 30, 2013 was primarily associated with the formation of Enable. As a result of the Enable formation, a deferred tax liability of $225 million was recorded for the book-to-tax basis differences 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 the Enable formation.

RESULTS OF OPERATIONS BY BUSINESS SEGMENT

The following table presents operating income (loss) for each of our business segments for the three and nine months ended September 30, 2014 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 September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
	(in millions)
Natural Gas Distribution	$	(8	)	$	5		$	184		$	169
Energy Services	6			2			43			12
Interstate Pipelines	—			—			—			72			(1	)
Field Services	—			—			—			73			(1	)
Other Operations	(1		)	(3		)	(3		)	(16		)
Total Consolidated Operating Income (Loss)	$	(3	)	$	4		$	224		$	310

______________

(1) 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 2013 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 nine months ended September 30, 2014 and 2013 (in millions, except throughput and customer data):



	Three Months Ended September 30,					Nine Months Ended September 30,
	2014			2013		2014		2013
Revenues	$	382		$	381	$	2,401	$	1,961
Expenses:
Natural gas	142			142		1,432		1,066
Operation and maintenance	169			158		524		488
Depreciation and amortization	52			47		149		138
Taxes other than income taxes	27			29		112		100
Total expenses	390			376		2,217		1,792
Operating Income (Loss)	$	(8	)	$	5	$	184	$	169
Throughput (in billion cubic feet (Bcf)):
Residential	12			12		140		117
Commercial and industrial	46			49		197		191
Total Throughput	58			61		337		308
Number of customers at end of period:
Residential	3,077,633			3,045,701		3,077,633		3,045,701
Commercial and industrial	246,789			242,587		246,789		242,587
Total	3,324,422			3,288,288		3,324,422		3,288,288

Three months ended September 30, 2014 compared to three months ended September 30, 2013

Our Natural Gas Distribution business segment reported an operating loss of $8 million for the three months ended September 30, 2014 compared to operating income of $5 million for the three months ended September 30, 2013. Operating income decreased $13 million due to higher labor and support services costs ($8 million), increased pipeline integrity work ($2 million), increased depreciation and other taxes ($6 million) and increased other operation and maintenance expenses ($2 million). These increases were partially offset by rate increases ($3 million) and increased economic activity across our footprint including the addition of approximately 36,000 customers ($2 million). Decreased expense related to lower gross receipt taxes ($3 million) was offset by the related revenues.

Nine months ended September 30, 2014 compared to nine months ended September 30, 2013

Our Natural Gas Distribution business segment reported operating income of $184 million for the nine months ended September 30, 2014 compared to $169 million for the nine months ended September 30, 2013. Operating income increased $15 million primarily due to rate increases ($27 million), increased usage resulting from colder than normal weather, partially mitigated by weather hedges and weather normalization adjustments ($15 million), increased economic activity across our footprint including the addition of approximately 36,000 customers ($8 million) and increased miscellaneous revenues ($7 million). These increases were partially offset by increased labor and support services costs ($18 million), higher depreciation ($9 million), higher bad debt expense ($4 million), an increase in other taxes ($5 million) and increased pipeline integrity work ($6 million). Increased expense related to energy efficiency programs ($8 million) and increased expense related to higher gross receipt taxes ($7 million) were offset by the related revenues.

Energy Services

For information regarding factors that may affect the future results of operations of our Energy 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 2013 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 Energy Services business segment for the three and nine months ended September 30, 2014 and 2013 (in millions, except throughput and customer data):



	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
Revenues	$	604	$	520	$	2,364	$	1,745
Expenses:
Natural gas	582		503		2,280		1,693
Operation and maintenance	14		13		36		35
Depreciation and amortization	2		2		4		4
Taxes other than income taxes	—		—		1		1
Total expenses	598		518		2,321		1,733
Operating Income	$	6	$	2	$	43	$	12
Throughput (in Bcf)	140		134		463		433
Number of customers at end of period	17,900		17,537		17,900		17,537

Three months ended September 30, 2014 compared to three months ended September 30, 2013

Our Energy Services business segment reported operating income of $6 million for the three months ended September 30, 2014 compared to $2 million for the three months ended September 30, 2013. The increase in operating income of $4 million was primarily due to a $13 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 a benefit of $6 million for the same period of 2013.

Nine months ended September 30, 2014 compared to nine months ended September 30, 2013

Our Energy Services business segment reported operating income of $43 million for the nine months ended September 30, 2014 compared to $12 million for the nine months ended September 30, 2013. The increase in operating income of $31 million was primarily due to $15 million of improved margins resulting from optimization of existing gas transportation assets, reduced fixed costs, increased throughput and price volatility. The first nine months of 2014 included a $23 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 a benefit of $7 million for the same period of 2013.

Interstate Pipelines

For information regarding factors that may affect our historical 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 2013 Form 10-K and and in Item 1A of Part II of our First Quarter Form 10-Q.

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



	Three Months Ended September 30, 2013		Nine Months Ended September 30, 2013 (1)
Revenues	$	—	$	186
Expenses:
Natural gas	—		35
Operation and maintenance	—		51
Depreciation and amortization	—		20
Taxes other than income taxes	—		8
Total expenses	—		114
Operating Income	$	—	$	72

Equity in earnings of unconsolidated affiliates	$	—	$	7

Transportation throughput (in Bcf)	—		482

______________

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

Our Interstate Pipeline business segment reported operating income of $-0- and $72 million for the three and nine months ended September 30, 2013, respectively. Substantially all of this segment was contributed to Enable on May 1, 2013. As a result, the three and nine months ended September 30, 2014 are not comparable to the same periods in the prior year. Effective May 1, 2013, our equity method investment and related equity income in Enable 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 $-0- and $7 million for the three and nine months ended September 30, 2013, respectively. Beginning May 1, 2013, equity earnings related to our interest in SESH and Enable are reported as components of equity income in our Midstream Investments segment.

Field Services

For information regarding factors that may affect our historical 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 2013 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 historical Field Services business segment for the three and nine months ended September 30, 2013 (in millions, except throughput data):



	Three Months Ended September 30, 2013		Nine Months Ended September 30, 2013 (1)
Revenues	$	—	$	196
Expenses:
Natural gas	—		54
Operation and maintenance	—		45
Depreciation and amortization	—		20
Taxes other than income taxes	—		4
Total expenses	—		123
Operating Income	$	—	$	73

Gathering throughput (in Bcf)	—		252

______________

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

Our Field Services business segment reported operating income of $-0- and $73 million for the three and nine months ended September 30, 2013, respectively. Substantially all of this segment was contributed to Enable on May 1, 2013. As a result, the three and nine months ended September 30, 2014 are not comparable to the same periods in the prior year. Effective May 1, 2013, our equity method investment and related equity income in Enable are included in our Midstream Investments segment.

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, Energy 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 2013 Form 10-K and in Item 1A of Part II of our First Quarter Form 10-Q.

The following table provides pre-tax equity income of our Midstream Investments business segment for the three and nine months ended September 30, 2014 and 2013 (in millions):



	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013 (1)
Enable	$	79	$	77	$	236	$	110
SESH	—		3		5		5
Total	$	79	$	80	$	241	$	115


(1)	Represents our 58.3% limited partner interest in Enable and our 25.05% interest in SESH for the five months ended September 30, 2013.

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 2013 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 2013 Form 10-K, “Risk Factors” in Item 1A of Part II in this Quarterly Report on Form 10-Q and “Cautionary Statement Regarding Forward-Looking Information” in our First Quarter 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 three months of 2014 include approximately $157 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 Enable will be sufficient to meet our anticipated cash needs for the remaining three months of 2014. 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 and additional credit facilities may not, however, be available to us on acceptable terms.

Off-Balance Sheet Arrangements

Prior to the distribution of CenterPoint Energy'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 guarantees 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 our remaining guarantees 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 guarantees 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 $46 million as of September 30, 2014. Based on market conditions in the fourth quarter of 2014 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.

We have also provided a guarantee of collection of $1.1 billion of Enable's Guaranteed Senior Notes. This guarantee is subordinated to all our senior debt and is subject to automatic release on May 1, 2016.

The fair value of these guarantees is not material. Other than the guarantees described above and operating leases, we have no off-balance sheet arrangements.

Regulatory Matters

Significant regulatory developments that have occurred since our Quarterly Report on Form 10-Q for the quarter ended June 30, 2014 was filed with the Securities and Exchange Commission (SEC) are discussed below.

Gas Operations

Minnesota Rate Proceeding. On August 2, 2013, our natural gas distribution business (Gas Operations) filed a general rate case in Minnesota to increase base rates by $44.3 million (including the movement of a $15 million energy efficiency rider into base rates), based on a rate base of $700 million and return on equity (ROE) of 10.3%. In compliance with state law, Gas Operations implemented interim rates reflecting $42.9 million dollars of the requested increase for gas used on and after October 1, 2013. This rate filing is intended to recover significant capital expenditures Gas Operations is making in Minnesota and included moving $15 million of energy efficiency expenditures to base rates. Evidentiary hearings were held before an administrative law judge (ALJ) in January 2014. On April 9, 2014 the ALJ issued its findings of fact and recommendations, which support a $31.6 million revenue increase based on a 9.59% ROE. In May 2014, the Minnesota Public Utility Commission (MPUC) entered an order approving a rate increase of $33 million based on a 9.59% ROE and a 52.6% equity ratio. The MPUC also authorized the implementation of a three-year pilot revenue decoupling mechanism with an effective date of July 1, 2015. Gas Operations anticipates final rates will

be implemented in the fourth quarter of 2014. Since the adopted revenue increase is less than the interim revenue increase, a refund to customers, which has been accrued, is anticipated in the fourth quarter of 2014.

Arkansas Government Mandated Expenditure Surcharge Rider (GMESR). On May 1, 2014, Gas Operations made a filing with the Arkansas Public Service Commission (APSC) requesting to increase revenue under its interim GMESR by an additional $1.8 million. Interim rates were implemented upon filing and are subject to refund pending a final order from the APSC.

Louisiana Rate Stabilization Plan (RSP). Gas Operations made its 2014 Louisiana RSP filings with the Louisiana Public Service Commission on October 1, 2014. The North Louisiana Rider RSP filing shows a revenue deficiency of $4.0 million, compared to the authorized return of 10.25%. The South Louisiana Rider RSP filing shows a revenue deficiency of $2.3 million, compared to the authorized return of 10.5%. Gas Operations will begin billing the revised rates in December 2014 subject to refund.

Mississippi Rate Regulation Adjustment (RRA). On May 1, 2014, Gas Operations filed for a $4.1 million RRA with an adjusted ROE of 9.27%. On August 5, 2014, the Mississippi Public Service Commission approved a joint stipulation for a revenue adjustment of $2.8 million, which included an adjustment to amortize over three years $0.5 million of expense incurred with the 2013 test year. New rates went into effect in September 2014.

Oklahoma Performance Based Rate Change (PBRC). In March 2014, Gas Operations made a PBRC filing for the 2013 calendar year proposing to increase revenues by $1.5 million. On July 3, 2014, the Oklahoma Corporation Commission approved a joint stipulation by Gas Operations and the intervening parties resulting in a rate increase of $0.3 million, which included an adjustment to amortize over five years $1.5 million of expense incurred within the 2013 test year. New rates went into effect on July 3, 2014.

Other Matters

Credit Facility

On September 9, 2014, our revolving credit facility was amended to, among other things, extend the maturity date of the commitment from September 9, 2018 to September 9, 2019. The amendment also reduced the swingline and letter of credit sub-facility, with the total commitments remaining unchanged. As of October 22, 2014, we had the following revolving credit facility (in millions):



Date Executed	Size of Facility		Amount Utilized at October 22, 2014		Termination Date
September 9, 2011	$	600	$	—	September 9, 2019

CERC Corp.’s $600 million revolving credit facility can be drawn at the London Interbank Offered Rate (LIBOR) plus 1.50% based on CERC Corp.’s current credit ratings. The revolving credit facility contains a financial covenant which limits our consolidated debt to an amount not to exceed 65% of our consolidated capitalization.

Borrowings under the revolving credit 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 revolving credit facility are subject to acceleration upon the occurrence of events of default that we consider customary. The revolving credit facility provides for customary fees, including commitment fees, administrative agent fees, fees in respect of letters of credit and other fees. The LIBOR borrowing spread and the commitment fees fluctuate based on our credit rating. We are currently in compliance with the various business and financial covenants in our revolving credit facility.

CERC Corp.'s $600 million revolving credit facility backstops its $600 million commercial paper program. As of October 22, 2014, 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 amounts of our senior debt securities.

Temporary Investments

As of October 22, 2014, we had no external temporary investments.

Money Pool

We participate in a money pool through which we and certain of our affiliates can borrow or invest on a short-term basis. Funding needs are aggregated and external borrowing or investing is based on the net cash position. The net funding requirements of the money pool are expected to be met with borrowings by CenterPoint Energy under its revolving credit facility or the sale by CenterPoint Energy of its commercial paper. At October 22, 2014, we had investments in the money pool of approximately $155 million. The money pool may not provide sufficient funds to meet our cash needs.

Impact on Liquidity of a Downgrade in Credit Ratings

The interest on borrowings under our credit facility is based on our credit rating. As of October 22, 2014, 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 an issuer's rating over the medium term.


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


(3)	A Fitch rating outlook indicates the direction a rating is likely to move over a one- to two-year period.

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 $600 million revolving credit facility. If our credit ratings had been downgraded one notch by each of the three principal credit rating agencies from the ratings that existed at September 30, 2014, 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 Energy 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 Energy Services business segment, provides natural gas sales and services primarily to commercial and industrial customers and electric and gas utilities throughout the central and eastern United States. In order to economically hedge its exposure to natural gas prices, CES uses derivatives with provisions standard for the industry, including those pertaining to credit thresholds. Typically, the credit threshold negotiated with each counterparty defines the amount of unsecured credit that such counterparty will extend to CES. To the extent that the credit exposure that a counterparty has to CES at a particular time does not exceed that credit threshold, CES is not obligated to provide collateral. Mark-to-market exposure in excess of the credit threshold is routinely collateralized by CES. As of September 30, 2014, the amount posted as collateral aggregated approximately $18 million. Should the credit ratings of CERC Corp. (as the credit support provider for CES) fall below certain levels, CES would be required to provide additional collateral up to the amount of its previously unsecured credit limit. We estimate that as of September 30, 2014, unsecured credit limits extended to CES by counterparties aggregated $308 million, and less than $1 million of such amount was utilized.

Pipeline tariffs and contracts typically provide that if the credit ratings of a shipper or the shipper’s guarantor drop below a threshold level, which is generally investment grade ratings from both Moody’s and S&P, cash or other collateral may be demanded from the shipper in an amount equal to the sum of three months’ charges for pipeline services plus the unrecouped cost of any lateral built for such shipper. If the credit ratings of CERC Corp. decline below the applicable threshold levels, CERC Corp. might need to provide cash or other collateral of as much as $161 million as of September 30, 2014. The amount of collateral will depend on seasonal variations in transportation levels.

Cross Defaults

Under CenterPoint Energy's revolving credit facility, a payment default on, or a non-payment default that permits acceleration of, any indebtedness exceeding $75 million by us will cause a default. In addition, three outstanding series of CenterPoint Energy's senior notes, aggregating $750 million in principal amount as of September 30, 2014, 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 revolving 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.

Enable Midstream Partners

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

Following its IPO in April 2014, Enable is expected to pay a minimum quarterly distribution of $0.2875 per unit on its outstanding units to the extent it has sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to its general partner and its affiliates (referred to as “available cash”) within 45 days after the end of each quarter. On October 24, 2014, Enable declared a quarterly cash distribution of $0.3025 per unit on all of its outstanding common and subordinated units for the quarter ended September 30, 2014. Accordingly, we expect to receive a cash distribution of approximately $71 million from Enable in the fourth quarter of 2014 to be made with respect to our limited partner interest in Enable for the third quarter of 2014.

Dodd-Frank Swaps Regulation

We use derivative instruments such as physical forward contracts, swaps and options to mitigate the impact of changes in commodity prices and weather on our operating results and cash flows. Following enactment of the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank) in July 2010, the Commodity Futures Trading Commission (CFTC) has promulgated regulations to implement Dodd-Frank’s changes to the Commodity Exchange Act, including the definition of commodity-based swaps subject to those regulations. The CFTC regulations are intended to implement new reporting and record keeping requirements related to their swap transactions and a mandatory clearing and exchange-execution regime for various types, categories or classes of swaps, subject to certain exemptions, including the trade-option and end-user exemptions. Although we anticipate that most if not all of our swap transactions should qualify for an exemption to the clearing and exchange-execution requirements, we will still be subject to record keeping and reporting requirements. Other changes to the Commodity Exchange Act made as a result of Dodd-Frank and the CFTC’s implementing regulations could increase the cost of entering into new swaps.

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 Energy 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 2013 Form 10-K and in Item 1A of Part II of our First Quarter Form 10-Q.

Certain Contractual Limits on Our Ability to Issue Securities and Borrow Money

Our revolving credit facility limits our consolidated debt to an amount not to exceed 65% of our consolidated capitalization.

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

On May 14, 2013, the Committee of Sponsoring Organizations of the Treadway Commission (COSO) issued an updated version of its Internal Control - Integrated Framework (2013 Framework). Originally issued in 1992 (1992 Framework), the framework helps organizations design, implement and evaluate the effectiveness of internal control concepts and simplify their use and application. The 1992 Framework remains available during the transition period, which extends to December 15, 2014, after which time COSO will consider it as superseded by the 2013 Framework. As of September 30, 2014, we continue to utilize the 1992 Framework and will transition to the 2013 Framework by the end of 2014.

In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our principal executive officer and principal financial officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of September 30, 2014

to provide assurance that information required to be disclosed in our reports filed or submitted under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms and such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding disclosure.

There has been no change in our internal controls over financial reporting that occurred during the three months ended September 30, 2014 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 2013 Form 10-K.

Item 1A. RISK FACTORS

There have been no material changes from the risk factors disclosed in our 2013 Form 10-K and First Quarter Form 10-Q.

Item 5. OTHER INFORMATION

Ratio of Earnings to Fixed Charges. Our ratio of earnings to fixed charges for the nine months ended September 30, 2014 and 2013 was 4.37 and 2.98, respectively. We do not believe that the ratios for these nine-month periods are necessarily indicative of the ratios for the twelve-month periods due to the seasonal nature of our business. The ratios were calculated pursuant to applicable rules of the Securities and Exchange Commission.

Item 6. EXHIBITS

The following exhibits are filed herewith:

Exhibits not incorporated by reference to a prior filing are designated by a cross (+); all exhibits not so designated are incorporated by reference to a prior filing 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
4.2	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
4.3	Second Amendment to Credit Agreement, dated as of September 9, 2013, among CERC Corp., as Borrower, and the banks named therein	Form 8-K dated September 9, 2013	1-13265	4.3
4.4	Third Amendment to Credit Agreement, dated September 9, 2014, among CERC Corp., as Borrower, and the banks named therein	Form 8-K dated September 10, 2014	1-13265	4.3
10.1	Indenture, dated as of May 27, 2014, between Enable Midstream Partners, LP and U.S. Bank National Association, as trustee.	Form 8-K dated May 27, 2014	1-13265	10.1
10.2	First Supplemental Indenture, dated as of May 27, 2014, among Enable Midstream Partners, LP, CenterPoint Energy Resources Corp., as guarantor, and U.S. Bank National Association, as trustee.	Form 8-K dated May 27, 2014	1-13265	10.2
10.3	Registration Rights Agreement, dated as of May 27, 2014, by and among Enable Midstream Partners, LP, CenterPoint Energy Resources Corp., as guarantor, and RBS Securities Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Credit Suisse Securities (USA) LLC, and RBC Capital Markets, LLC, as representatives of the initial purchasers.	Form 8-K dated May 27, 2014	1-13265	10.3
+12	Computation of Ratios of Earnings to Fixed Charges
+31.1	Rule 13a-14(a)/15d-14(a) Certification of Scott M. Prochazka
+31.2	Rule 13a-14(a)/15d-14(a) Certification of Gary L. Whitlock
+32.1	Section 1350 Certification of Scott M. Prochazka
+32.2	Section 1350 Certification of Gary L. Whitlock



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

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/ Kristie L. Colvin
	Kristie L. Colvin
	Senior Vice President and Chief Accounting Officer

Date: November 10, 2014

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
4.2	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
4.3	Second Amendment to Credit Agreement, dated as of September 9, 2013, among CERC Corp., as Borrower, and the banks named therein	Form 8-K dated September 9, 2013	1-13265	4.3
4.4	Third Amendment to Credit Agreement, dated September 9, 2014, among CERC Corp., as Borrower, and the banks named therein	Form 8-K dated September 10, 2014	1-13265	4.3
10.1	Indenture, dated as of May 27, 2014, between Enable Midstream Partners, LP and U.S. Bank National Association, as trustee.	Form 8-K dated May 27, 2014	1-13265	10.1
10.2	First Supplemental Indenture, dated as of May 27, 2014, among Enable Midstream Partners, LP, CenterPoint Energy Resources Corp., as guarantor, and U.S. Bank National Association, as trustee.	Form 8-K dated May 27, 2014	1-13265	10.2
10.3	Registration Rights Agreement, dated as of May 27, 2014, by and among Enable Midstream Partners, LP, CenterPoint Energy Resources Corp., as guarantor, and RBS Securities Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Credit Suisse Securities (USA) LLC, and RBC Capital Markets, LLC, as representatives of the initial purchasers.	Form 8-K dated May 27, 2014	1-13265	10.3
+12	Computation of Ratios of Earnings to Fixed Charges
+31.1	Rule 13a-14(a)/15d-14(a) Certification of Scott M. Prochazka
+31.2	Rule 13a-14(a)/15d-14(a) Certification of Gary L. Whitlock
+32.1	Section 1350 Certification of Scott M. Prochazka
+32.2	Section 1350 Certification of Gary L. Whitlock



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

CENTERPOINT ENERGY RESOURCES CORP - FORM 10-Q - November 10, 2014

Attached files

CENTERPOINT ENERGY RESOURCES CORP Reports