CENTERPOINT ENERGY RESOURCES CORP - FORM 10-Q

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EX-12 - EXHIBIT 12 - CENTERPOINT ENERGY RESOURCES CORP	cercexhibit12_6302016.htm
EX-32.2 - EXHIBIT 32.2 - CENTERPOINT ENERGY RESOURCES CORP	cercexhibit322_6302016.htm
EX-32.1 - EXHIBIT 32.1 - CENTERPOINT ENERGY RESOURCES CORP	cercexhibit321_6302016.htm
EX-31.2 - EXHIBIT 31.2 - CENTERPOINT ENERGY RESOURCES CORP	cercexhibit312_6302016.htm
EX-31.1 - EXHIBIT 31.1 - CENTERPOINT ENERGY RESOURCES CORP	cercexhibit311_6302016.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q



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

	FOR THE QUARTERLY PERIOD ENDED JUNE 30, 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 July 29, 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 JUNE 30, 2016

TABLE OF CONTENTS



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

	Condensed Statements of Consolidated Income
	Three and Six Months Ended June 30, 2016 and 2015 (unaudited)	1

	Condensed Statements of Consolidated Comprehensive Income
	Three and Six Months Ended June 30, 2016 and 2015 (unaudited)	2

	Condensed Consolidated Balance Sheets
	June 30, 2016 and December 31, 2015 (unaudited)	3

	Condensed Statements of Consolidated Cash Flows
	Six Months Ended June 30, 2016 and 2015 (unaudited)	5

	Notes to Unaudited Condensed Consolidated Financial Statements	6

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

Item 4.	Controls and Procedures	32

PART II.	OTHER INFORMATION

Item 1.	Legal Proceedings	33

Item 1A.	Risk Factors	33

Item 5.	Other Information	33

Item 6.	Exhibits	34



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
CECL		Current expected credit losses
CERC Corp.		CenterPoint Energy Resources Corp.
CERC		CERC Corp., together with its subsidiaries
CES		CenterPoint Energy Services, Inc.
Choice customers		Residential and small commercial customers who have the option to choose a natural gas supplier as governed by the local distribution company’s filed transportation tariffs
CIP		Conservation Improvement Program
Continuum		The retail energy services business of Continuum Retail Energy Services, LLC, including its wholly-owned subsidiary Lakeshore Energy Services, LLC and the natural gas wholesale assets of Continuum Energy Services, LLC
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.
MPSC		Mississippi Public Service Commission
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
ROR		Return on revenue
RRA		Rate Regulation Adjustment
RRI		Reliant Resources, Inc.
RSP		Rate Stabilization Plan



GLOSSARY (cont.)

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

iii

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;


•	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 June 30,						Six Months Ended June 30,
	2016			2015			2016			2015

Revenues	$	807		$	824		$	2,127		$	2,641

Expenses:
Natural gas	496			529			1,348			1,883
Operation and maintenance	196			179			396			376
Depreciation and amortization	63			56			123			112
Taxes other than income taxes	34			33			76			83
Total	789			797			1,943			2,454
Operating Income	18			27			184			187

Other Income (Expense):
Interest and other finance charges	(31		)	(35		)	(64		)	(69		)
Equity in earnings of unconsolidated affiliate, net	31			43			91			95
Other, net	2			(1		)	2			1
Total	2			7			29			27
Income Before Income Taxes	20			34			213			214
Income tax expense	14			12			87			83
Net Income	$	6		$	22		$	126		$	131

See Notes to the Interim Condensed Consolidated Financial Statements

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES

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

CONDENSED STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME

(Millions of Dollars)

(Unaudited)



	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2016		2015		2016		2015

Net income	$	6	$	22	$	126	$	131
Other comprehensive income, net of tax:
Adjustment to pension and other postretirement plans (net of tax of $1, $-0-, $1 and $-0-)	1		—		1		—
Other comprehensive income	1		—		1		—
Comprehensive income	$	7	$	22	$	127	$	131

See Notes to the Interim Condensed Consolidated Financial Statements

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES

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

CONDENSED CONSOLIDATED BALANCE SHEETS

(Millions of Dollars)

(Unaudited)

ASSETS



	June 30, 2016		December 31, 2015
Current Assets:
Cash and cash equivalents	$	1	$	—
Accounts receivable, less bad debt reserve of $23 and $19, respectively	305		350
Accrued unbilled revenues	65		183
Accounts and notes receivable–affiliated companies	12		8
Materials and supplies	50		45
Natural gas inventory	96		168
Non-trading derivative assets	47		89
Prepaid expenses and other current assets	66		61
Total current assets	642		904

Property, Plant and Equipment:
Property, plant and equipment	6,103		5,898
Less: accumulated depreciation and amortization	1,716		1,640
Property, plant and equipment, net	4,387		4,258

Other Assets:
Goodwill	861		840
Non-trading derivative assets	22		36
Notes receivable–unconsolidated affiliate	—		363
Investment in unconsolidated affiliate	2,536		2,594
Other	180		146
Total other assets	3,599		3,979

Total Assets	$	8,628	$	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



	June 30, 2016		December 31, 2015
Current Liabilities:
Short-term borrowings	$	17	$	40
Current portion of long-term debt	—		325
Accounts payable	259		307
Accounts and notes payable–affiliated companies	35		39
Taxes accrued	46		63
Interest accrued	32		36
Customer deposits	80		80
Non-trading derivative liabilities	17		11
Other	144		158
Total current liabilities	630		1,059

Other Liabilities:
Deferred income taxes, net	1,854		1,774
Non-trading derivative liabilities	6		5
Benefit obligations	94		89
Regulatory liabilities	764		734
Other	214		210
Total other liabilities	2,932		2,812

Long-Term Debt	1,978		2,016

Commitments and Contingencies (Note 11)

Stockholder’s Equity:
Common stock	—		—
Paid-in capital	2,489		2,417
Retained earnings	591		828
Accumulated other comprehensive income	8		9
Total stockholder’s equity	3,088		3,254

Total Liabilities and Stockholder’s Equity	$	8,628	$	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)



	Six Months Ended June 30,
	2016			2015
Cash Flows from Operating Activities:
Net income	$	126		$	131
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	123			112
Amortization of deferred financing costs	4			5
Deferred income taxes	82			80
Write-down of natural gas inventory	1			2
Equity in (earnings) losses of unconsolidated affiliate, net of distributions	(91		)	50
Changes in other assets and liabilities, excluding acquisitions:
Accounts receivable and unbilled revenues, net	221			442
Accounts receivable/payable–affiliated companies	(8		)	2
Inventory	66			105
Accounts payable	(96		)	(298		)
Fuel cost recovery	(17		)	86
Interest and taxes accrued	(21		)	(26		)
Non-trading derivatives, net	21			2
Margin deposits, net	65			25
Other current assets	(8		)	10
Other current liabilities	16			(20		)
Other assets	4			8
Other liabilities	13			14
Other, net	1			1
Net cash provided by operating activities	502			731
Cash Flows from Investing Activities:
Capital expenditures	(230		)	(248		)
Distribution from unconsolidated affiliate in excess of cumulative earnings	149			—
Decrease in notes receivable–unconsolidated affiliate	363			—
Acquisitions, net of cash acquired	(98		)	—
Other, net	(2		)	2
Net cash provided by (used in) investing activities	182			(246		)
Cash Flows from Financing Activities:
Decrease in short-term borrowings, net	(23		)	(29		)
Payments of commercial paper, net	(43		)	(269		)
Payments of long-term debt	(325		)	—
Dividends to parent	(363		)	—
Debt issuance costs	(1		)	—
Decrease in notes payable–affiliated companies	—			(188		)
Contribution from parent	73			—
Other, net	(1		)	—
Net cash used in financing activities	(683		)	(486		)
Net Increase (Decrease) in Cash and Cash Equivalents	1			(1		)
Cash and Cash Equivalents at Beginning of Period	—			2
Cash and Cash Equivalents at End of Period	$	1		$	1
Supplemental Disclosure of Cash Flow Information:
Cash Payments:
Interest, net of capitalized interest	$	63		$	64
Income taxes, net	3			6
Non-cash transactions:
Accounts payable related to capital expenditures	$	36		$	34

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 7. 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 natural gas utilities. As of June 30, 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 13.

(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 $11 million and $12 million as of June 30, 2016 and December 31, 2015, respectively.

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 or 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, April, and May 2016, the FASB issued ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (ASU 2016-08), ASU No. 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing (ASU 2016-10), and ASU No. 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients (ASU 2016-12), respectively. ASU 2016-08, ASU 2016-10, and ASU 2016-12 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, ASU 2016-12, and ASU 2014-09 will have on its financial position, results of operations, cash flows and disclosures and expects to adopt these ASUs on January 1, 2018.

In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments (ASU 2016-13). ASU 2016-13 requires a new model called the CECL model to estimate credit losses for financial assets subject to credit losses and measured at amortized cost and certain off-balance sheet credit exposures. This includes loans, held-to-maturity debt securities, loan commitments, financial guarantees, and net investments in leases, as well as reinsurance and trade receivables. Upon initial recognition of the exposure, the CECL model requires an entity to estimate the credit losses expected over the life of an exposure based on historical information, current information and reasonable and supportable forecasts, including estimates of prepayments. The update also amends the other-than-temporary impairment model for debt securities classified as available-for-sale. ASU 2016-13 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019, with early adoption permitted beginning after December 15, 2018. CERC is currently assessing the impact that this standard will have on its financial position, results of operations, cash flows and disclosures.

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

(3) Acquisition

On April 1, 2016, CES, a wholly-owned subsidiary of CERC, closed the previously announced agreement to acquire the retail energy services business and natural gas wholesale assets of Continuum for $98 million. The purchase price was allocated to identifiable assets acquired and liabilities assumed based on their estimated fair values on the acquisition date. As additional information becomes available, the preliminary purchase price allocation may be revised during the remainder of the measurement period (which will not exceed 12 months from the acquisition date). Any such revisions or changes are not expected to be material.

The following table summarizes the total preliminary purchase price allocation and the fair value amounts recognized for the assets acquired and liabilities assumed related to the acquisition:



	(in millions)
Total purchase price consideration	$	98
Receivables	$	75
Derivative assets	38
Property and equipment	1
Identifiable intangibles	36
Total assets acquired	150
Accounts payable	49
Derivative liabilities	24
Total liabilities assumed	73
Identifiable net assets acquired	77
Goodwill	21
Net assets acquired	$	98

The goodwill of $21 million resulting from the acquisition reflects the excess of the purchase price over the fair value of the net identifiable assets acquired. The goodwill recorded as part of the acquisition primarily reflects the value of the complementary operational and geographic footprints provided, along with the scale, geographic reach and expanded capabilities.

Identifiable intangible assets were recorded at estimated fair value as determined by management based on available information, which includes a preliminary valuation prepared by an independent third party. The significant assumptions used in arriving at the estimated identifiable intangible asset values included management’s estimates of future cash flows, the discount rate which is based on the weighted average cost of capital for comparable publicly traded guideline companies and projected customer attrition rates. The useful lives for the identifiable intangible assets were determined using methods that approximate the pattern of economic benefit provided by the utilization of the assets.

The estimated fair value of the identifiable intangible assets and related useful lives as included in the preliminary purchase price allocation include:



	Estimate Fair Value		Estimate Useful Life
	(in millions)		(in years)
Customer relationships	$	32	15
Covenants not to compete	4		4
Total identifiable intangibles	$	36

Amortization expense related to the above identifiable intangible assets was $1 million for the three and six months ended June 30, 2016 and is expected to be $2 million for 2016.

Revenues of $108 million and operating income of less than $1 million attributable to the acquisition are included in CERC’s Condensed Consolidated Statements of Income for the three and six months ended June 30, 2016.

As Continuum was a non-public company that did not prepare interim financial information, the historical financial information for the businesses and assets acquired was impracticable to obtain. As a result, pro forma results of the acquired businesses and assets are not presented.

(4) Employee Benefit Plans

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



	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2016		2015		2016		2015
	(in millions)
Interest cost on accumulated benefit obligation	$	1	$	1	$	2	$	2
Amortization of net loss	—		—		—		1
Net periodic cost	$	1	$	1	$	2	$	3

CERC expects to contribute approximately $6 million to its postretirement benefit plan in 2016, of which approximately $1 million and $3 million were contributed during the three and six months ended June 30, 2016, respectively.

(5) 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 June 30, 2016 and 2015, CERC recognized gains of $-0- and $1 million, respectively, related to these swaps. During the six months ended June 30, 2016 and 2015, CERC recognized losses of $-0- and $4 million, respectively, related to these swaps. Weather hedge gains and losses are included in revenues in the Condensed Statements of Consolidated Income.

(b) Derivative Fair Values and Income Statement Impacts

The following tables present information about CERC’s derivative instruments and hedging activities. The first four tables provide a balance sheet overview of CERC’s Derivative Assets and Liabilities as of June 30, 2016 and December 31, 2015, while the last two tables provide a breakdown of the related income statement impacts for the three and six months ended June 30, 2016 and 2015.



Fair Value of Derivative Instruments
		June 30, 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	$	49	$	2
Natural gas derivatives (1) (2) (3)	Other Assets: Non-trading derivative assets	28		6
Natural gas derivatives (1) (2) (3)	Current Liabilities: Non-trading derivative liabilities	28		45
Natural gas derivatives (1) (2) (3)	Other Liabilities: Non-trading derivative liabilities	—		6
Total		$	105	$	59


(1)	The fair value shown for natural gas contracts is comprised of derivative gross volumes totaling 1,085 Bcf or a net 6 Bcf short position. Of the net short position, basis swaps constitute a net 136 Bcf long position.

(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 natural gas derivative assets and liabilities was a $46 million asset as shown on CERC’s Condensed Consolidated Balance Sheets (and as detailed in the table below), and was comprised of the natural gas contracts derivative assets and liabilities separately shown above, offset by collateral netting of less than $1 million.


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



Offsetting of Natural Gas Derivative Assets and Liabilities
	June 30, 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	$	77		$	(30	)	$	47
Other Assets: Non-trading derivative assets	28			(6		)	22
Current Liabilities: Non-trading derivative liabilities	(47		)	30			(17		)
Other Liabilities: Non-trading derivative liabilities	(12		)	6			(6		)
Total	$	46		$	—		$	46


(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 natural gas 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 natural gas derivatives are recognized in the Condensed Statements of Consolidated Income as revenue for retail sales derivative contracts and as natural gas expense for financial natural gas derivatives and non-retail related physical natural gas derivatives.



Income Statement Impact of Derivative Activity
		Three Months Ended June 30,
Total derivatives not designated as hedging instruments	Income Statement Location	2016			2015
		(in millions)
Natural gas derivatives	Gains (Losses) in Revenues	$	(50	)	$	7
Natural gas derivatives	Gains (Losses) in Expense: Natural Gas	59			1
Total		$	9		$	8



Income Statement Impact of Derivative Activity
		Six Months Ended June 30,
Total derivatives not designated as hedging instruments	Income Statement Location	2016			2015
		(in millions)
Natural gas derivatives	Gains (Losses) in Revenues	$	(30	)	$	49
Natural gas derivatives	Gains (Losses) in Expenses: Natural Gas	48			(42		)
Total		$	18		$	7

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 as of both June 30, 2016 and December 31, 2015 was $3 million. CERC posted no assets as collateral towards derivative instruments that contain credit risk contingent features as of either June 30, 2016 or December 31, 2015. If all derivative contracts (in a net liability position) containing credit risk contingent features were triggered as of both June 30, 2016 and December 31, 2015, $2 million of additional assets would be required to be posted as collateral.

(6) 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. As of June 30, 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 $1.92 to $3.72 per one million British thermal units) as an unobservable input. Level 3 options are valued through Black-Scholes (including forward start) option models which include option volatilities (ranging from 0% to 85%) as an unobservable input. CERC’s Level 3 derivative assets and liabilities consist of both long and short positions (forwards and options) and their fair value is sensitive to forward prices and volatilities. If forward prices decrease, CERC’s long forwards lose value whereas its short forwards gain in value. If volatility decreases, CERC’s long options lose value whereas its short options gain in value.

CERC determines the appropriate level for each financial asset and liability on a quarterly basis and recognizes transfers between levels at the end of the reporting period. For the six months ended June 30, 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 June 30, 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 June 30, 2016
	(in millions)
Assets
Corporate equities	$	2	$	—	$	—	$	—		$	2
Investments, including money market funds (2)	11		—		—		—			11
Natural gas derivatives (3)	7		77		21		(36		)	69
Total assets	$	20	$	77	$	21	$	(36	)	$	82
Liabilities
Natural gas derivatives (3)	$	5	$	49	$	5	$	(36	)	$	23
Total liabilities	$	5	$	49	$	5	$	(36	)	$	23


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


(2)	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 June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
	(in millions)
Beginning balance	$	15		$	13		$	12		$	17
Purchases	12			—			12			—
Total gains	—			—			4			—
Total settlements	(11		)	(3		)	(16		)	(6		)
Transfers into Level 3	—			—			5			—
Transfers out of Level 3	—			—			(1		)	(1		)
Ending balance (1)	$	16		$	10		$	16		$	10
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	$	3		$	—		$	11		$	2


(1)	CERC did not have significant Level 3 sales during either of the three or six months ended June 30, 2016 or 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.



	June 30, 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	$	1,978	$	2,225	$	2,341	$	2,539

(7) 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 Sheets as of June 30, 2016, the guarantees discussed in Note 11, 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 $-0- and $2 million during the three months ended June 30, 2016 and 2015, respectively, and $1 million and $4 million during the six months ended June 30, 2016 and 2015, respectively, and had interest receivable from Enable of $-0- and $4 million as of June 30, 2016 and December 31, 2015, respectively, on its notes receivable.

Effective on the Formation Date, CenterPoint Energy and Enable entered into the 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.

Enable may terminate (i) the entire Services Agreement with at least 90 days’ notice prior to the end of any extension term, or (ii) either any service provided under the Services Agreement, or the entire Services Agreement, at any time upon approval by its board of directors and with at least 180 days’ notice.

CERC billed Enable for reimbursement of transition services of $2 million during both the three months ended June 30, 2016 and 2015, and $5 million and $7 million during the six months ended June 30, 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 $1 million and $3 million as of June 30, 2016 and December 31, 2015, respectively, for amounts billed for transition services.

CERC incurred natural gas expenses, including transportation and storage costs, of $24 million and $26 million during the three months ended June 30, 2016 and 2015, respectively, and $57 million and $65 million during the six months ended June 30, 2016 and 2015, respectively, for transactions with Enable. CERC had accounts payable to Enable of $8 million and $11 million as of June 30, 2016 and December 31, 2015, respectively, from such transactions.

As of June 30, 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 June 30, 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 June 30, 2016, the carrying value of CERC’s equity method investment in Enable was $10.85 per unit, which includes limited partner common and subordinated units, a general partner interest and incentive distribution rights. On June 30, 2016, Enable’s common unit price closed at $13.51.

Summarized unaudited consolidated income information for Enable is as follows:



	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
	(in millions)
Operating revenues	$	529	$	590	$	1,038	$	1,206
Cost of sales, excluding depreciation and amortization	254		277		449		569
Operating income	57		93		160		197
Net income attributable to Enable	35		77		121		168

Reconciliation of Equity in Earnings, net:
CERC’s interest	$	19	$	42	$	67	$	93
Basis difference amortization	12		1		24		2
CERC’s equity in earnings, net	$	31	$	43	$	91	$	95

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



	June 30, 2016			December 31, 2015
	(in millions)
Current assets	$	349		$	381
Non-current assets	10,851			10,857
Current liabilities	301			615
Non-current liabilities	3,150			3,092
Non-controlling interest	11			12
Preferred equity	362			—
Enable partners’ equity	7,376			7,519

Reconciliation of Equity Method Investment in Enable:
CERC’s ownership interest in Enable partners’ capital	$	4,084		$	4,163
CERC’s basis difference	(1,548		)	(1,569		)
CERC’s equity method investment in Enable	$	2,536		$	2,594

Distributions Received from Unconsolidated Affiliate:



	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
	(in millions)
Enable	$	75	$	73	$	149	$	145

(8) Goodwill

Goodwill by reportable business segment as of December 31, 2015 and changes in the carrying amount of goodwill as of June 30, 2016 are as follows:



	December 31, 2015			Continuum Acquisition (1)		June 30, 2016
	(in millions)
Natural Gas Distribution	$	746		$	—	$	746
Energy Services	83		(2)	21		104
Other Operations	11			—		11
Total	$	840		$	21	$	861


(1)	See Note 3.


(2)	Amount presented is net of accumulated goodwill impairment charge of $252 million.

(9) 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 no investments in the money pool as of both June 30, 2016 and December 31, 2015, which are included in accounts and notes receivable–affiliated companies in the Condensed Consolidated Balance Sheets. Affiliate related net interest income (expense) was not material for either the three or six months ended June 30, 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 June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
	(in millions)
Corporate service charges	$	29		$	29		$	59		$	55
Charges from Houston Electric for services provided	3			4			7			7
Billings to Houston Electric for services provided	(2		)	(2		)	(3		)	(3		)
	$	30		$	31		$	63		$	59

See Note 7 for related party transactions with Enable.

(10) 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 $17 million and $40 million as of June 30, 2016 and December 31, 2015, respectively.


(b)	Long-term Debt

Debt Repayments. In May 2016, CERC retired approximately $325 million aggregate principal amount of its 6.15% senior notes at their maturity. The retirement of senior notes was financed by the issuance of commercial paper.

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 June 30, 2016 and December 31, 2015, CERC Corp. had the following revolving credit facility and utilization of such facility:



		June 30, 2016							December 31, 2015
Size of Facility		Loans		Letters of Credit		Commercial Paper			Loans		Letters of Credit		Commercial Paper
(in millions)
$	600	$	—	$	3	$	176	(1)	$	—	$	2	$	219	(1)


(1)	Weighted average interest rate was 0.68% and 0.81% as of June 30, 2016 and December 31, 2015, respectively.

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 June 30, 2016, CERC’s debt to capital ratio, as defined in its credit facility agreement, was 30.7%.

CERC Corp. was in compliance with all financial covenants as of June 30, 2016.

(11) 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 June 30, 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 June 30, 2016, minimum payment obligations for natural gas supply commitments are approximately $190 million for the remaining six months in 2016, $473 million in 2017, $456 million in 2018, $270 million in 2019, $132 million in 2020 and $127 million after 2020.

(b) Legal, Environmental and Other 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 such cases. CES, a subsidiary of CERC Corp., was a defendant in a case now pending in federal court in Nevada alleging a conspiracy to inflate Wisconsin natural gas prices in 2000–2002. On May 24, 2016, the district court granted CES’s motion for summary judgment, dismissing CES from the case. That ruling is subject to appeal. 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 June 30, 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 $30 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 during its operations or on property where its predecessor companies have 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 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 $20 million as of June 30, 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.

(12) Income Taxes

The effective tax rate reported for the three months ended June 30, 2016 was 70% compared to 35% for the same period in 2015. The effective tax rate reported for the six months ended June 30, 2016 was 41% compared to 39% for the same period in 2015. The higher effective tax rate for the three and six months ended June 30, 2016 is due to a Louisiana state tax law change resulting in an increase to CERC’s deferred tax liability.

CERC reported no uncertain tax liability as of June 30, 2016 and expects no significant change to the uncertain tax liability over the next twelve months. CenterPoint Energy’s consolidated federal income tax returns have been audited and settled through 2014. CenterPoint Energy is under examination by the IRS for 2015 and 2016.

(13) 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 June 30, 2016
	Revenues from External Customers		Inter-segment Revenues			Operating Income
	(in millions)
Natural Gas Distribution	$	414	$	7		$	20
Energy Services	393		4			—
Midstream Investments (1)	—		—			—
Other Operations	—		—			(2		)
Reconciling Eliminations	—		(11		)	—
Consolidated	$	807	$	—		$	18



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



	For the Six Months Ended June 30, 2016
	Revenues from External Customers		Inter-segment Revenues			Operating Income			Total Assets as of June 30, 2016
	(in millions)
Natural Gas Distribution	$	1,302	$	14		$	180		$	5,585
Energy Services	825		11			6			973
Midstream Investments (1)	—		—			—			2,536
Other Operations	—		—			(2		)	362
Reconciling Eliminations	—		(25		)	—			(828		)
Consolidated	$	2,127	$	—		$	184		$	8,628



	For the Six Months Ended June 30, 2015
	Revenues from External Customers		Inter-segment Revenues			Operating Income		Total Assets as of December 31, 2015
	(in millions)
Natural Gas Distribution	$	1,605	$	15		$	165	$	5,657
Energy Services	1,036		22			22		857
Midstream Investments (1)	—		—			—		2,594
Other Operations	—		—			—		777
Reconciling Eliminations	—		(37		)	—		(744		)
Consolidated	$	2,641	$	—		$	187	$	9,141


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



	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
	(in millions)
Enable	$	31	$	43	$	91	$	95

Midstream Investments’ total assets are as follows:



	June 30, 2016		December 31, 2015
	(in millions)
Enable	$	2,536	$	2,594

(14) Other Current Assets and Liabilities

Included in other current assets on the Condensed Consolidated Balance Sheets at June 30, 2016 and December 31, 2015 were $22 million and $31 million, respectively, of margin deposits and $16 million and $12 million, respectively, of under-recovered gas cost. Included in other current liabilities on the Condensed Consolidated Balance Sheets at June 30, 2016 and December 31, 2015 were $42 million and $55 million, respectively, of over-recovered gas cost.

(15) Subsequent Events

On August 2, 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 June 30, 2016. Accordingly, CERC Corp. expects to receive a cash distribution of approximately $74 million from Enable in the third quarter of 2016 to be made with respect to CERC Corp.’s investment in common and subordinated units in Enable for the second 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 and six months ended June 30, 2016 and the three and six months ended June 30, 2015. Reference is made to “Management’s Narrative Analysis of Results of Operations” in Item 7 of our 2015 Form 10-K.

RECENT EVENTS

Continuum Acquisition. On April 1, 2016, CES, our wholly-owned subsidiary, closed the previously announced agreement to acquire the retail energy services business and natural gas wholesale assets of Continuum for $98 million. For more information regarding the acquisition, see Note 3 of our Interim Condensed Financial Statements.

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 in March 2016 representing an aggregate increase in revenue of $18.2 million based on incremental capital expenditures of $115.5 million. For each division, rates were approved and implemented by July 2016.

Minnesota Rate Case. In August 2015, NGD filed a general rate case with the MPUC requesting an annual increase of $54.1 million. In September 2015, the MPUC approved an interim increase of $47.8 million in revenues effective October 2, 2015, subject to a refund. The MPUC order was issued in June 2016 authorizing a $27.5 million rate adjustment based on an ROE of 9.49% and an ROR of 7.07%. On June 23, 2016, NGD filed a request for reconsideration. The MPUC has 60 days to take action or the reconsideration request is deemed denied by operation of law. The interim rate refund and final rates can only be implemented after the required compliance filing is accepted by the MPUC.

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 and six months ended June 30, 2016 and 2015, followed by a discussion of our consolidated results of operations.



	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
	(in millions)
Revenues	$	807		$	824		$	2,127		$	2,641
Expenses:
Natural gas	496			529			1,348			1,883
Operation and maintenance	196			179			396			376
Depreciation and amortization	63			56			123			112
Taxes other than income taxes	34			33			76			83
Total	789			797			1,943			2,454
Operating Income	18			27			184			187
Interest and other finance charges	(31		)	(35		)	(64		)	(69		)
Equity in earnings of unconsolidated affiliate, net	31			43			91			95
Other income (expense), net	2			(1		)	2			1
Income Before Income Taxes	20			34			213			214
Income tax expense	14			12			87			83
Net Income	$	6		$	22		$	126		$	131

Three months ended June 30, 2016 compared to three months ended June 30, 2015

We reported net income of $6 million for the three months ended June 30, 2016 compared to net income of $22 million for the same period in 2015.

The decrease in net income of $16 million was due to the following key factors:


•	a $12 million decrease in equity earnings from our investment in Enable;


•	a $9 million decrease in operating income (discussed by segment below); and


•	a $2 million increase in income tax expense.

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


•	a $4 million decrease in interest expense due to lower outstanding debt; and


•	a $3 million increase in other income, partially due to increased interest income.

Six months ended June 30, 2016 compared to six months ended June 30, 2015

We reported net income of $126 million for the six months ended June 30, 2016 compared to net income of $131 million for the same period in 2015.

The decrease in net income of $5 million was due to the following key factors:


•	a $4 million decrease in equity earnings from our investment in Enable;


•	a $4 million increase in income tax expense; and


•	a $3 million decrease in operating income (discussed by segment below).

These decreases were partially offset by the following:


•	a $5 million decrease in interest expense due to lower outstanding debt; and


•	a $1 million increase in other income, partially due to increased interest income.

Income Tax Expense

Our effective tax rate reported for the three months ended June 30, 2016 was 70% compared to 35% for the same period in 2015. The effective tax rate reported for the six months ended June 30, 2016 was 41% compared to 39% for the same period in 2015. The higher effective tax rate for the three and six months ended June 30, 2016 is due to a Louisiana state tax law change resulting in an increase to our deferred tax liability.

RESULTS OF OPERATIONS BY BUSINESS SEGMENT

The following table presents operating income (loss) for each of our business segments for the three and six months ended June 30, 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 June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
	(in millions)
Natural Gas Distribution	$	20		$	19		$	180		$	165
Energy Services	—			9			6			22
Other Operations	(2		)	(1		)	(2		)	—
Total Consolidated Operating Income	$	18		$	27		$	184		$	187

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 and six months ended June 30, 2016 and 2015:



	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
	(in millions, except throughput and customer data)
Revenues	$	421	$	427	$	1,316	$	1,620
Expenses:
Natural gas	130		152		575		908
Operation and maintenance	178		169		367		355
Depreciation and amortization	60		55		119		110
Taxes other than income taxes	33		32		75		82
Total expenses	401		408		1,136		1,455
Operating Income	$	20	$	19	$	180	$	165
Throughput (in Bcf):
Residential	20		19		93		116
Commercial and industrial	56		56		142		144
Total Throughput	76		75		235		260
Number of customers at end of period:
Residential	3,145,655		3,112,902		3,145,655		3,112,902
Commercial and industrial	252,172		249,142		252,172		249,142
Total	3,397,827		3,362,044		3,397,827		3,362,044

Three months ended June 30, 2016 compared to three months ended June 30, 2015

Our Natural Gas Distribution business segment reported operating income of $20 million for the three months ended June 30, 2016, compared to $19 million for the three months ended June 30, 2015.

Operating income increased $1 million as a result of the following key factors:


•	rate increases of $9 million;


•	increased miscellaneous revenues of $4 million, primarily due to weather-related decoupling and increased usage due to improved economic activity in Minnesota; and


•	customer growth of $2 million from the addition of approximately 36,000 new customers.

These increases were partially offset by the following:


•	higher depreciation, primarily due to ongoing additions to plant in service, and other taxes of $7 million;


•	increased contractor services expense of $5 million, primarily due to pipeline integrity work and higher disconnect activities that are recovered when service is reconnected; and


•	increased labor and benefits expense of $2 million.

Increased expense related to energy efficiency programs of $1 million and decreased expense related to gross receipt taxes of $1 million were offset by corresponding offsets in the related revenues.

Six months ended June 30, 2016 compared to six months ended June 30, 2015

Our Natural Gas Distribution business segment reported operating income of $180 million for the six months ended June 30, 2016, compared to $165 million for the six months ended June 30, 2015.

Operating income increased $15 million as a result of the following key factors:


•	rate increases of $31 million; and


•	customer growth of $3 million from the addition of approximately 36,000 new customers.

These increases were partially offset by the following:


•	higher depreciation, primarily due to ongoing additions to plant in service, and other taxes of $10 million;


•	increased contractor services expense of $6 million, primarily due to pipeline integrity work and higher disconnect activities that are recovered when service is reconnected; and


•	increased labor and benefits expense of $4 million.

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 and six months ended June 30, 2016 and 2015:



	Three Months Ended June 30,					Six Months Ended June 30,
	2016			2015		2016			2015
	(in millions, except throughput and customer data)
Revenues	$	397		$	408	$	836		$	1,058
Expenses:
Natural gas	377			388		798			1,012
Operation and maintenance	17			9		27			21
Depreciation and amortization	3			1		4			2
Taxes other than income taxes	—			1		1			1
Total expenses	397			399		830			1,036
Operating Income	$	—		$	9	$	6		$	22

Mark-to-market gain (loss)	$	(7	)	$	2	$	(16	)	$	(2	)

Throughput (in Bcf)	199			136		370			321

Number of customers at end of period	30,675			18,073		30,675			18,073

Three months ended June 30, 2016 compared to three months ended June 30, 2015

Our Energy Services business segment reported operating income of $-0- for the three months ended June 30, 2016 compared to $9 million for the three months ended June 30, 2015. The decrease in operating income of $9 million was primarily due to a $9 million decrease from mark-to-market accounting for derivatives associated with certain natural gas purchases and sales used to lock

in economic margins. The second quarter of 2016 included a $7 million mark-to-market charge compared to a $2 million mark-to-market benefit for the same period of 2015. The second quarter of 2016 also included $2 million of operation and maintenance expenses and $1 million of amortization expenses related to the acquisition and integration of Continuum.

Six months ended June 30, 2016 compared to six months ended June 30, 2015

Our Energy Services business segment reported operating income of $6 million for the six months ended June 30, 2016 compared to $22 million for the six months ended June 30, 2015. The decrease in operating income of $16 million was primarily due to a $14 million decrease from mark-to-market accounting for derivatives associated with certain natural gas purchases and sales used to lock in economic margins. The first half of 2016 included a $16 million mark-to-market charge compared to a $2 million mark-to-market charge for the same period of 2015. The six months ended June 30, 2016 also included $2 million of operation and maintenance expenses and $1 million of amortization expenses related to the acquisition and integration of Continuum. 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 and six months ended June 30, 2016 and 2015:



	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
	(in millions)
Enable	$	31	$	43	$	91	$	95

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 six months of 2016 include approximately $260 million of capital expenditures.

We expect that borrowings under our credit facility, proceeds from commercial paper, anticipated cash flows from operations, intercompany borrowings and distributions from Enable will be sufficient to meet our anticipated cash needs for the remaining six months of 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 $20 million as of June 30, 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. In July 2016, the Oklahoma Corporation Commission approved a joint stipulation that provides for a 10% ROE, a capital structure of 45% debt and 55% equity and no change in rates.

Arkansas BDA. In March 2016, NGD made its annual BDA filing with the APSC to request recovery of a calendar year 2015 shortfall of $5.5 million. Rates were implemented in June 2016.

Arkansas Rate Case. In November 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 non-unanimous settlement agreement was reached with the APSC staff and certain other parties for an annual revenue increase of $14.2 million and a 9.5% ROE plus the adoption of an annual rate mechanism to recover future capital and expenses. A hearing was held in July 2016 for the APSC to consider the non-unanimous settlement. 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 in October 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 Louisiana RSP filings utilized the capital structure and ROE factors approved by the LPSC in September 2015, which set an authorized ROE of 9.95% and a capital structure of 48% debt and 52% equity. NGD began billing in December 2015, subject to a refund. The 2015 Louisiana RSP filing is still subject to final approval from the LPSC. NGD made its 2014 Louisiana RSP filings with the LPSC in October 2014. The North Louisiana Rider RSP filing showed a revenue deficiency of $4.0 million, using the then-authorized ROE of 10.25% with a capital structure of 53% debt and 47% equity. The South Louisiana Rider RSP filing showed a revenue deficiency of $2.3 million, using the then-authorized ROE of 10.5% with a capital structure of 53% debt and 47% equity. NGD began billing the revised rates in December 2014, subject to refund or surcharge. After LPSC staff review and adjustments to conform to the RSP changes ordered by the LPSC in the 2013 RSP cases as approved in September 2015, NGD settled on an adjustment for the North Louisiana Rider RSP of $4.7 million, with an authorized ROE of 9.95% and a capital structure of 48% debt and 52% equity. NGD also settled on an adjustment for the South Louisiana Rider RSP of $2.5 million, with an authorized ROE of 9.95% and a capital structure of 48% debt and 52% equity. The settlements were approved by the LPSC and rates were implemented in July 2016.

Minnesota CIP. In May 2016, NGD filed a CIP request with the MPUC, seeking a $12.7 million financial incentive based on 2015 program performance. This request is currently pending approval from the MPUC and will be recognized when approved.

Mississippi RRA. In April 2016, NGD filed for a $3.5 million RRA with the MPSC, which was subsequently revised to a $3.3 million RRA with an adjusted ROE of 9.47%. The filing is currently pending approval from the MPSC. New rates are expected to be implemented in the third quarter 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.

In March 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 in October 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

Our 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 July 29, 2016, we had the following revolving credit facility and utilization of such facility:



Execution Date	Size of Facility		Amount Utilized at July 29, 2016			Termination Date
	(in millions)
March 3, 2016	$	600	$	221	(1)	March 3, 2021

(1) Represents outstanding commercial paper of $217 million and outstanding letters of credit of $4 million.

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 June 30, 2016, our debt to capital ratio, as defined in its credit facility agreement, was 30.7%.

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 July 29, 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 July 29, 2016, we had no borrowings from or investments in the money pool. The money pool may not provide sufficient funds to meet our cash needs.

Impact on Liquidity of a Downgrade in Credit Ratings

The interest on borrowings under our credit facility is based on our credit rating. As of July 29, 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 June 30, 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 natural 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 June 30, 2016, the amount posted as collateral aggregated

approximately $22 million. Should the credit ratings of CERC Corp. (as the credit support provider for CES) fall below certain levels, CES would be required to provide additional collateral up to the amount of its previously unsecured credit limit. We estimate that as of June 30, 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 $158 million as of June 30, 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 60 days after the end of each quarter. On August 2, 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 June 30, 2016. Accordingly, we expect to receive a cash distribution of approximately $74 million from Enable in the third quarter of 2016 to be made with respect to our limited partner interest in Enable for the second 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, although fixed customer charges are historically higher in Texas for NGD compared to our other jurisdictions. As a result, fluctuations from normal weather may have a positive or negative effect on NGD’s results in Texas. We have historically entered into heating-degree day swaps for certain NGD jurisdictions to mitigate the effect of fluctuations from normal weather on its results of operations and cash flows for the winter heating season. However, NGD did not enter into heating-degree day swaps for the 2015–2016 winter season as a result of NGD’s Minnesota division implementing a full decoupling pilot in July 2015.

Other Factors that Could Affect Cash Requirements

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


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


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


•	increased costs related to the acquisition of natural gas;


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


•	various legislative or regulatory actions;


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


•	the ability of GenOn and its subsidiaries to satisfy their obligations in respect of GenOn’s indemnity obligations to CenterPoint Energy and its subsidiaries 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 June 30, 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 June 30, 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 11(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 six months ended June 30, 2016 and 2015 was 5.11 and 4.72, respectively. We do not believe that the ratios for these six-month periods are necessarily indicative of the ratios for the twelve-month periods due to the seasonal nature of our business. The ratios were calculated pursuant to applicable rules of the 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	Fourth Amended and Restated Agreement of Limited Partnership of Enable Midstream Partners, LP, dated June 22, 2016	Form 8-K dated June 22, 2016	1-13265	10.1
10.2	Third Amended and Restated Limited Liability Company Agreement of Enable GP, LLC, dated June 22, 2016	Form 8-K dated June 22, 2016	1-13265	10.2
+12	Computation of Ratios of Earnings to Fixed Charges
+31.1	Rule 13a-14(a)/15d-14(a) Certification of Scott M. Prochazka
+31.2	Rule 13a-14(a)/15d-14(a) Certification of William D. Rogers
+32.1	Section 1350 Certification of Scott M. Prochazka
+32.2	Section 1350 Certification of William D. Rogers
+101.INS	XBRL Instance Document
+101.SCH	XBRL Taxonomy Extension Schema Document
+101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
+101.DEF	XBRL Taxonomy Extension Definition Linkbase Document
+101.LAB	XBRL Taxonomy Extension Labels Linkbase Document
+101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.



	CENTERPOINT ENERGY RESOURCES CORP.


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

Date: August 5, 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	Fourth Amended and Restated Agreement of Limited Partnership of Enable Midstream Partners, LP, dated June 22, 2016	Form 8-K dated June 22, 2016	1-13265	10.1
10.2	Third Amended and Restated Limited Liability Company Agreement of Enable GP, LLC, dated June 22, 2016	Form 8-K dated June 22, 2016	1-13265	10.2
+12	Computation of Ratios of Earnings to Fixed Charges
+31.1	Rule 13a-14(a)/15d-14(a) Certification of Scott M. Prochazka
+31.2	Rule 13a-14(a)/15d-14(a) Certification of William D. Rogers
+32.1	Section 1350 Certification of Scott M. Prochazka
+32.2	Section 1350 Certification of William D. Rogers
+101.INS	XBRL Instance Document
+101.SCH	XBRL Taxonomy Extension Schema Document
+101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
+101.DEF	XBRL Taxonomy Extension Definition Linkbase Document
+101.LAB	XBRL Taxonomy Extension Labels Linkbase Document
+101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

CENTERPOINT ENERGY RESOURCES CORP - FORM 10-Q - August 5, 2016

Attached files

CENTERPOINT ENERGY RESOURCES CORP Reports