CENTERPOINT ENERGY RESOURCES CORP - FORM 10-Q

Attached files

file	filename
EX-31.1 - EXHIBIT 31.1 - CENTERPOINT ENERGY RESOURCES CORP	cercexhibit311_9302015.htm
EX-32.2 - EXHIBIT 32.2 - CENTERPOINT ENERGY RESOURCES CORP	cercexhibit322_9302015.htm
EX-31.2 - EXHIBIT 31.2 - CENTERPOINT ENERGY RESOURCES CORP	cercexhibit312_9302015.htm
EX-32.1 - EXHIBIT 32.1 - CENTERPOINT ENERGY RESOURCES CORP	cercexhibit321_9302015.htm
EX-12 - EXHIBIT 12 - CENTERPOINT ENERGY RESOURCES CORP	cercexhibit12_9302015.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, 2015
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 23, 2015, 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, 2015

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, 2015 and 2014 (unaudited)	1

	Condensed Statements of Consolidated Comprehensive Income
	Three and Nine Months Ended September 30, 2015 and 2014 (unaudited)	2

	Condensed Consolidated Balance Sheets
	September 30, 2015 and December 31, 2014 (unaudited)	3

	Condensed Statements of Consolidated Cash Flows
	Nine Months Ended September 30, 2015 and 2014 (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	33

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 reasonably 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 from those expressed or implied by our forward-looking statements:


•	the performance of Enable Midstream Partners, LP (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 factors such as:


◦	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 crude oil, 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;


◦	recording of non-cash goodwill, long-lived asset or other than temporary impairment charges by or related to Enable;


◦	changes in tax status;


◦	access to growth capital; and


◦	the availability and prices of raw materials and services for current and future construction projects;


•	state and federal legislative and regulatory actions or developments affecting various aspects of our businesses (including the businesses of 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;


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


•	problems with regulatory approval, 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;


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


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


•	our ability to mitigate weather impacts through normalization or rate mechanisms, and the effectiveness of such mechanisms;


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


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


•	the impact of unplanned facility outages;


•	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;


•	our ability to invest planned capital;


•	our ability to control operation and maintenance costs;


•	the sufficiency of our insurance coverage, including availability, cost, coverage and terms;


•	the investment performance of CenterPoint Energy, Inc.’s pension and postretirement benefit plans;


•	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;


•	changes in interest rates or rates of inflation;


•	actions by credit rating agencies;


•	inability of various counterparties to meet their obligations to us;


•	non-payment for our services due to financial distress of our customers;


•	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;


•	our or Enable’s ability to recruit, effectively transition and retain management and key employees and maintain good labor relations;


•	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;


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


•	effectiveness of our risk management activities;


•	the effect of changes in and application of accounting standards and pronouncements; 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, 2014, which is incorporated herein by reference, and other reports we file from time to time with the Securities and Exchange Commission.

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

iii

PART I. FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES

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

CONDENSED STATEMENTS OF CONSOLIDATED INCOME

(Millions of Dollars)

(Unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014

Revenues	$	799		$	964		$	3,440		$	4,678

Expenses:
Natural gas	527			702			2,410			3,625
Operation and maintenance	165			184			541			562
Depreciation and amortization	57			53			169			153
Taxes other than income taxes	32			28			115			114
Total	781			967			3,235			4,454
Operating Income (Loss)	18			(3		)	205			224

Other Income (Expense):
Interest and other finance charges	(34		)	(36		)	(103		)	(105		)
Equity in earnings (losses) of unconsolidated affiliates, net	(794		)	79			(699		)	241
Other, net	2			3			3			7
Total	(826		)	46			(799		)	143
Income (Loss) Before Income Taxes	(808		)	43			(594		)	367
Income tax expense (benefit)	(300		)	15			(217		)	139
Net Income (Loss)	$	(508	)	$	28		$	(377	)	$	228

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,
	2015			2014		2015			2014

Net income (loss)	$	(508	)	$	28	$	(377	)	$	228
Other comprehensive income, net of tax:
Adjustment to pension and other postretirement plans (net of tax)	—			—		—			—
Other comprehensive income	—			—		—			—
Comprehensive income (loss)	$	(508	)	$	28	$	(377	)	$	228

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, 2015		December 31, 2014
Current Assets:
Cash and cash equivalents	$	1	$	2
Accounts receivable, less bad debt reserve of $18 and $23, respectively	261		595
Accrued unbilled revenue	68		262
Accounts and notes receivable–affiliated companies	75		18
Materials and supplies	49		41
Natural gas inventory	168		211
Non-trading derivative assets	78		99
Deferred income tax assets	—		1
Prepaid expenses and other current assets	41		90
Total current assets	741		1,319

Property, Plant and Equipment:
Property, plant and equipment	5,720		5,364
Less: accumulated depreciation and amortization	1,634		1,554
Property, plant and equipment, net	4,086		3,810

Other Assets:
Goodwill	840		840
Non-trading derivative assets	39		32
Investment in unconsolidated affiliates	3,604		4,521
Notes receivable from unconsolidated affiliates	363		363
Other	150		160
Total other assets	4,996		5,916

Total Assets	$	9,823	$	11,045

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, 2015		December 31, 2014
Current Liabilities:
Short-term borrowings	$	49	$	53
Current portion of long-term debt	325		—
Accounts payable	226		528
Accounts and notes payable–affiliated companies	33		228
Taxes accrued	60		67
Interest accrued	40		36
Customer deposits	78		80
Non-trading derivative liabilities	12		19
Other	164		137
Total current liabilities	987		1,148

Other Liabilities:
Deferred income taxes, net	2,078		2,252
Non-trading derivative liabilities	5		1
Benefit obligations	110		111
Regulatory liabilities	703		669
Other	199		194
Total other liabilities	3,095		3,227

Long-Term Debt	1,917		2,469

Commitments and Contingencies (Note 10)

Stockholder’s Equity:
Common stock	—		—
Paid-in capital	2,417		2,417
Retained earnings	1,406		1,783
Accumulated other comprehensive income	1		1
Total stockholder’s equity	3,824		4,201

Total Liabilities and Stockholder’s Equity	$	9,823	$	11,045

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,
	2015			2014
Cash Flows from Operating Activities:
Net income (loss)	$	(377	)	$	228
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	169			153
Amortization of deferred financing costs	7			7
Deferred income taxes	(162		)	132
Write-down of natural gas inventory	4			2
Equity in (earnings) losses of unconsolidated affiliates, net of distributions	843			(6		)
Changes in other assets and liabilities:
Accounts receivable and unbilled revenues, net	532			444
Accounts receivable/payable–affiliated companies	(64		)	7
Inventory	31			(118		)
Taxes receivable	—			18
Accounts payable	(302		)	(220		)
Fuel cost recovery	71			(57		)
Interest and taxes accrued	(3		)	(15		)
Non-trading derivatives, net	(6		)	(25		)
Margin deposits, net	20			(13		)
Other current assets	13			18
Other current liabilities	(12		)	(8		)
Other assets	11			8
Other liabilities	(9		)	22
Other, net	—			5
Net cash provided by operating activities	766			582
Cash Flows from Investing Activities:
Capital expenditures	(420		)	(376		)
Distribution of unconsolidated affiliates in excess of cumulative earnings	74			—
Increase in notes receivable–affiliated companies	—			(83		)
Other, net	3			(2		)
Net cash used in investing activities	(343		)	(461		)
Cash Flows from Financing Activities:
Increase (decrease) in short-term borrowings, net	(4		)	37
Payments of commercial paper, net	(232		)	(118		)
Decrease in notes payable–affiliated companies	(188		)	(38		)
Other, net	—			1
Net cash used in financing activities	(424		)	(118		)

Net Increase (Decrease) in Cash and Cash Equivalents	(1		)	3
Cash and Cash Equivalents at Beginning of Period	2			1
Cash and Cash Equivalents at End of Period	$	1		$	4

Supplemental Disclosure of Cash Flow Information:
Cash Payments:
Interest, net of capitalized interest	$	90		$	91
Income taxes (refunds), net	7			(1		)
Non-cash transactions:
Accounts payable related to capital expenditures	$	37		$	25
Exercise of SESH put to Enable	1			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, 2014.

Background. CERC owns and operates natural gas distribution systems and owns interests 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, 2015, 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 generally accepted accounting principles 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 February 2015, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update No. 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis (ASU 2015-02). ASU 2015-02 changes the analysis that reporting organizations must perform to evaluate whether they should consolidate certain legal entities, such as limited partnerships. The changes include, among others, modification of the evaluation of whether limited partnerships and similar legal entities are variable interest entities (VIEs) or voting interest entities and elimination of the presumption that a general partner should consolidate a limited partnership. ASU 2015-02 does not amend the related party guidance for situations in which power is shared between two or more entities that hold interests in a VIE. ASU 2015-02 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2015. CERC will adopt ASU 2015-02 on January 1, 2016 and is currently assessing the impact, if any, that this standard will have on its financial position, results of operations, cash flows and disclosures.

In April 2015, the FASB issued Accounting Standards Update No. 2015-03, Interest-Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Cost (ASU 2015-03). ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by ASU 2015-03. CERC will adopt ASU 2015-03 retrospectively on January 1, 2016, which will result in a reduction of both other long-term assets and long-term debt on its Condensed Consolidated Balance Sheets. CERC had debt issuance costs of $16 million and $18 million included in other long-term assets on its Condensed Consolidated Balance Sheets as of September 30, 2015 and December 31, 2014, respectively.

In April 2015, the FASB issued Accounting Standards Update No. 2015-05, Intangibles-Goodwill and Other-Internal-Use Software (Subtopic 350-40) (ASU 2015-05). ASU 2015-05 provides guidance to customers about whether a cloud computing

arrangement includes a software license. If a cloud computing arrangement includes a software license, the customer should account for the software license element of the arrangement consistent with the acquisition of other software licenses. If a cloud computing arrangement does not include a software license, the customer should account for the arrangement as a service contract. The guidance will not change a customer’s accounting for service contracts. ASU 2015-05 is effective for fiscal years, and interim periods within the fiscal years, beginning after December 15, 2015 and may be adopted either prospectively or retrospectively. CERC will adopt ASU 2015-05 on January 1, 2016 and is currently assessing the impact that this standard will have on its financial position, results of operations, cash flows and disclosures.

In May 2014, the FASB issued Accounting Standards Update 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 was initially 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. In August 2015, the FASB issued Accounting Standard Update No. 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date, which delays the effective date of ASU 2014-09 by one year. CERC is currently evaluating the impact that ASU 2014-09 will have on its financial position, results of operations, cash flows and disclosures, and may adopt ASU 2014-09 on January 1, 2018 as permitted by the new guidance.

In July 2015, the FASB issued Accounting Standards Update No. 2015-11, Inventory (Topic 330) Simplifying the Measurement of Inventory (ASU 2015-11). ASU 2015-11 changes the subsequent measurement guidance for inventory accounted for using methods other than the last in, first out (LIFO) and Retail Inventory methods. Companies will subsequently measure inventory at the lower of cost and net realizable value. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. Subsequent measurement is unchanged for inventory measured using LIFO or the retail inventory method. ASU 2015-11 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, with early adoption permitted. CERC does not believe that ASU 2015-11 will have a material impact 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,
	2015			2014			2015			2014
	(in millions)
Service cost	$	1		$	1		$	1		$	1
Interest cost on accumulated benefit obligation	2			1			$	4		$	4
Expected return on plan assets	(1		)	(1		)	(1		)	(1		)
Amortization of loss	—			1			1			1
Net periodic cost	$	2		$	2		$	5		$	5

CERC expects to contribute approximately $7 million to its postretirement benefit plan in 2015, of which $1 million and $4 million were contributed during the three and nine months ended September 30, 2015, 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 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, 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 natural gas distribution business (NGD) in Arkansas, Louisiana, Mississippi, Minnesota and Oklahoma. NGD in Texas does not have such mechanisms. As a result, fluctuations from normal weather may have a positive or negative effect on NGD’s results in Texas.

CERC has historically entered into heating-degree day swaps for certain NGD 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 $16 million in both 2013–2014 and 2014–2015. However, NGD did not enter into heating-degree day swaps for the 2015–2016 winter season as a result of NGD’s Minnesota division implementing a full decoupling pilot in July 2015. The swaps are based on ten-year normal weather. During both the three months ended September 30, 2015 and 2014, CERC recognized no losses related to these swaps. During the nine months ended September 30, 2015 and 2014, CERC recognized losses of $4 million and $7 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, 2015 and December 31, 2014, while the last two tables provide a breakdown of the related income statement impacts for the three and nine months ended September 30, 2015 and 2014.



Fair Value of Derivative Instruments
		September 30, 2015
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	$	80	$	2
Natural gas derivatives (1) (2)	Other Assets: Non-trading derivative assets	39		—
Natural gas derivatives (1) (2)	Current Liabilities: Non-trading derivative liabilities	16		59
Natural gas derivatives (1) (2)	Other Liabilities: Non-trading derivative liabilities	3		24
Total		$	138	$	85


(1)	The fair value shown for natural gas contracts is comprised of derivative gross volumes totaling 776 billion cubic feet (Bcf) or a net 77 Bcf long position. Of the net long position, basis swaps constitute 128 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 $100 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 $47 million.



Offsetting of Natural Gas Derivative Assets and Liabilities
	September 30, 2015
	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	$	96		$	(18	)	$	78
Other Assets: Non-trading derivative assets	42			(3		)	39
Current Liabilities: Non-trading derivative liabilities	(61		)	49			(12		)
Other Liabilities: Non-trading derivative liabilities	(24		)	19			(5		)
Total	$	53		$	47		$	100


(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, 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	$	101	$	1
Natural gas derivatives (1) (2)	Other Assets: Non-trading derivative assets	32		—
Natural gas derivatives (1) (2)	Current Liabilities: Non-trading derivative liabilities	14		83
Natural gas derivatives (1) (2)	Other Liabilities: Non-trading derivative liabilities	2		18
Total		$	149	$	102


(1)	The fair value shown for natural gas contracts is comprised of derivative gross volumes totaling 804 Bcf or a net 60 Bcf long position. Of the net long position, basis swaps constitute 127 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 $111 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 $64 million.



Offsetting of Natural Gas Derivative Assets and Liabilities
	December 31, 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	$	115		$	(16	)	$	99
Other Assets: Non-trading derivative assets	34			(2		)	32
Current Liabilities: Non-trading derivative liabilities	(84		)	65			(19		)
Other Liabilities: Non-trading derivative liabilities	(18		)	17			(1		)
Total	$	47		$	64		$	111


(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.

Realized and unrealized gains and losses on derivatives are recognized in the Condensed Statements of Consolidated Income as revenue for retail sales derivative contracts and as natural gas expense for financial natural gas derivatives and non-retail related 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	2015			2014
		(in millions)
Natural gas derivatives	Gains (Losses) in Revenue	$	39		$	22
Natural gas derivatives (1)	Gains (Losses) in Expense: Natural Gas	(30		)	(4		)
Total		$	9		$	18


(1)	The Gains (Losses) in Expense: Natural Gas includes $-0- during each of the three months ended September 30, 2015 and 2014, related to physical forwards purchased from Enable.



Income Statement Impact of Derivative Activity
		Nine Months Ended September 30,
Total derivatives not designated as hedging instruments	Income Statement Location	2015			2014
		(in millions)
Natural gas derivatives	Gains (Losses) in Revenue	$	88		$	(74	)
Natural gas derivatives (1)	Gains (Losses) in Expense: Natural Gas	(72		)	110
Total		$	16		$	36


(1)	The Gains (Losses) in Expense: Natural Gas includes $-0- and $2 million during the nine months ended September 30, 2015 and 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 September 30, 2015 and December 31, 2014 was $3 million and $2 million, respectively. CERC posted no assets as collateral towards derivative instruments that contain credit risk contingent features at either September 30, 2015 or December 31, 2014. If all derivative contracts (in a net liability position) containing credit risk contingent features were triggered at September 30, 2015 and December 31, 2014, $3 million and $2 million, respectively, of additional assets would be required to be posted as collateral.

(5) Fair Value Measurements

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

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

Level 2: Inputs, other than quoted prices included in Level 1, are observable for the asset or liability, either directly or indirectly. Level 2 inputs include quoted prices for similar instruments in active markets, and inputs other than quoted prices that are observable for the asset or liability. Fair value assets and liabilities that are generally included in this category are derivatives with fair values based on inputs from actively quoted markets. A market approach is utilized to value CERC’s Level 2 assets or liabilities.

Level 3: Inputs are unobservable for the asset or liability, and include situations where there is little, if any, market activity for the asset or liability. Unobservable inputs reflect CERC’s judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. CERC develops these inputs based on the best information available, including

CERC’s own data. A market approach is utilized to value CERC’s Level 3 assets or liabilities. At September 30, 2015, 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 $1.17 to $3.78 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 76%) 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, 2015, 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, 2015 and December 31, 2014, 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, 2015
	(in millions)
Assets
Corporate equities	$	2	$	—	$	—	$	—		$	2
Investments, including money market funds (2)	11		—		—		—			11
Natural gas derivatives	5		111		22		(21		)	117
Total assets	$	18	$	111	$	22	$	(21	)	$	130
Liabilities
Natural gas derivatives	$	14	$	63	$	8	$	(68	)	$	17
Total liabilities	$	14	$	63	$	8	$	(68	)	$	17


(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 $47 million posted with the same counterparties.


(2)	Amounts are included in Prepaid Expenses and Other Current Assets in the Condensed Consolidated Balance Sheets.



	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, 2014
	(in millions)
Assets
Corporate equities	$	2	$	—	$	—	$	—		$	2
Investments, including money market funds (2)	11		—		—		—			11
Natural gas derivatives	7		122		20		(18		)	131
Total assets	$	20	$	122	$	20	$	(18	)	$	144
Liabilities
Natural gas derivatives	$	22	$	77	$	3	$	(82	)	$	20
Total liabilities	$	22	$	77	$	3	$	(82	)	$	20


(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 $64 million posted with the same counterparties.


(2)	Amounts are included in Prepaid Expenses and Other Current Assets in the Condensed Consolidated Balance Sheets.

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,
	2015			2014			2015			2014
	(in millions)
Beginning balance	$	10		$	4		$	17		$	3
Total gains	5			6			5			6
Total settlements	(2		)	(1		)	(8		)	1
Transfers into Level 3	1			—			1			(1		)
Transfers out of Level 3	—			—			(1		)	—
Ending balance (1)	$	14		$	9		$	14		$	9
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		$	6		$	7		$	7


(1)	CERC did not have significant Level 3 purchases or sales during either of the three or nine months ended September 30, 2015 or 2014.

Items Measured at Fair Value on a Nonrecurring Basis

Based on the sustained low Enable common unit price and further declines in such price during the three months ended September 30, 2015 as well as the market outlook for continued depressed crude oil and natural gas prices impacting the midstream oil and gas industry, CERC determined in connection with its preparation of financial statements for the three months ended September 30, 2015, that an other than temporary decrease in the value of its investment in Enable had occurred. The impairment analysis compared the estimated fair value of CERC’s investment in Enable to its carrying value. The fair value of the investment was determined using multiple valuation methodologies under both the market and income approaches. Both of these approaches incorporate significant estimates and assumptions, including:

Market Approach


•	quoted price of Enable’s common units;


•	recent market transactions of comparable companies; and


•	EBITDA to total enterprise multiples for comparable companies.

Income Approach


•	Enable’s forecasted cash distributions;


•	projected cash flows of incentive distribution rights;


•	forecasted growth rate of Enable’s cash distributions; and


•	determination of the cost of equity, including market risk premiums.

Weighting of the different approaches

Significant unobservable inputs used include the growth rate applied to the projected cash distributions beyond 2020 and the discount rate used to determine the present value of the estimated future cash flows. Based on the significant unobservable estimates and assumptions required, CERC concluded that the fair value estimate should be classified as a Level 3 measurement within the

fair value hierarchy. As a result of the analysis, CERC recorded an other than temporary impairment on its investment in Enable of $250 million, reducing the fair value of the investment to $3.6 billion. See Note 6 for further discussion of the impairment. As of December 31, 2014, there were no significant assets or liabilities measured at fair value on a nonrecurring basis.

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, 2015				December 31, 2014
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in millions)
Financial assets:
Notes receivable from unconsolidated affiliates	$	363	$	362	$	363	$	362
Financial liabilities:
Long-term debt	$	2,242	$	2,460	$	2,469	$	2,772

(6) Unconsolidated Affiliates

On May 1, 2013 (the Closing Date) CERC Corp., OGE Energy Corp. (OGE) and ArcLight Capital Partners, LLC 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.

CERC’s maximum exposure to loss related to Enable, a VIE in which CERC is not the primary beneficiary, is limited to its equity investment as presented in the Condensed Consolidated Balance Sheet at September 30, 2015, 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 during each of the three months ended September 30, 2015 and 2014, and $6 million during each of the nine months ended September 30, 2015 and 2014, and had interest receivable from Enable of $2 million and $4 million as of September 30, 2015 and December 31, 2014, respectively, on its notes receivable.

Effective on the Closing Date, CenterPoint Energy and Enable entered into a Services Agreement, Employee Transition Agreement, Transitional Seconding Agreement and other agreements (Transition Agreements). Under the Services Agreement, CERC agreed to provide certain support services to Enable such as accounting, legal, risk management and treasury functions for an initial term. The initial term of the Services Agreement ends on April 30, 2016, after which date such services continue on a year-to-year basis unless terminated by Enable with at least 90 days’ notice. Enable may terminate the Services Agreement, or the provision of any services thereunder, upon approval by its board of directors and at least 180 days’ notice.

CERC provided seconded employees to Enable to support its operations for a term ending on December 31, 2014. Enable, at its discretion, had the right to select and offer employment to seconded employees from CERC. During the fourth quarter of 2014, Enable notified CERC that it provided employment offers to substantially all of the seconded employees from CERC. Substantially all of the seconded employees became employees of Enable effective January 1, 2015.

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 on the Closing Date, under which CERC would contribute its retained interest in SESH, in exchange for a specified number of limited partner common 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 exercisable with respect to (1) a 24.95% interest in SESH, which closed on May 30, 2014 and (2) a 0.1% interest in SESH, which closed on June 30, 2015.

CERC billed Enable for reimbursement of transition services, including the costs of seconded employees, $3 million and $36 million during the three months ended September 30, 2015 and 2014, respectively, and $10 million and $118 million during the nine months ended September 30, 2015 and 2014, respectively, under the Transition Agreements. Actual transition services costs are

recorded net of reimbursements received from Enable. CERC had accounts receivable from Enable of $4 million and $28 million as of September 30, 2015 and December 31, 2014, respectively, for amounts billed for transition services, including the cost of seconded employees.

CERC incurred natural gas expenses, including transportation and storage costs, of $23 million and $24 million during the three months ended September 30, 2015 and 2014, respectively, and $87 million and $99 million during the nine months ended September 30, 2015 and 2014, respectively, for transactions with Enable. CERC had accounts payable to Enable of $8 million and $23 million at September 30, 2015 and December 31, 2014, respectively, from such transactions.

As of September 30, 2015, CERC held an approximate 55.4% limited partner interest in Enable, consisting of 94,151,707 common units and 139,704,916 subordinated units. As of September 30, 2015, CERC and OGE each own a 50% management interest in the general partner of Enable and a 40% and 60% interest, respectively, in the incentive distribution rights held by the general partner.

CERC recognized a loss of $794 million from its investment in Enable for the three months ended September 30, 2015. This loss included impairment charges totaling $862 million composed of CERC’s impairment of its investment in Enable of $250 million and CERC’s share, $612 million, of impairment charges Enable recorded for goodwill and long-lived assets.

CERC evaluates its equity method investments for impairment when factors indicate that a decrease in the value of its investment has occurred and the carrying amount of its investment may not be recoverable. An impairment loss, based on the excess of the carrying value over estimated fair value of the investment, is recognized in earnings when an impairment is deemed to be other than temporary. Considerable judgment is used in determining if an impairment loss is other than temporary and the amount of any impairment. Based on the sustained low Enable common unit price and further declines in such price during the three months ended September 30, 2015 as well as the market outlook for continued depressed crude oil and natural gas prices impacting the midstream oil and gas industry, CERC determined in connection with its preparation of financial statements for the three months ended September 30, 2015, that an other than temporary decrease in the value of its investment in Enable had occurred. CERC wrote down the value of its investment in Enable to its estimated fair value of $3.6 billion which resulted in an impairment charge of $250 million as of September 30, 2015. Both the income approach and market approach were utilized to estimate the fair value of CERC’s total investment in Enable, which includes the limited partner common and subordinated units, general partner interest and incentive distribution rights held by CERC. The determination of fair value considered a number of relevant factors including Enable’s common unit price and forecasted results, recent comparable transactions and the limited float of Enable’s publicly traded common units. See Note 5 for further discussion of the determination of fair value of CERC’s investment in Enable.

Investment in Unconsolidated Affiliates:



	September 30, 2015		December 31, 2014
	(in millions)
Enable	$	3,604	$	4,520
SESH (1)	—		1
Total	$	3,604	$	4,521


(1)	CERC disposed of its remaining interest in SESH on June 30, 2015.

Equity in Earnings (Losses) of Unconsolidated Affiliates, net:



	Three Months Ended September 30,					Nine Months Ended September 30,
	2015			2014		2015			2014
	(in millions)
Enable	$	(794	)	$	79	$	(699	)	$	236
SESH (1)	—			—		—			5
Total	$	(794	)	$	79	$	(699	)	$	241


(1)	CERC disposed of its remaining interest in SESH on June 30, 2015.

Summarized unaudited consolidated income information for Enable is as follows:



	Three Months Ended September 30,					Nine Months Ended September 30,
	2015			2014		2015			2014
	(in millions)
Operating revenues	$	646		$	804	$	1,852		$	2,632
Cost of sales, excluding depreciation and amortization	287			439		856			1,550
Impairment of goodwill and other long-lived assets	1,105			1		1,105			1
Operating income (loss)	(975		)	151		(778		)	452
Net income (loss) attributable to Enable	(985		)	139		(817		)	408

Reconciliation of Equity in Earnings (Losses), net:
CERC’s interest	$	(546	)	$	76	$	(453	)	$	230
Basis difference accretion	2			3		4			6
Impairment of CERC’s equity method investment in Enable	(250		)	—		(250		)	—
CERC’s equity in earnings (losses), net (1)	$	(794	)	$	79	$	(699	)	$	236


(1)	These amounts include CERC’s share of Enable’s impairment of goodwill and long-lived assets and the impairment of CERC’s equity method investment in Enable totaling $862 million during the three and nine months ended September 30, 2015. This impairment is offset by $68 million and $163 million of earnings for the three and nine months ended September 30, 2015, respectively.

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



	September 30, 2015			December 31, 2014
	(in millions)
Current assets	$	427		$	438
Non-current assets	10,774			11,399
Current liabilities	804			671
Non-current liabilities	2,786			2,343
Non-controlling interest	25			31
Enable partners’ capital	7,586			8,792

Reconciliation of Investment in Enable:
CERC’s ownership interest in Enable partners’ capital	$	4,200		$	4,869
CERC’s existing basis difference	(346		)	(349		)
Impairment of CERC’s equity method investment in Enable	(250		)	—
CERC’s investment in Enable	$	3,604		$	4,520

Distributions Received from Unconsolidated Affiliates:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
	(in millions)
Enable	$	74	$	70	$	219	$	227
SESH (1)	—		1		—		8
Total	$	74	$	71	$	219	$	235


(1)	CERC disposed of its remaining interest in SESH on June 30, 2015.

(7) Goodwill

Goodwill by reportable business segment as of both September 30, 2015 and December 31, 2014 is as follows:



	(in millions)
Natural Gas Distribution	$	746
Energy Services	83
Other Operations	11
Total	$	840

CERC performs 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 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 goodwill impairment test in the third quarter of 2015 and determined, based on the results of the first step, that no goodwill 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 borrowings from the money pool of $-0- and $188 million at September 30, 2015 and December 31, 2014, respectively, which are included in accounts and notes payable–affiliated companies in the Consolidated Balance Sheets. Net interest income (expense) related to accounts and notes payables–affiliated companies was not material for either the three or nine months ended September 30, 2015 or 2014.

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 as follows and are included primarily in operation and maintenance expenses:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
	(in millions)
Corporate service charges	$	29	$	34	$	88	$	93

See Note 6 for related party transactions with Enable.

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

(a)Short-term Borrowings

Inventory Financing. NGD has asset management agreements associated with its utility distribution service in Arkansas, north Louisiana and Oklahoma that extend through 2018. Pursuant to the provisions of the agreements, NGD sells natural gas and agrees to repurchase an equivalent amount of natural gas during the winter heating seasons at the same cost, plus a financing charge. These transactions are accounted for as a financing and they had an associated principal obligation of $49 million and $53 million as of September 30, 2015 and December 31, 2014, respectively.


(b)	Long-term Debt

Revolving Credit Facility. As of September 30, 2015 and December 31, 2014, CERC had the following revolving credit facility and utilization of such facility:



		September 30, 2015						December 31, 2014
Size of Facility		Loans		Letters of Credit		Commercial Paper		Loans		Letters of Credit		Commercial Paper
(in millions)
$	600	$	—	$	2	$	109	$	—	$	—	$	341

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 as of September 30, 2015.

(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 Consolidated Balance Sheets as of September 30, 2015 and December 31, 2014 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, 2015, minimum payment obligations for natural gas supply commitments are approximately $159 million for the remaining three months in 2015, $489 million in 2016, $466 million in 2017, $413 million in 2018, $224 million in 2019 and $128 million after 2019.

(b) Legal, Environmental and Other Regulatory Matters

Legal Matters

Gas Market Manipulation Cases. CenterPoint Energy, CenterPoint Energy Houston Electric, LLC (CenterPoint Houston) or their predecessor, Reliant Energy, Incorporated (Reliant Energy), and certain of their former subsidiaries have been named as defendants in certain lawsuits described below. Under a master separation agreement between CenterPoint Energy and a former subsidiary, Reliant Resources, Inc. (RRI), CenterPoint Energy and its subsidiaries are entitled to be indemnified by RRI and its 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, and stayed the remainder of the case pending outcome of the appeals. The plaintiffs appealed this ruling to the U.S. Court of Appeals for the Ninth Circuit, which reversed the trial court’s dismissal of the plaintiffs’ claims. The U.S. Supreme Court agreed to review the case, and on April 21, 2015, affirmed the Ninth Circuit’s ruling and remanded the case to the district court for further proceedings. CenterPoint Energy and CES intend to continue vigorously defending against the plaintiffs’ claims on

remand. CERC does not expect the ultimate outcome of this matter to have a material adverse effect 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, 2015, CERC had a recorded liability of $7 million for remediation of these five Minnesota sites. The estimated range of possible remediation costs for the sites for which CERC believes it may have responsibility was $4 million to $28 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.

In addition to the Minnesota sites, the U.S. Environmental Protection Agency and other regulators have investigated MGP sites that were owned or operated by CERC or that may have been owned by one of its former affiliates. CERC and CenterPoint Energy do not expect the ultimate outcome of these investigations to have a material adverse effect 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 $31 million as of September 30, 2015. Based on market conditions in the

fourth quarter of 2015 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 months ended September 30, 2015 was 37% compared to 35% for the same period in 2014. For the three months ended September 30, 2014, CERC recognized a tax benefit of $2 million based on the reversal of previously accrued taxes as a result of CenterPoint Energy’s filing of its 2013 consolidated federal income tax return. The effective tax rate reported for the nine months ended September 30, 2015 was 37% compared to 38% for the same period in 2014. The impairment loss reduced the deferred tax liability on CERC’s investment in Enable.

CERC reported no uncertain tax liability as of September 30, 2015 and expects no significant change to the uncertain tax liability over the twelve-month period ending September 30, 2016. Tax years through 2013 have been audited and settled with the Internal Revenue Service (IRS). For 2014 and 2015, 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 of CERC’s investment in Enable. The Other Operations business segment includes unallocated corporate costs and inter-segment eliminations.

Financial data for business segments is as follows:



	For the Three Months Ended September 30, 2015
	Revenues from External Customers		Inter-segment Revenues			Operating Income
	(in millions)
Natural Gas Distribution	$	353	$	6		$	11
Energy Services	446		6			7
Midstream Investments (1)	—		—			—
Other Operations	—		—			—
Reconciling Eliminations	—		(12		)	—
Consolidated	$	799	$	—		$	18



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



	For the Nine Months Ended September 30, 2015
	Revenues from External Customers		Inter-segment Revenues			Operating Income		Total Assets as of September 30, 2015
	(in millions)
Natural Gas Distribution	$	1,958	$	21		$	176	$	5,360
Energy Services	1,482		28			29		852
Midstream Investments (1)	—		—			—		3,604
Other Operations	—		—			—		759
Reconciling Eliminations	—		(49		)	—		(752		)
Consolidated	$	3,440	$	—		$	205	$	9,823



	For the Nine Months Ended September 30, 2014
	Revenues from External Customers		Inter-segment Revenues			Operating Income (Loss)			Total Assets as of December 31, 2014
	(in millions)
Natural Gas Distribution	$	2,379	$	22		$	184		$	5,464
Energy Services	2,298		66			43			978
Midstream Investments (1)	—		—			—			4,521
Other Operations	1		—			(3		)	1,046
Reconciling Eliminations	—		(88		)	—			(964		)
Consolidated	$	4,678	$	—		$	224		$	11,045


(1)	Midstream Investments’ equity earnings (losses) are as follows:



	Three Months Ended September 30,					Nine Months Ended September 30,
	2015			2014		2015			2014
	(in millions)
Enable (1)	$	(794	)	$	79	$	(699	)	$	236
SESH	—			—		—			5
Total	$	(794	)	$	79	$	(699	)	$	241


(1)	These amounts include CERC’s share of Enable’s impairment of goodwill and long-lived assets and the impairment of CERC’s equity method investment in Enable totaling $862 million during the three and nine months ended September 30, 2015. This impairment is offset by $68 million and $163 million of earnings for the three and nine months ended September 30, 2015, respectively.

Midstream Investments’ total assets are as follows:



	September 30, 2015		December 31, 2014
	(in millions)
Enable	$	3,604	$	4,520
SESH	—		1
Total	$	3,604	$	4,521

(13) Other Current Assets and Liabilities

Included in other current assets on the Condensed Consolidated Balance Sheets at September 30, 2015 and December 31, 2014 were $16 million and $19 million, respectively, of margin deposits and $8 million and $45 million, respectively, of under-recovered gas cost. Included in other current liabilities on the Condensed Consolidated Balance Sheets at September 30, 2015 and December 31, 2014 were $78 million and $37 million, respectively, of over-recovered gas cost.

(14) Subsequent Events

On October 22, 2015, Enable declared a quarterly cash distribution of $0.318 per unit on all of its outstanding common and subordinated units for the quarter ended September 30, 2015. Accordingly, CERC Corp. expects to receive a cash distribution of approximately $74 million from Enable in the fourth quarter of 2015 to be made with respect to CERC Corp.’s limited partner interest in Enable for the third quarter of 2015.

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, 2014 (2014 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, 2015 and the three and nine months ended September 30, 2014. Reference is made to “Management’s Narrative Analysis of Results of Operations” in Item 7 of our 2014 Form 10-K.

RECENT EVENTS

Impairment of Equity Investment. We recognized a loss of $794 million from our investment in Enable for the three months ended September 30, 2015. This loss included impairment charges totaling $862 million composed of the impairment of our investment in Enable of $250 million and our share, $612 million, of impairment charges Enable recorded for goodwill and long-lived assets. For further discussion of the impairment, see Note 6.

Texas Coast Rate Case. On March 27, 2015, our regulated natural gas distribution business (NGD) filed a Statement of Intent with each of the 49 cities and unincorporated areas within its Texas Coast service territory for a $6.8 million annual revenue increase. This increase was based on a rate base of $132.3 million and a return on equity (ROE) of 10.25%. On July 6, 2015, the parties agreed to a settlement providing for a $4.9 million annual increase to rates, an ROE of 10.0%, 54.5% equity and authorized overall rate of return of 8.23%. This settlement resolved six outstanding cases on appeal: one on remand at the Railroad Commission of Texas (Railroad Commission) and five cost of service adjustment (COSA) appeals at the district court. The Railroad Commission unanimously approved the settlement on August 25, 2015. Rates were implemented in September 2015.

Minnesota Rate Case. In August 2015, NGD filed a general rate case with the Minnesota Public Utilities Commission (MPUC) requesting an increase of $54.1 million. On September 10, 2015, the MPUC approved an interim increase of $47.8 million in revenues effective October 2, 2015, subject to a refund. The MPUC is expected to issue a final decision in mid-2016 with final rates effective by the end of 2016.

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 2014 Form 10-K.

The following table sets forth our consolidated results of operations for the three and nine months ended September 30, 2015 and 2014, followed by a discussion of our consolidated results of operations.



	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
	(in millions)
Revenues	$	799		$	964		$	3,440		$	4,678
Expenses:
Natural gas	527			702			2,410			3,625
Operation and maintenance	165			184			541			562
Depreciation and amortization	57			53			169			153
Taxes other than income taxes	32			28			115			114
Total	781			967			3,235			4,454
Operating Income (Loss)	18			(3		)	205			224
Interest and other finance charges	(34		)	(36		)	(103		)	(105		)
Equity in earnings (losses) of unconsolidated affiliates, net	(794		)	79			(699		)	241
Other expense, net	2			3			3			7
Income (Loss) Before Income Taxes	(808		)	43			(594		)	367
Income tax expense (benefit)	(300		)	15			(217		)	139
Net Income (Loss)	$	(508	)	$	28		$	(377	)	$	228

Three months ended September 30, 2015 compared to three months ended September 30, 2014

We reported a net loss of $508 million for the three months ended September 30, 2015 compared to net income of $28 million for the same period in 2014.

The decrease in net income of $536 million was due to an $873 million decrease in equity earnings of unconsolidated affiliates, which included impairment charges of $862 million discussed further in Note 6.

This decrease in net income was partially offset by the following:

•$315 decrease in income tax expense;

•$21 million increase in operating income (discussed by segment below); and

•$2 million decrease in interest expense.

Nine months ended September 30, 2015 compared to nine months ended September 30, 2014

We reported a net loss of $377 million for the nine months ended September 30, 2015 compared to net income of $228 million for the same period in 2014.

The decrease in net income of $605 million was due to the following key factors:


•	$940 million decrease in equity earnings of unconsolidated affiliates, which included impairment charges of $862 million discussed further in Note 6;

•$19 million decrease in operating income (discussed by segment below); and

•$4 million decrease in other income.

These decreases in net income were partially offset by the following:

•$356 million decrease in income tax expense; and

•$2 million decrease in interest expense.

Income Tax Expense

Our effective tax rate reported for the three months ended September 30, 2015 was 37% compared to 35% for the same period in 2014. For the three months ended September 30, 2014, CERC recognized a tax benefit of $2 million based on the reversal of previously accrued taxes as a result of CenterPoint Energy’s filing of its 2013 consolidated federal income tax return. The effective tax rate reported for the nine months ended September 30, 2015 was 37% compared to 38% for the same period in 2014. The impairment loss reduced the deferred tax liability on our investment in Enable.

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, 2015 and 2014, 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 at current market prices.



	Three Months Ended September 30,					Nine Months Ended September 30,
	2015		2014			2015		2014
	(in millions)
Natural Gas Distribution	$	11	$	(8	)	$	176	$	184
Energy Services	7		6			29		43
Other Operations	—		(1		)	—		(3		)
Total Consolidated Operating Income (Loss)	$	18	$	(3	)	$	205	$	224

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 Associated with Our Consolidated Financial Condition,” “— Risk Factors Affecting Our Natural Gas Distribution and Energy Services Businesses” and “— Other Risk Factors Affecting Our Businesses or Our Interests in Enable Midstream Partners, LP” in Item 1A of Part I of our 2014 Form 10-K.

The following table provides summary data of our Natural Gas Distribution business segment for the three and nine months ended September 30, 2015 and 2014:



	Three Months Ended September 30,					Nine Months Ended September 30,
	2015		2014			2015		2014
	(in millions, except throughput and customer data)
Revenues	$	359	$	382		$	1,979	$	2,401
Expenses:
Natural gas	106		142			1,014		1,432
Operation and maintenance	155		169			510		524
Depreciation and amortization	55		52			165		149
Taxes other than income taxes	32		27			114		112
Total expenses	348		390			1,803		2,217
Operating Income (Loss)	$	11	$	(8	)	$	176	$	184
Throughput (in billion cubic feet (Bcf)):
Residential	12		12			128		140
Commercial and industrial	52		46			196		197
Total Throughput	64		58			324		337
Number of customers at end of period:
Residential	3,110,645		3,077,633			3,110,645		3,077,633
Commercial and industrial	248,911		246,789			248,911		246,789
Total	3,359,556		3,324,422			3,359,556		3,324,422

Three months ended September 30, 2015 compared to three months ended September 30, 2014

Our Natural Gas Distribution business segment reported operating income of $11 million for the three months ended September 30, 2015, compared to an operating loss of $8 million for the three months ended September 30, 2014.

Operating income increased $19 million as a result of the following key factors:


•	receipt of the Conservation Improvement Program Incentive (CIP) in August 2015, which has historically been received in the fourth quarter ($12 million);


•	increased rate relief ($5 million);


•	increased economic activity across our footprint, including customer growth ($3 million);


•	increased other revenues ($2 million); and


•	decreased operation and maintenance expense ($2 million).

These increases were partially offset by:


•	higher tax expense ($4 million); and


•	higher depreciation and amortization expense ($3 million).

Increased expense related to gross receipt taxes ($1 million) was offset by the related revenue.

Nine months ended September 30, 2015 compared to nine months ended September 30, 2014

Our Natural Gas Distribution business segment reported operating income of $176 million for the nine months ended September 30, 2015, compared to $184 million for the nine months ended September 30, 2014.

Operating income decreased $8 million as a result of the following key factors:


•	decreased usage, primarily due to colder than normal weather in 2014 ($19 million);


•	higher depreciation and amortization expense ($17 million); and


•	higher tax expense ($7 million).

These decreases were partially offset by:


•	receipt of the CIP in August 2015, which has historically been received in the fourth quarter ($12 million);


•	increased rate relief ($11 million);


•	increased economic activity across our footprint, including the addition of approximately 35,000 customers ($7 million); and


•	increased other revenues ($5 million).

Decreased expense related to energy efficiency programs ($2 million) and decreased expense related to gross receipt taxes ($5 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 Associated with Our Consolidated Financial Condition,” “— Risk Factors Affecting Our Natural Gas Distribution and Energy Services Businesses” and “— Other Risk Factors Affecting Our Businesses or Our Interests in Enable Midstream Partners, LP” in Item 1A of Part I of our 2014 Form 10-K.

The following table provides summary data of our Energy Services business segment for the three and nine months ended September 30, 2015 and 2014:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
	(in millions, except throughput and customer data)
Revenues	$	452	$	604	$	1,510	$	2,364
Expenses:
Natural gas	433		582		1,445		2,280
Operation and maintenance	11		14		32		36
Depreciation and amortization	1		2		3		4
Taxes other than income taxes	—		—		1		1
Total expenses	445		598		1,481		2,321
Operating Income	$	7	$	6	$	29	$	43

Mark-to-market gain	$	5	$	13	$	3	$	23

Throughput (in Bcf)	138		140		459		463

Number of customers at end of period	18,052		17,900		18,052		17,900

Three months ended September 30, 2015 compared to three months ended September 30, 2014

Our Energy Services business segment reported operating income of $7 million for the three months ended September 30, 2015 compared to $6 million for the three months ended September 30, 2014. The increase in operating income of $1 million was primarily due to $4 million of improved margins and $3 million of decreased operation and maintenance expenses. Offsetting these increases was an $8 million decrease from mark-to-market accounting for derivatives associated with certain natural gas purchases and sales used to lock in economic margins. The third quarter of 2015 included a $5 million mark-to-market benefit compared to a $13 million mark-to-market benefit for the same period of 2014.

Nine months ended September 30, 2015 compared to nine months ended September 30, 2014

Our Energy Services business segment reported operating income of $29 million for the nine months ended September 30, 2015 compared to $43 million for the nine months ended September 30, 2014. The decrease in operating income of $14 million was primarily due to a $20 million decrease from mark-to-market accounting for derivatives associated with certain natural gas purchases and sales used to lock in economic margins. The first nine months of 2015 included a $3 million mark-to-market benefit compared to a $23 million mark-to-market benefit for the same period of 2014. Offsetting this decrease was a $4 million reduction in operation and maintenance expenses.

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 Interests in Enable Midstream Partners, LP” and “— Other Risk Factors Affecting Our Businesses or Our Interests in Enable Midstream Partners, LP” in Item 1A of Part I of our 2014 Form 10-K.

The following table provides pre-tax equity income (loss) of our Midstream Investments business segment for the three and nine months ended September 30, 2015 and 2014:



	Three Months Ended September 30,					Nine Months Ended September 30,
	2015			2014		2015			2014
	(in millions)
Enable (1)	$	(794	)	$	79	$	(699	)	$	236
SESH	—			—		—			5
Total	$	(794	)	$	79	$	(699	)	$	241


(1)	These amounts include our share of Enable’s impairment of goodwill and long-lived assets and the impairment of our equity method investment in Enable totaling $862 million during the three and nine months ended September 30, 2015 (see Note 6). This impairment is offset by $68 million and $163 million of earnings for the three and nine months ended September 30, 2015, respectively.

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 2014 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 2014 Form 10-K and “Cautionary Statement Regarding Forward-Looking Information” in this Form 10-Q.

LIQUIDITY AND CAPITAL RESOURCES

Our liquidity and capital requirements are affected primarily by our results of operations, capital expenditures, debt service requirements, tax payments, working capital needs and various regulatory actions. Our capital expenditures are expected to be used for investment in infrastructure for our natural gas distribution operations. These capital expenditures are anticipated to maintain reliability and safety as well as expand our systems through value-added projects. Our principal anticipated cash requirements for the remaining three months of 2015 include approximately $149 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 2015. 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 $31 million as of September 30, 2015. Based on market conditions in the fourth quarter of 2015 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 senior notes due 2019 and 2024. 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 2014 Form 10-K was filed with the Securities and Exchange Commission (SEC) are discussed below.

Texas Coast Rate Case. On March 27, 2015, NGD filed a Statement of Intent with each of the 49 cities and unincorporated areas within its Texas Coast service territory for a $6.8 million annual revenue increase. This increase was based on a rate base of $132.3 million and an ROE of 10.25%. On July 6, 2015, the parties agreed to a settlement providing for a $4.9 million annual increase to rates, an ROE of 10.0%, 54.5% equity and authorized overall rate of return of 8.23%. This settlement resolved six outstanding cases on appeal: one on remand at the Railroad Commission and five COSA appeals at the district court. The Railroad Commission unanimously approved the settlement on August 25, 2015. Rates were implemented in September 2015.

Houston, South Texas and Beaumont/East Texas GRIP. NGD’s Houston, South Texas and Beaumont/East Texas Divisions each submitted annual GRIP filings on March 31, 2015. For the Houston Division, NGD asked that its GRIP filing to recover costs related to $46.4 million in incremental capital expenditures that were incurred in 2014 be operationally suspended for one year so as to ensure that earnings are more consistent with those currently approved. For the South Texas Division, the revised filing requested recovery of costs related to $22.2 million in incremental capital expenditures that were incurred in 2014. The increase in revenue requirements for this filing period is $4.0 million annually based on an authorized overall rate of return of 8.75%. For the Beaumont/East Texas Division, the GRIP filing requested recovery of costs related to $34.3 million in incremental capital expenditures that were incurred in 2014. The increase in revenue requirements for this filing period is $5.9 million annually based on an authorized overall rate of return of 8.51%. For the South Texas and Beaumont/East Texas Divisions, rates were implemented for certain customers in May 2015. For those areas that the jurisdictional deadline was extended by regulatory action, the rates were implemented in July 2015 following approval by the Railroad Commission.

Oklahoma Performance Based Rate Change (PBRC). In March 2015, NGD made a PBRC filing for the 2014 calendar year proposing to increase revenues by $0.9 million. On November 4, 2015, the Oklahoma Corporation Commission approved the request.

Arkansas Energy Efficiency Cost Recovery (EECR). On March 31, 2015, NGD made an EECR filing with the Arkansas Public Service Commission (APSC) to recover $5.9 million for the 2015 program year. The purpose of the EECR is to recover NGD’s estimated expenses and lost contributions to fixed cost for the energy efficiency programs approved by the APSC and administered either jointly or individually by NGD, plus a utility incentive earned for 2014, with adjustments for any over- or under-recovery from the prior period. The impact to customer bills is expected to be a small reduction due to actual program costs being less than estimated and a colder than normal year causing more EECR revenues than anticipated. New rates went into effect in July 2015.

Arkansas Rate Case. On August 17, 2015, NGD filed a Notice of Intent to file a general rate case with the APSC. The rate case will be filed no later than November 15, 2015.

Louisiana Rate Stabilization Plan (RSP). NGD made its 2015 Louisiana RSP filings with the Louisiana Public Service Commission (LPSC) on October 1, 2015. The North Louisiana Rider RSP filing shows a revenue deficiency of $1.0 million, and the South Louisiana Rider RSP filing shows a revenue deficiency of $1.5 million. Both 2015 RSP filings utilized the capital structure and ROE factors approved by the LPSC on September 23, 2015 discussed below. NGD will begin billing in December 2015 subject to a refund. NGD made its 2014 Louisiana RSP filings with the LPSC on October 1, 2014. The North Louisiana Rider RSP filing shows a revenue deficiency of $4.0 million, compared to the authorized ROE of 10.25%. The South Louisiana Rider RSP filing shows a revenue deficiency of $2.3 million, compared to the authorized ROE of 10.5%. NGD began billing the revised rates in December 2014, subject to refund. On November 19, 2014, NGD sought permission to amend the 2013 South Louisiana RSP filing to use a more representative capital structure and to adjust the filing’s equity banding mechanism. On December 2, 2014, NGD sought permission for similar amendments to the 2013 North Louisiana RSP filing. On September 3, 2015, Uncontested Stipulated Settlement Agreements (Stipulations) between NGD and the LPSC Staff were filed in the 2013 Louisiana RSP dockets recommending a capital structure of 48% debt and 52% equity and ROE of 9.95%. On September 23, 2015, the LPSC issued orders approving the Stipulations and ordered refunds of the 2013 RSP over-collections plus 5% annual interest. Refunds for the 2013 North and South Louisiana RSP filings in the amount of approximately $0.9 million and $0.6 million, respectively, became effective in September 2015. The 2014 and 2015 Louisiana RSP filings are still awaiting final approval from the LPSC.

On February 20, 2015, the LPSC issued orders reducing rates and requiring refunds of over-collections plus 5% interest based on disallowance of certain costs included in the 2012 RSP filings. North Louisiana was required to adjust its 2012 RSP increase from $36,400 to $2,600. South Louisiana’s 2012 RSP was further reduced by $0.1 million. New rates went into effect on February 23, 2015.

Mississippi Rate Regulation Adjustment (RRA). On May 1, 2015, NGD filed for a $2.5 million RRA with an adjusted ROE of 9.534% with the Mississippi Public Service Commission (MPSC). Additional filings were made under the Supplemental Growth Rider (SGR) of approximately $0.1 million with an ROE of 12% and the EECR rider of approximately $0.6 million. The MPSC approved the EECR and new rates were implemented on September 2, 2015. New rates for the RRA and the SGR are expected to be implemented in the fourth quarter of 2015.

Minnesota Conservation Cost Recovery Adjustment (CCRA) and CIP. On May 1, 2015, NGD filed applications with the MPUC for a CCRA and a Demand-Side Management Financial Incentive. NGD sought approval for a $2.3 million balance in its CIP Tracker, an $11.6 million financial incentive based on 2014 program performance, and an updated CCRA, to be effective on January 1, 2016. On August 11, 2015, the MPUC issued its order approving these requests.

Minnesota Rate Case. In August 2015, NGD filed a general rate case with the MPUC requesting an increase of $54.1 million. On September 10, 2015, the MPUC approved an interim increase of $47.8 million in revenues effective October 2, 2015, subject to a refund. The MPUC is expected to issue a final decision in mid-2016 with final rates effective by the end of 2016.

Other Matters

Credit Facility

As of October 23, 2015, we had the following revolving credit facility:



Execution Date	Size of Facility		Amount Utilized at October 23, 2015			Termination Date
	(in millions)
September 9, 2011	$	600	$	14	(1)	September 9, 2019

(1) Represents outstanding commercial paper of $12 million and outstanding letters of credit of $2 million.

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 spread to LIBOR 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 September 30, 2015, CERC Corp. had $109 million of outstanding commercial paper.

Securities Registered with the SEC

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

Temporary Investments

As of October 23, 2015, 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 23, 2015, we had no borrowings from or investments in the money pool. The money pool may not provide sufficient funds to meet our cash needs.

Impact on Liquidity of a Downgrade in Credit Ratings

The interest on borrowings under our credit facility is based on our credit rating. As of October 23, 2015, 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, 2015, the impact on the borrowing costs under our credit facility would have been immaterial in the three months ended September 30, 2015. 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 credit threshold is decreased due to a credit rating downgrade.

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, 2015, the amount posted as collateral aggregated approximately $63 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, 2015, unsecured credit limits extended to CES by counterparties aggregated $308 million, and $3 million of such amount was utilized.

Pipeline tariffs and contracts typically provide that if the credit ratings of a shipper or the shipper’s guarantor drop below a threshold level, which is generally investment grade ratings from both Moody’s and S&P, cash or other collateral may be demanded from the shipper in an amount equal to the sum of three months’ charges for pipeline services plus the unrecouped cost of any lateral built for such shipper. If the credit ratings of CERC Corp. decline below the applicable threshold levels, CERC Corp. might need to provide cash or other collateral of as much as $152 million as of September 30, 2015. 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 for borrowed money and certain other specified types of obligations (including guarantees) exceeding $75 million by us 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 our wholly-owned subsidiary that is scheduled to mature in 2017.

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 22, 2015, Enable declared a quarterly cash distribution of $0.318 per unit on all of its outstanding common and subordinated units for the quarter ended September 30, 2015. Accordingly, we expect to receive a cash distribution of approximately $74 million from Enable in the fourth quarter of 2015 to be made with respect to our limited partner interest in Enable for the third quarter of 2015.

We recognized a loss of $794 million from our investment in Enable for the three months ended September 30, 2015. This loss included impairment charges totaling $862 million composed of our impairment of our investment in Enable of $250 million and our share, $612 million, of impairment charges Enable recorded for goodwill and long-lived assets. For further discussion of the impairment, see Note 6.

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.

Weather Hedge

We have weather normalization or other rate mechanisms that mitigate the impact of weather on NGD in Arkansas, Louisiana, Mississippi, Minnesota and Oklahoma. NGD in Texas does not have such mechanisms. As a result, fluctuations from normal weather may have a positive or negative effect on NGD’s results in Texas. We have historically entered into heating-degree day swaps for certain NGD jurisdictions to mitigate the effect of fluctuations from normal weather on its results of operations and cash flows for the winter heating season. However, NGD did not enter into heating-degree day swaps for the 2015–2016 winter season as a result of NGD’s Minnesota division implementing a full decoupling pilot in July 2015.

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;


•	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 2014 Form 10-K.

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

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, 2015 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, 2015 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 2014 Form 10-K.

Item 1A. RISK FACTORS

There have been no material changes from the risk factors disclosed in our 2014 Form 10-K.

Item 5. OTHER INFORMATION

Ratio of Earnings to Fixed Charges. The ratio of earnings to fixed charges for the nine months ended September 30, 2015 and 2014 was 4.04 and 4.37, 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
+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 William D. Rogers
+32.1	Section 1350 Certification of Scott M. Prochazka
+32.2	Section 1350 Certification of William D. Rogers
+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 5, 2015

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
+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 William D. Rogers
+32.1	Section 1350 Certification of Scott M. Prochazka
+32.2	Section 1350 Certification of William D. Rogers
+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 5, 2015

Attached files

CENTERPOINT ENERGY RESOURCES CORP Reports