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SEC Document

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 MARCH 31, 2016
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 April 20, 2016, 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 MARCH 31, 2016

TABLE OF CONTENTS



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

	Condensed Statements of Consolidated Income
	Three Months Ended March 31, 2016 and 2015 (unaudited)	1

	Condensed Statements of Consolidated Comprehensive Income
	Three Months Ended March 31, 2016 and 2015 (unaudited)	2

	Condensed Consolidated Balance Sheets
	March 31, 2016 and December 31, 2015 (unaudited)	3

	Condensed Statements of Consolidated Cash Flows
	Three Months Ended March 31, 2016 and 2015 (unaudited)	5

	Notes to Unaudited Condensed Consolidated Financial Statements	6

Item 2.	Management’s Narrative Analysis of Results of Operations	20

Item 4.	Controls and Procedures	29

PART II.	OTHER INFORMATION

Item 1.	Legal Proceedings	29

Item 1A.	Risk Factors	29

Item 5.	Other Information	29

Item 6.	Exhibits	30



GLOSSARY

ArcLight		ArcLight Capital Partners, LLC
APSC		Arkansas Public Service Commission
ASU		Accounting Standards Update
Bcf		Billion cubic feet
BDA		Billing Determinant Adjustment
CenterPoint Energy		CenterPoint Energy, Inc., and its subsidiaries
CERC Corp.		CenterPoint Energy Resources Corp.
CERC		CERC Corp., together with its subsidiaries
CES		CenterPoint Energy Services, Inc.
Continuum		Continuum Energy Services, a Tulsa and Houston-based company
Enable		Enable Midstream Partners, LP
FASB		Financial Accounting Standards Board
Fitch		Fitch, Inc.
Form 10-Q		Quarterly Report on Form 10-Q
GenOn		GenOn Energy, Inc.
GRIP		Gas Reliability Infrastructure Program
Houston Electric		CenterPoint Energy Houston Electric, LLC and its subsidiaries
Interim Condensed Financial Statements		Condensed consolidated interim financial statements and notes
IRS		Internal Revenue Service
LIBOR		London Interbank Offered Rate
LPSC		Louisiana Public Service Commission
MGPs		Manufactured gas plants
Moody’s		Moody’s Investors Service, Inc.
MPUC		Minnesota Public Utilities Commission
NAV		Net asset value
NGD		Natural gas distribution business
NGLs		Natural gas liquids
NRG		NRG Energy, Inc.
OGE		OGE Energy Corp.
PBRC		Performance Based Rate Change
PHMSA		Pipeline and Hazardous Materials Safety Administration
Private Placement		CenterPoint Energy’s agreement with Enable to purchase an aggregate of 14,520,000 Series A Preferred Units
PRPs		Potentially responsible parties
Reliant Energy		Reliant Energy, Incorporated
ROE		Return on equity
RRI		Reliant Resources, Inc.
RSP		Rate Stabilization Plan
SEC		Securities and Exchange Commission
Series A Preferred Units		Enable’s 10% Series A Fixed-to-Floating Non-Cumulative Redeemable Perpetual Preferred Units
S&P		Standard & Poor’s Ratings Services, a division of The McGraw-Hill Companies
Transition Agreements		Services Agreement, Employee Transition Agreement, Transitional Seconding Agreement and other agreements entered into in connection with the formation of Enable
VIE		Variable interest entity
2015 Form 10-K		Annual Report on Form 10-K for the year ended December 31, 2015

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, 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 NGLs, the competitive effects of the available pipeline capacity in the regions served by Enable, and the effects of geographic and seasonal commodity price differentials, including the effects of these circumstances on re-contracting available capacity on Enable’s interstate pipelines;


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


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


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


◦	changes in tax status;


◦	access to debt and equity capital; and


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


•	state and federal legislative and regulatory actions or developments affecting various aspects of our businesses (including the businesses of Enable), including, among others, energy deregulation or re-regulation, pipeline integrity and safety, health care reform, financial reform, tax legislation and actions regarding the rates charged by our regulated businesses;


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


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


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


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


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


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

iii


•	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;


•	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 such as fires, earthquakes, explosions, leaks, floods, droughts, hurricanes, pandemic health events or other occurrences;


•	our ability to invest planned capital and the timely recovery of our investment in capital;


•	our ability to control operation and maintenance costs;


•	actions by credit rating agencies;


•	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;


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


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


•	effectiveness of our risk management activities;


•	our potential business strategies and strategic initiatives, 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 (formerly known as RRI Energy, Inc., Reliant Energy and RRI), a wholly-owned subsidiary of NRG, 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;


•	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 2015 Form 10-K, which is incorporated herein by reference, and other reports we file from time to time with the SEC.

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

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 March 31,
	2016			2015

Revenues	$	1,320		$	1,817

Expenses:
Natural gas	852			1,354
Operation and maintenance	200			197
Depreciation and amortization	60			56
Taxes other than income taxes	42			50
Total	1,154			1,657
Operating Income	166			160

Other Income (Expense):
Interest and other finance charges	(33		)	(34		)
Equity in earnings of unconsolidated affiliate, net	60			52
Other, net	—			2
Total	27			20
Income Before Income Taxes	193			180
Income tax expense	73			71
Net Income	$	120		$	109

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
	March 31,
	2016		2015

Net income	$	120	$	109
Comprehensive income	$	120	$	109

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



	March 31, 2016		December 31, 2015
Current Assets:
Cash and cash equivalents	$	4	$	—
Accounts receivable, less bad debt reserve of $24 and $19, respectively	353		350
Accrued unbilled revenues	122		183
Accounts and notes receivable–affiliated companies	34		8
Materials and supplies	46		45
Natural gas inventory	58		168
Non-trading derivative assets	75		89
Prepaid expenses and other current assets	49		61
Total current assets	741		904

Property, Plant and Equipment:
Property, plant and equipment	5,965		5,898
Less: accumulated depreciation and amortization	1,643		1,640
Property, plant and equipment, net	4,322		4,258

Other Assets:
Goodwill	840		840
Non-trading derivative assets	28		36
Notes receivable–unconsolidated affiliate	—		363
Investment in unconsolidated affiliate	2,580		2,594
Other	143		146
Total other assets	3,591		3,979

Total Assets	$	8,654	$	9,141

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



	March 31, 2016		December 31, 2015
Current Liabilities:
Short-term borrowings	$	—	$	40
Current portion of long-term debt	325		325
Accounts payable	233		307
Accounts and notes payable–affiliated companies	35		39
Taxes accrued	63		63
Interest accrued	39		36
Customer deposits	81		80
Non-trading derivative liabilities	8		11
Other	131		158
Total current liabilities	915		1,059

Other Liabilities:
Deferred income taxes, net	1,845		1,774
Non-trading derivative liabilities	3		5
Benefit obligations	88		89
Regulatory liabilities	779		734
Other	213		210
Total other liabilities	2,928		2,812

Long-Term Debt	1,800		2,016

Commitments and Contingencies (Note 10)

Stockholder’s Equity:
Common stock	—		—
Paid-in capital	2,417		2,417
Retained earnings	585		828
Accumulated other comprehensive income	9		9
Total stockholder’s equity	3,011		3,254

Total Liabilities and Stockholder’s Equity	$	8,654	$	9,141

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)



	Three Months Ended March 31,
	2016			2015
Cash Flows from Operating Activities:
Net income	$	120		$	109
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	60			56
Amortization of deferred financing costs	2			2
Deferred income taxes	71			68
Write-down of natural gas inventory	1			2
Equity in (earnings) losses of unconsolidated affiliate, net of distributions	(60		)	20
Changes in other assets and liabilities:
Accounts receivable and unbilled revenues, net	37			62
Accounts receivable/payable–affiliated companies	(6		)	—
Inventory	108			170
Accounts payable	(65		)	(174		)
Fuel cost recovery	(3		)	86
Interest and taxes accrued	3			1
Non-trading derivatives, net	8			1
Margin deposits, net	27			(4		)
Other current assets	(3		)	7
Other current liabilities	(2		)	(18		)
Other assets	5			12
Other liabilities	8			11
Other, net	1			—
Net cash provided by operating activities	312			411
Cash Flows from Investing Activities:
Capital expenditures	(98		)	(102		)
Distribution from unconsolidated affiliate in excess of cumulative earnings	74			—
Increase in notes receivable–affiliated companies	(24		)	—
Decrease in notes receivable–unconsolidated affiliate	363			—
Other, net	—			2
Net cash provided by (used in) investing activities	315			(100		)
Cash Flows from Financing Activities:
Decrease in short-term borrowings, net	(40		)	(53		)
Payments of commercial paper, net	(219		)	(62		)
Dividends to parent	(363		)	—
Debt issuance costs	(1		)	—
Decrease in notes payable–affiliated companies	—			(188		)
Net cash used in financing activities	(623		)	(303		)
Net Increase in Cash and Cash Equivalents	4			8
Cash and Cash Equivalents at Beginning of Period	—			2
Cash and Cash Equivalents at End of Period	$	4		$	10
Supplemental Disclosure of Cash Flow Information:
Cash Payments:
Interest, net of capitalized interest	$	28		$	28
Income taxes, net	—			3
Non-cash transactions:
Accounts payable related to capital expenditures	$	28		$	27

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 Form 10-Q are the Interim Condensed Financial Statements of CERC. The Interim Condensed Financial Statements are unaudited, omit certain financial statement disclosures and should be read with the 2015 Form 10-K.

Background. CERC owns and operates natural gas distribution systems and owns interests in 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 March 31, 2016, 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., 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 FASB issued ASU 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 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. CERC adopted ASU 2015-02 on January 1, 2016, which CERC determined did not have a material impact on its financial position, results of operations, cash flows and disclosures.

In April 2015, the FASB issued ASU 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 adopted ASU 2015-03 retrospectively on January 1, 2016, which resulted in a reduction of other long-term assets and total long-term debt on its Condensed Consolidated Balance Sheets. CERC had debt issuance costs, excluding amounts related to credit facility arrangements, of $12 million as of both March 31, 2016 and December 31, 2015.

In May 2015, the FASB issued ASU No. 2015-07, Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent) (ASU 2015-07). ASU 2015-07 removes the requirement to categorize within the fair value hierarchy investments for which fair values are measured at NAV using the practical expedient. Entities will be required to disclose the fair value of investments measured using the NAV practical expedient so that financial statement users can reconcile amounts reported in the fair value hierarchy table to amounts reported on the balance sheet. CERC adopted ASU 2015-07 on January 1, 2016, which will have an impact on its employee benefit plan disclosures, beginning with its annual report on Form 10-K for the year ended December 31, 2016. This standard did not have an impact on CERC’s financial position, results of operations or cash flows.

In September 2015, the FASB issued ASU No. 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments (ASU 2015-16). ASU 2015-16 eliminates the requirement for an acquirer in a business combination to account for measurement-period adjustments retrospectively. Instead, an acquirer would recognize a measurement-period adjustment during the period in which the amount of the adjustment is determined. CERC adopted ASU 2015-16 on January 1, 2016, which did not have an impact on its financial position, results of operations and cash flows.

In January 2016, the FASB issued ASU No. 2016-01, Financial Instruments-Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities (ASU 2016-01). ASU 2016-01 requires equity investments that do not result in consolidation and are not accounted for under the equity method to be measured at fair value and to recognize any changes in fair value in net income unless the investments qualify for the new practicability exception. It does not change the guidance for classifying and measuring investments in debt securities and loans. ASU 2016-01 also changes certain disclosure requirements and other aspects related to recognition and measurement of financial assets and financial liabilities. ASU 2016-01 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2017. CERC is currently assessing the impact that this standard will have on its financial position, results of operations, cash flows and disclosures.

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 provides a comprehensive new lease model that requires lessees to recognize assets and liabilities for most leases and would change certain aspects of lessor accounting. ASU 2016-02 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted. CERC is currently assessing the impact that this standard will have on its financial position, results of operations, cash flows and disclosures.

In March 2016, the FASB issued ASU No. 2016-05, Derivatives and Hedging (Topic 815): Effect of Derivative Contract Novation on Existing Hedge Accounting Relationships (ASU 2016-05). ASU 2016-05 clarifies that a change in the counterparty to a derivative instrument that has been designated as the hedging instrument in an existing hedging relationship would not, in and of itself, be considered a termination of the derivative instrument or a change in a critical term of the hedging relationship. This clarification applies to both cash flow and fair value hedging relationships. CERC adopted ASU 2016-05 prospectively in the first quarter of 2016, which did not have an impact on its financial position, results of operations, cash flows and disclosures.

In March and April 2016, the FASB issued ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (ASU 2016-08) and ASU No. 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing (ASU 2016-10), respectively. ASU 2016-08 and ASU 2016-10 clarify certain aspects of ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) (ASU 2014-09), which supersedes most current revenue recognition guidance. CERC is currently evaluating the impact that ASU 2016-08, ASU 2016-10, and ASU 2014-09 will have on its financial position, results of operations, cash flows and disclosures and expects to adopt the three ASUs on January 1, 2018.

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
	March 31,
	2016		2015
	(in millions)
Interest cost on accumulated benefit obligation	$	1	$	1
Amortization of net loss	—		1
Net periodic cost	$	1	$	2

CERC expects to contribute approximately $6 million to its postretirement benefit plan in 2016, of which $2 million was contributed during the three months ended March 31, 2016.

(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 NGD in Arkansas, Louisiana, Mississippi, Minnesota and Oklahoma. NGD in Texas does not have such mechanisms, although fixed customer charges are historically higher in Texas for NGD compared to CERC’s other jurisdictions. As a result, fluctuations from normal weather may have a positive or negative effect on NGD’s results in Texas.

CERC has historically entered into heating-degree day swaps for certain NGD jurisdictions to mitigate the effect of fluctuations from normal weather on its results of operations and cash flows for the winter heating season, which contained a bilateral dollar cap of $16 million in 2014–2015. However, NGD did not enter into heating-degree day swaps for the 2015–2016 winter season as a result of NGD’s Minnesota division implementing a full decoupling pilot in July 2015. The swaps are based on 10-year normal weather. During the three months ended March 31, 2016 and 2015, CERC recognized losses of $-0- and $5 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 March 31, 2016 and December 31, 2015, while the last two tables provide a breakdown of the related income statement impacts for the three months ended March 31, 2016 and 2015.



Fair Value of Derivative Instruments
		March 31, 2016
Total derivatives not designated as hedging instruments	Balance Sheet Location	Derivative Assets Fair Value		Derivative Liabilities Fair Value
		(in millions)
Natural gas derivatives (1) (2) (3)	Current Assets: Non-trading derivative assets	$	75	$	—
Natural gas derivatives (1) (2) (3)	Other Assets: Non-trading derivative assets	28		—
Natural gas derivatives (1) (2) (3)	Current Liabilities: Non-trading derivative liabilities	10		57
Natural gas derivatives (1) (2) (3)	Other Liabilities: Non-trading derivative liabilities	4		15
Total		$	117	$	72


(1)	The fair value shown for natural gas contracts is comprised of derivative gross volumes totaling 751 Bcf or a net 139 Bcf long position. Of the net long position, basis swaps constitute 122 Bcf.

(2)

Natural gas contracts are presented on a net basis in the Condensed Consolidated Balance Sheets as they 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 $92 million asset as shown on CERC’s Condensed Consolidated Balance Sheets (and as detailed in the table below), and was comprised of the natural gas contracts derivative assets and liabilities separately shown above, offset by collateral netting of $47 million.


(3)	Derivative Assets and Derivative Liabilities include no material amounts related to physical forward transactions with Enable.



Offsetting of Natural Gas Derivative Assets and Liabilities
	March 31, 2016
	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	$	85		$	(10	)	$	75
Other Assets: Non-trading derivative assets	32			(4		)	28
Current Liabilities: Non-trading derivative liabilities	(57		)	49			(8		)
Other Liabilities: Non-trading derivative liabilities	(15		)	12			(3		)
Total	$	45		$	47		$	92


(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, 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) (3)	Current Assets: Non-trading derivative assets	$	90	$	2
Natural gas derivatives (1) (2) (3)	Other Assets: Non-trading derivative assets	36		—
Natural gas derivatives (1) (2) (3)	Current Liabilities: Non-trading derivative liabilities	10		60
Natural gas derivatives (1) (2) (3)	Other Liabilities: Non-trading derivative liabilities	4		25
Total		$	140	$	87


(1)	The fair value shown for natural gas contracts is comprised of derivative gross volumes totaling 767 Bcf or a net 112 Bcf long position. Of the net long position, basis swaps constitute 133 Bcf.

(2)

Natural gas contracts are presented on a net basis in the Condensed Consolidated Balance Sheets as they 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 $109 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 $56 million.


(3)	Derivative Assets and Derivative Liabilities include no material amounts related to physical forward transactions with Enable.



Offsetting of Natural Gas Derivative Assets and Liabilities
	December 31, 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	$	100		$	(11	)	$	89
Other Assets: Non-trading derivative assets	40			(4		)	36
Current Liabilities: Non-trading derivative liabilities	(62		)	51			(11		)
Other Liabilities: Non-trading derivative liabilities	(25		)	20			(5		)
Total	$	53		$	56		$	109


(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 March 31,
Total derivatives not designated as hedging instruments	Income Statement Location	2016			2015
		(in millions)
Natural gas derivatives	Gains (Losses) in Revenues	$	20		$	(133	)
Natural gas derivatives	Gains (Losses) in Expenses: Natural Gas	(11		)	132
Total		$	9		$	(1	)

CERC enters into financial derivative contracts containing material adverse change provisions. These provisions could require CERC to post additional collateral if the S&P or Moody’s 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 March 31, 2016 or December 31, 2015 was $2 million and $3 million, respectively. CERC posted no assets as collateral towards derivative instruments that contain credit risk contingent features at either March 31, 2016 or December 31, 2015. If all derivative contracts (in a net liability position) containing credit risk contingent features were triggered at both March 31, 2016 or December 31, 2015, $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 March 31, 2016, 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 $1.37 to $3.36 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 20% to 84%) 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 three months ended March 31, 2016, 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 March 31, 2016 and December 31, 2015, 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 March 31, 2016
	(in millions)
Assets
Corporate equities	$	2	$	—	$	—	$	—		$	2
Investments, including money market funds (2)	11		—		—		—			11
Natural gas derivatives (3)	3		95		19		(14		)	103
Total assets	$	16	$	95	$	19	$	(14	)	$	116
Liabilities
Natural gas derivatives (3)	$	8	$	60	$	4	$	(61	)	$	11
Total liabilities	$	8	$	60	$	4	$	(61	)	$	11


(1)	Amounts represent the impact of legally enforceable master netting arrangements that allow CERC to settle positive and negative positions and also include cash collateral of $47 million posted with the same counterparties.


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


(3)	Natural gas derivatives include no material amounts related to physical forward transactions with Enable.



	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, 2015
	(in millions)
Assets
Corporate equities	$	2	$	—	$	—	$	—		$	2
Investments, including money market funds (2)	11		—		—		—			11
Natural gas derivatives (3)	4		115		21		(15		)	125
Total assets	$	17	$	115	$	21	$	(15	)	$	138
Liabilities
Natural gas derivatives (3)	$	13	$	65	$	9	$	(71	)	$	16
Total liabilities	$	13	$	65	$	9	$	(71	)	$	16


(1)	Amounts represent the impact of legally enforceable master netting arrangements that allow CERC to settle positive and negative positions and also include cash collateral of $56 million posted with the same counterparties.


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


(3)	Natural gas derivatives include no material amounts related to physical forward transactions with Enable.

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



	Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Derivative Assets and Liabilities, net
	Three Months Ended March 31,
	2016			2015
	(in millions)
Beginning balance	$	12		$	17
Total gains	4			—
Total settlements	(5		)	(3		)
Transfers into Level 3	5			—
Transfers out of Level 3	(1		)	(1		)
Ending balance (1)	$	15		$	13
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	$	8		$	2


(1)	CERC did not have significant Level 3 purchases or sales during either of the three months ended March 31, 2016 and 2015.

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.



	March 31, 2016				December 31, 2015
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in millions)
Financial assets:
Notes receivable–unconsolidated affiliate	$	—	$	—	$	363	$	356
Financial liabilities:
Long-term debt	$	2,125	$	2,317	$	2,341	$	2,539

(6) Unconsolidated Affiliate

On May 1, 2013 (the Formation Date) CERC Corp., OGE and ArcLight closed on the formation of Enable. CERC has the ability to significantly influence the operating and financial policies of Enable and, accordingly, accounts for its investment in Enable’s common and subordinated units 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 as of March 31, 2016, the guarantees discussed in Note 10, and outstanding current accounts receivable from Enable. In connection with the Private Placement, Enable redeemed $363 million of notes owed to a wholly-owned subsidiary of CERC Corp., which bore interest at an annual rate of 2.10% to 2.45%. CERC

recorded interest income of $1 million and $2 million during the three months ended March 31, 2016 and 2015, respectively, and had interest receivable from Enable of $-0- and $4 million as of March 31, 2016 and December 31, 2015, respectively, on its notes receivable.

Effective on the Formation Date, CenterPoint Energy and Enable entered into 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, which ended on April 30, 2016. CERC is providing certain services to Enable on a year-to-year basis unless terminated by Enable with at least 90 days’ notice prior to the end of the extension term. 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 billed Enable for reimbursement of transition services of $3 million and $5 million during the three months ended March 31, 2016 and 2015, respectively, under the Transition Agreements. Actual transition services costs are recorded net of reimbursements received from Enable. CERC had accounts receivable from Enable of $3 million as of both March 31, 2016 and December 31, 2015 for amounts billed for transition services.

CERC incurred natural gas expenses, including transportation and storage costs, of $33 million and $39 million during the three months ended March 31, 2016 and 2015, respectively, for transactions with Enable. CERC had accounts payable to Enable of $11 million as of both March 31, 2016 and December 31, 2015 from such transactions.

As of March 31, 2016, CERC held an approximate 55.4% limited partner interest in Enable consisting of 94,151,707 common units and 139,704,916 subordinated units. As of March 31, 2016, CERC and OGE each own a 50% management interest in the general partner of Enable and a 40% and 60% interest, respectively, in the incentive distribution rights held by the general partner.

CERC 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. As of March 31, 2016, the carrying value of CERC’s equity method investment in Enable was $11.03 per unit, which includes limited partner common and subordinated units, a general partner interest and incentive distribution rights. On March 31, 2016, Enable’s common unit price closed at $8.56. On April 29, 2016, Enable’s common unit price closed at $11.87.

Based on an analysis of its equity method investment in Enable as of March 31, 2016, CERC believes that the decline in the value of its investment is temporary, and that the carrying value of its investment of $2.6 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, to conclude that its equity method investment is not other than temporarily impaired as of March 31, 2016.

Summarized unaudited consolidated income information for Enable is as follows:



	Three Months Ended March 31,
	2016		2015
	(in millions)
Operating revenues	$	509	$	616
Cost of sales, excluding depreciation and amortization	195		292
Operating income	103		104
Net income attributable to Enable	86		91

Reconciliation of Equity in Earnings, net:
CERC’s interest	$	48	$	51
Basis difference amortization	12		1
CERC’s equity in earnings, net	$	60	$	52

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



	March 31, 2016			December 31, 2015
	(in millions)
Current assets	$	380		$	381
Non-current assets	10,869			10,857
Current liabilities	280			615
Non-current liabilities	3,122			3,092
Non-controlling interest	12			12
Preferred equity	362			—
Enable partners’ equity	7,473			7,519

Reconciliation of Equity Method Investment in Enable:
CERC’s ownership interest in Enable partners’ capital	$	4,138		$	4,163
CERC’s basis difference	(1,558		)	(1,569		)
CERC’s equity method investment in Enable	$	2,580		$	2,594

Distributions Received from Unconsolidated Affiliate:



	Three Months Ended March 31,
	2016		2015
	(in millions)
Enable	$	74	$	72

(7) Goodwill

Goodwill by reportable business segment as of both March 31, 2016 and December 31, 2015 is as follows:



	(in millions)
Natural Gas Distribution	$	746
Energy Services (1)	83
Other Operations	11
Total	$	840


(1)	Amounts presented are net of accumulated goodwill impairment charge of $252 million.

(8) Related Party Transactions

CERC participates in a money pool through which it can borrow or invest on a short-term basis. Funding needs are aggregated and external borrowing or investing is based on the net cash position. The net funding requirements of the money pool are expected to be met with borrowings under CenterPoint Energy’s revolving credit facility or the sale of CenterPoint Energy’s commercial paper. CERC had investments in the money pool of $24 million and $-0- as of March 31, 2016 and December 31, 2015, respectively, which are included in accounts and notes receivable–affiliated companies in the Consolidated Balance Sheets. Affiliate related net interest income (expense) was not material for either the three months ended March 31, 2016 and 2015.

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. Houston Electric provides a number of services to CERC. These services are billed at actual cost, either directly or as an allocation, and include fleet services, shop services, geographic services, surveying and right-of-way services, radio communications, data circuit management and field operations. Additionally, CERC provides certain services to Houston Electric. These services are billed at actual cost, either directly or as an allocation and include line locating and other miscellaneous services. These charges are not necessarily indicative of what would have been incurred had CERC not been an affiliate of CenterPoint Energy.

Amounts charged to and from CERC for these services were as follows and are included primarily in operation and maintenance expenses:



	Three Months Ended March 31,
	2016			2015
	(in millions)
Corporate service charges	$	30		$	26

Charges from Houston Electric for services provided	4			3

Billings to Houston Electric for services provided	(1		)	(1		)
	$	33		$	28

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 2019. 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 had an associated principal obligation of $-0- and $40 million as of March 31, 2016 and December 31, 2015, respectively.


(b)	Long-term Debt

Revolving Credit Facility. On March 4, 2016, CERC Corp. announced that it had refinanced its existing $600 million revolving credit facility, which would have expired in 2019, with a new $600 million five-year senior unsecured revolving credit facility. As of March 31, 2016 and December 31, 2015, CERC Corp. had the following revolving credit facility and utilization of such facility:



		March 31, 2016						December 31, 2015
Size of Facility		Loans		Letters of Credit		Commercial Paper		Loans		Letters of Credit		Commercial Paper
(in millions)
$	600	$	—	$	2	$	—	$	—	$	2	$	219	(1)


(1)	Weighted average interest rate was 0.81% as of December 31, 2015.

CERC Corp.’s $600 million revolving credit facility, which is scheduled to terminate on March 3, 2021, can be drawn at LIBOR plus 1.25% 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. As of March 31, 2016, CERC’s debt to capital ratio, as defined in its credit facility agreement, was 32.5%.

CERC Corp. was in compliance with all financial covenants as of March 31, 2016.

(10) Commitments and Contingencies

(a) Natural Gas Supply Commitments

Natural gas supply commitments include natural gas contracts related to CERC’s Natural Gas Distribution and Energy Services business segments, which have various quantity requirements and durations, that are not classified as non-trading derivative assets and liabilities in CERC’s Condensed Consolidated Balance Sheets as of March 31, 2016 and December 31, 2015 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 March 31, 2016, minimum

payment obligations for natural gas supply commitments are approximately $283 million for the remaining nine months in 2016, $449 million in 2017, $404 million in 2018, $217 million in 2019, $90 million in 2020 and $38 million after 2020.

(b) Legal, Environmental and Other Regulatory Matters

Legal Matters

Gas Market Manipulation Cases. CenterPoint Energy, Houston Electric or their predecessor, 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, 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. 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 Houston Electric, 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. 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. On April 21, 2015, the U.S. Supreme Court affirmed the Ninth Circuit’s ruling and remanded the case to the district court for further proceedings, which are now underway. CenterPoint Energy and CES intend to continue vigorously defending against the plaintiffs’ claims. 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 MGPs in the past. With respect to certain Minnesota MGP sites, CERC has completed state-ordered remediation and continues state-ordered monitoring and water treatment. As of March 31, 2016, CERC had a recorded liability of $7 million for continued monitoring and any future remediation required by regulators in Minnesota. 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 depend on the number of sites to be remediated, the participation of other PRPs, if any, and the remediation methods used.

In addition to the Minnesota sites, the Environmental Protection Agency and other regulators have investigated MGP sites that were owned or operated by CERC or may have been owned by one of its former affiliates. CERC does not expect the ultimate outcome of these matters to have a material adverse effect on its financial condition, results of operations or cash flows.

Asbestos. Some facilities owned by CERC or its predecessors contain or have contained asbestos insulation and other asbestos-containing materials. CERC and its predecessor companies are from time to time named, along with numerous others, as defendants in lawsuits filed by a number of individuals who claim injury due to exposure to asbestos, and CERC anticipates that additional claims may be asserted in the future. Although their ultimate outcome cannot be predicted at this time, CERC 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 and reasonably estimable 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 $24 million as of March 31, 2016. Based on market conditions in the fourth quarter of 2015 at the time the most recent annual calculation was made under the agreement, GenOn was not obligated to post any security. If GenOn should fail to perform the contractual obligations, CERC could have to honor its guarantee and, in such event, any collateral then provided as security may be insufficient to satisfy CERC’s obligations.

CERC Corp. had also provided a guarantee of collection of $1.1 billion of Enable’s senior notes due 2019 and 2024. This guarantee was subordinated to all senior debt of CERC Corp. and was automatically released 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 March 31, 2016 was 38% compared to 39% for the same period in 2015.

CERC reported no uncertain tax liability as of March 31, 2016 and expects no significant change to the uncertain tax liability over the next twelve months. Tax years through 2013 have been audited and settled with the IRS. For tax years 2014 through 2016, CenterPoint Energy is a participant in the IRS’s Compliance Assurance Process.

(12) Reportable Business Segments

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

CERC’s reportable business segments include the following: Natural Gas Distribution, Energy Services, Midstream Investments and Other Operations. Natural Gas Distribution consists of intrastate natural gas sales to, and natural gas transportation and distribution for, residential, commercial, industrial and institutional customers. Energy Services represents CERC’s non-rate regulated gas sales and services operations. Midstream Investments consists of CERC’s investment in Enable. The Other Operations business segment includes unallocated corporate costs and inter-segment eliminations.

Financial data for business segments is as follows:



	For the Three Months Ended March 31, 2016
	Revenues from External Customers		Inter-segment Revenues			Operating Income		Total Assets as of March 31, 2016
	(in millions)
Natural Gas Distribution	$	888	$	7		$	160	$	5,661
Energy Services	432		7			6		844
Midstream Investments (1)	—		—			—		2,580
Other Operations	—		—			—		398
Reconciling Eliminations	—		(14		)	—		(829		)
Consolidated	$	1,320	$	—		$	166	$	8,654



	For the Three Months Ended March 31, 2015
	Revenues from External Customers		Inter-segment Revenues			Operating Income		Total Assets as of December 31, 2015
	(in millions)
Natural Gas Distribution	$	1,185	$	8		$	146	$	5,657
Energy Services	632		18			13		857
Midstream Investments (1)	—		—			—		2,594
Other Operations	—		—			1		777
Reconciling Eliminations	—		(26		)	—		(744		)
Consolidated	$	1,817	$	—		$	160	$	9,141


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



	Three Months Ended March 31,
	2016		2015
	(in millions)
Enable	$	60	$	52

Midstream Investments’ total assets are as follows:



	March 31, 2016		December 31, 2015
	(in millions)
Enable	$	2,580	$	2,594

(13) Other Current Assets and Liabilities

Included in other current assets on the Condensed Consolidated Balance Sheets at March 31, 2016 and December 31, 2015 were $13 million and $31 million, respectively, of margin deposits and $13 million and $12 million, respectively, of under-recovered gas cost. Included in other current liabilities on the Condensed Consolidated Balance Sheets at March 31, 2016 and December 31, 2015 were $52 million and $55 million, respectively, of over-recovered gas cost.

(14) Subsequent Events

On April 1, 2016, CES, CERC Corp.’s wholly-owned subsidiary, closed the previously announced agreement to acquire the retail commercial and industrial businesses of Continuum for $98.2 million, comprised of a purchase price of $77.5 million, less a $4.7 million purchase price adjustment, and working capital of $25.4 million. Due to the limited amount of time since the acquisition,

the initial accounting for the acquisition is incomplete. CERC intends to provide additional business combination disclosures, if material, in its Form 10-Q for the second quarter of 2016.

On April 26, 2016, Enable declared a quarterly cash distribution of $0.318 per unit on all of its outstanding common and subordinated units for the quarter ended March 31, 2016. Accordingly, CERC Corp. expects to receive a cash distribution of approximately $74 million from Enable in the second quarter of 2016 to be made with respect to CERC Corp.’s investment in common and subordinated units in Enable for the first quarter of 2016.

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 this Form 10-Q and our 2015 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 months ended March 31, 2016 and the three months ended March 31, 2015. Reference is made to “Management’s Narrative Analysis of Results of Operations” in Item 7 of our 2015 Form 10-K.

RECENT EVENTS

Preferred Units. On January 28, 2016, CenterPoint Energy entered into a purchase agreement with Enable pursuant to which it agreed to purchase in a Private Placement an aggregate of 14,520,000 Series A Preferred Units from Enable for a cash purchase price of $25.00 per Series A Preferred Unit. The Private Placement closed on February 18, 2016. In connection with the Private Placement, Enable redeemed approximately $363 million of notes scheduled to mature in 2017 payable to our wholly-owned subsidiary. We made a dividend to CenterPoint Energy of $363 million and CenterPoint Energy used the dividend for its investment in the Series A Preferred Units.

Continuum Acquisition. On April 1, 2016, CES, our wholly-owned subsidiary, closed the previously announced agreement to acquire the retail commercial and industrial businesses of Continuum for $98.2 million, comprised of a purchase price of $77.5 million, less a $4.7 million purchase price adjustment, and working capital of $25.4 million.

Credit Facilities. On March 4, 2016, we announced that we had refinanced our existing $600 million revolving credit facility, which would have expired in 2019, with a new $600 million five-year senior unsecured revolving credit facility. The revolving credit facility may be drawn on from time to time to provide funds used for general corporate purposes and to backstop our commercial paper program. The facilities may also be utilized to obtain letters of credit.

Houston, South Texas, Beaumont/East Texas and Texas Coast GRIP. NGD’s Houston, South Texas, Beaumont/East Texas and Texas Coast divisions each submitted annual GRIP filings on March 31, 2016 representing an aggregate increase in revenue of $18.2 million based on incremental capital expenditures of $115.5 million. For the Houston Division, the GRIP filing requested an increase in revenues of $7.7 million related to $47.2 million in incremental capital expenditures that were incurred in 2015. The requested revenue requirement increase for this filing period is based on an 8.65% overall rate of return. For the South Texas Division, the filing requested an increase in revenues of $2.1 million for recovery of costs related to $13.8 million in incremental capital expenditures that were incurred in 2015. This requested amount is based on an 8.75% overall rate of return. For the Beaumont/East Texas Division, the GRIP filing requested recovery of costs related to $26.8 million in incremental capital expenditures incurred in 2015. The increase in revenue requirements for this filing period is $4.2 million annually, based on an overall rate of return of 8.51%. For the Texas Coast Division, NGD made its first GRIP filing, which requested an increase in revenues of $4.2 million, based on an overall rate of return of 8.23% and incremental capital expenditures of $27.7 million incurred during the fifteen-month period following the test year in NGD’s most recent rate case for the Texas Coast division through December 31, 2015. For each division, rates are expected to be implemented by July 2016.

CONSOLIDATED RESULTS OF OPERATIONS

Our results of operations are affected by seasonal fluctuations in the demand for natural gas and price movements of energy commodities as well as natural gas basis differentials. Our results of operations are also affected by, among other things, the actions of various federal, state and local governmental authorities having jurisdiction over rates we charge, competition in our various business operations, the effectiveness of our risk management activities, debt service costs and income tax expense. For more information regarding factors that may affect the future results of operations of our business, please read “Risk Factors” in Item 1A of Part I of our 2015 Form 10-K.

The following table sets forth our consolidated results of operations for the three months ended March 31, 2016 and 2015, followed by a discussion of our consolidated results of operations.



	Three Months Ended March 31,
	2016			2015
	(in millions)
Revenues	$	1,320		$	1,817
Expenses:
Natural gas	852			1,354
Operation and maintenance	200			197
Depreciation and amortization	60			56
Taxes other than income taxes	42			50
Total	1,154			1,657
Operating Income	166			160
Interest and other finance charges	(33		)	(34		)
Equity in earnings of unconsolidated affiliate, net	60			52
Other expense, net	—			2
Income Before Income Taxes	193			180
Income tax expense	73			71
Net Income	$	120		$	109

Three months ended March 31, 2016 compared to three months ended March 31, 2015

We reported net income of $120 million for the three months ended March 31, 2016 compared to net income of $109 million for the same period in 2015.

The increase in net income of $11 million was due to the following key factors:


•	an $8 million increase in equity earnings from our investment in Enable; and


•	a $6 million increase in operating income (discussed below by segment).

These increases were partially offset by the following:


•	a $2 million increase in income tax expense due to higher income offset by a lower effective tax rate; and


•	a $2 million decrease in other income, partially due to decreased interest income.

Income Tax Expense

Our effective tax rate reported for the three months ended March 31, 2016 was 38% compared to 39% for the same period in 2015.

RESULTS OF OPERATIONS BY BUSINESS SEGMENT

The following table presents operating income for each of our business segments for the three months ended March 31, 2016 and 2015, 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 March 31,
	2016		2015
	(in millions)
Natural Gas Distribution	$	160	$	146
Energy Services	6		13
Other Operations	—		1
Total Consolidated Operating Income	$	166	$	160

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 2015 Form 10-K.

The following table provides summary data of our Natural Gas Distribution business segment for the three months ended March 31, 2016 and 2015:



	Three Months Ended March 31,
	2016		2015
	(in millions, except throughput and customer data)
Revenues	$	895	$	1,193
Expenses:
Natural gas	445		756
Operation and maintenance	189		186
Depreciation and amortization	59		55
Taxes other than income taxes	42		50
Total expenses	735		1,047
Operating Income	$	160	$	146
Throughput (in Bcf):
Residential	73		97
Commercial and industrial	86		88
Total Throughput	159		185
Number of customers at end of period:
Residential	3,163,094		3,137,337
Commercial and industrial	254,781		251,811
Total	3,417,875		3,389,148

Three months ended March 31, 2016 compared to three months ended March 31, 2015

Our Natural Gas Distribution business segment reported operating income of $160 million for the three months ended March 31, 2016, compared to $146 million for the three months ended March 31, 2015.

Operating income increased $14 million as a result of the following key factors:


•	rate increases of $21 million; and


•	customer growth of $2 million from the addition of approximately 29,000 customers.

These increases were partially offset by the following:


•	decreased usage of $4 million, primarily due to milder weather in 2016;


•	higher depreciation and amortization expense of $4 million; and


•	increased labor and benefit expenses of $3 million.

Decreased expense related to energy efficiency programs of $1 million and decreased expense related to gross receipt taxes of $8 million were offset by a corresponding decrease in 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 2015 Form 10-K.

The following table provides summary data of our Energy Services business segment for the three months ended March 31, 2016 and 2015:



	Three Months Ended March 31,
	2016			2015
	(in millions, except throughput and customer data)
Revenues	$	439		$	650
Expenses:
Natural gas	421			624
Operation and maintenance	10			12
Depreciation and amortization	1			1
Taxes other than income taxes	1			—
Total expenses	433			637
Operating Income	$	6		$	13

Mark-to-market loss	$	(9	)	$	(4	)

Throughput (in Bcf)	171			185

Number of customers at end of period	18,073			18,206

Three months ended March 31, 2016 compared to three months ended March 31, 2015

Our Energy Services business segment reported operating income of $6 million for the three months ended March 31, 2016 compared to $13 million for the three months ended March 31, 2015. The decrease in operating income of $7 million was primarily due to a $5 million decrease from mark-to-market accounting for derivatives associated with certain natural gas purchases and sales used to lock in economic margins. The remaining decrease in operating income was margin related, resulting primarily 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 2015 Form 10-K.

The following table provides pre-tax equity income of our Midstream Investments business segment for the three months ended March 31, 2016 and 2015:



	Three Months Ended March 31,
	2016		2015
	(in millions)
Enable	$	60	$	52

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 2015 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 2015 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 nine months of 2016 include approximately $401 million of capital expenditures, maturing senior notes of $325 million and the acquisition of the retail commercial and industrial businesses of Continuum for $98.2 million.

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 nine months of 2016. Discretionary financing or refinancing may result in the issuance of debt securities in the capital markets or the arrangement of additional credit facilities. Issuances of debt in the capital markets, funds raised in the commercial paper markets and additional credit facilities may not, however, be available to us on acceptable terms.

Off-Balance Sheet Arrangements

Prior to the distribution of CenterPoint Energy’s ownership in 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) 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 $24 million as of March 31, 2016. Based on market conditions in the fourth quarter of 2015 at the time the most recent annual calculation was made under the agreement, GenOn was not obligated to post any security. If GenOn should fail to perform the contractual obligations, we could have to honor our guarantee and, in such event, any collateral provided as security may be insufficient to satisfy our obligations.

We had also provided a guarantee of collection of $1.1 billion of Enable’s senior notes due 2019 and 2024. This guarantee was subordinated to all our senior debt and was automatically released 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 2015 Form 10-K was filed with the SEC are discussed below.

Oklahoma PBRC. In March 2016, NGD made a PBRC filing for the 2015 calendar year proposing to increase revenues by $0.5 million. A hearing is scheduled for June 7, 2016.

Arkansas BDA. On March 31, 2016, NGD made its annual BDA filing with the APSC to request recovery of a calendar year 2015 shortfall of $5.5 million. Approval from the APSC is still pending and interim rates will be implemented in June of 2016.

Arkansas Rate Case. On November 10, 2015, NGD filed an Application for Approval of a General Change in Rates with the APSC seeking a $35.6 million increase in revenue requirement and a 10.3% ROE. A procedural schedule has been established with a hearing scheduled for July 12, 2016. A final determination by the APSC is expected in the third quarter of 2016.

Louisiana RSP. NGD made its 2015 Louisiana RSP filings with the LPSC on October 1, 2015. The North Louisiana Rider RSP filing shows a revenue deficiency of $1.0 million, and the South Louisiana Rider RSP filing shows a revenue deficiency of $1.5 million. Both 2015 RSP filings utilized the capital structure and ROE factors approved by the LPSC on September 23, 2015 discussed below. NGD began billing in December 2015, subject to a refund. NGD made its 2014 Louisiana RSP filings with the LPSC on October 1, 2014. The North Louisiana Rider RSP filing shows a revenue deficiency of $4.0 million, compared to the authorized ROE of 10.25%. The South Louisiana Rider RSP filing shows a revenue deficiency of $2.3 million, compared to the authorized ROE of 10.5%. NGD began billing the revised rates in December 2014, subject to a refund. The 2014 and 2015 Louisiana RSP filings are still awaiting final approval from the LPSC.

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

PHMSA Regulatory Proposals. Recent regulatory proposals from the U.S. Department of Transportation’s PHMSA would expand the scope of its safety, reporting, and recordkeeping requirements for both natural gas and hazardous liquids (including oil and NGLs) pipelines. These proposals, if finalized, would impose additional costs on us and Enable.

On March 17, 2016, PHMSA issued a notice of proposed rulemaking detailing proposed revisions to the safety standards applicable to natural gas transmission and gathering pipelines. The proposed rules would add requirements for pipelines already subject to integrity management requirements, including repair criteria for pipelines in high consequence areas and requirements for monitoring gas quality and managing corrosion. For pipelines not already subject to integrity management requirements, the proposed rules include a new moderate consequence area definition, require gas quality monitoring and corrosion management, establish repair criteria and require verification of certain pipeline parameters. The proposed rules would also expand the scope of gas gathering lines subject to PHMSA regulation-including imposing minimum safety standards on certain larger, currently exempt, gathering lines-while subjecting all gathering-line operators to recordkeeping and annual reporting requirements from which they are currently exempt. The rules would also require inspections of pipeline areas affected by severe weather, natural disasters or similar events.

PHMSA issued a similar notice of proposed rulemaking for hazardous liquid pipelines on October 1, 2015. The proposed rules would extend PHMSA reporting requirements to all gathering lines, require pipeline inspections in areas affected by extreme weather

or natural disasters, require periodic inline inspections of pipelines outside of high consequence areas, require use of leak detection systems on all hazardous liquid pipelines, modify applicable repair criteria and set a timeline for pipelines subject to integrity management requirements to be capable of accommodating inline inspection tools.

Other Matters

Credit Facility

On March 4, 2016, we announced that we had refinanced our existing $600 million revolving credit facility, which would have expired in 2019, with a new $600 million five-year senior unsecured revolving credit facility. The revolving credit facility may be drawn on from time to time to provide funds used for general corporate purposes and to backstop our commercial paper program. The facilities may also be utilized to obtain letters of credit.

As of April 20, 2016, we had the following revolving credit facility and utilization of such facility:



Execution Date	Size of Facility		Amount Utilized at April 20, 2016			Termination Date
	(in millions)
March 3, 2016	$	600	$	4	(1)	March 3, 2021

(1) Represents outstanding letters of credit.

CERC Corp.’s $600 million revolving credit facility, which is scheduled to terminate on March 3, 2021, can be drawn at LIBOR plus 1.25% 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. As of March 31, 2016, our debt to capital ratio, as defined in its credit facility agreement, was 32.5%.

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 also 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.

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 April 20, 2016, we had no temporary external 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 April 20, 2016, we had investments in the money pool of $149 million. The money pool may not provide sufficient funds to meet our cash needs.

Impact on Liquidity of a Downgrade in Credit Ratings

The interest on borrowings under our credit facility is based on our credit rating. As of April 20, 2016, Moody’s, S&P and 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-	Negative	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 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 from Moody’s or S&P could increase borrowing costs under our $600 million revolving credit facility. If our credit ratings had been downgraded one notch by Moody’s and/or S&P from the ratings that existed at March 31, 2016, the impact on the borrowing costs under our credit facility would have been immaterial. A decline in credit ratings would also increase the interest rate on long-term debt to be issued in the capital markets and could negatively impact our ability to complete capital market transactions and to access the commercial paper market. Additionally, a decline in credit ratings could increase cash collateral requirements and reduce earnings of our Natural Gas Distribution and Energy Services business segments.

We and our subsidiaries purchase natural gas from one of our suppliers under supply agreements that contain an aggregate credit threshold of $140 million based on CERC Corp.’s S&P senior unsecured long-term debt rating of A-. Under these agreements, we may need to provide collateral if the aggregate threshold is exceeded or if the credit threshold is decreased due to a credit rating downgrade.

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. 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 March 31, 2016, the amount posted as collateral aggregated approximately $60 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 March 31, 2016, unsecured credit limits extended to CES by counterparties aggregated $367 million, and $2 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 $144 million as of March 31, 2016. 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 $125 million by us will cause a default. A default by CenterPoint Energy would not trigger a default under our debt instruments or revolving credit facility.

Possible Acquisitions, Divestitures and Joint Ventures

From time to time, we consider the acquisition or the disposition of assets or businesses or possible joint ventures, strategic initiatives 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

On January 28, 2016, CenterPoint Energy entered into a purchase agreement with Enable pursuant to which it agreed to purchase in a Private Placement an aggregate of 14,520,000 Series A Preferred Units for a cash purchase price of $25.00 per Series A Preferred Unit. The Private Placement closed on February 18, 2016. In connection with the Private Placement, Enable redeemed approximately $363 million of notes scheduled to mature in 2017 payable to our wholly-owned subsidiary. We made a dividend to CenterPoint Energy of $363 million, and CenterPoint Energy used the dividend for its investment in the Series A Preferred Units.

Enable is expected to pay a minimum quarterly distribution of $0.2875 per unit on its outstanding common 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 April 26, 2016, Enable declared a quarterly cash distribution of $0.318 per unit on all of its outstanding common and subordinated units for the quarter ended March 31, 2016. Accordingly, we expect to receive a cash distribution of approximately $74 million from Enable in the second quarter of 2016 to be made with respect to our limited partner interest in Enable for the first quarter of 2016.

Weather Hedge

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

Other Factors that Could Affect Cash Requirements

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


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


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


•	increased costs related to the acquisition of natural gas;


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


•	various legislative or regulatory actions;


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


•	the ability of GenOn and its subsidiaries to satisfy their obligations in respect of GenOn’s indemnity obligations to CenterPoint Energy and its subsidiaries or in connection with the contractual obligations to a third party pursuant to which we are their guarantor;


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


•	the outcome of litigation brought by and against us;


•	restoration costs and revenue losses resulting from future natural disasters such as hurricanes and the timing of recovery of such restoration costs; and


•	various other risks identified in “Risk Factors” in Item 1A of Part I of our 2015 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 March 31, 2016 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 March 31, 2016 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 2015 Form 10-K.

Item 1A. RISK FACTORS

There have been no material changes from the risk factors disclosed in our 2015 Form 10-K.

Item 5. OTHER INFORMATION

Ratio of Earnings to Fixed Charges. The ratio of earnings to fixed charges for the three months ended March 31, 2016 and 2015 was 7.09 and 6.71, respectively. We do not believe that the ratios for these three-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 SEC.

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 CERC 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	$600,000,000 Credit Agreement, dated as of March 3, 2016, among CERC Corp., as Borrower, and the banks named therein	Form 8-K dated March 3, 2016	1-13265	4.3
10.1	Third Amended and Restated Agreement of Limited Partnership of Enable Midstream Partners, LP dated as of February 18, 2016	Form 8-K dated February 18, 2016	1-13265	10.1
+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: May 12, 2016

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	$600,000,000 Credit Agreement, dated as of March 3, 2016, among CERC Corp., as Borrower, and the banks named therein	Form 8-K dated March 3, 2016	1-13265	4.3
10.1	Third Amended and Restated Agreement of Limited Partnership of Enable Midstream Partners, LP dated as of February 18, 2016	Form 8-K dated February 18, 2016	1-13265	10.1
+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

SEC Exhibit

Exhibit 12

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES

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

COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES

(Millions of Dollars)



	Three Months Ended March 31,
	2016		2015

Net income	$	120	$	109
Equity in earnings of unconsolidated affiliates, net of distributions	14		20
Income tax expense	73		71
	207		200

Fixed charges, as defined:

Interest	33		34
Interest component of rentals charged to operating expense	1		1
Total fixed charges	34		35

Earnings, as defined	$	241	$	235

Ratio of earnings to fixed charges	7.09		6.71

SEC Exhibit

Exhibit 31.1

CERTIFICATIONS

I, Scott M. Prochazka, certify that:

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

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

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

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


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


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


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


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

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


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


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

Date: May 12, 2016

/s/ Scott M. Prochazka

Scott M. Prochazka

President and Chief Executive Officer

SEC Exhibit

Exhibit 31.2

CERTIFICATIONS

I, William D. Rogers, certify that:

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


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


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


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


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


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


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

Date: May 12, 2016

/s/ William D. Rogers

William D. Rogers

Executive Vice President and Chief Financial Officer

SEC Exhibit

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of CenterPoint Energy Resources Corp. (the “Company”) on Form 10-Q for the three months ended March 31, 2016 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, Scott M. Prochazka, Chief Executive Officer, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that:

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

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

/s/ Scott M. Prochazka

Scott M. Prochazka

President and Chief Executive Officer

May 12, 2016

SEC Exhibit

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of CenterPoint Energy Resources Corp. (the “Company”) on Form 10-Q for the three months ended March 31, 2016 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, William D. Rogers, Chief Financial Officer, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that:

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

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

/s/ William D. Rogers

William D. Rogers

Executive Vice President and Chief Financial Officer

May 12, 2016