CENTERPOINT ENERGY RESOURCES CORP - FORM 10-Q

Attached files

file	filename
EX-12 - EXHIBIT 12 - CENTERPOINT ENERGY RESOURCES CORP	cercexhibit12_6302015.htm
EX-32.2 - EXHIBIT 32.2 - CENTERPOINT ENERGY RESOURCES CORP	cercexhibit322_6302015.htm
EX-31.2 - EXHIBIT 31.2 - CENTERPOINT ENERGY RESOURCES CORP	cercexhibit312_6302015.htm
EX-31.1 - EXHIBIT 31.1 - CENTERPOINT ENERGY RESOURCES CORP	cercexhibit311_6302015.htm
EX-32.1 - EXHIBIT 32.1 - CENTERPOINT ENERGY RESOURCES CORP	cercexhibit321_6302015.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 JUNE 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 July 31, 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 JUNE 30, 2015

TABLE OF CONTENTS



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

	Condensed Statements of Consolidated Income
	Three and Six Months Ended June 30, 2015 and 2014 (unaudited)	1

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

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

	Condensed Statements of Consolidated Cash Flows
	Six Months Ended June 30, 2015 and 2014 (unaudited)	5

	Notes to Unaudited Condensed Consolidated Financial Statements	6

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

Item 4.	Controls and Procedures	31

PART II.	OTHER INFORMATION

Item 1.	Legal Proceedings	31

Item 1A.	Risk Factors	31

Item 5.	Other Information	31

Item 6.	Exhibits	32

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 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;


◦	potential recording of non-cash other-than-temporary impairment charges related to Enable;


◦	changes in tax status;


◦	access to growth capital; and


◦	the availability and prices of raw materials 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;


•	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 June 30,						Six Months Ended June 30,
	2015			2014			2015			2014

Revenues	$	824		$	1,183		$	2,641		$	3,714

Expenses:
Natural gas	529			880			1,883			2,923
Operation and maintenance	179			179			376			378
Depreciation and amortization	56			51			112			100
Taxes other than income taxes	33			34			83			86
Total	797			1,144			2,454			3,487
Operating Income	27			39			187			227

Other Income (Expense):
Interest and other finance charges	(35		)	(34		)	(69		)	(69		)
Equity in earnings of unconsolidated affiliates, net	43			71			95			162
Other, net	(1		)	2			1			4
Total	7			39			27			97
Income Before Income Taxes	34			78			214			324
Income tax expense	12			30			83			124
Net Income	$	22		$	48		$	131		$	200

See Notes to the Interim Condensed Consolidated Financial Statements

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES

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

CONDENSED STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME

(Millions of Dollars)

(Unaudited)



	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2015		2014		2015		2014

Net income	$	22	$	48	$	131	$	200
Other comprehensive income, net of tax:
Adjustment to pension and other postretirement plans (net of tax)	—		—		—		—
Other comprehensive income	—		—		—		—
Comprehensive income	$	22	$	48	$	131	$	200

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



	June 30, 2015		December 31, 2014
Current Assets:
Cash and cash equivalents	$	1	$	2
Accounts receivable, less bad debt reserve of $25 and $23, respectively	341		595
Accrued unbilled revenue	70		262
Accounts and notes receivable — affiliated companies	14		18
Materials and supplies	49		41
Natural gas inventory	96		211
Non-trading derivative assets	64		99
Deferred income tax assets	4		1
Prepaid expenses and other current assets	43		90
Total current assets	682		1,319

Property, Plant and Equipment:
Property, plant and equipment	5,605		5,364
Less: accumulated depreciation and amortization	1,645		1,554
Property, plant and equipment, net	3,960		3,810

Other Assets:
Goodwill	840		840
Non-trading derivative assets	33		32
Investment in unconsolidated affiliates	4,471		4,521
Notes receivable from unconsolidated affiliates	363		363
Other	152		160
Total other assets	5,859		5,916

Total Assets	$	10,501	$	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



	June 30, 2015		December 31, 2014
Current Liabilities:
Short-term borrowings	$	24	$	53
Current portion of long-term debt	325		—
Accounts payable	227		528
Accounts and notes payable — affiliated companies	38		228
Taxes accrued	41		67
Interest accrued	36		36
Customer deposits	78		80
Non-trading derivative liabilities	7		19
Other	159		137
Total current liabilities	935		1,148

Other Liabilities:
Deferred income taxes, net	2,333		2,252
Non-trading derivative liabilities	6		1
Benefit obligations	110		111
Regulatory liabilities	711		669
Other	195		194
Total other liabilities	3,355		3,227

Long-Term Debt	1,879		2,469

Commitments and Contingencies (Note 10)

Stockholder’s Equity:
Common stock	—		—
Paid-in capital	2,417		2,417
Retained earnings	1,914		1,783
Accumulated other comprehensive income	1		1
Total stockholder’s equity	4,332		4,201

Total Liabilities and Stockholder’s Equity	$	10,501	$	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)



	Six Months Ended June 30,
	2015			2014
Cash Flows from Operating Activities:
Net income	$	131		$	200
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	112			100
Amortization of deferred financing costs	5			5
Deferred income taxes	80			116
Write-down of natural gas inventory	2			—
Equity in earnings of unconsolidated affiliates, net of distributions	50			2
Changes in other assets and liabilities:
Accounts receivable and unbilled revenues, net	442			289
Accounts receivable/payable - affiliated companies	2			18
Inventory	105			(2		)
Taxes receivable	—			18
Accounts payable	(298		)	(174		)
Fuel cost recovery	86			(42		)
Interest and taxes accrued	(26		)	(32		)
Non-trading derivatives, net	2			(11		)
Margin deposits, net	25			(2		)
Other current assets	10			13
Other current liabilities	(20		)	(11		)
Other assets	8			13
Other liabilities	14			29
Other, net	1			3
Net cash provided by operating activities	731			532
Cash Flows from Investing Activities:
Capital expenditures	(248		)	(227		)
Increase in notes receivable - affiliated companies	—			(141		)
Investment in unconsolidated affiliates	—			(1		)
Other, net	2			(3		)
Net cash used in investing activities	(246		)	(372		)
Cash Flows from Financing Activities:
Decrease in short-term borrowings, net	(29		)	(1		)
Payments of commercial paper, net	(269		)	(118		)
Decrease in notes payable - affiliated companies	(188		)	(38		)
Other, net	—			1
Net cash used in financing activities	(486		)	(156		)

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

Supplemental Disclosure of Cash Flow Information:
Cash Payments:
Interest, net of capitalized interest	$	64		$	64
Income taxes (refunds), net	6			(1		)
Non-cash transactions:
Accounts payable related to capital expenditures	$	34		$	26
Exercise of SESH put to Enable	1			—

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 June 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 June 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 July 2015, the FASB issued Accounting Standard Update, 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.

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				Six Months Ended
	June 30,				June 30,
	2015		2014		2015		2014
	(in millions)
Interest cost on accumulated benefit obligation	1		2		$	2	$	3
Amortization of loss	—		—		1		—
Net periodic cost	$	1	$	2	$	3	$	3

CERC expects to contribute approximately $7 million to its postretirement benefit plan in 2015, of which $1 million and $3 million were contributed during the three and six months ended June 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 and Oklahoma. NGD in Texas and Minnesota do not have such mechanisms. As a result, fluctuations from normal weather may have a significant positive or negative effect on NGD’s results in Texas and Minnesota, although NGD’s Minnesota division implemented a full decoupling pilot in July 2015, which includes the effects of weather in the calculation.

CERC 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. The swaps are based on ten-year normal weather. During the three months ended June 30, 2015 and 2014, CERC recognized gains of $1 million and losses of $-0-, respectively, related to these swaps. During the six months ended June 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 June 30, 2015 and December 31, 2014, while the last two tables provide a breakdown of the related income statement impacts for the three and six months ended June 30, 2015 and 2014.



Fair Value of Derivative Instruments
		June 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	$	66	$	2
Natural gas derivatives (1) (2)	Other Assets: Non-trading derivative assets	33		—
Natural gas derivatives (1) (2)	Current Liabilities: Non-trading derivative liabilities	8		43
Natural gas derivatives (1) (2)	Other Liabilities: Non-trading derivative liabilities	2		19
Total		$	109	$	64

________________


(1)	The fair value shown for natural gas contracts is comprised of derivative gross volumes totaling 718 billion cubic feet (Bcf) or a net 77 Bcf long position. Of the net long position, basis swaps constitute 118 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 $84 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 $39 million.



Offsetting of Natural Gas Derivative Assets and Liabilities
	June 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	$	74		$	(10	)	$	64
Other Assets: Non-trading derivative assets	35			(2		)	33
Current Liabilities: Non-trading derivative liabilities	(45		)	38			(7		)
Other Liabilities: Non-trading derivative liabilities	(19		)	13			(6		)
Total	$	45		$	39		$	84

________________


(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 June 30,
Total derivatives not designated as hedging instruments	Income Statement Location	2015		2014
		(in millions)
Natural gas derivatives	Gains (Losses) in Revenue	$	7	$	5
Natural gas derivatives (1)	Gains (Losses) in Expense: Natural Gas	1		4
Total		$	8	$	9

________________


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



Income Statement Impact of Derivative Activity
		Six Months Ended June 30,
Total derivatives not designated as hedging instruments	Income Statement Location	2015			2014
		(in millions)
Natural gas derivatives	Gains (Losses) in Revenue	$	49		$	(96	)
Natural gas derivatives (1)	Gains (Losses) in Expense: Natural Gas	(42		)	114
Total		$	7		$	18

________________


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

(5) Fair Value Measurements

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

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

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

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

CERC’s own data. A market approach is utilized to value CERC’s Level 3 assets or liabilities. At June 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 $1.26 to $3.79 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 71%) as an unobservable input. CERC’s Level 3 derivative assets and liabilities consist of both long and short positions (forwards and options) and their fair value is sensitive to forward prices and volatilities. If forward prices decrease, CERC’s long forwards lose value whereas its short forwards gain in value. If volatility decreases, CERC’s long options lose value whereas its short options gain in value.

CERC determines the appropriate level for each financial asset and liability on a quarterly basis and recognizes transfers between levels at the end of the reporting period. For the six months ended June 30, 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 June 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 June 30, 2015
	(in millions)
Assets
Corporate equities	$	2	$	—	$	—	$	—		$	2
Investments, including money market funds (2)	11		—		—		—			11
Natural gas derivatives	2		96		11		(12		)	97
Total assets	$	15	$	96	$	11	$	(12	)	$	110
Liabilities
Natural gas derivatives	$	10	$	53	$	1	$	(51	)	$	13
Total liabilities	$	10	$	53	$	1	$	(51	)	$	13

________________


(1)	Amounts represent the impact of legally enforceable master netting arrangements that allow CERC to settle positive and negative positions and also include cash collateral of $39 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 less than $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 June 30,					Six Months Ended June 30,
	2015			2014		2015			2014
	(in millions)
Beginning balance	$	13		$	1	$	17		$	3
Total gains	—			2		—			—
Total settlements	(3		)	1		(6		)	2
Transfers into Level 3	—			—		—			(1		)
Transfers out of Level 3	—			—		(1		)	—
Ending balance ⁽¹⁾	$	10		$	4	$	10		$	4
The amount of total gains for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the reporting date	$	—		$	1	$	2		$	2

____________


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

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.



	June 30, 2015				December 31, 2014
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in millions)
Financial assets:
Notes receivable from unconsolidated affiliates	$	363	$	363	$	363	$	362
Financial liabilities:
Long-term debt	$	2,204	$	2,433	$	2,469	$	2,772

(6) Unconsolidated Affiliates

On May 1, 2013 (the Closing Date) CERC Corp., OGE Energy Corp. 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 June 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 June 30, 2015 and 2014, and $4 million during each of the six months ended June 30, 2015 and 2014, and had interest receivable from Enable of $5 million and $4 million as of June 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, $2 million and $37 million during the three months ended June 30, 2015 and 2014, respectively, and $7 million and $82 million during the six months ended June 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 June 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 $26 million and $27 million during the three months ended June 30, 2015 and 2014, respectively, and $65 million and $75 million during the six months ended June 30, 2015 and 2014, respectively, for transactions with Enable. CERC had accounts payable to Enable of $7 million and $23 million at June 30, 2015 and December 31, 2014, respectively, from such transactions.

As of June 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.

CERC evaluates its equity method investments for impairment when factors indicate that a decrease in 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 the best estimate of 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 an analysis of its investment in Enable as of June 30, 2015, CERC believes that the decline in the value of its investment is temporary, and that the carrying value of its investment of $4.5 billion will be recovered. CERC considered the severity and duration of the impairment, management’s intent and ability to hold its investment to recovery, significant events and conditions of Enable, including its investment grade credit rating and planned expansion projects, along with other factors, to conclude that its investment is not other than temporarily impaired as of June 30, 2015. A sustained low Enable common unit price or further declines in such price could result in CERC recording an impairment charge in future periods. If the decrease in value of CERC’s investment in Enable is determined to be other than temporary, an impairment will be recognized equal to the excess of the carrying value of CERC’s investment in Enable over its estimated fair value. Both the income approach and market approach would be utilized to estimate the fair value of CERC’s total investment in Enable, which includes CERC’s limited partner common and subordinated units, general partner interest and incentive distribution rights. The determination of fair value will consider a number of relevant factors including Enable’s forecasted results, recent comparable transactions and the limited float of Enable’s publicly traded common units. As of June 30, 2015, the carrying value of our investment in Enable was $19.12 per unit. On June 30, 2015, Enable’s common unit price closed at $15.98, based on its publicly traded common units which represent approximately 7% of total outstanding units, (an aggregate of approximately $734 million below carrying value). On July 31, 2015, Enable’s common unit price closed at $16.36 (approximately $645 million below carrying value).

Investment in Unconsolidated Affiliates:



	June 30, 2015		December 31, 2014
	(in millions)
Enable	$	4,471	$	4,520
SESH (1)	—		1
Total	$	4,471	$	4,521


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

Equity in Earnings of Unconsolidated Affiliates, net:



	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
	(in millions)
Enable	$	43	$	69	$	95	$	157
SESH (1)	—		2		—		5
Total	$	43	$	71	$	95	$	162


(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 June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
	(in millions)
Operating revenues	$	590	$	826	$	1,206	$	1,828
Cost of sales, excluding depreciation and amortization	277		478		569		1,111
Operating income	93		139		197		301
Net income attributable to Enable	77		120		168		269

CERC’s interest	$	42	$	67	$	93	$	154
Basis difference accretion	1		2		2		3
CERC’s equity in earnings, net	$	43	$	69	$	95	$	157

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



	June 30, 2015			December 31, 2014
	(in millions)
Current assets	$	414		$	438
Non-current assets	11,766			11,399
Current liabilities	834			671
Non-current liabilities	2,611			2,343
Non-controlling interest	31			31
Enable partners’ capital	8,704			8,792

CERC’s ownership interest in Enable partners’ capital	$	4,817		$	4,869

CERC’s basis difference attributable to goodwill (1)	(217		)	(217		)
CERC’s accretable basis difference (2)	(129		)	(132		)
CERC’s total basis difference	(346		)	(349		)
CERC’s investment in Enable	$	4,471		$	4,520


(1)	The difference relates to CERC’s proportionate share of Enable’s goodwill arising from its acquisition of Enogex LLC, and therefore will be recognized by CERC upon dilution or disposition of its interest in Enable.


(2)	The difference will be recognized by CERC over 30 years beginning May 1, 2013. CERC will also adjust the accretable basis difference for dilution or disposition of its interest in Enable.

Distributions Received from Unconsolidated Affiliates:



	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
	(in millions)
Enable	$	73	$	90	$	145	$	157
SESH (1)	—		4		—		7
Total	$	73	$	94	$	145	$	164


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

(7) Goodwill

Goodwill by reportable business segment as of both June 30, 2015 and December 31, 2014 is as follows (in millions):



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

(8) Related Party Transactions

CERC participates in a “money pool” through which it can borrow or invest on a short-term basis. Funding needs are aggregated and external borrowing or investing is based on the net cash position. The net funding requirements of the money pool are expected to be met with borrowings under CenterPoint Energy’s revolving credit facility or the sale of CenterPoint Energy’s commercial paper. CERC had borrowings from the money pool of $-0- and $188 million at June 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 six months ended June 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 June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
	(in millions)
Corporate service charges	$	31	$	31	$	59	$	59

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 $24 million and $53 million as of June 30, 2015 and December 31, 2014, respectively.


(b)	Long-term Debt

Revolving Credit Facility. As of June 30, 2015 and December 31, 2014, CERC had the following revolving credit facility and utilization of such facility (in millions):



		June 30, 2015						December 31, 2014
Size of Facility		Loans		Letters of Credit		Commercial Paper		Loans		Letters of Credit		Commercial Paper
$	600	$	—	$	—	$	72	$	—	$	—	$	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 June 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 June 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 June 30, 2015, minimum payment obligations for natural gas supply commitments are approximately $228 million for the remaining six months in 2015, $485 million in 2016, $471 million in 2017, $419 million in 2018, $227 million in 2019 and $130 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 June 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 $36 million as of June 30, 2015. Based on market conditions in the fourth quarter of 2014 at the time the most recent annual calculation was made under the agreement, GenOn was not obligated to post any security. If GenOn should fail to perform the contractual obligations, CERC could have to honor its guarantee and, in such event, any collateral then provided as security may be insufficient to satisfy CERC’s obligations.

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

The fair value of these guarantees is not material.

(11) Income Taxes

The effective tax rate reported for the three months ended June 30, 2015 was 35% compared to 38% for the same period in 2014. The lower effective tax rate for the three months ended June 30, 2015 was primarily due to the lower Texas tax rate enacted on June 15, 2015. The effective tax rate reported for the six months ended June 30, 2015 and 2014 was 39% and 38%, respectively.

CERC reported no uncertain tax liability as of June 30, 2015 and expects no significant change to the uncertain tax liability over the twelve-month period ending June 30, 2016. Tax years through 2011 have been audited and settled with the Internal Revenue Service (IRS). CenterPoint Energy’s consolidated federal income tax returns for the years 2012 and 2013 are currently under audit by the 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 (in millions):



	For the Three Months Ended June 30, 2015
	Revenues from External Customers		Inter-segment Revenues			Operating Income (Loss)
Natural Gas Distribution	$	420	$	7		$	19
Energy Services	404		4			9
Midstream Investments (1)	—		—			—
Other Operations	—		—			(1		)
Reconciling Eliminations	—		(11		)	—
Consolidated	$	824	$	—		$	27



	For the Three Months Ended June 30, 2014
	Revenues from External Customers		Inter-segment Revenues			Operating Income (Loss)
Natural Gas Distribution	$	526	$	6		$	30
Energy Services	657		19			11
Midstream Investments (1)	—		—			—
Other Operations	—		—			(2		)
Reconciling Eliminations	—		(25		)	—
Consolidated	$	1,183	$	—		$	39



	For the Six Months Ended June 30, 2015
	Revenues from External Customers		Inter-segment Revenues			Operating Income		Total Assets as of June 30, 2015
Natural Gas Distribution	$	1,605	$	15		$	165	$	5,301
Energy Services	1,036		22			22		837
Midstream Investments (1)	—		—			—		4,471
Other Operations	—		—			—		715
Reconciling Eliminations	—		(37		)	—		(823		)
Consolidated	$	2,641	$	—		$	187	$	10,501



	For the Six Months Ended June 30, 2014
	Revenues from External Customers		Inter-segment Revenues			Operating Income (Loss)			Total Assets as of December 31, 2014
Natural Gas Distribution	$	2,004	$	15		$	192		$	5,464
Energy Services	1,709		51			37			978
Midstream Investments (1)	—		—			—			4,521
Other Operations	1		—			(2		)	1,046
Reconciling Eliminations	—		(66		)	—			(964		)
Consolidated	$	3,714	$	—		$	227		$	11,045


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



	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
	(in millions)
Enable	$	43	$	69	$	95	$	157
SESH	—		2		—		5
Total	$	43	$	71	$	95	$	162

Midstream Investments’ total assets are as follows:



	June 30, 2015		December 31, 2014
	(in millions)
Enable	$	4,471	$	4,520
SESH	—		1
Total	$	4,471	$	4,521

(13) Other Current Assets and Liabilities

Included in other current assets on the Condensed Consolidated Balance Sheets at June 30, 2015 and December 31, 2014 were $19 million and $19 million, respectively, of margin deposits and $4 million and $45 million, respectively, of under-recovered gas cost. Included in other current liabilities on the Condensed Consolidated Balance Sheets at June 30, 2015 and December 31, 2014 were $89 million and $37 million, respectively, of over-recovered gas cost.

(14) Subsequent Events

On July 22, 2015, Enable declared a quarterly cash distribution of $0.316 per unit on all of its outstanding common and subordinated units for the quarter ended June 30, 2015. Accordingly, CERC Corp. expects to receive a cash distribution of approximately $74 million from Enable in the third quarter of 2015 to be made with respect to CERC Corp.’s limited partner interest in Enable for the second 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 six months ended June 30, 2015 and the three and six months ended June 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

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 is based on a rate base of $132.3 million and a return on equity (ROE) of 10.25%. On July 6, 2015, all parties signed a Unanimous Settlement Agreement (Settlement) disposing of all issues in the case. The Settlement includes a $4.9 million annual increase to rates and a ROE of 10.0%. The Railroad Commission of Texas (Railroad Commission) will review the Settlement and is expected to issue a final order by the third quarter of 2015. Rates are expected to be implemented in September 2015. The Settlement also establishes required parameters for filing any future Gas Reliability Infrastructure Programs (GRIP) until changed by a subsequent general rate proceeding.

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 based on a projected test year for the twelve months ending September 2016. NGD proposed a rate of return of 7.94%, a ROE of 10.3%, and a capital structure with 47% debt and 53% equity. NGD anticipates implementing interim rates in October 2015, 60 days after the rate case filing, as allowed by the State of Minnesota.

Exercise of Put Right. On June 30, 2015, we closed our put right with respect to our remaining interest in Southeast Supply Header (SESH) and contributed to Enable our remaining 0.1% interest in SESH in exchange for 25,341 limited partner units of Enable. No cash payment was required to be made pursuant to the Enable formation agreements in connection with our exercise.

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 six months ended June 30, 2015 and 2014, followed by a discussion of our consolidated results of operations.



	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
	(in millions)
Revenues	$	824		$	1,183		$	2,641		$	3,714
Expenses:
Natural gas	529			880			1,883			2,923
Operation and maintenance	179			179			376			378
Depreciation and amortization	56			51			112			100
Taxes other than income taxes	33			34			83			86
Total	797			1,144			2,454			3,487
Operating Income	27			39			187			227
Interest and other finance charges	(35		)	(34		)	(69		)	(69		)
Equity in earnings of unconsolidated affiliates, net	43			71			95			162
Other expense, net	(1		)	2			1			4
Income Before Income Taxes	34			78			214			324
Income tax expense	12			30			83			124
Net Income	$	22		$	48		$	131		$	200

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

We reported net income of $22 million for the three months ended June 30, 2015 compared to $48 million for the same period in 2014.

The decrease in net income of $26 million was due to the following key factors:

•$28 million decrease in equity earnings of unconsolidated affiliates; and

•$12 million decrease in operating income (discussed by segment below).

These decreases were partially offset by an $18 million decrease in income tax expense.

Six months ended June 30, 2015 compared to six months ended June 30, 2014

We reported net income of $131 million for the six months ended June 30, 2015 compared to $200 million for the same period in 2014.

The decrease in net income of $69 million was due to the following key factors:

•$67 million decrease in equity earnings of unconsolidated affiliates; and

•$40 million decrease in operating income (discussed by segment below).

These decreases were partially offset by a $41 million decrease in income tax expense.

Income Tax Expense

Our effective tax rate reported for the three months ended June 30, 2015 was 35% compared to 38% for the same period in 2014. The lower effective tax rate for the three months ended June 30, 2015 was primarily due to the lower Texas tax rate enacted on June 15, 2015. The effective tax rate reported for the six months ended June 30, 2015 and 2014 was 39% and 38%, respectively.

RESULTS OF OPERATIONS BY BUSINESS SEGMENT

The following table presents operating income (loss) for each of our business segments for the three and six months ended June 30, 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 June 30,						Six Months Ended June 30,
	2015			2014			2015		2014
	(in millions)
Natural Gas Distribution	$	19		$	30		$	165	$	192
Energy Services	9			11			22		37
Other Operations	(1		)	(2		)	—		(2		)
Total Consolidated Operating Income	$	27		$	39		$	187	$	227

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 six months ended June 30, 2015 and 2014 (in millions, except throughput and customer data):



	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
Revenues	$	427	$	532	$	1,620	$	2,019
Expenses:
Natural gas	152		251		908		1,290
Operation and maintenance	169		168		355		355
Depreciation and amortization	55		49		110		97
Taxes other than income taxes	32		34		82		85
Total expenses	408		502		1,455		1,827
Operating Income	$	19	$	30	$	165	$	192
Throughput (in billion cubic feet (Bcf)):
Residential	19		21		116		128
Commercial and industrial	56		55		144		151
Total Throughput	75		76		260		279
Number of customers at end of period:
Residential	3,112,902		3,080,462		3,112,902		3,080,462
Commercial and industrial	249,142		246,055		249,142		246,055
Total	3,362,044		3,326,517		3,362,044		3,326,517

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

Our Natural Gas Distribution business segment reported operating income of $19 million for the three months ended June 30, 2015 compared to operating income of $30 million for the three months ended June 30, 2014.

Operating income decreased $11 million as a result of the following key factors:


•	decreased usage of $5 million, primarily due to colder than normal weather in 2014; and


•	higher depreciation and amortization expense of $6 million.

Decreased expense related to energy efficiency programs ($2 million) and decreased expense related to gross receipt taxes ($1 million) were offset by the related revenues.

Six months ended June 30, 2015 compared to six months ended June 30, 2014

Our Natural Gas Distribution business segment reported operating income of $165 million for the six months ended June 30, 2015 compared to $192 million for the six months ended June 30, 2014.

Operating income decreased $27 million as a result of the following key factors:


•	decreased usage of $17 million, primarily due to colder than normal weather in 2014; and


•	higher depreciation and amortization expenses of $13 million.

These decreases to operating income were partially offset by increased economic activity across our footprint of $5 million, including the addition of approximately 36,000 customers.

Decreased expense related to energy efficiency programs ($3 million) and decreased expense related to gross receipt taxes ($6 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 six months ended June 30, 2015 and 2014 (in millions, except throughput and customer data):



	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015			2014
Revenues	$	408	$	676	$	1,058		$	1,760
Expenses:
Natural gas	388		653		1,012			1,698
Operation and maintenance	9		10		21			22
Depreciation and amortization	1		1		2			2
Taxes other than income taxes	1		1		1			1
Total expenses	399		665		1,036			1,723
Operating Income	$	9	$	11	$	22		$	37

Mark-to-market gain (loss)	$	2	$	6	$	(2	)	$	10

Throughput (in Bcf)	136		139		321			323

Number of customers at end of period	18,073		17,746		18,073			17,746

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

Our Energy Services business segment reported operating income of $9 million for the three months ended June 30, 2015 compared to $11 million for the three months ended June 30, 2014. The decrease in operating income of $2 million was due to a $4 million decrease from mark-to-market accounting for derivatives associated with certain natural gas purchases and sales used to lock in economic margins, partially offset by improved margins and a decrease in operation and maintenance expenses. The second quarter of 2015 included a $2 million mark-to-market benefit compared to a $6 million mark-to-market benefit for the same period of 2014.

Six months ended June 30, 2015 compared to six months ended June 30, 2014

Our Energy Services business segment reported operating income of $22 million for the six months ended June 30, 2015 compared to $37 million for the six months ended June 30, 2014. The decrease in operating income of $15 million was primarily due to a $12 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 half of 2015 included a $2 million mark-to-market charge compared to a $10 million mark-to-market benefit for the same period of 2014. The remaining decrease in operating income was margin related, resulting from reduced weather-related optimization opportunities of existing gas transportation assets.

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 of our Midstream Investments business segment for the three and six months ended June 30, 2015 and 2014 (in millions):



	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
Enable	$	43	$	69	$	95	$	157
SESH	—		2		—		5
Total	$	43	$	71	$	95	$	162

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 six months of 2015 include approximately $324 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 six 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 $36 million as of June 30, 2015. Based on market conditions in the fourth quarter of 2014 at the time the most recent annual calculation was made under the agreement, GenOn was not obligated to post any security. If GenOn should fail to perform the contractual obligations, we could have to honor our guarantee and, in such event, any collateral provided as security may be insufficient to satisfy our obligations.

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

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

Regulatory Matters

Significant regulatory developments that have occurred since our 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 is based on a rate base of $132.3 million and a ROE of 10.25%. On July 6, 2015, all parties signed a Settlement disposing of all issues in the case. The Settlement includes a $4.9 million annual increase to rates and a ROE of 10.0%. The Railroad Commission will review the Settlement and is expected to issue a final order by the third quarter of 2015. Rates are expected to be implemented in September 2015. The Settlement also establishes required parameters for filing any future GRIP until changed by a subsequent general rate proceeding.

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 requests 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 requests 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.

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. The Oklahoma Corporation Commission is expected to reach a decision in late third quarter or early fourth quarter of 2015.

Arkansas Energy Efficiency Cost Recovery (EECR). On March 31, 2015, NGD made an EECR filing with the 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.

Louisiana Rate Stabilization Plan (RSP). NGD made its 2014 Louisiana RSP filings with the Louisiana Public Service Commission (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. The LPSC has yet to take action on either request.

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 $100,000. 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. Additional filings were made under the Supplemental Growth Rider of approximately $129,000 with an ROE of 12% and the EECR rider of approximately $612,000. New rates are expected to be implemented in September 2015.

Minnesota Conservation Cost Recovery Adjustment (CCRA). 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 Conservation Improvement Program 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 6, 2015, the MPUC approved these requests. We expect an order from the MPUC by the third quarter of 2015.

Minnesota Rate Case. In August 2015, NGD filed a general rate case with the MPUC requesting an increase of $54.1 million based on a projected test year for the twelve months ending September 2016. NGD proposed a rate of return of 7.94%, a ROE of 10.3%, and a capital structure with 47% debt and 53% equity. NGD anticipates implementing interim rates in October 2015, 60 days after the rate case filing, as allowed by the State of Minnesota.

Other Matters

Credit Facility

As of July 31, 2015, we had the following revolving credit facility (in millions):



Date Executed	Size of Facility		Amount Utilized at July 31, 2015			Termination Date
September 9, 2011	$	600	$	126	₍₁₎	September 9, 2019

________________


(1)	Represents outstanding commercial paper of $124 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 June 30, 2015, CERC Corp. had $72 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 July 31, 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 July 31, 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 July 31, 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 June 30, 2015, the impact on the borrowing costs under our credit facility would have been immaterial in the three months ended June 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 S&P senior unsecured long-term debt rating is downgraded below BBB+.

CenterPoint Energy Services, Inc. (CES), our wholly owned subsidiary operating in our Energy Services business segment, provides natural gas sales and services primarily to commercial and industrial customers and electric and gas utilities throughout the central and eastern United States. In order to economically hedge its exposure to natural gas prices, CES uses derivatives with provisions standard for the industry, including those pertaining to credit thresholds. Typically, the credit threshold negotiated with each counterparty defines the amount of unsecured credit that such counterparty will extend to CES. To the extent that the credit

exposure that a counterparty has to CES at a particular time does not exceed that credit threshold, CES is not obligated to provide collateral. Mark-to-market exposure in excess of the credit threshold is routinely collateralized by CES. As of June 30, 2015, the amount posted as collateral aggregated approximately $58 million. Should the credit ratings of CERC Corp. (as the credit support provider for CES) fall below certain levels, CES would be required to provide additional collateral up to the amount of its previously unsecured credit limit. We estimate that as of June 30, 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 $135 million as of June 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. In addition, three outstanding series of CenterPoint Energy’s senior notes, aggregating $750 million in principal amount as of June 30, 2015, provide that a payment default by us in respect of, or an acceleration of, borrowed money and certain other specified types of obligations (including guarantees), in the aggregate principal amount of $50 million, will cause a default. A default by CenterPoint Energy would not trigger a default under our debt instruments or revolving credit facility.

Possible Acquisitions, Divestitures and Joint Ventures

From time to time, we consider the acquisition or the disposition of assets or businesses or possible joint ventures or other joint ownership arrangements with respect to assets or businesses. Any determination to take action in this regard will be based on market conditions and opportunities existing at the time, and accordingly, the timing, size or success of any efforts and the associated potential capital commitments are unpredictable. We may seek to fund all or part of any such efforts with proceeds from debt issuances. Debt financing may not, however, be available to us at that time due to a variety of events, including, among others, maintenance of our credit ratings, industry conditions, general economic conditions, market conditions and market perceptions.

Enable Midstream Partners

Certain of the entities contributed to Enable by us are obligated on approximately $363 million of indebtedness owed to 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 July 22, 2015, Enable declared a quarterly cash distribution of $0.316 per unit on all of its outstanding common and subordinated units for the quarter ended June 30, 2015. Accordingly, we expect to receive a cash distribution of approximately $74 million from Enable in the third quarter of 2015 to be made with respect to our limited partner interest in Enable for the second quarter of 2015.

We evaluate our equity method investments for impairment when factors indicate that a decrease in value of our investment has occurred and the carrying amount of our investment may not be recoverable. An impairment loss, based on the excess of the carrying value over the best estimate of 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 an analysis of our investment in Enable as of June 30, 2015, we believe that the decline in the value of our investment is temporary, and that the carrying value of our investment of $4.5 billion will be recovered. We considered the severity and duration of the impairment, management’s intent and ability to hold our investment to recovery, significant events and conditions of Enable, including its investment grade credit rating and planned expansion projects, along with other factors, to conclude that our investment is not other than temporarily impaired as of June 30, 2015. A sustained low Enable common unit price or further declines in such price could result in us recording an impairment charge in future periods. If the decrease in value of our investment in Enable is determined to be other than temporary, an impairment will be recognized equal to the excess of the carrying value of our investment in Enable over its estimated fair value. Both the income approach and market approach would be utilized to estimate the fair value

of our total investment in Enable, which includes our limited partner common and subordinated units, general partner interest and incentive distribution rights. The determination of fair value will consider a number of relevant factors including Enable’s forecasted results, recent comparable transactions and the limited float of Enable’s publicly traded common units. As of June 30, 2015, the carrying value of our investment in Enable was $19.12 per unit. On June 30, 2015, Enable’s common unit price closed at $15.98, based on its publicly traded common units which represent approximately 7% of total outstanding units, (an aggregate of approximately $734 million below carrying value). On July 31, 2015, Enable’s common unit price closed at $16.36 (approximately $645 million below carrying value).

Dodd-Frank Swaps Regulation

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

Other Factors that Could Affect Cash Requirements

In addition to the above factors, our liquidity and capital resources could be affected by:


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


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


•	increased costs related to the acquisition of natural gas;


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


•	various legislative or regulatory actions;


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


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


•	slower customer payments and increased write-offs of receivables due to higher gas prices or changing economic conditions;


•	the outcome of litigation;


•	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 June 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 June 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. Our ratio of earnings to fixed charges for the six months ended June 30, 2015 and 2014 was 4.72 and 5.59, respectively. We do not believe that the ratios for these six-month periods are necessarily indicative of the ratios for the twelve-month periods due to the seasonal nature of our business. The ratios were calculated pursuant to applicable rules of the Securities and Exchange Commission.

Item 6. EXHIBITS

The following exhibits are filed herewith:

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

Agreements included as exhibits are included only to provide information to investors regarding their terms. Agreements listed below may contain representations, warranties and other provisions that were made, among other things, to provide the parties thereto with specified rights and obligations and to allocate risk among them, and no such agreement should be relied upon as constituting or providing any factual disclosures about CenterPoint Energy Resources Corp., any other persons, any state of affairs or other matters.



Exhibit Number	Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference
3.1.1	Certificate of Incorporation of RERC Corp.	Form 10-K for the year ended December 31, 1997	1-13265	3(a)(1)
3.1.2	Certificate of Merger merging former NorAm Energy Corp. with and into HI Merger, Inc. dated August 6, 1997	Form 10-K for the year ended December 31, 1997	1-13265	3(a)(2)
3.1.3	Certificate of Amendment changing the name to Reliant Energy Resources Corp.	Form 10-K for the year ended December 31, 1998	1-13265	3(a)(3)
3.1.4	Certificate of Amendment changing the name to CenterPoint Energy Resources Corp.	Form 10-Q for the quarter ended June 30, 2003	1-13265	3(a)(4)
3.2	Bylaws of RERC Corp.	Form 10-K for the year ended December 31, 1997	1-13265	3(b)
4.1	$950,000,000 Credit Agreement, dated as of September 9, 2011, among CERC Corp., as Borrower, and the banks named therein	Form 8-K dated September 9, 2011	1-13265	4.3
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: August 13, 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 - August 13, 2015

Attached files

CENTERPOINT ENERGY RESOURCES CORP Reports