10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)
þ	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2017
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, a smaller reporting company or an emerging growth company. See definitions of “large accelerated filer”, “accelerated filer”, “smaller reporting company” and “emerging growth 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	Emerging growth company o
		(Do not check if a smaller reporting company)

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).Yes o  No þ

As of October 26, 2017, all 1,000 shares of CenterPoint Energy Resources Corp. common stock were held by Utility Holding, LLC, a wholly-owned subsidiary of CenterPoint Energy, Inc.

CENTERPOINT ENERGY RESOURCES CORP.

QUARTERLY REPORT ON FORM 10-Q

FOR THE QUARTER ENDED SEPTEMBER 30, 2017

TABLE OF CONTENTS

PART I.	FINANCIAL INFORMATION
		Page
Item 1.	Financial Statements	1
	Condensed Statements of Consolidated Income
	Three and Nine Months Ended September 30, 2017 and 2016 (unaudited)	1
	Condensed Statements of Consolidated Comprehensive Income
	Three and Nine Months Ended September 30, 2017 and 2016 (unaudited)	2
	Condensed Consolidated Balance Sheets
	September 30, 2017 and December 31, 2016 (unaudited)	3
	Condensed Statements of Consolidated Cash Flows
	Nine Months Ended September 30, 2017 and 2016 (unaudited)	5
	Notes to Unaudited Condensed Consolidated Financial Statements	6
Item 2.	Management’s Narrative Analysis of Results of Operations	24
Item 4.	Controls and Procedures	34
PART II.	OTHER INFORMATION
Item 1.	Legal Proceedings	34
Item 1A.	Risk Factors	34
Item 5.	Other Information	34
Item 6.	Exhibits	35

i

GLOSSARY
AEM	Atmos Energy Marketing, LLC, previously a wholly-owned subsidiary of Atmos Energy Holdings, Inc., a wholly-owned subsidiary of Atmos Energy Corporation
AMAs	Asset Management Agreements
APSC	Arkansas Public Service Commission
ASU	Accounting Standards Update
Bcf	Billion cubic feet
BDA	Billing Determinant Adjustment, which is a revenue stabilization mechanism used to adjust revenues impacted by declines in natural gas consumption which occurred after the most recent rate case
CenterPoint Energy	CenterPoint Energy, Inc., and its subsidiaries
CERC Corp.	CenterPoint Energy Resources Corp.
CERC	CERC Corp., together with its subsidiaries
CES	CenterPoint Energy Services, Inc.
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 previously owned by Continuum Energy Services, LLC
EECR	Energy Efficiency Cost Recovery
Enable	Enable Midstream Partners, LP
FASB	Financial Accounting Standards Board
Fitch	Fitch, Inc.
Form 10-Q	Quarterly Report on Form 10-Q
FRP	Formula Rate Plan
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
MLP	Master Limited Partnership
MMBtu	One million British thermal units
Moody’s	Moody’s Investors Service, Inc.
MPSC	Mississippi Public Service Commission
MPUC	Minnesota Public Utilities Commission
NGD	Natural gas distribution business
NGLs	Natural gas liquids
NRG	NRG Energy, Inc.
OCC	Oklahoma Corporation Commission
OGE	OGE Energy Corp.
PBRC	Performance Based Rate Change
PHMSA	U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration
PRPs	Potentially responsible parties
Railroad Commission	Railroad Commission of Texas
Reliant Energy	Reliant Energy, Incorporated
ROE	Return on equity

ii

GLOSSARY (cont.)
RRA	Rate Regulation Adjustment
RRI	Reliant Resources, Inc.
RSP	Rate Stabilization Plan
SEC	Securities and Exchange Commission
S&P	Standard & Poor’s Ratings Services, a division of The McGraw-Hill Companies
TBD	To be determined
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
2016 Form 10-K	Annual Report on Form 10-K for the year ended December 31, 2016

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,” “target,” “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;

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

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

• 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;

• 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 and changes in regulation and legislation pertaining to trade, health care, finance and actions regarding the rates charged by our regulated businesses;

• tax reform and legislation;

• 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;

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• 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;

• the extent and effectiveness of our risk management and hedging activities, including, but not limited to, our financial hedges and weather hedges;

• timely and appropriate regulatory actions allowing recovery of costs associated with Hurricane Harvey and any future hurricanes or natural disasters;

• our or Enable’s potential business strategies and strategic initiatives, including restructurings, joint ventures and acquisitions or dispositions of assets or businesses (including a reduction of our interests in Enable, whether through our election to sell the common units we own in the public equity markets or otherwise, subject to certain limitations), which we cannot assure you will be completed or will have the anticipated benefits to us or Enable;

• 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, currently the subject of bankruptcy proceedings, to satisfy their obligations to us, including indemnity obligations;

• 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 2016 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, and we undertake no obligation to update or revise any forward-looking statements. 

v

PART I. FINANCIAL INFORMATION

Item 1.  FINANCIAL STATEMENTS

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES

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

CONDENSED STATEMENTS OF CONSOLIDATED INCOME

(Millions of Dollars)

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
Revenues:
Utility revenues	$	390		$	370		$	1,767		$	1,672
Non-utility revenues	861			608			2,964			1,433
Total	1,251			978			4,731			3,105
Expenses:
Utility natural gas	106			99			706			663
Non-utility natural gas	832			584			2,843			1,368
Operation and maintenance	187			175			603			571
Depreciation and amortization	68			62			202			185
Taxes other than income taxes	32			32			104			108
Total	1,225			952			4,458			2,895
Operating Income	26			26			273			210
Other Income (Expense):
Interest and other finance charges	(32		)	(29		)	(92		)	(93		)
Equity in earnings of unconsolidated affiliate, net	68			73			199			164
Other, net	1			(1		)	3			1
Total	37			43			110			72
Income Before Income Taxes	63			69			383			282
Income tax expense	25			26			144			113
Net Income	$	38		$	43		$	239		$	169

See Notes to Interim Condensed Consolidated Financial Statements

1

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES

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

CONDENSED STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME

(Millions of Dollars)

(Unaudited)

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2017			2016		2017			2016
Net income	$	38		$	43	$	239		$	169
Other comprehensive income, net of tax:
Adjustment to pension and other postretirement plans (net of tax of $2, $1, $2 and $-0-)	1			1		1			2
Net deferred loss from cash flow hedges (net of tax of $1, $-0-, $1 and $-0-)	(1		)	—		(1		)	—
Other comprehensive income	—			1		—			2
Comprehensive income	$	38		$	44	$	239		$	171

See Notes to Interim Condensed Consolidated Financial Statements

2

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES

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

CONDENSED CONSOLIDATED BALANCE SHEETS

(Millions of Dollars)

(Unaudited)

ASSETS

	September 30, 2017		December 31, 2016
Current Assets:
Cash and cash equivalents	$	1	$	1
Accounts receivable, less bad debt reserve of $15 and $14, respectively	448		512
Accrued unbilled revenues	84		229
Accounts and notes receivable–affiliated companies	8		5
Materials and supplies	53		47
Natural gas inventory	252		131
Non-trading derivative assets	64		51
Prepaid expenses and other current assets	102		81
Total current assets	1,012		1,057
Property, Plant and Equipment:
Property, plant and equipment	6,694		6,351
Less: accumulated depreciation and amortization	1,995		1,782
Property, plant and equipment, net	4,699		4,569
Other Assets:
Goodwill	867		862
Non-trading derivative assets	56		19
Investment in unconsolidated affiliate	2,481		2,505
Other	261		206
Total other assets	3,665		3,592
Total Assets	$	9,376	$	9,218

See Notes to Interim Condensed Consolidated Financial Statements

3

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES

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

CONDENSED CONSOLIDATED BALANCE SHEETS

(Millions of Dollars)

(Unaudited)

LIABILITIES AND STOCKHOLDER’S EQUITY

	September 30, 2017		December 31, 2016
Current Liabilities:
Short-term borrowings	$	48	$	35
Current portion of long-term debt	550		250
Accounts payable	375		471
Accounts and notes payable–affiliated companies	42		40
Taxes accrued	64		73
Interest accrued	33		33
Customer deposits	76		80
Non-trading derivative liabilities	17		41
Other	118		124
Total current liabilities	1,323		1,147
Other Liabilities:
Deferred income taxes, net	2,066		1,925
Non-trading derivative liabilities	10		5
Benefit obligations	105		104
Regulatory liabilities	699		769
Other	226		221
Total other liabilities	3,106		3,024
Long-Term Debt	2,086		2,125
Commitments and Contingencies (Note 12)
Stockholder’s Equity:
Common stock	—		—
Paid-in capital	2,528		2,489
Retained earnings	332		430
Accumulated other comprehensive income	1		3
Total stockholder’s equity	2,861		2,922
Total Liabilities and Stockholder’s Equity	$	9,376	$	9,218

See Notes to Interim Condensed Consolidated Financial Statements

4

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES

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

CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS

(Millions of Dollars)

(Unaudited)

	Nine Months Ended September 30,
	2017			2016
Cash Flows from Operating Activities:
Net income	$	239		$	169
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	202			185
Amortization of deferred financing costs	7			7
Deferred income taxes	140			108
Write-down of natural gas inventory	—			1
Equity in earnings of unconsolidated affiliate, net of distributions	(199		)	(164		)
Changes in other assets and liabilities, excluding acquisitions:
Accounts receivable and unbilled revenues, net	346			220
Accounts receivable/payable–affiliated companies	(1		)	(5		)
Inventory	(49		)	(1		)
Accounts payable	(227		)	(85		)
Fuel cost recovery	(30		)	(43		)
Interest and taxes accrued	(9		)	(8		)
Non-trading derivatives, net	(51		)	23
Margin deposits, net	(49		)	65
Other current assets	23			(11		)
Other current liabilities	(5		)	15
Other assets	(32		)	(5		)
Other liabilities	6			1
Other, net	1			2
Net cash provided by operating activities	312			474
Cash Flows from Investing Activities:
Capital expenditures	(373		)	(378		)
Distribution from unconsolidated affiliate in excess of cumulative earnings	223			223
Decrease in notes receivable–unconsolidated affiliate	—			363
Acquisitions, net of cash acquired	(132		)	(102		)
Other, net	2			(1		)
Net cash provided by (used in) investing activities	(280		)	105
Cash Flows from Financing Activities:
Decrease in short-term borrowings, net	13			3
Proceeds from (payments of) commercial paper, net	(40		)	240
Proceeds from long-term debt	298			—
Payments of long-term debt	—			(325		)
Dividends to parent	(337		)	(567		)
Debt issuance costs	(4		)	(1		)
Contribution from parent	38			73
Other, net	—			(2		)
Net cash used in financing activities	(32		)	(579		)
Net Increase in Cash and Cash Equivalents	—			—
Cash and Cash Equivalents at Beginning of Period	1			—
Cash and Cash Equivalents at End of Period	$	1		$	—
Supplemental Disclosure of Cash Flow Information:
Cash Payments:
Interest, net of capitalized interest	$	86		$	90
Income taxes, net	4			3
Non-cash transactions:
Accounts payable related to capital expenditures	$	53		$	32

See Notes to Interim Condensed Consolidated Financial Statements

5

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 2016 Form 10-K.

Background. CERC Corp. is an indirect, wholly-owned subsidiary of CenterPoint Energy, a public utility holding company. CERC Corp.’s operating subsidiaries own and operate natural gas distribution facilities, supply natural gas to commercial and industrial customers and electric and natural gas utilities and own interests in Enable as described in Note 8. CERC Corp.’s operating subsidiaries and divisions include:

• NGD, which owns and operates natural gas distribution systems in six states; and

• CES, which obtains and offers competitive variable and fixed-price physical natural gas supplies and services primarily to commercial and industrial customers and electric and natural gas utilities in 33 states.

As of September 30, 2017, CERC Corp. also owned approximately 54.1% of the common units representing limited partner interests in Enable, which owns, operates and develops natural gas and crude oil infrastructure assets.

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 14.

(2) New Accounting Pronouncements

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. As of the first reporting period in which the guidance is adopted, a cumulative-effect adjustment to beginning retained earnings will be made, with two features that will be adopted prospectively. CERC does not believe this standard will have a material impact on its financial position, results of operations, cash flows and disclosures.

In 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02) and related amendments. 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. A modified retrospective adoption approach is required. 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. 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09).  The new guidance simplifies several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification

6

on the statement of cash flows. CERC adopted this standard as of January 1, 2017. The adoption did not have a material impact on CERC’s financial position or results of operations.  However, CERC’s statement of cash flows reflects a decrease in financing activity and a corresponding increase in operating activity of $1 million as of both September 30, 2017 and 2016 due to the retrospective application of the requirement that cash paid to a tax authority when shares are withheld to satisfy statutory income tax withholding obligations should be presented as a financing rather than as an operating activity.

In 2016, the FASB issued ASUs which amended ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606). ASU 2014-09, as amended, provides a comprehensive new revenue recognition model that requires revenue to be recognized in a manner that depicts the transfer of goods or services to a customer at an amount that reflects the consideration expected to be received in exchange for those goods or services. Early adoption is permitted, and entities have the option of using either a full retrospective or a modified retrospective adoption approach. CERC is currently evaluating its revenue streams under these ASUs and has not yet identified any significant changes as the result of these new standards. A substantial amount of CERC’s revenues are tariff and derivative based, which we do not anticipate will be significantly impacted by these ASUs. CERC expects to adopt these ASUs on January 1, 2018 using the modified retrospective adoption approach.

In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (ASU 2016-15). ASU 2016-15 provides clarifying guidance on the classification of certain cash receipts and payments in the statement of cash flows and eliminates the variation in practice related to such classifications. ASU 2016-15 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017, with early adoption permitted. A retrospective adoption approach is required. CERC is currently assessing the impact that this standard will have on its statement of cash flows.

In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (ASU 2016-18). ASU 2016-18 requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, restricted cash and restricted cash equivalents. As a result, the statement of cash flows will no longer present transfers between cash and cash equivalents and restricted cash and restricted cash equivalents. When cash, cash equivalents, restricted cash and restricted cash equivalents are presented in more than one line item on the balance sheet, the new guidance requires a reconciliation of the totals in the statement of cash flows to the related captions in the balance sheet. ASU 2016-18 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017, with early adoption permitted. A retrospective adoption approach is required. This standard will not have an impact on CERC’s financial position, results of operations, cash flows and disclosures.

In January 2017, the FASB issued ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business (ASU 2017-01). ASU 2017-01 revises the definition of a business. If substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or a group of similar identifiable assets, then under ASU 2017-01, the asset or group of assets is not a business. The guidance also requires a business to include at least one substantive process and narrows the definition of outputs to be more closely aligned with how outputs are described in ASC 606. ASU 2017-01 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017, with early adoption permitted in certain circumstances. A prospective adoption approach is required. ASU 2017-01 could have a potential impact on CERC’s accounting for future acquisitions.

In January 2017, the FASB issued ASU No. 2017-04, Intangibles-Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment (ASU 2017-04). ASU 2017-04 eliminates Step 2 of the goodwill impairment test, which requires a hypothetical purchase price allocation. A goodwill impairment will now be the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill. ASU 2017-04 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019, with early adoption permitted. A prospective adoption approach is required. ASU 2017-04 will have an impact on CERC’s future calculation of goodwill impairments if an impairment is identified.

In February 2017, the FASB issued ASU No. 2017-05, Other Income-Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20): Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets (ASU 2017-05). ASU 2017-05 clarifies when and how to apply ASC 610-20 Gains and Losses from the Derecognition of Nonfinancial Assets, which was issued as part of ASU 2014-09 Revenue from Contracts with Customers (Topic 606). ASU 2017-05 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017, with early adoption permitted. Companies can elect a retrospective or modified retrospective approach to adoption. CERC does not believe this standard will have a material impact on its financial position, results of operations, cash flows and disclosures.

In March 2017, the FASB issued ASU No. 2017-07, Compensation-Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires an employer to report the service cost component of the net periodic pension cost and postretirement benefit cost in the same line item(s) as other

7

employee compensation costs arising from services rendered during the period; all other components will be presented separately from the line item(s) that includes the service cost and outside of any subtotal of operating income. In addition, only the service cost component will be eligible for capitalization in assets. ASU 2017-07 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017, with early adoption permitted. ASU 2017-07 should be applied retrospectively for the presentation of the service cost component and the other components and prospectively for the capitalization of the service cost component. The adoption of this guidance is expected to result in an increase to operating income and a decrease to other income. Prospectively, other components previously capitalized in assets will be recorded as regulatory assets in CERC’s rate-regulated businesses. CERC does not believe this standard will have a material impact on its financial position, results of operations, cash flows and disclosures.

In August 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12). ASU 2017-12 expands an entity’s ability to hedge nonfinancial and financial risk components and reduce complexity in fair value hedges of interest rate risk. The guidance eliminates the requirement to separately measure and report hedge ineffectiveness, eases certain documentation and assessment requirements, and updates the presentation and disclosure requirements. ASU 2017-12 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted. A cumulative-effect adjustment to eliminate the separate measurement of ineffectiveness upon adoption is required for existing cash flow and net investment hedges. Presentation and disclosure guidance should be applied prospectively. 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 January 3, 2017,CES, a wholly-owned subsidiary of CERC, completed its acquisition of AEM. After working capital adjustments, the final purchase price was $147 million and was allocated to identifiable assets acquired and liabilities assumed based on their estimated fair values on the acquisition date.

The following table summarizes the final 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	$	147
Cash	$	15
Receivables	140
Natural gas inventory	78
Derivative assets	35
Prepaid expenses and other current assets	5
Property and equipment	8
Identifiable intangibles	25
Total assets acquired	306
Accounts payable	113
Derivative liabilities	43
Other current liabilities	7
Other liabilities	1
Total liabilities assumed	164
Identifiable net assets acquired	142
Goodwill	5
Net assets acquired	$	147

The goodwill of $5 millionresulting 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, scale and expanded capabilities provided by the acquisition.

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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 final purchase price allocation include:

	Estimate Fair Value		Estimate Useful Life
	(in millions)		(in years)
Customer relationships	$	25	15

Amortization expense related to the above identifiable intangible assets was $-0- and $1 million for the three and nine months ended September 30, 2017, respectively.

Revenues of approximately $311 million and $989 million, respectively, and operating income of approximately $3 million and $28 million, respectively, attributable to the AEM acquisition are reported in the Energy Services business segment and included in CERC’s Condensed Statements of Consolidated Income for the three and nine months ended September 30, 2017.

The following unaudited pro forma financial information reflects the consolidated results of operations of CERC, assuming the AEM acquisition had taken place on January 1, 2016. Adjustments to pro forma net income include intercompany sales, amortization of intangible assets, depreciation of fixed assets, interest expense associated with debt financing to fund the acquisition, and related income tax effects. The pro forma information does not include the mark-to-market impact of financial instruments designated as cash flow hedges of anticipated purchases and sales at index prices. The effective portion of these hedges are excluded from earnings and reported as changes in Other Comprehensive Income. Additionally, the pro forma information does not include the mark-to-market impact of physical forward transactions that were previously accounted for as normal purchase and sale transactions.

The unaudited pro forma financial information has been presented for illustrative purposes only and is not necessarily indicative of the consolidated results of operations that would have been achieved had the acquisition taken place on the dates indicated or the future consolidated results of operations of the combined company.

	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
	(in millions)
Operating Revenue	$	1,251	$	1,234	$	4,731	$	3,819
Net Income	38		43		239		173

(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						Nine Months Ended
	September 30,						September 30,
	2017			2016			2017			2016
	(in millions)
Service cost	$	1		$	1		$	1		$	1
Interest cost	1			1			3			3
Expected return on plan assets	(1		)	(1		)	(1		)	(1		)
Amortization of prior service cost	—			—			1			—
Net periodic cost (1)	$	1		$	1		$	4		$	3

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(1) Net periodic cost in this table is before considering amounts subject to overhead allocations for capital expenditure projects or for amounts subject to deferral for regulatory purposes.  

CERC expects to contribute approximately $5 million to its postretirement benefit plan in 2017, of which approximately $1 million and $4 million were contributed during the three and nine months ended September 30, 2017, respectively.

(5) Regulatory Accounting

Hurricane Harvey. NGD suffered damage as a result of Hurricane Harvey, a major storm classified as a Category 4 hurricane on the Saffir-Simpson Hurricane Wind Scale, that first struck the Texas coast on Friday, August 25, 2017 and remained over the Houston area for the next several days. The unprecedented flooding from torrential amounts of rainfall accompanying the storm caused significant damage to or destruction of residences and businesses served by NGD.

Currently, NGD estimates that total costs to restore natural gas distribution facilities damaged as a result of Hurricane Harvey will range from $25 million to $30 million and estimates that the total restoration costs covered by insurance will be approximately $17 million.  NGD will defer the uninsured storm restoration costs as management believes it is probable that such costs will be recovered through traditional rate adjustment mechanisms for capital costs and through the next rate proceeding for operation and maintenance expenses. As of September 30, 2017, NGD has recorded approximately $7 million in regulatory assets, net of $2 million of insurance receivables recorded, for restoration costs incurred. As a result, storm restoration costs should not materially affect CERC’s reported net income for 2017.

(6) 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, weather and interest rates 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 mitigate the effects of commodity price movements. Certain financial instruments used to hedge portions of the natural gas inventory of the Energy Services business segment are designated as fair value hedges for accounting purposes. All other 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 entered into heating-degree day swaps for certain NGD Texas jurisdictions to mitigate the effect of fluctuations from normal weather on its results of operations and cash flows for the 2017–2018 winter heating season, which contained a bilateral dollar cap of $8 million. However, CERC did not enter into heating-degree day swaps for NGD jurisdictions for the 2015–2016 or 2016–2017 winter heating seasons.

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Hedging of Interest Expense for Future Debt Issuances. In August 2017, CERC Corp. entered into forward interest rate agreements with several counterparties, having an aggregate notional amount of $150 million. These agreements were executed to hedge, in part, volatility in the 30-year U.S. treasury rate by reducing CERC Corp.’s exposure to variability in cash flows related to interest payments of CERC Corp.’s $300 million issuance of fixed rate debt in August 2017. These forward interest rate agreements were designated as cash flow hedges. Accordingly, the effective portion of realized losses associated with the agreements, which totaled approximately $1.5 million, is a component of accumulated other comprehensive income in 2017 and will be amortized over the life of the notes.

(b) Derivative Fair Values and Income Statement Impacts

The following tables present information about CERC’s derivative instruments and hedging activities. The first four tables provide a balance sheet overview of CERC’s Derivative Assets and Liabilities as of September 30, 2017 and December 31, 2016, while the last table provides a breakdown of the related income statement impacts for the three and nine months ended September 30, 2017 and 2016.

Fair Value of Derivative Instruments
	September 30, 2017
Derivatives designated as fair value hedges:	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	$	—	$	—
Natural gas derivatives (1) (2) (3)	Current Liabilities: Non-trading derivative liabilities	5		—
Derivatives not designated as hedging instruments:
Natural gas derivatives (1) (2) (3)	Current Assets: Non-trading derivative assets	65		2
Natural gas derivatives (1) (2) (3)	Other Assets: Non-trading derivative assets	58		2
Natural gas derivatives (1) (2) (3)	Current Liabilities: Non-trading derivative liabilities	27		55
Natural gas derivatives (1) (2) (3)	Other Liabilities: Non-trading derivative liabilities	9		25
Total		$	164	$	84

(1) The fair value shown for natural gas contracts is comprised of derivative gross volumes totaling 1,866 Bcf or a net 46 Bcf long position.  Certain natural gas contracts hedge basis risk only and lack a fixed price exposure.

(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 $93 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, impacted by collateral netting of $13 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
	September 30, 2017
	Gross AmountsRecognized (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	$	97		$	(33	)	$	64
Other Assets: Non-trading derivative assets	67			(11		)	56
Current Liabilities: Non-trading derivative liabilities	(57		)	40			(17		)
Other Liabilities: Non-trading derivative liabilities	(27		)	17			(10		)
Total	$	80		$	13		$	93

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(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, 2016
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	$	79	$	14
Natural gas derivatives (1) (2) (3)	Other Assets: Non-trading derivative assets	24		5
Natural gas derivatives (1) (2) (3)	Current Liabilities: Non-trading derivative liabilities	2		43
Natural gas derivatives (1) (2) (3)	Other Liabilities: Non-trading derivative liabilities	—		5
Total (4)		$	105	$	67

(1) The fair value shown for natural gas contracts is comprised of derivative gross volumes totaling 1,035 Bcf or a net 59 Bcf long position.  Certain natural gas contracts hedge basis risk only and lack a fixed price exposure.

(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 $24 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, impacted by collateral netting of $14 million.

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

(4) No derivatives were designated as fair value hedges as of December 31, 2016.

Offsetting of Natural Gas Derivative Assets and Liabilities
	December 31, 2016
	Gross AmountsRecognized (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	$	81		$	(30	)	$	51
Other Assets: Non-trading derivative assets	24			(5		)	19
Current Liabilities: Non-trading derivative liabilities	(57		)	16			(41		)
Other Liabilities: Non-trading derivative liabilities	(10		)	5			(5		)
Total	$	38		$	(14	)	$	24

(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 physical sales derivative contracts and as natural gas expense for financial natural gas derivatives and physical purchase natural gas derivatives.

Hedge ineffectiveness is recorded as a component of natural gas expense and primarily results from differences in the location of the derivative instrument and the hedged item. Basis ineffectiveness arises from natural gas market price differences between the locations of the hedged inventory and the delivery location specified in the hedge instruments. The impact of natural gas derivatives

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designated as fair value hedges, the related hedged item, and natural gas derivatives not designated as hedging instruments are presented in the table below.

Income Statement Impact of Derivative Activity
		Three Months Ended September 30,
	Income Statement Location	2017			2016
Derivatives designated as fair value hedges:		(in millions)
Natural gas derivatives	Gains (Losses) in Expenses: Natural Gas	$	(4	)	$	—
Fair value adjustments for natural gas inventory designated as the hedged item	Gains (Losses) in Expenses: Natural Gas	4			—
Total increase in Expenses: Natural Gas (1)		$	—		$	—
Derivatives not designated as hedging instruments:
Natural gas derivatives	Gains (Losses) in Revenues	$	30		$	31
Natural gas derivatives	Gains (Losses) in Expenses: Natural Gas	(9		)	(13		)
Total - derivatives not designated as hedging instruments		$	21		$	18

Income Statement Impact of Derivative Activity
		Nine Months Ended September 30,
	Income Statement Location	2017			2016
Derivatives designated as fair value hedges:		(in millions)
Natural gas derivatives	Gains (Losses) in Expenses: Natural Gas	$	8		$	—
Fair value adjustments for natural gas inventory designated as the hedged item	Gains (Losses) in Expenses: Natural Gas	(10		)	—
Total increase in Expenses: Natural Gas (1)		$	(2	)	$	—
Derivatives not designated as hedging instruments:
Natural gas derivatives	Gains (Losses) in Revenues	$	162		$	1
Natural gas derivatives	Gains (Losses) in Expenses: Natural Gas	(91		)	35
Total - derivatives not designated as hedging instruments		$	71		$	36

(1) Hedge ineffectiveness results from the basis ineffectiveness discussed above, and excludes the impact to natural gas expense from timing ineffectiveness.  Timing ineffectiveness arises due to changes in the difference between the spot price and the futures price, as well as the difference between the timing of the settlement of the futures and the valuation of the underlying physical commodity.  As the commodity contract nears the settlement date, spot-to-forward price differences should converge, which should reduce or eliminate the impact of this ineffectiveness on natural gas expense.

(c) Credit Risk Contingent Features

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 September 30, 2017 and December 31, 2016 was $1 million.  CERC posted no assets as collateral toward derivative instruments that contain credit risk contingent features as of either September 30, 2017 or December 31, 2016. If all derivative contracts (in a net liability position) containing credit risk contingent features were triggered as of September 30, 2017 and December 31, 2016, $1 million and $-0-, respectively, of additional assets would be required to be posted as collateral.

(7) 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:

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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, as well as natural gas inventory that has been designated as the hedged item in a fair value hedge.

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 September 30, 2017, CERC’s Level 3 assets and liabilities are comprised of physical natural gas forward contracts and options. Level 3 physical natural gas forward contracts are valued using a discounted cash flow model which includes illiquid forward price curve locations (ranging from $1.08 to $5.83 per MMBtu) 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 87%) as an unobservable input.  CERC’s Level 3 physical natural gas forward contracts and options derivative assets and liabilities consist of both long and short positions (forwards and options) and their fair value is sensitive to forward prices and volatilities.  If forward prices decrease, CERC’s long forwards lose value whereas its short forwards gain in value.  If volatility decreases, CERC’s long options lose value whereas its short options gain in value.

CERC determines the appropriate level for each financial asset and liability on a quarterly basis and recognizes transfers between levels at the end of the reporting period.  For the nine months ended September 30, 2017, there were no transfers between Level 1 and 2. CERC also recognizes purchases of Level 3 financial assets and liabilities at their fair market value at the end of the reporting period.

The following tables present information about CERC’s assets and liabilities (including derivatives that are presented net) measured at fair value on a recurring basis as of September 30, 2017 and December 31, 2016, and indicate the fair value hierarchy of the valuation techniques utilized by CERC to determine such fair value.

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Netting Adjustments (1)			Balance as of September 30, 2017
	(in millions)
Assets
Corporate equities	$	3	$	—	$	—	$	—		$	3
Investments, including money market funds (2)	11		—		—		—			11
Natural gas derivatives (3)	3		128		33		(44		)	120
Hedged portion of natural gas inventory	65		—		—		—			65
Total assets	$	82	$	128	$	33	$	(44	)	$	199
Liabilities
Natural gas derivatives (3)	$	3	$	74	$	7	$	(57	)	$	27
Total liabilities	$	3	$	74	$	7	$	(57	)	$	27

(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 $13 million posted with the same counterparties.

(2) Amounts are included in Other Assets in the Condensed Consolidated Balance Sheets.

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

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	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, 2016
	(in millions)
Assets
Corporate equities	$	3	$	—	$	—	$	—		$	3
Investments, including money market funds (2)	10		—		—		—			10
Natural gas derivatives (3)	11		74		20		(35		)	70
Total assets	$	24	$	74	$	20	$	(35	)	$	83
Liabilities
Natural gas derivatives (3)	$	4	$	56	$	7	$	(21	)	$	46
Total liabilities	$	4	$	56	$	7	$	(21	)	$	46

(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 $14 million held by CES from the same counterparties.

(2) Amounts are included in Other 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 September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(in millions)
Beginning balance	$	28		$	16		$	13		$	12
Purchases (1)	—			—			—			12
Total gains	(2		)	9			21			13
Total settlements	(1		)	(8		)	(5		)	(24		)
Transfers into Level 3	7			—			9			5
Transfers out of Level 3	(6		)	—			(12		)	(1		)
Ending balance (2)	$	26		$	17		$	26		$	17
The amount of total gains for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the reporting date	$	—		$	6		$	17		$	14

(1) Mark-to-market value of Level 3 derivative assets acquired through the purchase of AEM was less than $1 million at the acquisition date.

(2) CERC did not have significant Level 3 sales during either of the three or nine months ended September 30, 2017 or 2016.

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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. The carrying amounts of 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 a combination of historical trading prices and comparable issue data. These 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 2 in the fair value hierarchy.

	September 30, 2017				December 31, 2016
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in millions)
Financial liabilities:
Long-term debt	$	2,636	$	2,854	$	2,375	$	2,551

(8) Unconsolidated Affiliate

CERC Corp. has the ability to significantly influence the operating and financial policies of Enable, a publicly traded MLP, and, accordingly, accounts for its investment in Enable’s common units using the equity method of accounting.

CERC Corp.’s maximum exposure to loss related to Enable, a VIE in which CERC Corp. is not the primary beneficiary, is limited to its equity investment as presented in the Condensed Consolidated Balance Sheets as of September 30, 2017 and outstanding current accounts receivable from Enable.

Transactions with Enable:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
	(in millions)
Reimbursement of transition services (1)	$	—	$	1	$	3	$	6
Natural gas expenses, including transportation and storage costs	23		22		80		79
Interest income related to notes receivable from Enable	—		—		—		1

(1) Represents amounts billed under the Transition Agreements for certain support services provided to Enable. Actual transition services costs are recorded net of reimbursement.

	September 30, 2017		December 31, 2016
	(in millions)
Accounts receivable for amounts billed for transition services	$	1	$	1
Accounts payable for natural gas purchases from Enable	8		10

Limited Partner Interest in Enable:

	September 30, 2017
CERC Corp.	54.1	%
OGE	25.7	%

In November 2016, Enable completed a public offering of 11,500,000 common units of which 1,424,281 were sold by ArcLight Capital Partners, LLC. The common units issued and sold by Enable resulted in dilution of both CERC Corp.’s and OGE’s limited partner interest in Enable.

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Enable Common Units Held:

	September 30, 2017
CERC Corp.	233,856,623
OGE	110,982,805

The 139,704,916 subordinated units previously owned by CERC Corp. converted into common units of Enable on a one-for-one basis on August 30, 2017, at the end of the subordination period, as set forth in Enable’s Fourth Amended and Restated Agreement of Limited Partnership. Upon conversion, holders of common units resulting from the conversion of subordinated units have all the rights and obligations of unitholders holding all other common units, including the right to receive distributions pro rata made with respect to common units.

Generally, sales of more than 5% of the aggregate of the common units CERC Corp. owns in Enable or sales by OGE of more than 5% of the aggregate of the common units it owns in Enable are subject to mutual rights of first offer and first refusal.

Enable is controlled jointly by CERC Corp. and OGE, and each own 50% of the management rights in the general partner of Enable. Sale of CERC Corp.’s or OGE’s ownership interests in Enable’s general partner to a third party is subject to mutual rights of first offer and first refusal, and CERC Corp. is not permitted to dispose of less than all of its interest in Enable’s general partner.

Summarized unaudited consolidated income information for Enable is as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
	(in millions)
Operating revenues	$	705	$	620	$	1,997	$	1,658
Cost of sales, excluding depreciation and amortization	349		268		936		717
Impairment of goodwill and other long-lived assets	—		8		—		8
Operating income	137		139		399		299
Net income attributable to Enable	104		110		301		231
Reconciliation of Equity in Earnings, net:
CERC Corp.’s interest	$	56	$	61	$	163	$	128
Basis difference amortization (1)	12		12		36		36
CERC Corp.’s equity in earnings, net	$	68	$	73	$	199	$	164

(1) Equity in earnings of unconsolidated affiliates includes CERC Corp.’s share of Enable’s earnings adjusted for the amortization of the basis difference of CERC Corp.’s original investment in Enable and its underlying equity in Enable’s net assets. The basis difference is amortized over approximately 33 years, the average life of the assets to which the basis difference is attributed.

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

	September 30, 2017			December 31, 2016
	(in millions)
Current assets	$	446		$	396
Non-current assets	10,816			10,816
Current liabilities	831			362
Non-current liabilities	2,740			3,056
Non-controlling interest	12			12
Preferred equity	362			362
Enable partners’ equity	7,317			7,420
Reconciliation of Equity Method Investment in Enable:
CERC Corp.’s ownership interest in Enable partners’ capital	$	4,007		$	4,067
CERC Corp.’s basis difference	(1,526		)	(1,562		)
CERC Corp.’s equity method investment in Enable	$	2,481		$	2,505

Distributions Received from Unconsolidated Affiliate:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
	(in millions)
Investment in Enable’s common units	$	74	$	74	$	223	$	223

As of September 30, 2017, CERC Corp. and OGE also own 40% and 60%, respectively, of the incentive distribution rights held by the general partner of Enable. Enable is expected to pay a minimum quarterly distribution of $0.2875 per common 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, within 60 days after the end of each quarter. If cash distributions to Enable’s unitholders exceed $0.330625 per common unit in any quarter, the general partner will receive increasing percentages or incentive distributions rights, up to 50%, of the cash Enable distributes in excess of that amount. In certain circumstances the general partner of Enable will have the right to reset the minimum quarterly distribution and the target distribution levels at which the incentive distributions receive increasing percentages to higher levels based on Enable’s cash distributions at the time of the exercise of this reset election. To date, no incentive distributions have been made.

(9) Goodwill

Goodwill by reportable business segment as of December 31, 2016 and changes in the carrying amount of goodwill as of September 30, 2017 are as follows:

	December 31, 2016			AEM Acquisition (1)		September 30, 2017
	(in millions)
Natural Gas Distribution	$	746		$	—	$	746
Energy Services	105		(2)	5		110		(2)
Other Operations	11			—		11
Total	$	862		$	5	$	867

(1) See Note 3.

(2) Amount presented is net of the accumulated goodwill impairment charge of $252 million recorded in 2012.

CERC performs its goodwill impairment tests at least annually and evaluates goodwill when events or changes in circumstances indicate that its carrying value may not be recoverable. The impairment evaluation for goodwill is performed using a two-step process.

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In the first step, the fair value of each reporting unit is compared with the carrying amount of the reporting unit, including goodwill. The estimated fair value of the reporting unit is generally determined on the basis of discounted cash flows. If the estimated fair value of the reporting unit is less than the carrying amount of the reporting unit, then a second step must be completed to determine the amount of the goodwill impairment that should be recorded. In the second step, the implied fair value of the reporting unit’s goodwill is determined by allocating the reporting unit’s fair value to all of its assets and liabilities other than goodwill (including any unrecognized intangible assets) in a manner similar to a purchase price allocation. The resulting implied fair value of the goodwill that results from the application of this second step is then compared to the carrying amount of the goodwill and an impairment charge is recorded for the difference.

CERC performed its annual impairment test in the third quarter of 2017 and determined, based on the results of the first step, that no impairment charge was required for any reportable segment.

(10) 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 September 30, 2017 and December 31, 2016, which would be 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 nine months ended September 30, 2017 or 2016.

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 by CERC for these services were as follows and are included primarily in operation and maintenance expenses:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(in millions)
Corporate service charges	$	30		$	31		$	93		$	90
Charges from Houston Electric for services provided	3			4			11			11
Billings to Houston Electric for services provided	(2		)	(2		)	(5		)	(5		)

See Note 8 for related party transactions with Enable.

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

(a)Short-term Borrowings

Inventory Financing. NGD currently has AMAs associated with its utility distribution service in Arkansas, north Louisiana and Oklahoma that extend through 2020. 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 an inventory financing and had an associated principal obligation of $48 million and $35 million as of September 30, 2017 and December 31, 2016, respectively.

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(b) Long-term Debt

Debt Issuances. During the nine months ended September 30, 2017, CERC issued the following unsecured senior notes:

Issuance Date	Aggregate Principal Amount		Interest Rate	Maturity Date
	(in millions)
August 2017	$	300	4.10%	2047

The proceeds from the issuance of these unsecured senior notes were used for general corporate purposes and to repay a portion of outstanding commercial paper.

Revolving Credit Facility.  In June 2017, CERC entered into an amendment to its revolving credit facility to extend the termination date thereof from March 3, 2021 to March 3, 2022 and to terminate the swingline loan subfacility thereunder. The amendment also increased the aggregate commitments by $300 million to $900 million under its revolving credit facility. In connection with the amendment to increase the aggregate commitments under its revolving credit facility, CERC increased the size of its commercial paper program to permit the issuance of commercial paper notes in an aggregate principal amount not to exceed $900 million at any time outstanding.

As of September 30, 2017 and December 31, 2016, CERC had the following revolving credit facility and utilization of such facility:

September 30, 2017									December 31, 2016
Size of Facility		Loans		Letters of Credit		Commercial Paper			Size of Facility		Loans		Letters of Credit		Commercial Paper
(in millions)
$	900	$	—	$	—	$	529	(1)	$	600	$	—	$	4	$	569	(1)

(1) Weighted average interest rate was approximately 1.43% and 1.03% as of September 30, 2017 and December 31, 2016, respectively.

Execution Date	Size of Facility			Draw Rate of LIBOR plus (2)		Financial Covenant Limit on Debt for Borrowed Money to Capital Ratio		Debt for Borrowed Money to Capital Ratio as of September 30, 2017	Termination Date (3)
	(in millions)
March 3, 2016	$	900	(1)	1.25	%	65	%	38.6%	March 3, 2022

(1) Amended on June 16, 2017 to increase the aggregate commitment size as noted above.

(2) Based on current credit ratings.

(3) Amended on June 16, 2017 to extend the termination date as noted above.

CERC Corp. was in compliance with all financial debt covenants as of September 30, 2017.

(12) Commitments and Contingencies

(a) Natural Gas Supply Commitments

Natural gas supply commitments include natural gas contracts related to CERC’s Natural Gas Distribution and Energy Services business segments, which have various quantity requirements and durations, that are not classified as non-trading derivative assets and liabilities in CERC’s Condensed Consolidated Balance Sheets as of September 30, 2017 and December 31, 2016 as these contracts meet an exception as “normal purchases contracts” or do not meet the definition of a derivative. Natural gas supply commitments

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also include natural gas transportation contracts that do not meet the definition of a derivative. As of September 30, 2017, minimum payment obligations for natural gas supply commitments are approximately:

	(in millions)
Remaining three months of 2017	$	169
2018	507
2019	348
2020	166
2021	76
2022 and beyond	113

(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.

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. The plaintiffs have appealed that ruling. CenterPoint Energy and CES intend to continue vigorously defending against the plaintiffs’ claims. In June 2017, GenOn and various affiliates filed for protection under Chapter 11 of the U.S. Bankruptcy Code. CenterPoint Energy, CERC, and CES submitted proofs of claim in the bankruptcy proceedings to protect their indemnity rights. If GenOn were unable to meet its indemnity obligations or satisfy a liability that has been assumed in the gas market manipulation litigation, then CERC, CenterPoint Energy or Houston Electric could incur liability and be responsible for satisfying the liability. CERC does not expect the ultimate outcome of the case against CES to have a material adverse effect on its financial condition, results of operations or cash flows.

Minnehaha Academy.  On August 2, 2017, a natural gas explosion occurred at the Minnehaha Academy in Minneapolis, Minnesota, resulting in the deaths of two school employees, serious injuries to others and significant property damage to the school.  CenterPoint Energy, certain of its subsidiaries, including CERC Corp., and the contractor company working in the school have been named in litigation arising out of this incident.  Additionally, CenterPoint Energy is cooperating with ongoing investigations conducted by the National Transportation Safety Board, the Minnesota Occupational Safety and Health Administration and the Minnesota Office of Pipeline Safety.  CenterPoint Energy’s general and excess liability insurance policies provide coverage for third party bodily injury and property damage claims. 

Environmental Matters

MGP 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 September 30, 2017, 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. 

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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.

(13) Income Taxes

The effective tax rate reported for the three months ended September 30, 2017 was 40% compared to 38% for the same period in 2016. The effective tax rate reported for the nine months ended September 30, 2017 was 38% compared to 40% for the same period in 2016. The higher effective tax rate for the nine months ended September 30, 2016 was 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 September 30, 2017 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 2015. For the 2016 and 2017 tax years, CenterPoint Energy is a participant in the IRS’s Compliance Assurance Process.

(14) Reportable Business Segments

CERC’s determination of reportable business segments considers the strategic operating units under which it 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 other than Midstream Investments, where it uses equity in earnings of unconsolidated affiliates.

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 equity investment in Enable. The Other Operations business segment includes unallocated corporate costs and inter-segment eliminations.

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Financial data for business segments is as follows:

	For the Three Months Ended September 30, 2017
	Revenues from External Customers		Inter-segment Revenues			Operating Income
	(in millions)
Natural Gas Distribution	$	390	$	8		$	19
Energy Services	861		10			7
Midstream Investments (1)	—		—			—
Other Operations	—		—			—
Reconciling Eliminations	—		(18		)	—
Consolidated	$	1,251	$	—		$	26

	For the Three Months Ended September 30, 2016
	Revenues from External Customers		Inter-segment Revenues			Operating Income (Loss)
	(in millions)
Natural Gas Distribution	$	370	$	7		$	22
Energy Services	608		6			5
Midstream Investments (1)	—		—			—
Other Operations	—		—			(1		)
Reconciling Eliminations	—		(13		)	—
Consolidated	$	978	$	—		$	26

	For the Nine Months Ended September 30, 2017
	Revenues from External Customers		Inter-segment Revenues			Operating Income (Loss)			Total Assets as of September 30, 2017
	(in millions)
Natural Gas Distribution	$	1,767	$	24		$	220		$	6,067
Energy Services	2,964		34			58			1,337
Midstream Investments (1)	—		—			—			2,481
Other Operations	—		—			(5		)	73
Reconciling Eliminations	—		(58		)	—			(582		)
Consolidated	$	4,731	$	—		$	273		$	9,376

	For the Nine Months Ended September 30, 2016
	Revenues from External Customers		Inter-segment Revenues			Operating Income (Loss)			Total Assets as of December 31, 2016
	(in millions)
Natural Gas Distribution	$	1,672	$	21		$	202		$	6,099
Energy Services	1,433		17			11			1,102
Midstream Investments (1)	—		—			—			2,505
Other Operations	—		—			(3		)	75
Reconciling Eliminations	—		(38		)	—			(563		)
Consolidated	$	3,105	$	—		$	210		$	9,218

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
	(in millions)
Enable	$	68	$	73	$	199	$	164

(15) Other Current Assets and Liabilities

Included in other current assets on the Condensed Consolidated Balance Sheets as of September 30, 2017 and December 31, 2016 were $22 million and less than $1 million, respectively, of margin deposits and $55 million and $40 million, respectively, of under-recovered gas cost. Included in other current liabilities on the Condensed Consolidated Balance Sheets at September 30, 2017 and December 31, 2016 were $2 million and $10 million, respectively, of over-recovered gas cost.

(16) Subsequent Events

On October 31, 2017, Enable declared a quarterly cash distribution of $0.318 per unit on all of its outstanding common units for the quarter ended September 30, 2017. Accordingly, CERC Corp. expects to receive a cash distribution of approximately $74 million from Enable in the fourth quarter of 2017 to be made with respect to CERC Corp.’s investment in common units of Enable for the third quarter of 2017.

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 2016 Form 10-K.

We meet the conditions specified in General Instruction H(1)(a) and (b) to Form 10-Q and are therefore permitted to use the reduced disclosure format for wholly-owned subsidiaries of reporting companies. Accordingly, we have omitted from this report the information called for by Item 2 (Management’s Discussion and Analysis of Financial Condition and Results of Operations) and Item 3 (Quantitative and Qualitative Disclosures About Market Risk) of Part I and the following Part II items of Form 10-Q: Item 2 (Unregistered Sales of Equity Securities and Use of Proceeds), Item 3 (Defaults Upon Senior Securities) and Item 4 (Submission of Matters to a Vote of Security Holders). The following discussion explains material changes in our revenue and expense items between the three and nine months ended September 30, 2017 and the three and nine months ended September 30, 2016. Reference is made to “Management’s Narrative Analysis of Results of Operations” in Item 7 of our 2016 Form 10-K.

RECENT EVENTS

Hurricane Harvey. NGD suffered damage as a result of Hurricane Harvey, which struck the Texas coast on Friday, August 25, 2017. For further information regarding the impact of Hurricane Harvey, see Note 5 to our Interim Condensed Financial Statements.

Regulatory Proceedings. For details related to our pending and completed regulatory proceedings to date in 2017, see “—Liquidity and Capital Resources —Regulatory Matters” below.

Debt Issuances. In August 2017, we issued $300 million aggregate principal amount of unsecured senior notes. For further information about our 2017 debt issuances, see Note 11 to our Interim Condensed Financial Statements.

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 2016 Form 10-K.

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The following table sets forth our consolidated results of operations for the three and nine months ended September 30, 2017 and 2016, followed by a discussion of our consolidated results of operations.

	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(in millions)
Revenues	$	1,251		$	978		$	4,731		$	3,105
Expenses:
Natural gas	938			683			3,549			2,031
Operation and maintenance	187			175			603			571
Depreciation and amortization	68			62			202			185
Taxes other than income taxes	32			32			104			108
Total	1,225			952			4,458			2,895
Operating Income	26			26			273			210
Interest and other finance charges	(32		)	(29		)	(92		)	(93		)
Equity in earnings of unconsolidated affiliate, net	68			73			199			164
Other income, net	1			(1		)	3			1
Income Before Income Taxes	63			69			383			282
Income tax expense	25			26			144			113
Net Income	$	38		$	43		$	239		$	169

Three months ended September 30, 2017 compared to three months ended September 30, 2016

We reported net income of $38 million for the three months ended September 30, 2017 compared to net income of $43 million for the three months ended September 30, 2016.  

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

• a $5 million decrease in equity earnings from our investment in Enable, discussed further in Note 8 to our Interim Condensed Financial Statements; and

• a $3 million increase in interest expense due to the issuance of $300 million of unsecured senior notes and higher weighted average commercial paper interest rates discussed further in Note 11 to our Interim Condensed Financial Statements.

These decreases in net income were partially offset by a $2 million increase in miscellaneous other non-operating income included in Other income, net shown above, and a $1 million decrease in income tax expense due to lower net income.

Nine months ended September 30, 2017 compared to nine months ended September 30, 2016

We reported net income of $239 million for the nine months ended September 30, 2017 compared to net income of $169 million for the nine months ended September 30, 2016.  

The increase in net income of $70 million was primarily due to the following key factors:

• a $63 million increase in operating income, discussed below by segment; and

• a $35 million increase in equity earnings from our investment in Enable, discussed further in Note 8 to our Interim Condensed Financial Statements.

These increases in net income were partially offset by a $31 million increase in income tax expense due to higher net income.

Income Tax Expense

Our effective tax rates reported for the three months ended September 30, 2017 was 40% compared to 38% for the same period in 2016. The effective tax rate reported for the nine months ended September 30, 2017 was 38% compared to 40% for the same

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period in 2016. The higher effective tax rate for the nine months ended September 30, 2016 was due to a Louisiana state tax law change resulting in an increase to CERC’s 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 nine months ended September 30, 2017 and 2016, followed by a discussion of the results of operations by business segment based on operating income. Included in revenues are intersegment sales.  We account for intersegment sales as if the sales were to third parties at current market prices.

	Three Months Ended September 30,					Nine Months Ended September 30,
	2017		2016			2017			2016
	(in millions)
Natural Gas Distribution	$	19	$	22		$	220		$	202
Energy Services	7		5			58			11
Other Operations	—		(1		)	(5		)	(3		)
Total Consolidated Operating Income	$	26	$	26		$	273		$	210

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 2016 Form 10-K.

The following table provides summary data of our Natural Gas Distribution business segment for the three and nine months ended September 30, 2017 and 2016:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
	(in millions, except throughput and customer data)
Revenues	$	398	$	377	$	1,791	$	1,693
Expenses:
Natural gas	117		104		742		679
Operation and maintenance	163		159		531		526
Depreciation and amortization	66		61		194		180
Taxes other than income taxes	33		31		104		106
Total expenses	379		355		1,571		1,491
Operating Income	$	19	$	22	$	220	$	202
Throughput (in Bcf):
Residential	13		12		94		105
Commercial and industrial	50		51		189		193
Total Throughput	63		63		283		298
Number of customers at end of period:
Residential	3,179,284		3,143,357		3,179,284		3,143,357
Commercial and industrial	253,041		251,043		253,041		251,043
Total	3,432,325		3,394,400		3,432,325		3,394,400

Three months ended September 30, 2017 compared to three months ended September 30, 2016

Our Natural Gas Distribution business segment reported operating income of $19 million for the three months ended September 30, 2017 compared to $22 million for the three months ended September 30, 2016.

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Operating income decreased $3 million as a result of the following key factors:

• increased depreciation and amortization expense, primarily due to ongoing additions to plant-in-service, and other taxes of $6 million;

• lower usage of $4 million, primarily due to the timing of a decoupling normalization adjustment; and

• higher operation and maintenance expenses of $3 million.

These decreases were partially offset by the following:

• rate relief increased $5 million, primarily from Texas jurisdictions of $2 million, Arkansas rate case filing of $1 million and Mississippi RRA of $1 million; and

• customer growth of $2 million associated with the addition of approximately 38,000 new customers.

Increased operation and maintenance expenses related to energy efficiency programs of $1 million were offset by corresponding increases in the related revenues.

Nine months ended September 30, 2017 compared to nine months ended September 30, 2016

Our Natural Gas Distribution business segment reported operating income of $220 million for the nine months ended September 30, 2017 compared to $202 million for the nine months ended September 30, 2016.

Operating income increased $18 million as a result of the following key factors:

• rate increases of $25 million, primarily from Texas jurisdictions of $12 million, Arkansas rate case filing of $10 million and Mississippi RRA of $3 million;

• labor and benefits were favorable by $11 million resulting primarily from the recording of a regulatory asset (and a corresponding reduction in expense) to recover $16 million of prior postretirement expenses in future rates established in the Texas Gulf rate order; and

• customer growth of $3 million associated with the addition of approximately 38,000 new customers.

These increases were partially offset by the following:

• increased depreciation and amortization expense, primarily due to ongoing additions to plant-in-service, and other taxes of $10 million;

• higher operation and maintenance expenses of $9 million partially resulting from an adjustment associated with the Texas Gulf rate order of $4 million, which is timing related; and

• lower usage of $7 million primarily due to milder weather effects, partially mitigated by decoupling and weather normalization adjustments.

Increased operation and maintenance expenses related to energy efficiency programs of $7 million and increased gross receipts taxes of $2 million were offset by corresponding increases in the related revenues.

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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 2016 Form 10-K.

The following table provides summary data of our Energy Services business segment for the three and nine months ended September 30, 2017 and 2016:

	Three Months Ended September 30,					Nine Months Ended September 30,
	2017		2016			2017		2016
	(in millions, except throughput and customer data)
Revenues	$	871	$	614		$	2,998	$	1,450
Expenses:
Natural gas	839		591			2,865		1,389
Operation and maintenance	22		16			65		43
Depreciation and amortization	3		1			9		5
Taxes other than income taxes	—		1			1		2
Total expenses	864		609			2,940		1,439
Operating Income	$	7	$	5		$	58	$	11
Timing impacts related to mark-to-market gain (loss) (1)	$	2	$	(2	)	$	23	$	(18	)
Throughput (in Bcf)	272		200			864		570
Number of customers at end of period (2)	30,817		31,669			30,817		31,669

(1) Includes the change in unrealized mark-to-market value and the impact from derivative assets and liabilities acquired through the purchase of Continuum and AEM.

(2) Does not include approximately 66,100 natural gas customers as of September 30, 2017 that are under residential and small commercial choice programs invoiced by their host utility.

Three months ended September 30, 2017 compared to three months ended September 30, 2016

Our Energy Services business segment reported operating income of $7 million for the three months ended September 30, 2017 compared to $5 million for the three months ended September 30, 2016.  The increase in operating income of $2 million was primarily due to a $4 million increase from mark-to-market accounting for derivatives associated with certain natural gas purchases and sales used to lock in economic margins. Operating income for the three months ended September 30, 2017 also included $2 million of expenses related to the acquisition and integration of AEM.

Nine months ended September 30, 2017 compared to nine months ended September 30, 2016

Our Energy Services business segment reported operating income of $58 million for the nine months ended September 30, 2017 compared to $11 million for the nine months ended September 30, 2016.  The increase in operating income of $47 million was primarily due to a $41 million increase from mark-to-market accounting for derivatives associated with certain natural gas purchases and sales used to lock in economic margins. Operating income in the first nine months of 2017 also included $3 million of expenses related to the acquisition and integration of AEM. The remaining increase in operating income was primarily due to the increased throughput related to the acquisition of AEM in 2017.

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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 2016 Form 10-K.

The following table provides pre-tax equity income of our Midstream Investments business segment for the three and nine months ended September 30, 2017 and 2016:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
	(in millions)
Enable	$	68	$	73	$	199	$	164

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 2016 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 2016 Form 10-K and “Cautionary Statement Regarding Forward-Looking Information” in this Form 10-Q.

LIQUIDITY AND CAPITAL RESOURCES

Our liquidity and capital requirements are affected primarily by our results of operations, capital expenditures, debt service requirements, tax payments, working capital needs and various regulatory actions. Our capital expenditures are expected to be used for investment in infrastructure for our natural gas distribution operations. These capital expenditures are anticipated to maintain reliability and safety as well as expand our systems through value-added projects. Our principal anticipated cash requirements for the remaining three months of 2017 include approximately $153 million of capital expenditures, $250 million of maturing senior notes and restoration costs related to Hurricane Harvey.

We expect that borrowings under our credit facility, proceeds from commercial paper, anticipated cash flows from operations, intercompany borrowings and distributions on our investment in common units from Enable will be sufficient to meet our anticipated cash needs for the remaining three months of 2017. 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

Other than operating leases, we have no off-balance sheet arrangements.

Regulatory Matters

PHMSA Matters

On December 14, 2016, PHMSA announced an interim final rule to impose industry-developed recommendations as enforceable safety standards for downhole (underground) equipment, including wells, wellbore tubing, and casing, at both interstate and intrastate underground natural gas storage facilities. Both CERC and Enable own and operate underground storage facilities that are subject to this rule’s provisions, which include procedures and practices for operations, maintenance, threat identification, monitoring, assessment, site security, emergency response and preparedness, training and recordkeeping. This rule went into effect on January 18, 2017, with an announced compliance deadline of January 18, 2018. PHMSA determined, however, that it will not issue enforcement citations to any operators for violations of provisions of the interim final rule that had previously been non-mandatory provisions of American Petroleum Institute Recommended Practices 1170 and 1171 until one year after PHMSA issues a final rule, which it expects to publish in January of 2018. On October 19, 2017, PHMSA formally reopened the comment period on the interim final rule in response to a petition for reconsideration. This matter remains ongoing and subject to future PHMSA determinations. CERC and Enable will continue to monitor developments and assess the potential impact of any modifications to this rule.

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Rate Change Applications

We are routinely involved in rate change applications before state regulatory authorities.  Those applications include general rate cases where the entire cost of service of the utility is assessed and reset. We are periodically involved in proceedings to adjust our capital tracking mechanisms in Texas (GRIP), our cost of service adjustments in Arkansas, Louisiana, Mississippi, and Oklahoma (FRP, RSP, RRA and PBRC), our decoupling mechanism in Minnesota, and our energy efficiency cost trackers in Arkansas, Minnesota, Mississippi and Oklahoma (EECR, CIP, EECR and EECR). The table below reflects significant applications pending or completed since our 2016 Form 10-K was filed with the SEC.

Mechanism	Annual Increase (1) (in millions)	Filing  Date	Effective Date	Approval Date	Additional Information
South Texas and Beaumont/East Texas (Railroad Commission)
GRIP	$7.6	March 2017	July 2017	June 2017	Based on net change in invested capital of $46.5 million.
Houston and Texas Coast (Railroad Commission)
Rate Case	16.5	November 2016	May 2017	May 2017	The Railroad Commission approved a unanimous settlement agreement establishing parameters for future GRIP filings, including a 9.6% ROE on a 55.15% equity ratio.
Texarkana, Texas Service Area (Multiple City Jurisdictions)
Rate Case	1.1	July 2017	September 2017	August 2017	Approved rates are consistent with Arkansas rates approved in 2016.
Arkansas (APSC)
EECR (2)	0.5	May 2017	January 2018	September 2017	Recovers $11.0 million, including an incentive of $0.5 million based on 2016 program performance.
FRP	7.6	April 2017	October 2017	September 2017	Based on ROE of 9.5% as approved in the last rate case. Unanimous Settlement Agreement was filed in July 2017 for $7.6 million and was subsequently approved.
BDA	3.9	March 2017	June 2017	June 2017	For the evaluation period between January 2016 and August 2016. Amounts are recorded during the evaluation period.
Minnesota (MPUC)
Rate Case	56.5	August 2017	TBD	TBD	Reflects a proposed 10.0% ROE on a 52.18% equity ratio. Includes a proposal to extend decoupling beyond current expiration date of June 2018. Interim rates reflecting an annual increase of $47.8 million were effective October 1, 2017.
CIP (2)	13.8	May 2017	August 2017	August 2017	Annual reconciliation filing for program year 2016 and includes performance bonus of $13.8 million.
Decoupling	20.4	September 2017	September 2017	TBD	Reflects revenue under recovery for the period July 1, 2016 through June 30, 2017 and $3.0 million related to the under recovery of prior period adjustment factor. $9.2 million was recognized in 2016 and $11.2 million has been recognized in 2017.
Mississippi (MPSC)
RRA	2.3	May 2017	July 2017	July 2017	Authorized ROE of 9.59% and a capital structure of 50% debt and 50% equity.
Louisiana (LPSC)
RSP	1.0	September 2016	December 2016	April 2017	Authorized ROE of 9.95% and a capital structure of 48% debt and 52% equity.
RSP	3.4	September 2017	December 2017	TBD	Authorized ROE of 9.95% and a capital structure of 48% debt and 52% equity.
Oklahoma (OCC)
EECR (2)	0.4	March 2017	November 2017	October 2017	Recovers $2.6 million, including an incentive of $0.4 million based on 2016 program performance.
PBRC	2.2	March 2017	November 2017	October 2017	Based on ROE of 10%.

(1) Represents proposed increases when effective date and/or approval date is not yet determined. Approved rates could differ materially from proposed rates.

(2) Amounts are recorded when approved.

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Other Matters

Credit Facility

Our revolving credit facility may be drawn on from time to time to provide funds used for general corporate purposes, including to backstop our commercial paper program. The facilities may also be utilized to obtain letters of credit. For further details related to our revolving credit facility and the 2017 amendment, please see Note 11 to our Interim Condensed Financial Statements.

As of October 26, 2017, we had the following revolving credit facility and utilization of such facility:

Execution Date	Size of Facility		Amount Utilized at October 26, 2017			Termination Date
(in millions)
March 3, 2016	$	900	$	561	(1)	March 3, 2022

(1) Represents outstanding commercial paper.

Borrowings under our 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 our revolving credit facility are subject to acceleration upon the occurrence of events of default that we consider customary. The revolving credit facility also provides for customary fees, including commitment fees, administrative agent fees, fees in respect of letters of credit and other fees. In our revolving credit facility, 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.

Debt Financing Transactions

In August 2017, we issued $300 million aggregate principal amount of unsecured senior notes. For further information about our 2017 debt transactions, see Note 11 to our Interim Condensed Financial Statements.

Securities Registered with the SEC

On January 31, 2017, we filed a shelf registration statement with the SEC registering an indeterminate principal amount of our senior debt securities. The shelf registration statement will expire on January 31, 2020.

Temporary Investments

As of October 26, 2017, 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. As of October 26, 2017, 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. On August 4, 2017, S&P revised its rating outlook on our senior debt to positive from developing and affirmed its rating. On September 24, 2017, Fitch revised its rating outlook on our senior debt to positive from stable and affirmed its rating.

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As of October 26, 2017, 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-	Positive	BBB	Positive

(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 could increase borrowing costs under our revolving credit facility. If our credit ratings had been downgraded one notch by each of the three principal credit rating agencies from the ratings that existed as of September 30, 2017, 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.

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 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 or settled-to-market by CES. As of September 30, 2017, the amounts posted as collateral and settled-to-market aggregated approximately $35 million. Should the credit ratings of CERC Corp. (as the credit support provider for CES) fall below certain levels, CES would be required to provide additional collateral up to the amount of its previously unsecured credit limit. We estimate that as of September 30, 2017, unsecured credit limits extended to CES by counterparties aggregated $358 million, and $1 million of such amount was utilized.

Pipeline tariffs and contracts typically provide that if the credit ratings of a shipper or the shipper’s guarantor drop below a threshold level, which is generally investment grade ratings from both Moody’s and S&P, cash or other collateral may be demanded from the shipper in an amount equal to the sum of three months’ charges for pipeline services plus the unrecouped cost of any lateral built for such shipper. If the credit ratings of CERC Corp. decline below the applicable threshold levels, CERC Corp. might need to provide cash or other collateral of as much as $197 million as of September 30, 2017. 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

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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.

In February 2016, CenterPoint Energy announced that it was evaluating strategic alternatives for our investment in Enable, including a sale or spin-off qualifying under Section 355 of the U.S. Internal Revenue Code. CenterPoint Energy has determined that it will no longer pursue the spin option. Should the sale option not be viable, we intend to reduce our ownership in Enable over time through a sale of the common units we hold in the public equity markets, subject to market conditions. There can be no assurances that these evaluations will result in any specific action, and we do not intend to disclose further developments on these initiatives unless and until CenterPoint Energy’s board of directors approves a specific action or as otherwise required.

Enable Midstream Partners

We receive quarterly cash distributions from Enable on its common units we own. A reduction in the cash distributions we receive from Enable could significantly impact our liquidity. For additional information about cash distributions from Enable, see Notes 8 and 16 to our Interim Condensed Financial Statements.

Weather Hedge

We have entered into partial weather hedges for certain NGD jurisdictions to mitigate the impact of fluctuations from normal weather. We remain exposed to some weather risk as a result of the partial hedges. For more information about our weather hedges, see Note 6(a) to our Interim Condensed Financial Statements.

Hedging of Interest Expense for Future Debt Issuances

During August 2017, we entered into forward interest rate agreements to hedge, in part, volatility in the U.S. treasury rates by reducing variability in cash flows related to interest payments. For further information, see Note 6(a) to our Interim Condensed Financial Statements.

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 our credit facility;

• 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, currently the subject of bankruptcy proceedings, to satisfy their obligations in respect of GenOn’s indemnity obligations to CenterPoint Energy and its subsidiaries;

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

• the outcome of litigation brought by or 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

33

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

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

For information about the total debt to capitalization financial covenants in our revolving credit facility, see Note 11 to our Interim Condensed Financial Statements.

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, incorporated herein by reference, for a discussion of new accounting pronouncements that affect us.

Item 4. CONTROLS AND PROCEDURES

In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our principal executive officer and principal financial officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report.  Based on that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of September 30, 2017 to provide assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding disclosure.

There has been no change in our internal controls over financial reporting that occurred during the three months ended September 30, 2017 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 12(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 2016 Form 10-K.

Item 1A. RISK FACTORS

There have been no material changes from the risk factors disclosed in our 2016 Form 10-K.

Item 5.OTHER INFORMATION

Ratio of Earnings to Fixed Charges. The ratio of earnings to fixed charges for the nine months ended September 30, 2017 and 2016 was 5.27 and 4.51, respectively. We do not believe that the ratios for these nine-month periods are necessarily indicative of the ratios for the 12-month periods due to the seasonal nature of our business. The ratios were calculated pursuant to applicable rules of the SEC.

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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
4.2	First Amendment to Credit Agreement, dated as of June 16, 2017, among CERC Corp., as Borrower, and the banks named therein	Form 8-K dated June 16, 2017	1-13265	4.3
4.3	Indenture, dated as of February 1, 1998, between Reliant Energy Resources Corp. and Chase Bank of Texas, National Association, as Trustee	Form 8-K dated February 5, 1998	1-13265	4.1
+4.4	Supplemental Indenture No. 16 to Exhibit 4.3, dated as of August 23, 2017, providing for the issuance of CERC Corp.’s 4.10% Senior Notes due 2047
+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

35

SIGNATURES

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

	CENTERPOINT ENERGY RESOURCES CORP.
By:	/s/ Kristie L. Colvin
	Kristie L. Colvin
	Senior Vice President and Chief Accounting Officer

Date: November 3, 2017

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EX-4.4

Exhibit 4.4

CENTERPOINT ENERGY RESOURCES CORP.

(formerly known as NorAm Energy Corp.)

To

THE BANK OF NEW YORK MELLON TRUST COMPANY, NATIONAL ASSOCIATION

(successor to JPMorgan Chase Bank, National Association (formerly Chase Bank of Texas, National Association))

Trustee

__________________

SUPPLEMENTAL INDENTURE NO. 16

Dated as of August 23, 2017

_________________

$300,000,000

4.10% Senior Notes due 2047

CENTERPOINT ENERGY RESOURCES CORP.

SUPPLEMENTAL INDENTURE NO. 16

4.10% Senior Notes due 2047

SUPPLEMENTAL INDENTURE No. 16, dated as of August 23, 2017, between CENTERPOINT ENERGY RESOURCES CORP., a Delaware corporation formerly known as NorAm Energy Corp. (the “Company”), and THE BANK OF NEW YORK MELLON TRUST COMPANY, NATIONAL ASSOCIATION (successor to JPMorgan Chase Bank, National Association (formerly Chase Bank of Texas, National Association)), as Trustee (the “Trustee”).

RECITALS

The Company has heretofore executed and delivered to the Trustee an Indenture, dated as of February 1, 1998 (the “Original Indenture” and, as previously and hereby supplemented and amended, the “Indenture”), providing for the issuance from time to time of one or more series of the Company’s Securities.

     The Company has changed its name from “NorAm Energy Corp.” to “CenterPoint Energy Resources Corp.” and all references in the Indenture to the “Company” or “NorAm Energy Corp.” shall be deemed to refer to CenterPoint Energy Resources Corp.

Pursuant to the terms of the Indenture, the Company desires to provide for the establishment of a new series of Securities to be designated as the “4.10% Senior Notes due 2047” (the “Notes”), the form and substance of such Notes and the terms, provisions and conditions thereof to be set forth as provided in the Original Indenture and this Supplemental Indenture No. 16.

Section 301 of the Original Indenture provides that various matters with respect to any series of Securities issued under the Indenture may be established in an indenture supplemental to the Indenture.

Subparagraph (7) of Section 901 of the Original Indenture provides that the Company and the Trustee may enter into an indenture supplemental to the Indenture to establish the form or terms of Securities of any series as permitted by Sections 201 and 301 of the Original Indenture.

For and in consideration of the premises and the issuance of the series of Securities provided for herein, it is mutually covenanted and agreed, for the equal and proportionate benefit of the Holders of the Securities of such series, as follows:

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ARTICLE ONE

Relation to Indenture; Additional Definitions

Section 101    Relation to Indenture.  This Supplemental Indenture No. 16 constitutes an integral part of the Original Indenture.

Section 102    Additional Definitions.   For all purposes of this Supplemental Indenture No. 16:

Capitalized terms used herein shall have the meaning specified herein or in the Original Indenture, as the case may be;

“Business Day” means, with respect to any Note, any day other than a Saturday, a Sunday or a day on which banking institutions in The City of New York are authorized or required by law, regulation or executive order to close.  If any Interest Payment Date, Stated Maturity or Redemption Date of a Note falls on a day that is not a Business Day, the required payment will be made on the next succeeding Business Day with the same force and effect as if made on the relevant date that the payment was due and no interest will accrue on such payment for the period from and after the Interest Payment Date, Stated Maturity or Redemption Date, as the case may be, to the date of that payment on the next succeeding Business Day.  The definition of “Business Day” in this Supplemental Indenture No. 16 and the provisions described in the preceding sentence shall supersede the definition of Business Day in the Original Indenture and Section 113 of the Original Indenture;

“Capital Lease” means a lease that, in accordance with accounting principles generally accepted in the United States of America, would be recorded as a capital lease on the balance sheet of the lessee;

“Comparable Treasury Issue” has the meaning set forth in Section 402 hereof;

“Comparable Treasury Price” has the meaning set forth in Section 402 hereof;

“Consolidated Net Tangible Assets” means the total amount of assets of the Company, including the assets of its Subsidiaries, less, without duplication: (a) total current liabilities (excluding indebtedness due within 12 months); (b) all reserves for depreciation and other asset valuation reserves, but excluding reserves for deferred federal income taxes; (c) all intangible assets such as goodwill, trademarks, trade names, patents and unamortized debt discount and expense carried as an asset; and (d) all appropriate adjustments on account of minority interests of other Persons holding common stock of any Subsidiary, all as reflected in the Company’s most recent audited consolidated balance sheet preceding the date of such determination;

“Corporate Trust Office” means the principal office of the Trustee at which at any particular time its corporate trust business shall be administered, which office as of the

2

date hereof is located at: 601 Travis Street, 16th Floor, Houston, Texas 77002, Attention: Global Corporate Trust; telephone: (713) 483-6817; telecopy: (713) 483-7038;

“Equity Interests” means any capital stock, partnership, joint venture, member or limited liability or unlimited liability company interest, beneficial interest in a trust or similar entity or other equity interest or investment of whatever nature;

The term “indebtedness” as applied to the Company or any Subsidiary, means bonds, debentures, notes and other instruments or arrangements representing obligations created or assumed by the Company or any such Subsidiary, including any and all: (i) obligations for money borrowed (other than unamortized debt discount or premium); (ii) obligations evidenced by a note or similar instrument given in connection with the acquisition of any business, properties or assets of any kind; (iii) obligations as lessee under a Capital Lease; and (iv) amendments, renewals, extensions, modifications and refundings of any such indebtedness or obligation listed in clause (i), (ii) or (iii) above. All indebtedness secured by a lien upon property owned by the Company or any Subsidiary and upon which indebtedness the Company or any such Subsidiary customarily pays interest, although the Company or any such Subsidiary has not assumed or become liable for the payment of such indebtedness, shall for all purposes hereof be deemed to be indebtedness of the Company or any such Subsidiary. All indebtedness for borrowed money incurred by other Persons which is directly guaranteed as to payment of principal by the Company or any Subsidiary shall for all purposes hereof be deemed to be indebtedness of the Company or any such Subsidiary, as applicable, but no other contingent obligation of the Company or any such Subsidiary in respect of indebtedness incurred by other Persons shall for any purpose be deemed to be indebtedness of the Company or any such Subsidiary;

“Independent Investment Banker” has the meaning set forth in Section 402 hereof;

“Interest Payment Date” has the meaning set forth in Section 204(a) hereof;

“Issue Date” has the meaning set forth in Section 204(a) hereof;

 “lien” or “liens” means any mortgage, deed of trust, pledge, hypothecation, assignment, deposit arrangement, charge, security interest, encumbrance or lien of any kind whatsoever (including any Capital Lease);

“Maturity Date” has the meaning set forth in Section 203 hereof;

“Non-Recourse Debt” means (i) any indebtedness for borrowed money incurred by any Project Finance Subsidiary to finance the acquisition, improvement, installation, design, engineering, construction, development, completion, maintenance or operation of, or otherwise to pay costs and expenses relating to or providing financing for, any project, which indebtedness for borrowed money does not provide for recourse against the Company or any Subsidiary of the Company (other than a Project Finance Subsidiary and

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such recourse as exists under a Performance Guaranty) or any property or asset of the Company or any Subsidiary of the Company (other than Equity Interests in, or the property or assets of, a Project Finance Subsidiary and such recourse as exists under a Performance Guaranty) and (ii) any refinancing of such indebtedness for borrowed money that does not increase the outstanding principal amount thereof (other than to pay costs incurred in connection therewith and the capitalization of any interest or fees) at the time of the refinancing or increase the property subject to any lien securing such indebtedness for borrowed money or otherwise add additional security or support for such indebtedness for borrowed money;

“Notes” has the meaning set forth in the third paragraph of the Recitals hereof;

“Original Indenture” has the meaning set forth in the first paragraph of the Recitals hereof;

“Par Call Date” has the meaning set forth in Section 401 hereof;

“Performance Guaranty” means any guaranty issued in connection with any Non-Recourse Debt that (i) if secured, is secured only by assets of or Equity Interests in a Project Finance Subsidiary, and (ii) guarantees to the provider of such Non-Recourse Debt or any other person (a) performance of the improvement, installation, design, engineering, construction, acquisition, development, completion, maintenance or operation of, or otherwise affects any such act in respect of, all or any portion of the project that is financed by such Non-Recourse Debt, (b) completion of the minimum agreed equity or other contributions or support to the relevant Project Finance Subsidiary, or (c) performance by a Project Finance Subsidiary of obligations to persons other than the provider of such Non-Recourse Debt;

“Project Finance Subsidiary” means any Subsidiary designated by the Company whose principal purpose is to incur Non-Recourse Debt and/or construct, lease, own or operate the assets financed thereby, or to become a direct or indirect partner, member or other equity participant or owner in a Person created for such purpose, and substantially all the assets of which Subsidiary or Person are limited to (x) those assets being financed (or to be financed), or the operation of which is being financed (or to be financed), in whole or in part by Non-Recourse Debt, or (y) Equity Interests in, or indebtedness or other obligations of, one or more other such Subsidiaries or Persons, or (z) indebtedness or other obligations of the Company or any Subsidiary or other Persons. At the time of designation of any Project Finance Subsidiary, the sum of the net book value of the assets of such Subsidiary and the net book value of the assets of all other Project Finance Subsidiaries then existing shall not in the aggregate exceed 10 percent of Consolidated Net Tangible Assets;

“Reference Treasury Dealer” has the meaning set forth in Section 402 hereof;

“Reference Treasury Dealer Quotations” has the meaning set forth in Section 402 hereof;

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“Regular Record Date” has the meaning set forth in Section 204(a) hereof;

“Remaining Term” has the meaning set forth in Section 402 hereof;

“Subsidiary” of any entity means any corporation, partnership, joint venture, limited liability company, trust or estate of which (or in which) more than 50% of (i) the issued and outstanding capital stock having ordinary voting power to elect a majority of the Board of Directors of such corporation (irrespective of whether at the time capital stock of any other class or classes of such corporation shall or might have voting power upon the occurrence of any contingency), (ii) the interest in the capital or profits of such limited liability company, partnership, joint venture or other entity or (iii) the beneficial interest in such trust or estate is at the time directly or indirectly owned or controlled by such entity, by such entity and one or more of its other subsidiaries or by one or more of such entity’s other subsidiaries;

“Treasury Rate” has the meaning set forth in Section 402 hereof;

All references herein to Articles and Sections, unless otherwise specified, refer to the corresponding Articles and Sections of this Supplemental Indenture No. 16; and

The terms “herein,” “hereof,” “hereunder” and other words of similar import refer to this Supplemental Indenture No. 16.

ARTICLE TWO

The Series of Securities

Section 201    Title of the Securities.   The Notes shall be designated as the “4.10% Senior Notes due 2047.”

Section 202    Limitation on Aggregate Principal Amount.  The Trustee shall authenticate and deliver the Notes for original issue on the Issue Date in the aggregate principal amount of $300,000,000 upon a Company Order for the authentication and delivery thereof and satisfaction of Sections 301 and 303 of the Original Indenture.  Such order shall specify the amount of the Notes to be authenticated, the date on which the original issue of Notes is to be authenticated and the name or names of the initial Holder or Holders.  The aggregate principal amount of Notes that may initially be outstanding shall not exceed $300,000,000; provided, however, that the authorized aggregate principal amount of the Notes may be increased above such amount by a Board Resolution to such effect.

Section 203    Stated Maturity.  The Stated Maturity of the Notes shall be September 1, 2047 (the “Maturity Date”).

Section 204    Interest and Interest Rates.

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(a)     The Notes shall bear interest at a rate of 4.10% per year, from and including August 23, 2017 (the “Issue Date”) to, but excluding, the Maturity Date.  Such interest shall be payable semiannually in arrears on March 1 and September 1 of each year (each an “Interest Payment Date”), beginning March 1, 2018 to the persons in whose names the Notes (or one or more Predecessor Securities) are registered at the close of business on February 15 and August 15 (each a “Regular Record Date”) (whether or not a Business Day), as the case may be, immediately preceding such Interest Payment Date.

(b)     Any such interest not so punctually paid or duly provided for shall forthwith cease to be payable to the Holder on such Regular Record Date and shall either (i) be paid to the Person in whose name such Note (or one or more Predecessor Securities) is registered at the close of business on the Special Record Date for the payment of such Defaulted Interest to be fixed by the Trustee, notice whereof shall be given to Holders of the Notes not less than 10 days prior to such Special Record Date, or (ii) be paid at any time in any other lawful manner not inconsistent with the requirements of any securities exchange or automated quotation system on which the Notes may be listed or traded, and upon such notice as may be required by such exchange or automated quotation system, all as more fully provided in the Indenture.

(c)    The amount of interest payable for any period shall be computed on the basis of a 360-day year of twelve 30-day months. The amount of interest payable for any partial period shall be computed on the basis of a 360-day year of twelve 30-day months and the days elapsed in any partial month. In the event that any date on which interest is payable on a Note is not a Business Day, then a payment of the interest payable on such date will be made on the next succeeding day which is a Business Day (and without any interest or other payment in respect of any such delay) with the same force and effect as if made on the date the payment was originally payable.

(d)    Any principal and premium, if any, and any installment of interest, which is overdue shall bear interest at the rate of 4.10% per annum (to the extent permitted by law), from the dates such amounts are due until they are paid or made available for payment, and such interest shall be payable on demand.

Section 205    Paying Agent; Place of Payment.  The Trustee shall initially serve as the Paying Agent for the Notes.  The Company may appoint and change any Paying Agent or approve a change in the office through which any Paying Agent acts without notice, other than notice to the Trustee.  The Company or any of its Subsidiaries or any of their Affiliates may act as Paying Agent.  The Place of Payment where the Notes may be presented or surrendered for payment shall be the Corporate Trust Office of the Trustee.  At the option of the Company, payment of interest may be made (i) by check mailed to the address of the Person entitled thereto as such address shall appear in the Security Register or (ii) by wire transfer in immediately available funds at such place and to such account as may be designated in writing by the Person entitled thereto as specified in the Security Register.

Section 206    Place of Registration or Exchange; Notices and Demands With Respect to the Notes.  The place where the Holders of the Notes may present the Notes for registration of

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transfer or exchange and may make notices and demands to or upon the Company in respect of the Notes shall be the Corporate Trust Office of the Trustee.

Section 207    Percentage of Principal Amount.  The Notes shall be initially issued at 99.417% of their principal amount plus accrued interest, if any, from August 23, 2017.

Section 208    Global Securities. The Notes shall be issuable in whole or in part in the form of one or more Global Securities.  Such Global Securities shall be deposited with, or on behalf of, The Depository Trust Company, New York, New York, which shall act as Depositary with respect to the Notes.  Such Global Securities shall bear the legends set forth in the form of Security attached as Exhibit A hereto.

Section 209    Form of Securities.  The Notes shall be substantially in the form attached as Exhibit A hereto.

Section 210    Securities Registrar.  The Trustee shall initially serve as the Security Registrar for the Notes.

Section 211    Defeasance and Discharge; Covenant Defeasance.

(a)    Article Fourteen of the Original Indenture, including without limitation Sections 1402 and 1403 thereof (as modified by Section 211(b) hereof), shall apply to the Notes.

(b)    Solely with respect to the Notes issued hereby, the first sentence of Section 1403 of the Original Indenture is hereby deleted in its entirety, and the following is substituted in lieu thereof:

“Upon the Company’s exercise of its option (if any) to have this Section 1403 applied to any Securities or any series of Securities, as the case may be, (1) the Company shall be released from its obligations under Article Eight and under any covenants provided pursuant to Section 301(20), 901(2) or 901(7) for the benefit of the Holders of such Securities, including without limitation, the covenants provided for in Article Three of Supplemental Indenture No. 16 to the Indenture, and (2) the occurrence of any event specified in Sections 501(4) (with respect to Article Eight and to any such covenants provided pursuant to Section 301(20), 901(2) or 901(7)) and 501(7) shall be deemed not to be or result in an Event of Default, in each case with respect to such Securities as provided in this Section 1403 on and after the date the conditions set forth in Section 1404 are satisfied (hereinafter called “Covenant Defeasance”).”

Section 212    Sinking Fund Obligations.  The Company shall have no obligation to redeem or purchase any Notes pursuant to any sinking fund or analogous requirement or upon the happening of a specified event or at the option of a Holder thereof.

ARTICLE THREE

Additional Covenants

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Section 301. Maintenance of Properties. The Company shall cause all properties used or useful in the conduct of its business or the business of any Subsidiary to be maintained and kept in good condition, repair and working order and supplied with all necessary equipment and shall cause to be made all necessary repairs, renewals, replacements, betterments and improvements thereof, all as in the judgment of the Company may be necessary so that the business carried on in connection therewith may be properly conducted at all times; provided, however, that nothing in this Section 301 shall prevent the Company from discontinuing the operation or maintenance of any of such properties if such discontinuance is, in the judgment of the Company, desirable in the conduct of its business or the business of any Subsidiary.

Section 302. Payment of Taxes and Other Claims. The Company shall pay or discharge or cause to be paid or discharged, before the same shall become delinquent, (1) all taxes, assessments and governmental charges levied or imposed upon the Company or any Subsidiary or upon the income, profits or property of the Company or any Subsidiary, and (2) all lawful claims for labor, materials and supplies which, if unpaid, might by law become a lien upon the property of the Company or any Subsidiary; provided, however, that the Company shall not be required to pay or discharge or cause to be paid or discharged any such tax, assessment, charge or claim whose amount, applicability or validity is being contested in good faith by appropriate proceedings.

ARTICLE FOUR

Optional Redemption of the Notes

Section 401    Redemption Price. The Notes shall be redeemable, at the option of the Company, at any time or from time to time, in whole or in part, on any date prior to March 1, 2047 (the “Par Call Date”) at a price equal to the greater of (i) 100% of the principal amount of the Notes to be redeemed or (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the Notes to be redeemed that would be due if the Notes matured on the Par Call Date but for the redemption (not including any portion of such payments of interest accrued to the Redemption Date) discounted to the Redemption Date on a semiannual basis (assuming a 360-day year consisting of twelve 30-day months) at the applicable Treasury Rate plus 20 basis points plus, in each case, accrued and unpaid interest on the principal amount being redeemed, if any, to, but excluding, the Redemption Date. On or after the Par Call Date, the Company may redeem the Notes, at any time or from time to time, in whole or in part, by paying 100% of the principal amount of the Notes to be redeemed plus accrued and unpaid interest on the principal amount being redeemed, if any, to, but excluding, the Redemption Date. The Trustee shall have no responsibility for the calculation of such amount.

Section 402    Calculation. The Treasury Rate will be calculated by the Independent Investment Banker on the third Business Day preceding the Redemption Date. For purposes of this Article Four, the following terms shall mean as follows:

“Treasury Rate” means, with respect to any Redemption Date, the yield calculated on the third Business Day preceding the redemption date, as follows: for the latest day that appears in

8

the most recent statistical release published by the Board of Governors of the Federal Reserve System designated as “Selected Interest Rates (Daily) - H.15” (or any successor publication) under the caption “Treasury Constant Maturities - Nominal”, the Independent Investment Banker shall select two yields – one for the maturity immediately before and one for the maturity immediately after the remaining maturity of the Notes (assuming the Notes matured on the Par Call Date) – and shall interpolate on a straight-line basis using such yields; if there is no such maturity either before or after, the Independent Investment Banker shall select the maturity closest to the Par Call Date that appears on the release; or if such release (or any successor release) is not published during the week preceding the calculation date or does not contain such yields, the rate per annum equal to the semiannual equivalent yield to maturity of the applicable Comparable Treasury Issue, calculated by the Independent Investment Banker using a price for the Comparable Treasury Issue (expressed as a percentage of its principal amount) equal to the Comparable Treasury Price for such Redemption Date.

“Comparable Treasury Issue” means the U.S. Treasury security selected by an Independent Investment Banker as having an actual or interpolated maturity comparable to the remaining term (“Remaining Term”) of the Notes to be redeemed (assuming for this purpose that the Notes matured on the Par Call Date) that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the Remaining Term of such Notes.

“Comparable Treasury Price” means (1) the average of three Reference Treasury Dealer Quotations for such Redemption Date, after excluding the highest and lowest Reference Treasury Dealer Quotations, or (2) if the Independent Investment Banker obtains fewer than three such Reference Treasury Dealer Quotations, the average of all such quotations.

“Independent Investment Banker” means one of Deutsche Bank Securities Inc., Goldman Sachs & Co. LLC or Morgan Stanley & Co. LLC, as specified by the Company, or if these firms are unwilling or unable to select the Comparable Treasury Issue, an independent investment banking institution of national standing selected by the Company.

“Reference Treasury Dealer” means each of (1) Deutsche Bank Securities Inc., Goldman Sachs & Co. LLC and Morgan Stanley & Co. LLC, each of which is a primary U.S. government securities dealer in the United States of America (a “Primary Treasury Dealer”), provided, however, that if any of the foregoing shall cease to be a Primary Treasury Dealer, the Company shall substitute therefor another Primary Treasury Dealer and (2) any other Primary Treasury Dealer selected by the Company after consultation with the Independent Investment Banker.

“Reference Treasury Dealer Quotations” means, with respect to each Reference Treasury Dealer and any Redemption Date, the average, as determined by the Independent Investment Banker, of the bid and asked prices for the Comparable Treasury Issue (expressed in each case as a percentage of its principal amount) quoted in writing to the Independent Investment Banker at 5:00 p.m., New York City time, on the third Business Day preceding such Redemption Date.

Section 403   Partial Redemption.  If fewer than all of the Notes are to be redeemed by the Company pursuant to this Article Four, not more than 60 days prior to the Redemption Date,

9

the particular Notes or portions thereof for redemption will be selected from the outstanding Notes not previously called by such method as the Trustee deems fair and appropriate. The Trustee may select for redemption Notes and portions of Notes in amounts of $1,000 or whole multiples of $1,000.  A new Note in principal amount equal to the unredeemed portion of the original Note shall be issued upon the cancellation of the original Note. In the case of a partial redemption of Notes registered in the name of Cede & Co, the Notes to be redeemed will be determined in accordance with the procedures of The Depository Trust Company.

Section 404   Notice of Optional Redemption.  The Trustee, at the written direction of the Company, will send a notice of redemption prepared by the Company to each holder of Notes to be redeemed by first-class mail (or in accordance with the procedures of The Depository Trust Company with respect to Notes registered in the name of Cede & Co.) at least 15 and not more than 60 days prior to the date fixed for redemption. Unless the Company defaults on payment of the redemption price, interest will cease to accrue on the Notes or portions thereof called for redemption on the Redemption Date. If any Note is to be redeemed in part only, the notice of redemption shall state the portion of the principal amount to be redeemed.

ARTICLE FIVE

Remedies

Section 501    Additional Event of Default; Acceleration of Maturity.

(a)      Solely with respect to the Notes issued hereby, Section 501(7) of the Original Indenture is hereby deleted in its entirety, and the following is substituted in lieu thereof as an Event of Default in addition to the other events set forth in Section 501 of the Original Indenture:

“(7)     the default by the Company or any Subsidiary, other than a Project Finance Subsidiary, in the payment, when due, after the expiration of any applicable grace period, of principal of indebtedness for money borrowed, other than Non-Recourse Debt, in the aggregate principal amount then outstanding of $125 million or more, or acceleration of any indebtedness for money borrowed in such aggregate principal amount so that it becomes due and payable prior to the date on which it would otherwise have become due and payable and such acceleration is not rescinded or such default is not cured within 30 days after there has been given, by registered or certified mail, to the Company by the Trustee or to the Company and the Trustee by the holders of at least 33% in principal amount of Notes written notice specifying such default and requiring the Company to cause such acceleration to be rescinded or such default to be cured and stating that such notice is a “Notice of Default” under the Indenture;”.

10

(b)    Solely with respect to the Notes issued hereby, the first paragraph of Section 502 of the Original Indenture is hereby deleted in its entirety, and the following is substituted in lieu thereof:

“If an Event of Default (other than an Event of Default specified in Section 501(5) or 501(6)) with respect to the Notes at the time Outstanding occurs and is continuing, then in every such case the Trustee or the Holders of not less than 33% in principal amount of the Notes Outstanding may declare the principal amount of all the Notes to be due and payable immediately, by a notice in writing to the Company (and to the Trustee if given by Holders), and upon any such declaration such principal amount (or specified amount) shall become immediately due and payable. If an Event of Default specified in Section 501(5) or 501(6) with respect to the Notes at the time Outstanding occurs and is continuing, the principal amount of all the Notes shall automatically, and without any declaration or other action on the part of the Trustee or any Holder, become immediately due and payable.”

Section 502   Amendment of Certain Provisions.  Solely with respect to the Notes issued hereby, references to “25%” in Article Five of the Indenture are hereby deleted in their entirety and “33%” is substituted in lieu thereof.

ARTICLE SIX

Miscellaneous Provisions

Section 601    The Indenture, as supplemented and amended by this Supplemental Indenture No. 16, is in all respects hereby adopted, ratified and confirmed.

Section 602    This Supplemental Indenture No. 16 may be executed in any number of counterparts, each of which shall be an original, but such counterparts shall together constitute but one and the same instrument.

Section 603    THIS SUPPLEMENTAL INDENTURE NO. 16 AND EACH NOTE SHALL BE DEEMED TO BE A CONTRACT MADE UNDER THE LAWS OF THE STATE OF NEW YORK AND SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF NEW YORK WITHOUT REGARD TO CONFLICTS OF LAWS PRINCIPLES THEREOF.

Section 604    If any provision in this Supplemental Indenture No. 16 limits, qualifies or conflicts with another provision hereof which is required to be included herein by any provisions of the Trust Indenture Act, such required provision shall control.

11

Section 605    In case any provision in this Supplemental Indenture No. 16 or the Notes shall be invalid, illegal or unenforceable, the validity, legality and enforceability of the remaining provisions shall not in any way be affected or impaired thereby.

12

IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture No. 16 to be duly executed, as of the day and year first written above.

CENTERPOINT ENERGY RESOURCES CORP.

By:	/s/ Carla A. Kneipp
	Carla A. Kneipp
	Vice President and Treasurer

Attest:

/s/ Vincent A. Mercaldi

Assistant Corporate Secretary

(SEAL)

THE BANK OF NEW YORK MELLON TRUST
COMPANY, NATIONAL ASSOCIATION,
As Trustee
By:	/s/ Karen Yu
	Karen Yu
	Vice President

13

Exhibit A

[FORM OF FACE OF SECURITY]

[IF THIS SECURITY IS TO BE A GLOBAL SECURITY -] THIS SECURITY IS A GLOBAL SECURITY WITHIN THE MEANING OF THE INDENTURE HEREINAFTER REFERRED TO AND IS REGISTERED IN THE NAME OF A DEPOSITARY OR A NOMINEE OF A DEPOSITARY. THIS SECURITY IS EXCHANGEABLE FOR SECURITIES REGISTERED IN THE NAME OF A PERSON OTHER THAN THE DEPOSITARY OR ITS NOMINEE ONLY IN THE LIMITED CIRCUMSTANCES DESCRIBED IN THE INDENTURE AND MAY NOT BE TRANSFERRED EXCEPT AS A WHOLE BY THE DEPOSITARY TO A NOMINEE OF THE DEPOSITARY OR BY A NOMINEE OF THE DEPOSITARY TO THE DEPOSITARY OR ANOTHER NOMINEE OF THE DEPOSITARY.

[FOR AS LONG AS THIS GLOBAL SECURITY IS DEPOSITED WITH OR ON BEHALF OF THE DEPOSITORY TRUST COMPANY IT SHALL BEAR THE FOLLOWING LEGEND.]  UNLESS THIS CERTIFICATE IS PRESENTED BY AN AUTHORIZED REPRESENTATIVE OF THE DEPOSITORY TRUST COMPANY, A NEW YORK CORPORATION (“DTC”), TO CENTERPOINT ENERGY RESOURCES CORP. OR ITS AGENT FOR REGISTRATION OF TRANSFER, EXCHANGE, OR PAYMENT, AND ANY CERTIFICATE ISSUED IS REGISTERED IN THE NAME OF CEDE & CO. OR IN SUCH OTHER NAME AS IS REQUESTED BY AN AUTHORIZED REPRESENTATIVE OF DTC (AND ANY PAYMENT IS MADE TO CEDE & CO. OR TO SUCH OTHER ENTITY AS IS REQUESTED BY AN AUTHORIZED REPRESENTATIVE OF DTC), ANY TRANSFER, PLEDGE, OR OTHER USE HEREOF FOR VALUE OR OTHERWISE BY OR TO ANY PERSON IS WRONGFUL INASMUCH AS THE REGISTERED OWNER HEREOF, CEDE & CO., HAS AN INTEREST HEREIN.

CENTERPOINT ENERGY RESOURCES CORP.

4.10% Senior Notes due 2047

Original Interest Accrual Date: August 23, 2017 Stated Maturity: September 1, 2047 Interest Rate: 4.10% Interest Payment Dates: March 1 and September 1 Initial Interest Payment Date: March 1, 2018 Regular Record Dates: February 15 and August 15 immediately preceding the respective Interest Payment Date Redeemable: Yes [X] No [ ] Redemption Date: At any time. Redemption Price: 1) On any date prior to March 1, 2047 (the “Par Call Date”) at a price equal to the greater of (i) 100% of the principal amount of this Security or the portion hereof to be redeemed or (ii) the sum of the present values of the remaining scheduled payments of principal and interest on this Security, or the portion thereof to be redeemed, that would be due if this Security matured on the Par Call Date but for the redemption (not including any portion of such payments of interest accrued to the Redemption Date) discounted to the Redemption Date on a semiannual basis at the applicable Treasury Rate

plus 20 basis points; plus, in each case, accrued and unpaid interest on the principal amount being redeemed to, but excluding, the Redemption Date; or 2) on or after the Par Call Date, at a price equal to 100% of the principal amount of this Security or the portion thereof to be redeemed plus accrued and unpaid interest on the principal amount being redeemed to, but excluding, the Redemption Date.

This Security is not an Original Issue Discount Security
within the meaning of the within-mentioned Indenture.
_____________________________

Principal Amount	Registered No. T-1
$______________*	CUSIP 15189W AJ9

CENTERPOINT ENERGY RESOURCES CORP., a corporation duly organized and existing under the laws of the State of Delaware, formerly known as NorAm Energy Corp. (herein called the “Company,” which term includes any successor Person under the Indenture referred to below), for value received, hereby promises to pay to

***CEDE & Co.***

, or its registered assigns, the principal sum of DOLLARS on the Stated Maturity specified above, and to pay interest thereon from the Original Interest Accrual Date specified above or from the most recent Interest Payment Date to which interest has been paid or duly provided for, semi-annually in arrears on the Interest Payment Dates specified above in each year, commencing on March 1, 2018, and at Maturity, at the Interest Rate per annum specified above, until the principal hereof is paid or made available for payment, provided that any principal and premium, and any such installment of interest, which is overdue shall bear interest at the rate of 4.10% per annum (to the extent permitted by applicable law), from the dates such amounts are due until they are paid or made available for payment, and such interest shall be payable on demand.  The amount of interest payable for any period shall be computed on the basis of twelve 30-day months and a 360-day year. The amount of interest payable for any partial period shall be computed on the basis of a 360-day year of twelve 30-day months and the days elapsed in any partial month. In the event that any date on which interest is payable on this Security is not a Business Day, then a payment of the interest payable on such date will be made on the next succeeding day which is a Business Day (and without any interest or other payment in respect of any such delay) with the same force and effect as if made on the date the payment was originally payable. A “Business Day” shall mean any day other than a Saturday, a Sunday or a day on which banking institutions in The City of New York are

___________________________

Reference is made to Schedule A attached hereto with respect to decreases and increases in the aggregate principal amount of Securities evidenced hereby.

A-2

authorized or required by law, regulation or executive order to close.  The interest so payable, and punctually paid or duly provided for, on any Interest Payment Date will, as provided in such Indenture, be paid to the Person in whose name this Security (or one or more Predecessor Securities) is registered at the close of business on the Regular Record Date for such interest, which shall be February 15 or August 15 (whether or not a Business Day), as the case may be, next preceding such Interest Payment Date.  Any such interest not so punctually paid or duly provided for shall forthwith cease to be payable to the Holder on such Regular Record Date and shall either be paid to the Person in whose name this Security (or one or more Predecessor Securities) is registered at the close of business on a Special Record Date for the payment of such Defaulted Interest to be fixed by the Trustee, notice whereof shall be given to Holders of Securities of this series not less than 10 days prior to such Special Record Date, or be paid at any time in any other lawful manner not inconsistent with the requirements of any securities exchange or automated quotation system on which the Securities of this series may be listed or traded, and upon such notice as may be required by such exchange or automated quotation system, all as more fully provided in said Indenture.

Payment of the principal of (and premium, if any) and any such interest on this Security will be made at the Corporate Trust Office of the Trustee, in such coin or currency of the United States of America as at the time of payment is legal tender for payment of public and private debts; provided, however, that at the option of the Company payment of interest may be made (i) by check mailed to the address of the Person entitled thereto as such address shall appear in the Security Register or (ii) by wire transfer in immediately available funds at such place and to such account as may be designated in writing by the Person entitled thereto as specified in the Security Register.

Reference is hereby made to the further provisions of this Security set forth on the reverse hereof, which further provisions shall for all purposes have the same effect as if set forth at this place.

Unless the certificate of authentication hereon has been executed by the Trustee referred to on the reverse hereof by manual signature, this Security shall not be entitled to any benefit under the Indenture or be valid or obligatory for any purpose.

A-3

IN WITNESS WHEREOF, the Company has caused this instrument to be duly executed.

Dated:	CENTERPOINT ENERGY RESOURCES
	CORP.
	By:
	Name: Carla A. Kneipp
	Title: Vice President and Treasurer
(SEAL)
Attest:
Name: Vincent A. Mercaldi
Title: Assistant Corporate Secretary

A-4

CERTIFICATE OF AUTHENTICATION

This is one of the Securities of the series designated therein referred to in the within-mentioned Indenture.

	THE BANK OF NEW YORK MELLON
	TRUST COMPANY, NATIONAL
	ASSOCIATION,
	As Trustee
Dated:
	By:
		Authorized Signatory

A-5

SCHEDULE A

         The initial aggregate principal amount of Securities evidenced by the Certificate to which this Schedule is attached is $ . The notations on the following table evidence decreases and increases in the aggregate principal amount of Securities evidenced by such Certificate.

			Aggregate Principal
			Amount of Securities
	Decrease in Aggregate	Increase in Aggregate	Remaining After	Notation by
Date of	Principal Amount of	Principal Amount of	Such Decrease or	Security
Adjustment	Securities	Securities	Increase	Registrar

A-6

[FORM OF REVERSE SIDE OF SECURITY]

CENTERPOINT ENERGY RESOURCES CORP.

4.10% NOTES DUE 2047

This Security is one of a duly authorized issue of securities of the Company (herein called the “Securities”), issued and to be issued in one or more series under an Indenture, dated as of February 1, 1998 (herein called the “ Indenture,” which term shall have the meaning assigned to it in such instrument), between the Company and The Bank of New York Mellon Trust Company, National Association (successor to JPMorgan Chase Bank, National Association (formerly Chase Bank of Texas, National Association)), as Trustee (herein called the “Trustee,” which term includes any successor trustee under the Indenture), to which Indenture and all indentures supplemental thereto reference is hereby made for a statement of the respective rights, limitations of rights, duties and immunities thereunder of the Company, the Trustee and the Holders of the Securities and of the terms upon which the Securities are, and are to be, authenticated and delivered.  This Security is one of the series designated on the face hereof, initially limited in aggregate principal amount to $300,000,000; provided, however, that the authorized aggregate principal amount of the Securities may be increased above such amount by a Board Resolution to such effect.

This Security shall be redeemable, at the option of the Company, at any time or from time to time, in whole or in part, on any date prior to March 1, 2047 (the “Par Call Date”) at a price equal to the greater of (i) 100% of the principal amount of this Security (or the portion hereof to be redeemed) or (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the Securities to be redeemed that would be due if this Security (or the portion hereof to be redeemed) matured on the Par Call Date but for the redemption (not including any portion of such payments of interest accrued to the Redemption Date) discounted to the Redemption Date on a semiannual basis (assuming a 360-day year consisting of twelve 30-day months) at the applicable Treasury Rate plus 20 basis points plus, in each case, accrued and unpaid interest on the principal amount being redeemed, if any, to, but excluding, the Redemption Date. On or after the Par Call Date, the Company may redeem this Security, at any time or from time to time, in whole or in part, by paying 100% of the principal amount of this Security (or such portion to be redeemed) plus accrued and unpaid interest on the principal amount being redeemed, if any, to, but excluding, the Redemption Date. The Trustee shall have no responsibility for the calculation of such amount.

The Treasury Rate will be calculated by the Independent Investment Banker on the third Business Day preceding the Redemption Date. For purposes of calculating the Redemption Price, the following terms shall mean as follows:

“Treasury Rate” means, with respect to any Redemption Date, the yield calculated on the third Business Day preceding the redemption date, as follows: for the latest day that appears in the most recent statistical release published by the Board of Governors of the Federal Reserve System designated as “Selected Interest Rates (Daily) - H.15” (or any successor publication) under the caption “Treasury Constant Maturities - Nominal”, the Independent Investment Banker

A-7

shall select two yields – one for the maturity immediately before and one for the maturity immediately after the remaining maturity of this Security (assuming this Security matured on the Par Call Date) – and shall interpolate on a straight-line basis using such yields; if there is no such maturity either before or after, the Independent Investment Banker shall select the maturity closest to the Par Call Date that appears on the release; or if such release (or any successor release) is not published during the week preceding the calculation date or does not contain such yields, the rate per annum equal to the semiannual equivalent yield to maturity of the Comparable Treasury Issue, calculated by the Independent Investment Banker using a price for the Comparable Treasury Issue (expressed as a percentage of its principal amount) equal to the Comparable Treasury Price for such Redemption Date.

“Comparable Treasury Issue” means the U.S. Treasury security selected by an Independent Investment Banker as having an actual or interpolated maturity comparable to the remaining term (“Remaining Term”) of this Security to be redeemed (assuming for this purpose that the Securities matured on the Par Call Date) that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the Remaining Term of this Security.

“Comparable Treasury Price” means (1) the average of three Reference Treasury Dealer Quotations for such Redemption Date, after excluding the highest and lowest Reference Treasury Dealer Quotations, or (2) if the Independent Investment Banker obtains fewer than three such Reference Treasury Dealer Quotations, the average of all such quotations.

“Independent Investment Banker” means one of Deutsche Bank Securities Inc., Goldman Sachs & Co. LLC or Morgan Stanley & Co. LLC as specified by the Company, or if these firms are unwilling or unable to select the Comparable Treasury Issue, an independent investment banking institution of national standing selected by the Company.

“Reference Treasury Dealer” means each of (1) Deutsche Bank Securities Inc., Goldman Sachs & Co. LLC and Morgan Stanley & Co. LLC, each of which is a primary U.S. government securities dealer in the United States of America (a “Primary Treasury Dealer”), provided, however, that if any of the foregoing shall cease to be a Primary Treasury Dealer, the Company shall substitute therefor another Primary Treasury Dealer and (2) any other Primary Treasury Dealer selected by the Company after consultation with the Independent Investment Banker.

“Reference Treasury Dealer Quotations” means, with respect to each Reference Treasury Dealer and any Redemption Date, the average, as determined by the Independent Investment Banker, of the bid and asked prices for the Comparable Treasury Issue (expressed in each case as a percentage of its principal amount) quoted in writing to the Independent Investment Banker at 5:00 p.m., New York City time, on the third Business Day preceding such Redemption Date.

In the event of redemption of this Security in part only, a new Security or Securities of this series and of like tenor for the unredeemed portion hereof will be issued in the name of the Holder hereof upon the cancellation hereof.

The Securities of this series are not entitled to the benefit of any sinking fund.

A-8

The Indenture contains provisions for satisfaction and discharge of the entire indebtedness of this Security upon compliance by the Company with certain conditions set forth in the Indenture.

The Indenture contains provisions for defeasance at any time of the entire indebtedness of this Security or certain restrictive covenants and Events of Default with respect to this Security, in each case upon compliance with certain conditions set forth in the Indenture.

If an Event of Default with respect to Securities of this series shall occur and be continuing, the principal of the Securities of this series may be declared due and payable in the manner and with the effect provided in the Indenture.

The Indenture permits, with certain exceptions as therein provided, the amendment thereof and the modification of the rights and obligations of the Company and the rights of the Holders of the Securities of each series to be affected under the Indenture at any time by the Company and the Trustee with the consent of the Holders of a majority in principal amount of the Securities at the time Outstanding of each series to be affected.  The Indenture also contains provisions permitting the Holders of specified percentages in principal amount of the Securities of each series at the time Outstanding, on behalf of the Holders of all Securities of such series, to waive compliance by the Company with certain provisions of the Indenture and certain past defaults under the Indenture and their consequences.  Any such consent or waiver by the Holder of this Security shall be conclusive and binding upon such Holder and upon all future Holders of this Security and of any Security issued upon the registration of transfer hereof or in exchange herefor or in lieu hereof, whether or not notation of such consent or waiver is made upon this Security.

     As provided in and subject to the provisions of the Indenture, the Holder of this Security shall not have the right to institute any proceeding with respect to the Indenture or for the appointment of a receiver or trustee or for any other remedy thereunder, unless such Holder shall have previously given the Trustee written notice of a continuing Event of Default with respect to the Securities of this series, the Holders of not less than 33% in principal amount of the Securities of this series at the time Outstanding shall have made written request to the Trustee to institute proceedings in respect of such Event of Default as Trustee and offered the Trustee reasonable indemnity, and the Trustee shall not have received from the Holders of a majority in principal amount of Securities of this series at the time Outstanding a direction inconsistent with such request, and shall have failed to institute any such proceeding, for 60 days after receipt of such notice, request and offer of indemnity.  The foregoing shall not apply to any suit instituted by the Holder of this Security for the enforcement of any payment of principal hereof or any premium or interest hereon on or after the respective due dates expressed herein.

No reference herein to the Indenture and no provision of this Security or of the Indenture shall alter or impair the obligation of the Company, which is absolute and unconditional, to pay the principal of and any premium and interest on this Security at the times, place and rate, and in the coin or currency, herein prescribed.

A-9

As provided in the Indenture and subject to certain limitations therein set forth, the transfer of this Security is registrable in the Security Register, upon surrender of this Security for registration of transfer at the office or agency of the Company in any place where the principal of and any premium and interest on this Security are payable, duly endorsed by, or accompanied by a written instrument of transfer in form satisfactory to the Company and the Security Registrar duly executed by the Holder hereof or his attorney duly authorized in writing, and thereupon one or more new Securities of this series and of like tenor, of authorized denominations and for the same aggregate principal amount, will be issued to the designated transferee or transferees.  No service charge shall be made for any such registration of transfer or exchange, but the Company may require payment of a sum sufficient to cover any tax or other governmental charge payable in connection therewith.

Prior to due presentment of this Security for registration of transfer, the Company, the Trustee and any agent of the Company or the Trustee may treat the Person in whose name this Security is registered as the owner hereof for all purposes, whether or not this Security be overdue, and neither the Company, the Trustee nor any such agent shall be affected by notice to the contrary.

The Securities of this series are issuable only in registered form without coupons in denominations of $1,000 and any integral multiple thereof.  As provided in the Indenture and subject to certain limitations therein set forth, Securities of this series are exchangeable for a like aggregate principal amount of Securities of this series and of like tenor of a different authorized denomination, as requested by the Holder surrendering the same.

All terms used in this Security which are defined in the Indenture shall have the meanings assigned to them in the Indenture.

THE INDENTURE AND THIS SECURITY SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF NEW YORK WITHOUT REGARD TO CONFLICTS OF LAWS PRINCIPLES THEREOF.

A-10

EX-12

Exhibit 12

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES

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

COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES

	Nine Months Ended September 30,
	2017			2016
	(in millions, except ratios)
Net income	$	239		$	169
Equity in earnings of unconsolidated affiliates, net of distributions	24			59
Income tax expense	144			113
Capitalized interest	(1		)	(1		)
	406			340
Fixed charges, as defined:
Interest	92			93
Capitalized interest	1			1
Interest component of rentals charged to operating expense	2			3
Total fixed charges	95			97
Earnings, as defined	$	501		$	437
Ratio of earnings to fixed charges	5.27			4.51

EX-31.1

Exhibit 31.1

CERTIFICATIONS

I, Scott M. Prochazka, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date:  November 3, 2017

/s/ Scott M. Prochazka

Scott M. Prochazka

President and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATIONS

I, William D. Rogers, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date:  November 3, 2017

/s/ William D. Rogers

William D. Rogers

Executive Vice President and Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of CenterPoint Energy Resources Corp. (the “Company”) on Form 10-Q for the three months ended September 30, 2017 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, Scott M. Prochazka, Chief Executive Officer, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that:

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

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

/s/ Scott M. Prochazka

Scott M. Prochazka

President and Chief Executive Officer

November 3, 2017

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of CenterPoint Energy Resources Corp. (the “Company”) on Form 10-Q for the three months ended September 30, 2017 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, William D. Rogers, Chief Financial Officer, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that:

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

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

/s/ William D. Rogers

William D. Rogers

Executive Vice President and Chief Financial Officer

November 3, 2017

XML

Document and Entity Information - USD ($)	9 Months Ended
	Sep. 30, 2017	Oct. 26, 2017	Jun. 30, 2016
Entity Information [Line Items]
Entity Registrant Name	CENTERPOINT ENERGY RESOURCES CORP
Entity Central Index Key	0001042773
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Document Type	10-Q
Document Period End Date	Sep. 30, 2017
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	Q3
Amendment Flag	false
Entity Common Stock, Shares Outstanding		1,000
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 0

XML

CONDENSED STATEMENTS OF CONSOLIDATED INCOME (Unaudited) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Revenues:
Utility revenues	$ 390	$ 370	$ 1,767	$ 1,672
Non-utility revenues	861	608	2,964	1,433
Total	1,251	978	4,731	3,105
Expenses:
Utility natural gas	106	99	706	663
Non-utility natural gas	832	584	2,843	1,368
Operation and maintenance	187	175	603	571
Depreciation and amortization	68	62	202	185
Taxes other than income taxes	32	32	104	108
Total	1,225	952	4,458	2,895
Operating Income	26	26	273	210
Other Income (Expense):
Interest and other finance charges	(32)	(29)	(92)	(93)
Equity in earnings of unconsolidated affiliate, net	68	73	199	164
Other, net	1	(1)	3	1
Total	37	43	110	72
Income Before Income Taxes	63	69	383	282
Income tax expense	25	26	144	113
Net Income	$ 38	$ 43	$ 239	$ 169

XML

CONDENSED STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME (Unaudited) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Statement of Comprehensive Income [Abstract]
Net income	$ 38	$ 43	$ 239	$ 169
Other comprehensive income, net of tax:
Adjustment to pension and other postretirement plans (net of tax of $2, $1, $2 and $-0-)	1	1	1	2
Net deferred loss from cash flow hedges (net of tax of $1, $-0-, $1 and $-0-)	(1)	0	(1)	0
Other comprehensive income	0	1	0	2
Comprehensive income	$ 38	$ 44	$ 239	$ 171

XML

CONDENSED STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Statement of Comprehensive Income [Abstract]
Tax benefit (expense) on adjustment related to pension and postretirement plans	$ (2)	$ (1)	$ (2)	$ 0
Tax expense (benefit) on net deferred loss from cash flow hedges	$ (1)	$ 0	$ (1)	$ 0

XML

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Current Assets:
Cash and cash equivalents	$ 1	$ 1
Accounts receivable, less bad debt reserve of $15 and $14, respectively	448	512
Accrued unbilled revenues	84	229
Accounts and notes receivable–affiliated companies	8	5
Materials and supplies	53	47
Natural gas inventory	252	131
Non-trading derivative assets	64	51
Prepaid expenses and other current assets	102	81
Total current assets	1,012	1,057
Property, Plant and Equipment:
Property, plant and equipment	6,694	6,351
Less: accumulated depreciation and amortization	1,995	1,782
Property, plant and equipment, net	4,699	4,569
Other Assets:
Goodwill	867	862
Non-trading derivative assets	56	19
Investment in unconsolidated affiliate	2,481	2,505
Other	261	206
Total other assets	3,665	3,592
Total Assets	9,376	9,218
Current Liabilities:
Short-term borrowings	48	35
Current portion of long-term debt	550	250
Accounts payable	375	471
Accounts and notes payable–affiliated companies	42	40
Taxes accrued	64	73
Interest accrued	33	33
Customer deposits	76	80
Non-trading derivative liabilities	17	41
Other	118	124
Total current liabilities	1,323	1,147
Other Liabilities:
Deferred income taxes, net	2,066	1,925
Non-trading derivative liabilities	10	5
Benefit obligations	105	104
Regulatory liabilities	699	769
Other	226	221
Total other liabilities	3,106	3,024
Long-Term Debt	2,086	2,125
Commitments and Contingencies (Note 12)
Stockholder’s Equity:
Common stock	0	0
Paid-in capital	2,528	2,489
Retained earnings	332	430
Accumulated other comprehensive income	1	3
Total stockholder’s equity	2,861	2,922
Total Liabilities and Stockholder’s Equity	$ 9,376	$ 9,218

XML

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Statement of Financial Position [Abstract]
Bad debt reserve	$ 15	$ 14

XML

CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS (Unaudited) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
Cash Flows from Operating Activities:
Net income	$ 239	$ 169
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	202	185
Amortization of deferred financing costs	7	7
Deferred income taxes	140	108
Write-down of natural gas inventory	0	1
Equity in earnings of unconsolidated affiliate, net of distributions	(199)	(164)
Changes in other assets and liabilities, excluding acquisitions:
Accounts receivable and unbilled revenues, net	346	220
Accounts receivable/payable–affiliated companies	(1)	(5)
Inventory	(49)	(1)
Accounts payable	(227)	(85)
Fuel cost recovery	(30)	(43)
Interest and taxes accrued	(9)	(8)
Non-trading derivatives, net	(51)	23
Margin deposits, net	(49)	65
Other current assets	23	(11)
Other current liabilities	(5)	15
Other assets	(32)	(5)
Other liabilities	6	1
Other, net	1	2
Net cash provided by operating activities	312	474
Cash Flows from Investing Activities:
Capital expenditures	(373)	(378)
Distribution from unconsolidated affiliate in excess of cumulative earnings	223	223
Decrease in notes receivable–unconsolidated affiliate	0	363
Acquisitions, net of cash acquired	(132)	(102)
Other, net	2	(1)
Net cash provided by (used in) investing activities	(280)	105
Cash Flows from Financing Activities:
Decrease in short-term borrowings, net	13	3
Proceeds from (payments of) commercial paper, net	(40)	240
Proceeds from long-term debt	298	0
Payments of long-term debt	0	(325)
Dividends to parent	(337)	(567)
Debt issuance costs	(4)	(1)
Contribution from parent	38	73
Other, net	0	(2)
Net cash used in financing activities	(32)	(579)
Net Increase in Cash and Cash Equivalents	0	0
Cash and Cash Equivalents at Beginning of Period	1	0
Cash and Cash Equivalents at End of Period	1	0
Cash Payments:
Interest, net of capitalized interest	86	90
Income taxes, net	4	3
Non-cash transactions:
Accounts payable related to capital expenditures	$ 53	$ 32

XML

Background and Basis of Presentation

9 Months Ended

Sep. 30, 2017

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Background and Basis of Presentation [Text Block]

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 2016 Form 10-K.

Background. CERC Corp. is an indirect, wholly-owned subsidiary of CenterPoint Energy, a public utility holding company. CERC Corp.’s operating subsidiaries own and operate natural gas distribution facilities, supply natural gas to commercial and industrial customers and electric and natural gas utilities and own interests in Enable as described in Note 8. CERC Corp.’s operating subsidiaries and divisions include:

• NGD, which owns and operates natural gas distribution systems in six states; and

• CES, which obtains and offers competitive variable and fixed-price physical natural gas supplies and services primarily to commercial and industrial customers and electric and natural gas utilities in 33 states.

As of September 30, 2017, CERC Corp. also owned approximately 54.1% of the common units representing limited partner interests in Enable, which owns, operates and develops natural gas and crude oil infrastructure assets.

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 14.

XML

New Accounting Pronouncements

9 Months Ended

Sep. 30, 2017

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

New Accounting Pronouncements [Text Block]

New Accounting Pronouncements

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. As of the first reporting period in which the guidance is adopted, a cumulative-effect adjustment to beginning retained earnings will be made, with two features that will be adopted prospectively. CERC does not believe this standard will have a material impact on its financial position, results of operations, cash flows and disclosures.

In 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02) and related amendments. 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. A modified retrospective adoption approach is required. 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. 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09).  The new guidance simplifies several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. CERC adopted this standard as of January 1, 2017. The adoption did not have a material impact on CERC’s financial position or results of operations.  However, CERC’s statement of cash flows reflects a decrease in financing activity and a corresponding increase in operating activity of $1 million as of both September 30, 2017 and 2016 due to the retrospective application of the requirement that cash paid to a tax authority when shares are withheld to satisfy statutory income tax withholding obligations should be presented as a financing rather than as an operating activity.

In 2016, the FASB issued ASUs which amended ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606). ASU 2014-09, as amended, provides a comprehensive new revenue recognition model that requires revenue to be recognized in a manner that depicts the transfer of goods or services to a customer at an amount that reflects the consideration expected to be received in exchange for those goods or services. Early adoption is permitted, and entities have the option of using either a full retrospective or a modified retrospective adoption approach. CERC is currently evaluating its revenue streams under these ASUs and has not yet identified any significant changes as the result of these new standards. A substantial amount of CERC’s revenues are tariff and derivative based, which we do not anticipate will be significantly impacted by these ASUs. CERC expects to adopt these ASUs on January 1, 2018 using the modified retrospective adoption approach.

In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (ASU 2016-15). ASU 2016-15 provides clarifying guidance on the classification of certain cash receipts and payments in the statement of cash flows and eliminates the variation in practice related to such classifications. ASU 2016-15 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017, with early adoption permitted. A retrospective adoption approach is required. CERC is currently assessing the impact that this standard will have on its statement of cash flows.

In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (ASU 2016-18). ASU 2016-18 requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, restricted cash and restricted cash equivalents. As a result, the statement of cash flows will no longer present transfers between cash and cash equivalents and restricted cash and restricted cash equivalents. When cash, cash equivalents, restricted cash and restricted cash equivalents are presented in more than one line item on the balance sheet, the new guidance requires a reconciliation of the totals in the statement of cash flows to the related captions in the balance sheet. ASU 2016-18 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017, with early adoption permitted. A retrospective adoption approach is required. This standard will not have an impact on CERC’s financial position, results of operations, cash flows and disclosures.

In January 2017, the FASB issued ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business (ASU 2017-01). ASU 2017-01 revises the definition of a business. If substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or a group of similar identifiable assets, then under ASU 2017-01, the asset or group of assets is not a business. The guidance also requires a business to include at least one substantive process and narrows the definition of outputs to be more closely aligned with how outputs are described in ASC 606. ASU 2017-01 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017, with early adoption permitted in certain circumstances. A prospective adoption approach is required. ASU 2017-01 could have a potential impact on CERC’s accounting for future acquisitions.

In January 2017, the FASB issued ASU No. 2017-04, Intangibles-Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment (ASU 2017-04). ASU 2017-04 eliminates Step 2 of the goodwill impairment test, which requires a hypothetical purchase price allocation. A goodwill impairment will now be the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill. ASU 2017-04 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019, with early adoption permitted. A prospective adoption approach is required. ASU 2017-04 will have an impact on CERC’s future calculation of goodwill impairments if an impairment is identified.

In February 2017, the FASB issued ASU No. 2017-05, Other Income-Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20): Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets (ASU 2017-05). ASU 2017-05 clarifies when and how to apply ASC 610-20 Gains and Losses from the Derecognition of Nonfinancial Assets, which was issued as part of ASU 2014-09 Revenue from Contracts with Customers (Topic 606). ASU 2017-05 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017, with early adoption permitted. Companies can elect a retrospective or modified retrospective approach to adoption. CERC does not believe this standard will have a material impact on its financial position, results of operations, cash flows and disclosures.

In March 2017, the FASB issued ASU No. 2017-07, Compensation-Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires an employer to report the service cost component of the net periodic pension cost and postretirement benefit cost in the same line item(s) as other employee compensation costs arising from services rendered during the period; all other components will be presented separately from the line item(s) that includes the service cost and outside of any subtotal of operating income. In addition, only the service cost component will be eligible for capitalization in assets. ASU 2017-07 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017, with early adoption permitted. ASU 2017-07 should be applied retrospectively for the presentation of the service cost component and the other components and prospectively for the capitalization of the service cost component. The adoption of this guidance is expected to result in an increase to operating income and a decrease to other income. Prospectively, other components previously capitalized in assets will be recorded as regulatory assets in CERC’s rate-regulated businesses. CERC does not believe this standard will have a material impact on its financial position, results of operations, cash flows and disclosures.

In August 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12). ASU 2017-12 expands an entity’s ability to hedge nonfinancial and financial risk components and reduce complexity in fair value hedges of interest rate risk. The guidance eliminates the requirement to separately measure and report hedge ineffectiveness, eases certain documentation and assessment requirements, and updates the presentation and disclosure requirements. ASU 2017-12 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted. A cumulative-effect adjustment to eliminate the separate measurement of ineffectiveness upon adoption is required for existing cash flow and net investment hedges. Presentation and disclosure guidance should be applied prospectively. 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.

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Acquisition

9 Months Ended

Sep. 30, 2017

Business Combinations [Abstract]

Acquisition [Text Block]

Acquisition

On January 3, 2017,CES, a wholly-owned subsidiary of CERC, completed its acquisition of AEM. After working capital adjustments, the final purchase price was $147 million and was allocated to identifiable assets acquired and liabilities assumed based on their estimated fair values on the acquisition date.

The following table summarizes the final 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	$	147
Cash	$	15
Receivables	140
Natural gas inventory	78
Derivative assets	35
Prepaid expenses and other current assets	5
Property and equipment	8
Identifiable intangibles	25
Total assets acquired	306
Accounts payable	113
Derivative liabilities	43
Other current liabilities	7
Other liabilities	1
Total liabilities assumed	164
Identifiable net assets acquired	142
Goodwill	5
Net assets acquired	$	147

The goodwill of $5 millionresulting 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, scale and expanded capabilities provided by the acquisition.

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 final purchase price allocation include:

	Estimate Fair Value		Estimate Useful Life
	(in millions)		(in years)
Customer relationships	$	25	15

Amortization expense related to the above identifiable intangible assets was $-0- and $1 million for the three and nine months ended September 30, 2017, respectively.

Revenues of approximately $311 million and $989 million, respectively, and operating income of approximately $3 million and $28 million, respectively, attributable to the AEM acquisition are reported in the Energy Services business segment and included in CERC’s Condensed Statements of Consolidated Income for the three and nine months ended September 30, 2017.

The following unaudited pro forma financial information reflects the consolidated results of operations of CERC, assuming the AEM acquisition had taken place on January 1, 2016. Adjustments to pro forma net income include intercompany sales, amortization of intangible assets, depreciation of fixed assets, interest expense associated with debt financing to fund the acquisition, and related income tax effects. The pro forma information does not include the mark-to-market impact of financial instruments designated as cash flow hedges of anticipated purchases and sales at index prices. The effective portion of these hedges are excluded from earnings and reported as changes in Other Comprehensive Income. Additionally, the pro forma information does not include the mark-to-market impact of physical forward transactions that were previously accounted for as normal purchase and sale transactions.

The unaudited pro forma financial information has been presented for illustrative purposes only and is not necessarily indicative of the consolidated results of operations that would have been achieved had the acquisition taken place on the dates indicated or the future consolidated results of operations of the combined company.

	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
	(in millions)
Operating Revenue	$	1,251	$	1,234	$	4,731	$	3,819
Net Income	38		43		239		173

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Employee Benefit Plans

9 Months Ended

Sep. 30, 2017

Compensation and Retirement Disclosure [Abstract]

Employee Benefits Plans [Text Block]

Employee Benefit Plans

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2017			2016			2017			2016
	(in millions)
Service cost	$	1		$	1		$	1		$	1
Interest cost	1			1			3			3
Expected return on plan assets	(1		)	(1		)	(1		)	(1		)
Amortization of prior service cost	—			—			1			—
Net periodic cost (1)	$	1		$	1		$	4		$	3

(1) Net periodic cost in this table is before considering amounts subject to overhead allocations for capital expenditure projects or for amounts subject to deferral for regulatory purposes.  

CERC expects to contribute approximately $5 million to its postretirement benefit plan in 2017, of which approximately $1 million and $4 million were contributed during the three and nine months ended September 30, 2017, respectively.

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Regulatory Accounting

9 Months Ended

Sep. 30, 2017

Regulatory Assets and Liabilities, Other Disclosures [Abstract]

Regulatory Accounting [Text Block]

Regulatory Accounting

Hurricane Harvey. NGD suffered damage as a result of Hurricane Harvey, a major storm classified as a Category 4 hurricane on the Saffir-Simpson Hurricane Wind Scale, that first struck the Texas coast on Friday, August 25, 2017 and remained over the Houston area for the next several days. The unprecedented flooding from torrential amounts of rainfall accompanying the storm caused significant damage to or destruction of residences and businesses served by NGD.

Currently, NGD estimates that total costs to restore natural gas distribution facilities damaged as a result of Hurricane Harvey will range from $25 million to $30 million and estimates that the total restoration costs covered by insurance will be approximately $17 million.  NGD will defer the uninsured storm restoration costs as management believes it is probable that such costs will be recovered through traditional rate adjustment mechanisms for capital costs and through the next rate proceeding for operation and maintenance expenses. As of September 30, 2017, NGD has recorded approximately $7 million in regulatory assets, net of $2 million of insurance receivables recorded, for restoration costs incurred. As a result, storm restoration costs should not materially affect CERC’s reported net income for 2017.

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Derivative Instruments

9 Months Ended

Sep. 30, 2017

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments [Text Block]

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, weather and interest rates 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 mitigate the effects of commodity price movements. Certain financial instruments used to hedge portions of the natural gas inventory of the Energy Services business segment are designated as fair value hedges for accounting purposes. All other 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 entered into heating-degree day swaps for certain NGD Texas jurisdictions to mitigate the effect of fluctuations from normal weather on its results of operations and cash flows for the 2017–2018 winter heating season, which contained a bilateral dollar cap of $8 million. However, CERC did not enter into heating-degree day swaps for NGD jurisdictions for the 2015–2016 or 2016–2017 winter heating seasons.

Hedging of Interest Expense for Future Debt Issuances. In August 2017, CERC Corp. entered into forward interest rate agreements with several counterparties, having an aggregate notional amount of $150 million. These agreements were executed to hedge, in part, volatility in the 30-year U.S. treasury rate by reducing CERC Corp.’s exposure to variability in cash flows related to interest payments of CERC Corp.’s $300 million issuance of fixed rate debt in August 2017. These forward interest rate agreements were designated as cash flow hedges. Accordingly, the effective portion of realized losses associated with the agreements, which totaled approximately $1.5 million, is a component of accumulated other comprehensive income in 2017 and will be amortized over the life of the notes.

(b) Derivative Fair Values and Income Statement Impacts

The following tables present information about CERC’s derivative instruments and hedging activities. The first four tables provide a balance sheet overview of CERC’s Derivative Assets and Liabilities as of September 30, 2017 and December 31, 2016, while the last table provides a breakdown of the related income statement impacts for the three and nine months ended September 30, 2017 and 2016.

Fair Value of Derivative Instruments
	September 30, 2017
Derivatives designated as fair value hedges:	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	$	—	$	—
Natural gas derivatives (1) (2) (3)	Current Liabilities: Non-trading derivative liabilities	5		—
Derivatives not designated as hedging instruments:
Natural gas derivatives (1) (2) (3)	Current Assets: Non-trading derivative assets	65		2
Natural gas derivatives (1) (2) (3)	Other Assets: Non-trading derivative assets	58		2
Natural gas derivatives (1) (2) (3)	Current Liabilities: Non-trading derivative liabilities	27		55
Natural gas derivatives (1) (2) (3)	Other Liabilities: Non-trading derivative liabilities	9		25
Total		$	164	$	84

(1) The fair value shown for natural gas contracts is comprised of derivative gross volumes totaling 1,866 Bcf or a net 46 Bcf long position.  Certain natural gas contracts hedge basis risk only and lack a fixed price exposure.

(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 $93 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, impacted by collateral netting of $13 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
	September 30, 2017
	Gross AmountsRecognized (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	$	97		$	(33	)	$	64
Other Assets: Non-trading derivative assets	67			(11		)	56
Current Liabilities: Non-trading derivative liabilities	(57		)	40			(17		)
Other Liabilities: Non-trading derivative liabilities	(27		)	17			(10		)
Total	$	80		$	13		$	93

(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, 2016
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	$	79	$	14
Natural gas derivatives (1) (2) (3)	Other Assets: Non-trading derivative assets	24		5
Natural gas derivatives (1) (2) (3)	Current Liabilities: Non-trading derivative liabilities	2		43
Natural gas derivatives (1) (2) (3)	Other Liabilities: Non-trading derivative liabilities	—		5
Total (4)		$	105	$	67

(1) The fair value shown for natural gas contracts is comprised of derivative gross volumes totaling 1,035 Bcf or a net 59 Bcf long position.  Certain natural gas contracts hedge basis risk only and lack a fixed price exposure.

(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 $24 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, impacted by collateral netting of $14 million.

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

(4) No derivatives were designated as fair value hedges as of December 31, 2016.

Offsetting of Natural Gas Derivative Assets and Liabilities
	December 31, 2016
	Gross AmountsRecognized (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	$	81		$	(30	)	$	51
Other Assets: Non-trading derivative assets	24			(5		)	19
Current Liabilities: Non-trading derivative liabilities	(57		)	16			(41		)
Other Liabilities: Non-trading derivative liabilities	(10		)	5			(5		)
Total	$	38		$	(14	)	$	24

(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 physical sales derivative contracts and as natural gas expense for financial natural gas derivatives and physical purchase natural gas derivatives.

Hedge ineffectiveness is recorded as a component of natural gas expense and primarily results from differences in the location of the derivative instrument and the hedged item. Basis ineffectiveness arises from natural gas market price differences between the locations of the hedged inventory and the delivery location specified in the hedge instruments. The impact of natural gas derivatives designated as fair value hedges, the related hedged item, and natural gas derivatives not designated as hedging instruments are presented in the table below.

Income Statement Impact of Derivative Activity
		Three Months Ended September 30,
	Income Statement Location	2017			2016
Derivatives designated as fair value hedges:		(in millions)
Natural gas derivatives	Gains (Losses) in Expenses: Natural Gas	$	(4	)	$	—
Fair value adjustments for natural gas inventory designated as the hedged item	Gains (Losses) in Expenses: Natural Gas	4			—
Total increase in Expenses: Natural Gas (1)		$	—		$	—
Derivatives not designated as hedging instruments:
Natural gas derivatives	Gains (Losses) in Revenues	$	30		$	31
Natural gas derivatives	Gains (Losses) in Expenses: Natural Gas	(9		)	(13		)
Total - derivatives not designated as hedging instruments		$	21		$	18

Income Statement Impact of Derivative Activity
		Nine Months Ended September 30,
	Income Statement Location	2017			2016
Derivatives designated as fair value hedges:		(in millions)
Natural gas derivatives	Gains (Losses) in Expenses: Natural Gas	$	8		$	—
Fair value adjustments for natural gas inventory designated as the hedged item	Gains (Losses) in Expenses: Natural Gas	(10		)	—
Total increase in Expenses: Natural Gas (1)		$	(2	)	$	—
Derivatives not designated as hedging instruments:
Natural gas derivatives	Gains (Losses) in Revenues	$	162		$	1
Natural gas derivatives	Gains (Losses) in Expenses: Natural Gas	(91		)	35
Total - derivatives not designated as hedging instruments		$	71		$	36

(1) Hedge ineffectiveness results from the basis ineffectiveness discussed above, and excludes the impact to natural gas expense from timing ineffectiveness.  Timing ineffectiveness arises due to changes in the difference between the spot price and the futures price, as well as the difference between the timing of the settlement of the futures and the valuation of the underlying physical commodity.  As the commodity contract nears the settlement date, spot-to-forward price differences should converge, which should reduce or eliminate the impact of this ineffectiveness on natural gas expense.

(c) Credit Risk Contingent Features

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 September 30, 2017 and December 31, 2016 was $1 million.  CERC posted no assets as collateral toward derivative instruments that contain credit risk contingent features as of either September 30, 2017 or December 31, 2016. If all derivative contracts (in a net liability position) containing credit risk contingent features were triggered as of September 30, 2017 and December 31, 2016, $1 million and $-0-, respectively, of additional assets would be required to be posted as collateral.

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Fair Value Measurements

9 Months Ended

Sep. 30, 2017

Fair Value Disclosures [Abstract]

Fair Value Measurements [Text Block]

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, as well as natural gas inventory that has been designated as the hedged item in a fair value hedge.

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 September 30, 2017, CERC’s Level 3 assets and liabilities are comprised of physical natural gas forward contracts and options. Level 3 physical natural gas forward contracts are valued using a discounted cash flow model which includes illiquid forward price curve locations (ranging from $1.08 to $5.83 per MMBtu) 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 87%) as an unobservable input.  CERC’s Level 3 physical natural gas forward contracts and options derivative assets and liabilities consist of both long and short positions (forwards and options) and their fair value is sensitive to forward prices and volatilities.  If forward prices decrease, CERC’s long forwards lose value whereas its short forwards gain in value.  If volatility decreases, CERC’s long options lose value whereas its short options gain in value.

CERC determines the appropriate level for each financial asset and liability on a quarterly basis and recognizes transfers between levels at the end of the reporting period.  For the nine months ended September 30, 2017, there were no transfers between Level 1 and 2. CERC also recognizes purchases of Level 3 financial assets and liabilities at their fair market value at the end of the reporting period.

The following tables present information about CERC’s assets and liabilities (including derivatives that are presented net) measured at fair value on a recurring basis as of September 30, 2017 and December 31, 2016, and indicate the fair value hierarchy of the valuation techniques utilized by CERC to determine such fair value.

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Netting Adjustments (1)			Balance as of September 30, 2017
	(in millions)
Assets
Corporate equities	$	3	$	—	$	—	$	—		$	3
Investments, including money market funds (2)	11		—		—		—			11
Natural gas derivatives (3)	3		128		33		(44		)	120
Hedged portion of natural gas inventory	65		—		—		—			65
Total assets	$	82	$	128	$	33	$	(44	)	$	199
Liabilities
Natural gas derivatives (3)	$	3	$	74	$	7	$	(57	)	$	27
Total liabilities	$	3	$	74	$	7	$	(57	)	$	27

(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 $13 million posted with the same counterparties.

(2) Amounts are included in Other 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, 2016
	(in millions)
Assets
Corporate equities	$	3	$	—	$	—	$	—		$	3
Investments, including money market funds (2)	10		—		—		—			10
Natural gas derivatives (3)	11		74		20		(35		)	70
Total assets	$	24	$	74	$	20	$	(35	)	$	83
Liabilities
Natural gas derivatives (3)	$	4	$	56	$	7	$	(21	)	$	46
Total liabilities	$	4	$	56	$	7	$	(21	)	$	46

(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 $14 million held by CES from the same counterparties.

(2) Amounts are included in Other 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 September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(in millions)
Beginning balance	$	28		$	16		$	13		$	12
Purchases (1)	—			—			—			12
Total gains	(2		)	9			21			13
Total settlements	(1		)	(8		)	(5		)	(24		)
Transfers into Level 3	7			—			9			5
Transfers out of Level 3	(6		)	—			(12		)	(1		)
Ending balance (2)	$	26		$	17		$	26		$	17
The amount of total gains for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the reporting date	$	—		$	6		$	17		$	14

(1) Mark-to-market value of Level 3 derivative assets acquired through the purchase of AEM was less than $1 million at the acquisition date.

(2) CERC did not have significant Level 3 sales during either of the three or nine months ended September 30, 2017 or 2016.

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. The carrying amounts of 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 a combination of historical trading prices and comparable issue data. These 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 2 in the fair value hierarchy.

	September 30, 2017				December 31, 2016
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in millions)
Financial liabilities:
Long-term debt	$	2,636	$	2,854	$	2,375	$	2,551

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Unconsolidated Affiliate

9 Months Ended

Sep. 30, 2017

Equity Method Investments and Joint Ventures [Abstract]

Unconsolidated Affiliate [Text Block]

Unconsolidated Affiliate

CERC Corp. has the ability to significantly influence the operating and financial policies of Enable, a publicly traded MLP, and, accordingly, accounts for its investment in Enable’s common units using the equity method of accounting.

CERC Corp.’s maximum exposure to loss related to Enable, a VIE in which CERC Corp. is not the primary beneficiary, is limited to its equity investment as presented in the Condensed Consolidated Balance Sheets as of September 30, 2017 and outstanding current accounts receivable from Enable.

Transactions with Enable:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
	(in millions)
Reimbursement of transition services (1)	$	—	$	1	$	3	$	6
Natural gas expenses, including transportation and storage costs	23		22		80		79
Interest income related to notes receivable from Enable	—		—		—		1

(1) Represents amounts billed under the Transition Agreements for certain support services provided to Enable. Actual transition services costs are recorded net of reimbursement.

	September 30, 2017		December 31, 2016
	(in millions)
Accounts receivable for amounts billed for transition services	$	1	$	1
Accounts payable for natural gas purchases from Enable	8		10

Limited Partner Interest in Enable:

	September 30, 2017
CERC Corp.	54.1	%
OGE	25.7	%

In November 2016, Enable completed a public offering of 11,500,000 common units of which 1,424,281 were sold by ArcLight Capital Partners, LLC. The common units issued and sold by Enable resulted in dilution of both CERC Corp.’s and OGE’s limited partner interest in Enable.

Enable Common Units Held:

	September 30, 2017
CERC Corp.	233,856,623
OGE	110,982,805

The 139,704,916 subordinated units previously owned by CERC Corp. converted into common units of Enable on a one-for-one basis on August 30, 2017, at the end of the subordination period, as set forth in Enable’s Fourth Amended and Restated Agreement of Limited Partnership. Upon conversion, holders of common units resulting from the conversion of subordinated units have all the rights and obligations of unitholders holding all other common units, including the right to receive distributions pro rata made with respect to common units.

Generally, sales of more than 5% of the aggregate of the common units CERC Corp. owns in Enable or sales by OGE of more than 5% of the aggregate of the common units it owns in Enable are subject to mutual rights of first offer and first refusal.

Enable is controlled jointly by CERC Corp. and OGE, and each own 50% of the management rights in the general partner of Enable. Sale of CERC Corp.’s or OGE’s ownership interests in Enable’s general partner to a third party is subject to mutual rights of first offer and first refusal, and CERC Corp. is not permitted to dispose of less than all of its interest in Enable’s general partner.

Summarized unaudited consolidated income information for Enable is as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
	(in millions)
Operating revenues	$	705	$	620	$	1,997	$	1,658
Cost of sales, excluding depreciation and amortization	349		268		936		717
Impairment of goodwill and other long-lived assets	—		8		—		8
Operating income	137		139		399		299
Net income attributable to Enable	104		110		301		231
Reconciliation of Equity in Earnings, net:
CERC Corp.’s interest	$	56	$	61	$	163	$	128
Basis difference amortization (1)	12		12		36		36
CERC Corp.’s equity in earnings, net	$	68	$	73	$	199	$	164

(1) Equity in earnings of unconsolidated affiliates includes CERC Corp.’s share of Enable’s earnings adjusted for the amortization of the basis difference of CERC Corp.’s original investment in Enable and its underlying equity in Enable’s net assets. The basis difference is amortized over approximately 33 years, the average life of the assets to which the basis difference is attributed.

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

	September 30, 2017			December 31, 2016
	(in millions)
Current assets	$	446		$	396
Non-current assets	10,816			10,816
Current liabilities	831			362
Non-current liabilities	2,740			3,056
Non-controlling interest	12			12
Preferred equity	362			362
Enable partners’ equity	7,317			7,420
Reconciliation of Equity Method Investment in Enable:
CERC Corp.’s ownership interest in Enable partners’ capital	$	4,007		$	4,067
CERC Corp.’s basis difference	(1,526		)	(1,562		)
CERC Corp.’s equity method investment in Enable	$	2,481		$	2,505

Distributions Received from Unconsolidated Affiliate:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
	(in millions)
Investment in Enable’s common units	$	74	$	74	$	223	$	223

As of September 30, 2017, CERC Corp. and OGE also own 40% and 60%, respectively, of the incentive distribution rights held by the general partner of Enable. Enable is expected to pay a minimum quarterly distribution of $0.2875 per common 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, within 60 days after the end of each quarter. If cash distributions to Enable’s unitholders exceed $0.330625 per common unit in any quarter, the general partner will receive increasing percentages or incentive distributions rights, up to 50%, of the cash Enable distributes in excess of that amount. In certain circumstances the general partner of Enable will have the right to reset the minimum quarterly distribution and the target distribution levels at which the incentive distributions receive increasing percentages to higher levels based on Enable’s cash distributions at the time of the exercise of this reset election. To date, no incentive distributions have been made.

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Goodwill

9 Months Ended

Sep. 30, 2017

Goodwill and Intangible Assets Disclosure [Abstract]

Goodwill [Text Block]

Goodwill

Goodwill by reportable business segment as of December 31, 2016 and changes in the carrying amount of goodwill as of September 30, 2017 are as follows:

	December 31, 2016			AEM Acquisition (1)		September 30, 2017
	(in millions)
Natural Gas Distribution	$	746		$	—	$	746
Energy Services	105		(2)	5		110		(2)
Other Operations	11			—		11
Total	$	862		$	5	$	867

(1) See Note 3.

(2) Amount presented is net of the accumulated goodwill impairment charge of $252 million recorded in 2012.

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

CERC performed its annual impairment test in the third quarter of 2017 and determined, based on the results of the first step, that no impairment charge was required for any reportable segment.

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Related Party Transactions

9 Months Ended

Sep. 30, 2017

Related Party Transactions [Abstract]

Related Party Transactions [Text Block]

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 September 30, 2017 and December 31, 2016, which would be 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 nine months ended September 30, 2017 or 2016.

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 by CERC for these services were as follows and are included primarily in operation and maintenance expenses:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(in millions)
Corporate service charges	$	30		$	31		$	93		$	90
Charges from Houston Electric for services provided	3			4			11			11
Billings to Houston Electric for services provided	(2		)	(2		)	(5		)	(5		)

See Note 8 for related party transactions with Enable.

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Short-term Borrowings and Long-term Debt

9 Months Ended

Sep. 30, 2017

Debt Disclosure [Abstract]

Short-term Borrowings and Long-term Debt [Text Block]

Short-term Borrowings and Long-term Debt

(a)Short-term Borrowings

Inventory Financing. NGD currently has AMAs associated with its utility distribution service in Arkansas, north Louisiana and Oklahoma that extend through 2020. 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 an inventory financing and had an associated principal obligation of $48 million and $35 million as of September 30, 2017 and December 31, 2016, respectively.

(b) Long-term Debt

Debt Issuances. During the nine months ended September 30, 2017, CERC issued the following unsecured senior notes:

Issuance Date	Aggregate Principal Amount		Interest Rate	Maturity Date
	(in millions)
August 2017	$	300	4.10%	2047

The proceeds from the issuance of these unsecured senior notes were used for general corporate purposes and to repay a portion of outstanding commercial paper.

Revolving Credit Facility.  In June 2017, CERC entered into an amendment to its revolving credit facility to extend the termination date thereof from March 3, 2021 to March 3, 2022 and to terminate the swingline loan subfacility thereunder. The amendment also increased the aggregate commitments by $300 million to $900 million under its revolving credit facility. In connection with the amendment to increase the aggregate commitments under its revolving credit facility, CERC increased the size of its commercial paper program to permit the issuance of commercial paper notes in an aggregate principal amount not to exceed $900 million at any time outstanding.

As of September 30, 2017 and December 31, 2016, CERC had the following revolving credit facility and utilization of such facility:

September 30, 2017									December 31, 2016
Size of Facility		Loans		Letters of Credit		Commercial Paper			Size of Facility		Loans		Letters of Credit		Commercial Paper
(in millions)
$	900	$	—	$	—	$	529	(1)	$	600	$	—	$	4	$	569	(1)

(1) Weighted average interest rate was approximately 1.43% and 1.03% as of September 30, 2017 and December 31, 2016, respectively.

Execution Date	Size of Facility			Draw Rate of LIBOR plus (2)		Financial Covenant Limit on Debt for Borrowed Money to Capital Ratio		Debt for Borrowed Money to Capital Ratio as of September 30, 2017	Termination Date (3)
	(in millions)
March 3, 2016	$	900	(1)	1.25	%	65	%	38.6%	March 3, 2022

(1) Amended on June 16, 2017 to increase the aggregate commitment size as noted above.

(2) Based on current credit ratings.

(3) Amended on June 16, 2017 to extend the termination date as noted above.

CERC Corp. was in compliance with all financial debt covenants as of September 30, 2017.

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Commitments and Contingencies

9 Months Ended

Sep. 30, 2017

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies [Text Block]

Commitments and Contingencies

(a) Natural Gas Supply Commitments

Natural gas supply commitments include natural gas contracts related to CERC’s Natural Gas Distribution and Energy Services business segments, which have various quantity requirements and durations, that are not classified as non-trading derivative assets and liabilities in CERC’s Condensed Consolidated Balance Sheets as of September 30, 2017 and December 31, 2016 as these contracts meet an exception as “normal purchases contracts” or do not meet the definition of a derivative. Natural gas supply commitments also include natural gas transportation contracts that do not meet the definition of a derivative. As of September 30, 2017, minimum payment obligations for natural gas supply commitments are approximately:

	(in millions)
Remaining three months of 2017	$	169
2018	507
2019	348
2020	166
2021	76
2022 and beyond	113

(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.

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. The plaintiffs have appealed that ruling. CenterPoint Energy and CES intend to continue vigorously defending against the plaintiffs’ claims. In June 2017, GenOn and various affiliates filed for protection under Chapter 11 of the U.S. Bankruptcy Code. CenterPoint Energy, CERC, and CES submitted proofs of claim in the bankruptcy proceedings to protect their indemnity rights. If GenOn were unable to meet its indemnity obligations or satisfy a liability that has been assumed in the gas market manipulation litigation, then CERC, CenterPoint Energy or Houston Electric could incur liability and be responsible for satisfying the liability. CERC does not expect the ultimate outcome of the case against CES to have a material adverse effect on its financial condition, results of operations or cash flows.

Minnehaha Academy.  On August 2, 2017, a natural gas explosion occurred at the Minnehaha Academy in Minneapolis, Minnesota, resulting in the deaths of two school employees, serious injuries to others and significant property damage to the school.  CenterPoint Energy, certain of its subsidiaries, including CERC Corp., and the contractor company working in the school have been named in litigation arising out of this incident.  Additionally, CenterPoint Energy is cooperating with ongoing investigations conducted by the National Transportation Safety Board, the Minnesota Occupational Safety and Health Administration and the Minnesota Office of Pipeline Safety.  CenterPoint Energy’s general and excess liability insurance policies provide coverage for third party bodily injury and property damage claims. 

Environmental Matters

MGP 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 September 30, 2017, 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.

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Income Taxes

9 Months Ended

Sep. 30, 2017

Income Tax Disclosure [Abstract]

Income Taxes [Text Block]

Income Taxes

The effective tax rate reported for the three months ended September 30, 2017 was 40% compared to 38% for the same period in 2016. The effective tax rate reported for the nine months ended September 30, 2017 was 38% compared to 40% for the same period in 2016. The higher effective tax rate for the nine months ended September 30, 2016 was 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 September 30, 2017 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 2015. For the 2016 and 2017 tax years, CenterPoint Energy is a participant in the IRS’s Compliance Assurance Process.

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Reportable Business Segments

9 Months Ended

Sep. 30, 2017

Segment Reporting [Abstract]

Reportable Business Segments [Text Block]

Reportable Business Segments

CERC’s determination of reportable business segments considers the strategic operating units under which it 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 other than Midstream Investments, where it uses equity in earnings of unconsolidated affiliates.

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 equity investment in Enable. The Other Operations business segment includes unallocated corporate costs and inter-segment eliminations.

Financial data for business segments is as follows:

	For the Three Months Ended September 30, 2017
	Revenues from External Customers		Inter-segment Revenues			Operating Income
	(in millions)
Natural Gas Distribution	$	390	$	8		$	19
Energy Services	861		10			7
Midstream Investments (1)	—		—			—
Other Operations	—		—			—
Reconciling Eliminations	—		(18		)	—
Consolidated	$	1,251	$	—		$	26

	For the Three Months Ended September 30, 2016
	Revenues from External Customers		Inter-segment Revenues			Operating Income (Loss)
	(in millions)
Natural Gas Distribution	$	370	$	7		$	22
Energy Services	608		6			5
Midstream Investments (1)	—		—			—
Other Operations	—		—			(1		)
Reconciling Eliminations	—		(13		)	—
Consolidated	$	978	$	—		$	26

	For the Nine Months Ended September 30, 2017
	Revenues from External Customers		Inter-segment Revenues			Operating Income (Loss)			Total Assets as of September 30, 2017
	(in millions)
Natural Gas Distribution	$	1,767	$	24		$	220		$	6,067
Energy Services	2,964		34			58			1,337
Midstream Investments (1)	—		—			—			2,481
Other Operations	—		—			(5		)	73
Reconciling Eliminations	—		(58		)	—			(582		)
Consolidated	$	4,731	$	—		$	273		$	9,376

	For the Nine Months Ended September 30, 2016
	Revenues from External Customers		Inter-segment Revenues			Operating Income (Loss)			Total Assets as of December 31, 2016
	(in millions)
Natural Gas Distribution	$	1,672	$	21		$	202		$	6,099
Energy Services	1,433		17			11			1,102
Midstream Investments (1)	—		—			—			2,505
Other Operations	—		—			(3		)	75
Reconciling Eliminations	—		(38		)	—			(563		)
Consolidated	$	3,105	$	—		$	210		$	9,218

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
	(in millions)
Enable	$	68	$	73	$	199	$	164

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Other Current Assets and Liabilities

9 Months Ended

Sep. 30, 2017

Other Current Assets and Liabilities [Abstract]

Other Current Assets and Liabilities [Text Block]

Other Current Assets and Liabilities

Included in other current assets on the Condensed Consolidated Balance Sheets as of September 30, 2017 and December 31, 2016 were $22 million and less than $1 million, respectively, of margin deposits and $55 million and $40 million, respectively, of under-recovered gas cost. Included in other current liabilities on the Condensed Consolidated Balance Sheets at September 30, 2017 and December 31, 2016 were $2 million and $10 million, respectively, of over-recovered gas cost.

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Subsequent Events

9 Months Ended

Sep. 30, 2017

Subsequent Events [Abstract]

Subsequent Events [Text Block]

Subsequent Events

On October 31, 2017, Enable declared a quarterly cash distribution of $0.318 per unit on all of its outstanding common units for the quarter ended September 30, 2017. Accordingly, CERC Corp. expects to receive a cash distribution of approximately $74 million from Enable in the fourth quarter of 2017 to be made with respect to CERC Corp.’s investment in common units of Enable for the third quarter of 2017.

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Acquisition (Tables)

9 Months Ended

Sep. 30, 2017

Business Combinations [Abstract]

Schedule of Business Acquisitions, by Acquisition [Table Text Block]

The following table summarizes the final 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	$	147
Cash	$	15
Receivables	140
Natural gas inventory	78
Derivative assets	35
Prepaid expenses and other current assets	5
Property and equipment	8
Identifiable intangibles	25
Total assets acquired	306
Accounts payable	113
Derivative liabilities	43
Other current liabilities	7
Other liabilities	1
Total liabilities assumed	164
Identifiable net assets acquired	142
Goodwill	5
Net assets acquired	$	147

Schedule of Finite-Lived Intangible Assets Acquired as Part of Business Combination [Table Text Block]

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

	Estimate Fair Value		Estimate Useful Life
	(in millions)		(in years)
Customer relationships	$	25	15

Business Acquisition, Pro Forma Information [Table Text Block]

The following unaudited pro forma financial information reflects the consolidated results of operations of CERC, assuming the AEM acquisition had taken place on January 1, 2016. Adjustments to pro forma net income include intercompany sales, amortization of intangible assets, depreciation of fixed assets, interest expense associated with debt financing to fund the acquisition, and related income tax effects. The pro forma information does not include the mark-to-market impact of financial instruments designated as cash flow hedges of anticipated purchases and sales at index prices. The effective portion of these hedges are excluded from earnings and reported as changes in Other Comprehensive Income. Additionally, the pro forma information does not include the mark-to-market impact of physical forward transactions that were previously accounted for as normal purchase and sale transactions.

The unaudited pro forma financial information has been presented for illustrative purposes only and is not necessarily indicative of the consolidated results of operations that would have been achieved had the acquisition taken place on the dates indicated or the future consolidated results of operations of the combined company.

	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
	(in millions)
Operating Revenue	$	1,251	$	1,234	$	4,731	$	3,819
Net Income	38		43		239		173

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Employee Benefit Plans (Tables)

9 Months Ended

Sep. 30, 2017

Compensation and Retirement Disclosure [Abstract]

Schedule of Net Benefit Costs [Table Text Block]

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2017			2016			2017			2016
	(in millions)
Service cost	$	1		$	1		$	1		$	1
Interest cost	1			1			3			3
Expected return on plan assets	(1		)	(1		)	(1		)	(1		)
Amortization of prior service cost	—			—			1			—
Net periodic cost (1)	$	1		$	1		$	4		$	3

(1) Net periodic cost in this table is before considering amounts subject to overhead allocations for capital expenditure projects or for amounts subject to deferral for regulatory purposes.

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Derivative Instruments (Tables)

9 Months Ended

Sep. 30, 2017

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Fair Value of Derivative Instruments [Table Text Block]

Fair Value of Derivative Instruments
	December 31, 2016
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	$	79	$	14
Natural gas derivatives (1) (2) (3)	Other Assets: Non-trading derivative assets	24		5
Natural gas derivatives (1) (2) (3)	Current Liabilities: Non-trading derivative liabilities	2		43
Natural gas derivatives (1) (2) (3)	Other Liabilities: Non-trading derivative liabilities	—		5
Total (4)		$	105	$	67

(1) The fair value shown for natural gas contracts is comprised of derivative gross volumes totaling 1,035 Bcf or a net 59 Bcf long position.  Certain natural gas contracts hedge basis risk only and lack a fixed price exposure.

(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 $24 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, impacted by collateral netting of $14 million.

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

(4) No derivatives were designated as fair value hedges as of December 31, 2016.

The following tables present information about CERC’s derivative instruments and hedging activities. The first four tables provide a balance sheet overview of CERC’s Derivative Assets and Liabilities as of September 30, 2017 and December 31, 2016, while the last table provides a breakdown of the related income statement impacts for the three and nine months ended September 30, 2017 and 2016.

Fair Value of Derivative Instruments
	September 30, 2017
Derivatives designated as fair value hedges:	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	$	—	$	—
Natural gas derivatives (1) (2) (3)	Current Liabilities: Non-trading derivative liabilities	5		—
Derivatives not designated as hedging instruments:
Natural gas derivatives (1) (2) (3)	Current Assets: Non-trading derivative assets	65		2
Natural gas derivatives (1) (2) (3)	Other Assets: Non-trading derivative assets	58		2
Natural gas derivatives (1) (2) (3)	Current Liabilities: Non-trading derivative liabilities	27		55
Natural gas derivatives (1) (2) (3)	Other Liabilities: Non-trading derivative liabilities	9		25
Total		$	164	$	84

(1) The fair value shown for natural gas contracts is comprised of derivative gross volumes totaling 1,866 Bcf or a net 46 Bcf long position.  Certain natural gas contracts hedge basis risk only and lack a fixed price exposure.

(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 $93 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, impacted by collateral netting of $13 million.

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

Derivative Instruments, Offsetting Assets and Liabilities [Table Text Block]

Offsetting of Natural Gas Derivative Assets and Liabilities
	September 30, 2017
	Gross AmountsRecognized (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	$	97		$	(33	)	$	64
Other Assets: Non-trading derivative assets	67			(11		)	56
Current Liabilities: Non-trading derivative liabilities	(57		)	40			(17		)
Other Liabilities: Non-trading derivative liabilities	(27		)	17			(10		)
Total	$	80		$	13		$	93

(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.

Offsetting of Natural Gas Derivative Assets and Liabilities
	December 31, 2016
	Gross AmountsRecognized (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	$	81		$	(30	)	$	51
Other Assets: Non-trading derivative assets	24			(5		)	19
Current Liabilities: Non-trading derivative liabilities	(57		)	16			(41		)
Other Liabilities: Non-trading derivative liabilities	(10		)	5			(5		)
Total	$	38		$	(14	)	$	24

(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.

Income Statement Impact of Derivative Activity [Table Text Block]

Hedge ineffectiveness is recorded as a component of natural gas expense and primarily results from differences in the location of the derivative instrument and the hedged item. Basis ineffectiveness arises from natural gas market price differences between the locations of the hedged inventory and the delivery location specified in the hedge instruments. The impact of natural gas derivatives designated as fair value hedges, the related hedged item, and natural gas derivatives not designated as hedging instruments are presented in the table below.

Income Statement Impact of Derivative Activity
		Three Months Ended September 30,
	Income Statement Location	2017			2016
Derivatives designated as fair value hedges:		(in millions)
Natural gas derivatives	Gains (Losses) in Expenses: Natural Gas	$	(4	)	$	—
Fair value adjustments for natural gas inventory designated as the hedged item	Gains (Losses) in Expenses: Natural Gas	4			—
Total increase in Expenses: Natural Gas (1)		$	—		$	—
Derivatives not designated as hedging instruments:
Natural gas derivatives	Gains (Losses) in Revenues	$	30		$	31
Natural gas derivatives	Gains (Losses) in Expenses: Natural Gas	(9		)	(13		)
Total - derivatives not designated as hedging instruments		$	21		$	18

Income Statement Impact of Derivative Activity
		Nine Months Ended September 30,
	Income Statement Location	2017			2016
Derivatives designated as fair value hedges:		(in millions)
Natural gas derivatives	Gains (Losses) in Expenses: Natural Gas	$	8		$	—
Fair value adjustments for natural gas inventory designated as the hedged item	Gains (Losses) in Expenses: Natural Gas	(10		)	—
Total increase in Expenses: Natural Gas (1)		$	(2	)	$	—
Derivatives not designated as hedging instruments:
Natural gas derivatives	Gains (Losses) in Revenues	$	162		$	1
Natural gas derivatives	Gains (Losses) in Expenses: Natural Gas	(91		)	35
Total - derivatives not designated as hedging instruments		$	71		$	36

(1) Hedge ineffectiveness results from the basis ineffectiveness discussed above, and excludes the impact to natural gas expense from timing ineffectiveness.  Timing ineffectiveness arises due to changes in the difference between the spot price and the futures price, as well as the difference between the timing of the settlement of the futures and the valuation of the underlying physical commodity.  As the commodity contract nears the settlement date, spot-to-forward price differences should converge, which should reduce or eliminate the impact of this ineffectiveness on natural gas expense.

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Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2017

Fair Value Disclosures [Abstract]

Fair Value, Assets Measured on Recurring Basis [Table Text Block]

The following tables present information about CERC’s assets and liabilities (including derivatives that are presented net) measured at fair value on a recurring basis as of September 30, 2017 and December 31, 2016, and indicate the fair value hierarchy of the valuation techniques utilized by CERC to determine such fair value.

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Netting Adjustments (1)			Balance as of September 30, 2017
	(in millions)
Assets
Corporate equities	$	3	$	—	$	—	$	—		$	3
Investments, including money market funds (2)	11		—		—		—			11
Natural gas derivatives (3)	3		128		33		(44		)	120
Hedged portion of natural gas inventory	65		—		—		—			65
Total assets	$	82	$	128	$	33	$	(44	)	$	199
Liabilities
Natural gas derivatives (3)	$	3	$	74	$	7	$	(57	)	$	27
Total liabilities	$	3	$	74	$	7	$	(57	)	$	27

(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 $13 million posted with the same counterparties.

(2) Amounts are included in Other 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, 2016
	(in millions)
Assets
Corporate equities	$	3	$	—	$	—	$	—		$	3
Investments, including money market funds (2)	10		—		—		—			10
Natural gas derivatives (3)	11		74		20		(35		)	70
Total assets	$	24	$	74	$	20	$	(35	)	$	83
Liabilities
Natural gas derivatives (3)	$	4	$	56	$	7	$	(21	)	$	46
Total liabilities	$	4	$	56	$	7	$	(21	)	$	46

(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 $14 million held by CES from the same counterparties.

(2) Amounts are included in Other Assets in the Condensed Consolidated Balance Sheets.

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

Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Table Text Block]

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

	Fair Value Measurements Using Significant  Unobservable Inputs (Level 3)
	Derivative Assets and Liabilities, Net
	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(in millions)
Beginning balance	$	28		$	16		$	13		$	12
Purchases (1)	—			—			—			12
Total gains	(2		)	9			21			13
Total settlements	(1		)	(8		)	(5		)	(24		)
Transfers into Level 3	7			—			9			5
Transfers out of Level 3	(6		)	—			(12		)	(1		)
Ending balance (2)	$	26		$	17		$	26		$	17
The amount of total gains for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the reporting date	$	—		$	6		$	17		$	14

(1) Mark-to-market value of Level 3 derivative assets acquired through the purchase of AEM was less than $1 million at the acquisition date.

(2) CERC did not have significant Level 3 sales during either of the three or nine months ended September 30, 2017 or 2016.

Fair Value, by Balance Sheet Grouping [Table Text Block]

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. The carrying amounts of 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 a combination of historical trading prices and comparable issue data. These 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 2 in the fair value hierarchy.

	September 30, 2017				December 31, 2016
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in millions)
Financial liabilities:
Long-term debt	$	2,636	$	2,854	$	2,375	$	2,551

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Unconsolidated Affiliate (Tables)

9 Months Ended

Sep. 30, 2017

Equity Method Investments and Joint Ventures [Abstract]

Equity Method Investments [Table Text Block]

Summarized unaudited consolidated income information for Enable is as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
	(in millions)
Operating revenues	$	705	$	620	$	1,997	$	1,658
Cost of sales, excluding depreciation and amortization	349		268		936		717
Impairment of goodwill and other long-lived assets	—		8		—		8
Operating income	137		139		399		299
Net income attributable to Enable	104		110		301		231
Reconciliation of Equity in Earnings, net:
CERC Corp.’s interest	$	56	$	61	$	163	$	128
Basis difference amortization (1)	12		12		36		36
CERC Corp.’s equity in earnings, net	$	68	$	73	$	199	$	164

(1) Equity in earnings of unconsolidated affiliates includes CERC Corp.’s share of Enable’s earnings adjusted for the amortization of the basis difference of CERC Corp.’s original investment in Enable and its underlying equity in Enable’s net assets. The basis difference is amortized over approximately 33 years, the average life of the assets to which the basis difference is attributed.

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

	September 30, 2017			December 31, 2016
	(in millions)
Current assets	$	446		$	396
Non-current assets	10,816			10,816
Current liabilities	831			362
Non-current liabilities	2,740			3,056
Non-controlling interest	12			12
Preferred equity	362			362
Enable partners’ equity	7,317			7,420
Reconciliation of Equity Method Investment in Enable:
CERC Corp.’s ownership interest in Enable partners’ capital	$	4,007		$	4,067
CERC Corp.’s basis difference	(1,526		)	(1,562		)
CERC Corp.’s equity method investment in Enable	$	2,481		$	2,505

Distributions Received from Unconsolidated Affiliate:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
	(in millions)
Investment in Enable’s common units	$	74	$	74	$	223	$	223

Transactions with Enable:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
	(in millions)
Reimbursement of transition services (1)	$	—	$	1	$	3	$	6
Natural gas expenses, including transportation and storage costs	23		22		80		79
Interest income related to notes receivable from Enable	—		—		—		1

(1) Represents amounts billed under the Transition Agreements for certain support services provided to Enable. Actual transition services costs are recorded net of reimbursement.

	September 30, 2017		December 31, 2016
	(in millions)
Accounts receivable for amounts billed for transition services	$	1	$	1
Accounts payable for natural gas purchases from Enable	8		10

Limited Partner Interest in Enable:

	September 30, 2017
CERC Corp.	54.1	%
OGE	25.7	%

Enable Common Units Held:

	September 30, 2017
CERC Corp.	233,856,623
OGE	110,982,805

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Goodwill (Tables)

9 Months Ended

Sep. 30, 2017

Goodwill and Intangible Assets Disclosure [Abstract]

Schedule of Goodwill [Table Text Block]

Goodwill by reportable business segment as of December 31, 2016 and changes in the carrying amount of goodwill as of September 30, 2017 are as follows:

	December 31, 2016			AEM Acquisition (1)		September 30, 2017
	(in millions)
Natural Gas Distribution	$	746		$	—	$	746
Energy Services	105		(2)	5		110		(2)
Other Operations	11			—		11
Total	$	862		$	5	$	867

(1) See Note 3.

(2) Amount presented is net of the accumulated goodwill impairment charge of $252 million recorded in 2012.

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Related Party Transactions (Tables)

9 Months Ended

Sep. 30, 2017

Related Party Transactions [Abstract]

Schedule of Related Party Transactions [Table Text Block]

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 by CERC for these services were as follows and are included primarily in operation and maintenance expenses:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(in millions)
Corporate service charges	$	30		$	31		$	93		$	90
Charges from Houston Electric for services provided	3			4			11			11
Billings to Houston Electric for services provided	(2		)	(2		)	(5		)	(5		)

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

9 Months Ended

Sep. 30, 2017

Debt Disclosure [Abstract]

Schedule of Debt [Table Text Block]

Debt Issuances. During the nine months ended September 30, 2017, CERC issued the following unsecured senior notes:

Issuance Date	Aggregate Principal Amount		Interest Rate	Maturity Date
	(in millions)
August 2017	$	300	4.10%	2047

Schedule of Line of Credit Facilities [Table Text Block]

Revolving Credit Facility.  In June 2017, CERC entered into an amendment to its revolving credit facility to extend the termination date thereof from March 3, 2021 to March 3, 2022 and to terminate the swingline loan subfacility thereunder. The amendment also increased the aggregate commitments by $300 million to $900 million under its revolving credit facility. In connection with the amendment to increase the aggregate commitments under its revolving credit facility, CERC increased the size of its commercial paper program to permit the issuance of commercial paper notes in an aggregate principal amount not to exceed $900 million at any time outstanding.

As of September 30, 2017 and December 31, 2016, CERC had the following revolving credit facility and utilization of such facility:

September 30, 2017									December 31, 2016
Size of Facility		Loans		Letters of Credit		Commercial Paper			Size of Facility		Loans		Letters of Credit		Commercial Paper
(in millions)
$	900	$	—	$	—	$	529	(1)	$	600	$	—	$	4	$	569	(1)

(1) Weighted average interest rate was approximately 1.43% and 1.03% as of September 30, 2017 and December 31, 2016, respectively.

Execution Date	Size of Facility			Draw Rate of LIBOR plus (2)		Financial Covenant Limit on Debt for Borrowed Money to Capital Ratio		Debt for Borrowed Money to Capital Ratio as of September 30, 2017	Termination Date (3)
	(in millions)
March 3, 2016	$	900	(1)	1.25	%	65	%	38.6%	March 3, 2022

(1) Amended on June 16, 2017 to increase the aggregate commitment size as noted above.

(2) Based on current credit ratings.

(3) Amended on June 16, 2017 to extend the termination date as noted above.

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Commitments and Contingencies (Tables)

9 Months Ended

Sep. 30, 2017

Commitments and Contingencies Disclosure [Abstract]

Long-term Purchase Commitment [Table Text Block]

Natural gas supply commitments include natural gas contracts related to CERC’s Natural Gas Distribution and Energy Services business segments, which have various quantity requirements and durations, that are not classified as non-trading derivative assets and liabilities in CERC’s Condensed Consolidated Balance Sheets as of September 30, 2017 and December 31, 2016 as these contracts meet an exception as “normal purchases contracts” or do not meet the definition of a derivative. Natural gas supply commitments also include natural gas transportation contracts that do not meet the definition of a derivative. As of September 30, 2017, minimum payment obligations for natural gas supply commitments are approximately:

	(in millions)
Remaining three months of 2017	$	169
2018	507
2019	348
2020	166
2021	76
2022 and beyond	113

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Reportable Business Segments (Tables)

9 Months Ended

Sep. 30, 2017

Segment Reporting [Abstract]

Schedule of Segment Reporting Information, by Segment [Table Text Block]

Financial data for business segments is as follows:

	For the Three Months Ended September 30, 2017
	Revenues from External Customers		Inter-segment Revenues			Operating Income
	(in millions)
Natural Gas Distribution	$	390	$	8		$	19
Energy Services	861		10			7
Midstream Investments (1)	—		—			—
Other Operations	—		—			—
Reconciling Eliminations	—		(18		)	—
Consolidated	$	1,251	$	—		$	26

	For the Three Months Ended September 30, 2016
	Revenues from External Customers		Inter-segment Revenues			Operating Income (Loss)
	(in millions)
Natural Gas Distribution	$	370	$	7		$	22
Energy Services	608		6			5
Midstream Investments (1)	—		—			—
Other Operations	—		—			(1		)
Reconciling Eliminations	—		(13		)	—
Consolidated	$	978	$	—		$	26

	For the Nine Months Ended September 30, 2017
	Revenues from External Customers		Inter-segment Revenues			Operating Income (Loss)			Total Assets as of September 30, 2017
	(in millions)
Natural Gas Distribution	$	1,767	$	24		$	220		$	6,067
Energy Services	2,964		34			58			1,337
Midstream Investments (1)	—		—			—			2,481
Other Operations	—		—			(5		)	73
Reconciling Eliminations	—		(58		)	—			(582		)
Consolidated	$	4,731	$	—		$	273		$	9,376

	For the Nine Months Ended September 30, 2016
	Revenues from External Customers		Inter-segment Revenues			Operating Income (Loss)			Total Assets as of December 31, 2016
	(in millions)
Natural Gas Distribution	$	1,672	$	21		$	202		$	6,099
Energy Services	1,433		17			11			1,102
Midstream Investments (1)	—		—			—			2,505
Other Operations	—		—			(3		)	75
Reconciling Eliminations	—		(38		)	—			(563		)
Consolidated	$	3,105	$	—		$	210		$	9,218

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
	(in millions)
Enable	$	68	$	73	$	199	$	164

Midstream Investments [Table Text Block]

Midstream Investments’ equity earnings are as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
	(in millions)
Enable	$	68	$	73	$	199	$	164

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Background and Basis of Presentation (Details)	Sep. 30, 2017 state
Enable Midstream Partners [Member]
Ownership percentage of equity method investment	54.10%
Natural Gas Distribution [Member]
Number of states in which entity operates	6
Energy Services [Member]
Number of states in which entity operates	33

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New Accounting Pronouncements (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
Payments related to tax withholding for share-based compensation	$ 1	$ 1

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Acquisition (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
	Jan. 03, 2017	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net [Abstract]
Goodwill		$ 867		$ 867		$ 862
Atmos Energy Marketing [Member]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net [Abstract]
Total purchase price consideration	$ 147
Cash	15
Receivables	140
Natural gas inventory	78
Derivative assets	35
Prepaid expenses and other current assets	5
Property and equipment	8
Identifiable intangibles	25
Total assets acquired	306
Accounts payable	113
Derivative liabilities	43
Other current liabilities	7
Other liabilities	1
Total liabilities assumed	164
Identifiable net assets acquired	142
Goodwill	5
Net assets acquired	147
Amortization of intangible assets		0		1
Business Acquisition, Pro Forma Information [Abstract]
Revenue of acquiree since acquisition date		311		989
Operating income of acquiree since acquisition date		3		28
Operating Revenue		1,251	$ 1,234	4,731	$ 3,819
Net Income		$ 38	$ 43	$ 239	$ 173
Customer Relationships [Member] | Atmos Energy Marketing [Member]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net [Abstract]
Intangibles estimated fair value	$ 25
Intangibles estimated useful life	15 years

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Employee Benefit Plans (Details) - Other Postretirement Benefit Plans, Defined Benefit [Member] - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Defined Benefit Plan Disclosure [Line Items]
Service cost		$ 1	$ 1	$ 1	$ 1
Interest cost		1	1	3	3
Expected return on plan assets		(1)	(1)	(1)	(1)
Amortization of prior service cost		0	0	1	0
Net periodic cost (1)	[1]	1	$ 1	4	$ 3
Contribution expected in 2017				5
Contribution made in period		$ 1		$ 4

[1] Net periodic cost in this table is before considering amounts subject to overhead allocations for capital expenditure projects or for amounts subject to deferral for regulatory purposes.

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Regulatory Accounting (Details) - Hurricane Harvey [Member] $ in Millions	Sep. 30, 2017 USD ($)
Estimated restoration costs covered by insurance	$ 17
Recorded increase in regulatory assets	7
Recorded insurance receivables	2
Minimum [Member]
Estimated costs to restore damaged facilities	25
Maximum [Member]
Estimated costs to restore damaged facilities	$ 30

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Derivative Instruments (Details)		3 Months Ended			9 Months Ended			12 Months Ended
		Sep. 30, 2017 USD ($)		Sep. 30, 2016 USD ($)	Sep. 30, 2017 USD ($) Bcf		Sep. 30, 2016 USD ($)	Dec. 31, 2016 USD ($) Bcf		Aug. 21, 2017 USD ($)
Derivatives, Fair Value [Line Items]
Derivative Assets Fair Value		$ 164,000,000			$ 164,000,000			$ 105,000,000	[1]
Derivative Liabilities Fair Value		84,000,000			84,000,000			67,000,000	[1]
Gross Amounts Offset in the Consolidated Balance Sheets		13,000,000			13,000,000			(14,000,000)
Gain (loss) on derivative instruments not designated as hedging instruments		21,000,000		$ 18,000,000	71,000,000		$ 36,000,000
Total fair value of the derivative instruments that contain credit risk contingency features that are in a net liability position		1,000,000			1,000,000			1,000,000
The aggregate fair value of assets already posted as collateral		0			0			0
Credit risk contingent feature assets		1,000,000			1,000,000			$ 0
Gains (Losses) in Expense: Natural Gas [Member]
Derivatives, Fair Value [Line Items]
Change in unrealized gain (loss) on hedged item in fair value hedge		4,000,000		0	(10,000,000)		0
Gain (loss) on fair value hedges recognized in earnings	[2]	0		0	$ (2,000,000)		0
Natural gas derivatives [Member]
Derivatives, Fair Value [Line Items]
Derivative gross volume notional amount (in Bcf) | Bcf					1,866			1,035
Gross Amounts Recognized	[3]	80,000,000			$ 80,000,000			$ 38,000,000
Gross Amounts Offset in the Consolidated Balance Sheets		13,000,000			13,000,000			(14,000,000)
Net Amount Presented in the Consolidated Balance Sheets	[4]	93,000,000			93,000,000			24,000,000
Natural gas derivatives [Member] | Current Assets [Member]
Derivatives, Fair Value [Line Items]
Gross Amounts Recognized	[3]	97,000,000			97,000,000			81,000,000
Gross Amounts Offset		(33,000,000)			(33,000,000)			(30,000,000)
Derivative Asset	[4]	64,000,000			64,000,000			51,000,000
Natural gas derivatives [Member] | Other Noncurrent Assets [Member]
Derivatives, Fair Value [Line Items]
Gross Amounts Recognized	[3]	67,000,000			67,000,000			24,000,000
Gross Amounts Offset		(11,000,000)			(11,000,000)			(5,000,000)
Derivative Asset	[4]	56,000,000			56,000,000			19,000,000
Natural gas derivatives [Member] | Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Gross Amounts Recognized	[3]	(57,000,000)			(57,000,000)			(57,000,000)
Gross Amounts Offset		40,000,000			40,000,000			16,000,000
Derivative Liability	[4]	(17,000,000)			(17,000,000)			(41,000,000)
Natural gas derivatives [Member] | Other Noncurrent Liabilities [Member]
Derivatives, Fair Value [Line Items]
Gross Amounts Recognized	[3]	(27,000,000)			(27,000,000)			(10,000,000)
Gross Amounts Offset		17,000,000			17,000,000			5,000,000
Derivative Liability	[4]	(10,000,000)			(10,000,000)			(5,000,000)
Natural gas derivatives [Member] | Gains (Losses) in Revenue [Member]
Derivatives, Fair Value [Line Items]
Gain (loss) on derivative instruments not designated as hedging instruments		30,000,000		31,000,000	162,000,000		1,000,000
Natural gas derivatives [Member] | Gains (Losses) in Expense: Natural Gas [Member]
Derivatives, Fair Value [Line Items]
Change in unrealized gain (loss) on fair value hedging instruments		(4,000,000)		0	8,000,000		0
Gain (loss) on derivative instruments not designated as hedging instruments		(9,000,000)		$ (13,000,000)	(91,000,000)		$ 35,000,000
Natural gas derivatives [Member] | Designated as Fair Value Hedge [Member] | Current Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Assets Fair Value	[5],[6],[7]	0			0
Derivative Liabilities Fair Value	[5],[6],[7]	0			0
Natural gas derivatives [Member] | Designated as Fair Value Hedge [Member] | Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Assets Fair Value	[5],[6],[7]	5,000,000			5,000,000
Derivative Liabilities Fair Value	[5],[6],[7]	0			0
Natural gas derivatives [Member] | Not Designated as Hedging Instrument [Member] | Current Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Assets Fair Value	[5]	65,000,000	[6],[7]		65,000,000	[6],[7]		79,000,000	[8],[9]
Derivative Liabilities Fair Value	[5]	2,000,000	[6],[7]		2,000,000	[6],[7]		14,000,000	[8],[9]
Natural gas derivatives [Member] | Not Designated as Hedging Instrument [Member] | Other Noncurrent Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Assets Fair Value	[5]	58,000,000	[6],[7]		58,000,000	[6],[7]		24,000,000	[8],[9]
Derivative Liabilities Fair Value	[5]	2,000,000	[6],[7]		2,000,000	[6],[7]		5,000,000	[8],[9]
Natural gas derivatives [Member] | Not Designated as Hedging Instrument [Member] | Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Assets Fair Value	[5]	27,000,000	[6],[7]		27,000,000	[6],[7]		2,000,000	[8],[9]
Derivative Liabilities Fair Value	[5]	55,000,000	[6],[7]		55,000,000	[6],[7]		43,000,000	[8],[9]
Natural gas derivatives [Member] | Not Designated as Hedging Instrument [Member] | Other Noncurrent Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Assets Fair Value	[5]	9,000,000	[6],[7]		9,000,000	[6],[7]		0	[8],[9]
Derivative Liabilities Fair Value	[5]	25,000,000	[6],[7]		$ 25,000,000	[6],[7]		$ 5,000,000	[8],[9]
Natural gas derivatives [Member] | Long [Member]
Derivatives, Fair Value [Line Items]
Derivative gross volume notional amount (in Bcf) | Bcf					46			59
Natural Gas Distribution [Member] | 2017to2018 [Member]
Derivatives, Fair Value [Line Items]
Weather hedge bilateral cap amount					$ 8,000,000
August [Member] | Treasury Lock [Member]
Derivatives, Fair Value [Line Items]
Aggregate notional amount		$ 150,000,000			150,000,000
Effective portion of realized losses					$ 1,500,000
Senior Notes [Member]
Derivatives, Fair Value [Line Items]
Principal amount of debt issued										$ 300,000,000

[1] No derivatives were designated as fair value hedges as of December 31, 2016.

[2] Hedge ineffectiveness results from the basis ineffectiveness discussed above, and excludes the impact to natural gas expense from timing ineffectiveness. Timing ineffectiveness arises due to changes in the difference between the spot price and the futures price, as well as the difference between the timing of the settlement of the futures and the valuation of the underlying physical commodity. As the commodity contract nears the settlement date, spot-to-forward price differences should converge, which should reduce or eliminate the impact of this ineffectiveness on natural gas expense.

[3] Gross amounts recognized include some derivative assets and liabilities that are not subject to master netting arrangements.

[4] 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.

[5] Derivative Assets and Derivative Liabilities include no material amounts related to physical forward transactions with Enable.

[6] 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 $93 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, impacted by collateral netting of $13 million.

[7] The fair value shown for natural gas contracts is comprised of derivative gross volumes totaling 1,866 Bcf or a net 46 Bcf long position. Certain natural gas contracts hedge basis risk only and lack a fixed price exposure.

[8] 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 $24 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, impacted by collateral netting of $14 million.

[9] The fair value shown for natural gas contracts is comprised of derivative gross volumes totaling 1,035 Bcf or a net 59 Bcf long position.

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Fair Value Measurements (Details)		3 Months Ended			9 Months Ended
		Sep. 30, 2017 USD ($)		Sep. 30, 2016 USD ($)	Sep. 30, 2017 USD ($)		Sep. 30, 2016 USD ($)	Dec. 31, 2016 USD ($)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value amount of Level 1 to Level 2 assets transferred		$ 0			$ 0
Fair value amount of Level 2 to Level 1 assets transferred		0			0
Fair value amount of Level 1 to Level 2 liabilities transferred		0			0
Fair value amount of Level 2 to Level 1 liabilities transferred		0			0
Assets
Total derivative assets, netting adjustment		(44,000,000)	[1]		(44,000,000)	[1]		$ (35,000,000)	[2]
Total assets		199,000,000			199,000,000			83,000,000
Derivative fair value offsets, net		13,000,000			13,000,000			(14,000,000)
Liabilities
Total derivative liabilities, netting adjustment		(57,000,000)	[1]		(57,000,000)	[1]		(21,000,000)	[2]
Total liabilities		27,000,000			27,000,000			46,000,000
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Beginning balance		28,000,000		$ 16,000,000	13,000,000		$ 12,000,000
Purchases (1)	[3]	0		0	0		12,000,000
Total gains		(2,000,000)		9,000,000	21,000,000		13,000,000
Total settlements		(1,000,000)		(8,000,000)	(5,000,000)		(24,000,000)
Transfers into Level 3		7,000,000		0	9,000,000		5,000,000
Transfers out of Level 3		(6,000,000)		0	(12,000,000)		(1,000,000)
Ending balance (2)	[4]	26,000,000		17,000,000	26,000,000		17,000,000
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		0		$ 6,000,000	17,000,000		$ 14,000,000
Carrying Amount [Member]
Estimated Fair Value of FInancial Instruments
Long-term debt		2,636,000,000			2,636,000,000			2,375,000,000
Fair Value [Member]
Estimated Fair Value of FInancial Instruments
Long-term debt		2,854,000,000			$ 2,854,000,000			2,551,000,000
Atmos Energy Marketing [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Mark-to-market value of Level 3 derivative assets acquired					less than $1 million
Energy Related Derivative [Member]
Assets
Derivative fair value offsets, net		13,000,000			$ 13,000,000			(14,000,000)
Fair Value, Inputs, Level 1 [Member]
Assets
Total assets		82,000,000			82,000,000			24,000,000
Liabilities
Total liabilities		3,000,000			3,000,000			4,000,000
Fair Value, Inputs, Level 2 [Member]
Assets
Total assets		128,000,000			128,000,000			74,000,000
Liabilities
Total liabilities		74,000,000			74,000,000			56,000,000
Fair Value, Inputs, Level 3 [Member]
Assets
Total assets		33,000,000			33,000,000			20,000,000
Liabilities
Total liabilities		7,000,000			$ 7,000,000			7,000,000
Fair Value, Inputs, Level 3 [Member] | Options Held [Member] | Minimum [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value options volatility rate					0.00%
Fair Value, Inputs, Level 3 [Member] | Options Held [Member] | Maximum [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value options volatility rate					87.00%
Fair Value, Inputs, Level 3 [Member] | Forward Contracts [Member] | Minimum [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value inputs (price per MMBtu)					1.08
Fair Value, Inputs, Level 3 [Member] | Forward Contracts [Member] | Maximum [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value inputs (price per MMBtu)					5.83
Fair Value, Measurements, Recurring [Member]
Assets
Corporate equities		3,000,000			$ 3,000,000			3,000,000
Investments, including money market funds (2)	[5]	11,000,000			11,000,000			10,000,000
Hedged portion of natural gas inventory		65,000,000			65,000,000
Fair Value, Measurements, Recurring [Member] | Energy Related Derivative [Member]
Assets
Derivative asset, netting adjustment	[6]	(44,000,000)	[1]		(44,000,000)	[1]		(35,000,000)	[2]
Derivative assets	[6]	120,000,000			120,000,000			70,000,000
Liabilities
Derivative liabilities, netting adjustment	[6]	(57,000,000)	[1]		(57,000,000)	[1]		(21,000,000)	[2]
Derivative liabilities	[6]	27,000,000			27,000,000			46,000,000
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
Assets
Corporate equities		3,000,000			3,000,000			3,000,000
Investments, including money market funds (2)	[5]	11,000,000			11,000,000			10,000,000
Hedged portion of natural gas inventory		65,000,000			65,000,000
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Energy Related Derivative [Member]
Assets
Derivative asset	[6]	3,000,000			3,000,000			11,000,000
Liabilities
Derivative liability	[6]	3,000,000			3,000,000			4,000,000
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Assets
Corporate equities		0			0			0
Investments, including money market funds (2)	[5]	0			0			0
Hedged portion of natural gas inventory		0			0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Energy Related Derivative [Member]
Assets
Derivative asset	[6]	128,000,000			128,000,000			74,000,000
Liabilities
Derivative liability	[6]	74,000,000			74,000,000			56,000,000
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]
Assets
Corporate equities		0			0			0
Investments, including money market funds (2)	[5]	0			0			0
Hedged portion of natural gas inventory		0			0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Energy Related Derivative [Member]
Assets
Derivative asset	[6]	33,000,000			33,000,000			20,000,000
Liabilities
Derivative liability	[6]	$ 7,000,000			$ 7,000,000			$ 7,000,000

[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 $13 million posted with the same counterparties.

[2] 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 $14 million held by CES from the same counterparties.

[3] Mark-to-market value of Level 3 derivative assets acquired through the purchase of AEM was less than $1 million at the acquisition date.

[4] CERC did not have significant Level 3 sales during either of the three or nine months ended September 30, 2017 or 2016.

[5] Amounts are included in Other Assets in the Condensed Consolidated Balance Sheets.

[6] Natural gas derivatives include no material amounts related to physical forward transactions with Enable.

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Unconsolidated Affiliate (Details) - USD ($) $ / shares in Units, $ in Millions			3 Months Ended		9 Months Ended
		Nov. 22, 2016	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Aug. 30, 2017	Dec. 31, 2016
Percentage sale of units which trigger right of first refusal					5.00%
Equity Method Investment, Summarized Financial Information, Income Statement [Abstract]
CERC Corp.’s equity in earnings, net			$ 68	$ 73	$ 199	$ 164
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity [Abstract]
CERC Corp.’s equity method investment in Enable			$ 2,481		$ 2,481			$ 2,505
Enable Midstream Partners [Member]
Equity method investment limited partner interest in Enable			54.10%		54.10%
Equity Method Investment, Summarized Financial Information, Income Statement [Abstract]
Operating revenues			$ 705	620	$ 1,997	1,658
Cost of sales, excluding depreciation and amortization			349	268	936	717
Impairment of goodwill and other long-lived assets			0	8	0	8
Operating income			137	139	399	299
Net income attributable to Enable			104	110	301	231
CERC Corp.’s interest			56	61	163	128
Basis difference amortization (1)	[1]		12	12	36	36
CERC Corp.’s equity in earnings, net			68	73	$ 199	164
Basis difference amortization period					33 years
Equity Method Investment, Summarized Financial Information, Assets and Liabilities [Abstract]
Current assets			446		$ 446			396
Non-current assets			10,816		10,816			10,816
Current liabilities			831		831			362
Non-current liabilities			2,740		2,740			3,056
Non-controlling interest			12		12			12
Preferred equity			362		362			362
Enable partners’ capital			7,317		7,317			7,420
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity [Abstract]
CERC’s ownership interest in Enable partners’ capital			4,007		4,007			4,067
CERC Corp.’s basis difference			(1,526)		(1,526)			(1,562)
CERC Corp.’s equity method investment in Enable			2,481		2,481			2,505
Distributions received from equity method investment			74	74	$ 223	223
ArcLight [Member]
Units sold in public offering		1,424,281
OGE [Member]
Percentage sale of units which trigger right of first refusal					5.00%
Enable Midstream Partners [Member]
Units sold in public offering		11,500,000
Enable Midstream Partners [Member]
Interest income related to notes receivable from Enable			0	0	$ 0	1
Enable Midstream Partners [Member]
Management rights ownership percentage					50.00%
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity [Abstract]
Incentive distribution right					40.00%
Maximum incentive distribution right					50.00%
Enable Midstream Partners [Member] | OGE [Member]
Limited partner interest in Enable					25.70%
Management rights ownership percentage					50.00%
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity [Abstract]
Incentive distribution right					60.00%
Minimum [Member] | Enable Midstream Partners [Member]
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity [Abstract]
Incentive distribution per unit					$ 0.2875
Maximum [Member] | Enable Midstream Partners [Member]
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity [Abstract]
Incentive distribution per unit					$ 0.330625
Natural Gas Expenses [Member] | Enable Midstream Partners [Member]
Natural gas expenses, including transportation and storage costs			23	22	$ 80	79
Accounts payable for natural gas purchases from Enable			8		8			10
Transitional Service [Member] | Enable Midstream Partners [Member]
Reimbursement of transition services (1)	[2]		0	$ 1	3	$ 6
Accounts receivable for amounts billed for transition services			$ 1		$ 1			$ 1
Common Stock [Member] | Enable Midstream Partners [Member]
Enable equity method investment units held			233,856,623		233,856,623
Common Stock [Member] | Enable Midstream Partners [Member] | OGE [Member]
Enable units held					110,982,805
Subordinated Units [Member] | Enable Midstream Partners [Member]
Enable equity method investment units held							139,704,916

[1] Equity in earnings of unconsolidated affiliates includes CERC Corp.’s share of Enable’s earnings adjusted for the amortization of the basis difference of CERC Corp.’s original investment in Enable and its underlying equity in Enable’s net assets. The basis difference is amortized over approximately 33 years, the average life of the assets to which the basis difference is attributed.

[2] Represents amounts billed under the Transition Agreements for certain support services provided to Enable. Actual transition services costs are recorded net of reimbursement.

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Goodwill (Details)	9 Months Ended
	Sep. 30, 2017 USD ($)
Goodwill [Line Items]
Goodwill impairment charge recorded from annual impairment test	$ 0
Goodwill [Roll Forward]
Goodwill, Beginning Balance	862,000,000
Goodwill, Acquired During Period	5,000,000	[1]
Goodwill, Ending Balance	867,000,000
Natural Gas Distribution [Member]
Goodwill [Roll Forward]
Goodwill, Beginning Balance	746,000,000
Goodwill, Acquired During Period	0	[1]
Goodwill, Ending Balance	746,000,000
Energy Services [Member]
Goodwill [Line Items]
Accumulated goodwill impairment charge recorded in 2012	252,000,000
Goodwill [Roll Forward]
Goodwill, Beginning Balance	105,000,000	[2]
Goodwill, Acquired During Period	5,000,000	[1]
Goodwill, Ending Balance	110,000,000	[2]
Other Operations [Member]
Goodwill [Roll Forward]
Goodwill, Beginning Balance	11,000,000
Goodwill, Acquired During Period	0	[1]
Goodwill, Ending Balance	$ 11,000,000

[1] See Note 3.

[2] Amount presented is net of the accumulated goodwill impairment charge of $252 million recorded in 2012.

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Related Party Transactions (Details) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Investments in the Money Pool	$ 0		$ 0		$ 0
CenterPoint Energy [Member] | Operation And Maintenance Expense [Member]
Corporate service charges	30,000,000	$ 31,000,000	93,000,000	$ 90,000,000
CenterPoint Houston [Member] | Operation And Maintenance Expense [Member]
Corporate service charges	3,000,000	4,000,000	11,000,000	11,000,000
Billings to Houston Electric for services provided	$ (2,000,000)	$ (2,000,000)	$ (5,000,000)	$ (5,000,000)

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Short-term Borrowings and Long-term Debt (Details) - USD ($) $ in Millions			9 Months Ended
		Aug. 21, 2017	Sep. 30, 2017		Dec. 31, 2016
Debt Instrument [Line Items]
Size of credit facility			$ 900	[1]	$ 600
Credit facility size increase			300
Short-term Debt [Line Items]
Short-term borrowings			$ 48		35
Line of Credit [Member]
Debt Instrument [Line Items]
Percentage on limitation of debt to total capitalization under covenant (in hundredths)			65.00%
Ratio of indebtedness to net capital			0.386
Line of Credit [Member] | London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument [Line Items]
Basis spread on LIBOR	[2]		1.25%
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Long-term line of credit			$ 0		0
Letter of Credit [Member]
Debt Instrument [Line Items]
Long-term line of credit			0		4
Commercial Paper [Member]
Debt Instrument [Line Items]
Size of credit facility			900
Long-term line of credit	[3]		$ 529		$ 569
Weighted average interest rate of debt			1.43%		1.03%
Senior Notes [Member]
Debt Instrument [Line Items]
Principal amount of debt issued		$ 300
Interest rate of debt issued		4.10%
Maturity date of debt issued		Sep. 01, 2047
Product Financing Arrangement [Member]
Short-term Debt [Line Items]
Short-term borrowings			$ 48		$ 35

[1] Amended on June 16, 2017 to increase the aggregate commitment size as noted above.

[2] Based on current credit ratings.

[3] Weighted average interest rate was approximately 1.43% and 1.03% as of September 30, 2017 and December 31, 2016, respectively.

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Commitments and Contingencies (Details) $ in Millions	9 Months Ended
	Sep. 30, 2017 USD ($)
Minnesota Service Territory [Member]
LegalEnvironmentalAndOtherRegulatoryMattersLegalMattersGasMarketManipulationCasesAbstract
Liability recorded for remediation of Minnesota sites	$ 7
Minnesota Service Territory [Member] | Minimum [Member]
LegalEnvironmentalAndOtherRegulatoryMattersLegalMattersGasMarketManipulationCasesAbstract
Estimated remediation costs for the Minnesota sites	$ 4
Years to resolve contingency	30 years
Minnesota Service Territory [Member] | Maximum [Member]
LegalEnvironmentalAndOtherRegulatoryMattersLegalMattersGasMarketManipulationCasesAbstract
Estimated remediation costs for the Minnesota sites	$ 30
Years to resolve contingency	50 years
Natural Gas Supply Commitments [Member]
Recorded Unconditional Purchase Obligation Payment Schedule [Abstract]
Remaining three months of 2017	$ 169
2018	507
2019	348
2020	166
2021	76
2022 and beyond	$ 113

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Income Taxes (Details)	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Income Tax Disclosure [Abstract]
Effective income tax rate	40.00%	38.00%	38.00%	40.00%

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Reportable Business Segments (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Segment Reporting Information [Line Items]
Revenues from External Customers		$ 1,251	$ 978	$ 4,731	$ 3,105
Operating Income (Loss)		26	26	273	210
Total Assets		9,376		9,376		$ 9,218
Equity in earnings of unconsolidated affiliate, net		68	73	199	164
Natural Gas Distribution [Member]
Segment Reporting Information [Line Items]
Revenues from External Customers		390	370	1,767	1,672
Operating Income (Loss)		19	22	220	202
Energy Services [Member]
Segment Reporting Information [Line Items]
Revenues from External Customers		861	608	2,964	1,433
Operating Income (Loss)		7	5	58	11
Midstream Investments [Member]
Segment Reporting Information [Line Items]
Revenues from External Customers	[1]	0	0	0	0
Operating Income (Loss)	[1]	0	0	0	0
Other Operations [Member]
Segment Reporting Information [Line Items]
Revenues from External Customers		0	0	0	0
Operating Income (Loss)		0	(1)	(5)	(3)
Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues from External Customers		(18)	(13)	(58)	(38)
Total Assets		(582)		(582)		(563)
Intersegment Eliminations [Member] | Natural Gas Distribution [Member]
Segment Reporting Information [Line Items]
Revenues from External Customers		(8)	(7)	(24)	(21)
Intersegment Eliminations [Member] | Energy Services [Member]
Segment Reporting Information [Line Items]
Revenues from External Customers		(10)	(6)	(34)	(17)
Intersegment Eliminations [Member] | Midstream Investments [Member]
Segment Reporting Information [Line Items]
Revenues from External Customers	[1]	0	0	0	0
Intersegment Eliminations [Member] | Other Operations [Member]
Segment Reporting Information [Line Items]
Revenues from External Customers		0	0	0	0
Operating Segments [Member] | Natural Gas Distribution [Member]
Segment Reporting Information [Line Items]
Total Assets		6,067		6,067		6,099
Operating Segments [Member] | Energy Services [Member]
Segment Reporting Information [Line Items]
Total Assets		1,337		1,337		1,102
Operating Segments [Member] | Midstream Investments [Member]
Segment Reporting Information [Line Items]
Total Assets	[1]	2,481		2,481		2,505
Operating Segments [Member] | Other Operations [Member]
Segment Reporting Information [Line Items]
Total Assets		73		73		$ 75
Enable Midstream Partners [Member]
Segment Reporting Information [Line Items]
Equity in earnings of unconsolidated affiliate, net		68	73	199	164
Enable Midstream Partners [Member] | Midstream Investments [Member]
Segment Reporting Information [Line Items]
Equity in earnings of unconsolidated affiliate, net		$ 68	$ 73	$ 199	$ 164

[1] Midstream Investments’ equity earnings are as follows: Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in millions)Enable $68 $73 $199 $164

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Other Current Assets and Liabilities (Details) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Prepaid Expenses and Other Current Assets [Member]
Margin deposits	$ 22	$ 1
Under recovered gas costs	55	40
Other Current Liabilities [Member]
Over recovered gas costs	$ 2	$ 10

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Subsequent Events (Details) - Enable Midstream Partners [Member] - USD ($) $ / shares in Units, $ in Millions		3 Months Ended		9 Months Ended
	Oct. 31, 2017	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Subsequent Event [Line Items]
Expected cash distribution from equity method investment		$ 74	$ 74	$ 223	$ 223
Subsequent Event [Member]
Subsequent Event [Line Items]
Dividends payable, date declared	Oct. 31, 2017
Quarterly cash distribution per unit declared	$ 0.318
Expected cash distribution from equity method investment	$ 74