10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 _______________________________________

FORM 10-Q

 _______________________________________

þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES AND EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2016

or

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _____to_____

Commission File No. 1-36413

 _______________________________________

ENABLE MIDSTREAM PARTNERS, LP

(Exact name of registrant as specified in its charter)

 _______________________________________

Delaware	72-1252419
(State or jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

One Leadership Square

211 North Robinson Avenue

Suite 150

Oklahoma City, Oklahoma 73102

(Address of principal executive offices)

(Zip Code)

Registrant’s telephone number, including area code: (405) 525-7788

 _______________________________________

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. þ Yes ¨ No

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). þ Yes ¨ No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer	þ	Accelerated filer	¨
Non-accelerated filer	¨ (Do not check if a smaller reporting company)	Smaller reporting company	¨

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

As of April 15, 2016, there were 214,467,409 common units and 207,855,430 subordinated units outstanding.

ENABLE MIDSTREAM PARTNERS, LP

FORM 10-Q

TABLE OF CONTENTS

	Page
GLOSSARY OF TERMS	1
FORWARD-LOOKING STATEMENTS	3
Part I - FINANCIAL INFORMATION
Item 1. Financial Statements (Unaudited)
Condensed Consolidated Statements of Income	4
Condensed Consolidated Statements of Comprehensive Income	5
Condensed Consolidated Balance Sheets	6
Condensed Consolidated Statements of Cash Flows	7
Condensed Consolidated Statements of Partners' Equity	8
Notes to Condensed Consolidated Financial Statements	9
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations	28
Item 3. Quantitative and Qualitative Disclosures About Market Risk	36
Item 4. Controls and Procedures	36
Part II - OTHER INFORMATION
Item 1. Legal Proceedings	37
Item 1A. Risk Factors	37
Item 6. Exhibits	42
Signature	0

i

GLOSSARY

Adjusted EBITDA.	A non-GAAP measure calculated as net income from continuing operations before interest expense, income tax expense, depreciation and amortization expense and certain other items management believes affect the comparability of operating results.
Annual Report.	Annual Report on Form 10-K for the year ended December 31, 2015.
ASU.	Accounting Standards Update.
Barrel.	42 U.S. gallons of petroleum products.
Bbl.	Barrel.
Bbl/d.	Barrels per day.
Bcf/d.	Billion cubic feet per day.
Btu.	British thermal unit. When used in terms of volume, Btu refers to the amount of natural gas required to raise the temperature of one pound of water by one degree Fahrenheit at one atmospheric pressure.
CenterPoint Energy.	CenterPoint Energy, Inc., a Texas corporation, and its subsidiaries, other than Enable Midstream Partners, LP for periods prior to formation of the Partnership on May 1, 2013.
Condensate.	A natural gas liquid with a low vapor pressure, mainly composed of propane, butane, pentane and heavier hydrocarbon fractions.
EGT.	Enable Gas Transmission, LLC, a wholly owned subsidiary of the Partnership that operates a 5,900-mile interstate pipeline that provides natural gas transportation and storage services to customers principally in the Anadarko, Arkoma and Ark-La-Tex basins in Oklahoma, Texas, Arkansas, Louisiana and Kansas.
Enable GP.	Enable GP, LLC, a Delaware limited liability company and the general partner of Enable Midstream Partners, LP.
Enable Midstream Services.	Enable Midstream Services, LLC, a wholly owned subsidiary of Enable Midstream Partners, LP.
Enogex.	Enogex LLC, a Delaware limited liability company.
EOIT.	Enable Oklahoma Intrastate Transmission, LLC, formerly Enogex LLC, a wholly owned subsidiary of the Partnership that operates a 2,200-mile intrastate pipeline that provides natural gas transportation and storage services to customers in Oklahoma.
Exchange Act.	Securities Exchange Act of 1934, as amended.
FASB.	Financial Accounting Standards Board.
FERC.	Federal Energy Regulatory Commission.
Fractionation.	The separation of the heterogeneous mixture of extracted NGLs into individual components for end-use sale.
GAAP.	Generally accepted accounting principles in the United States.
Gas imbalance.	The difference between the actual amounts of natural gas delivered from or received by a pipeline, as compared to the amounts scheduled to be delivered or received.
General partner.	Enable GP, LLC, a Delaware limited liability company, the general partner of Enable Midstream Partners, LP.
Gross margin.	A non-GAAP measure calculated as revenues minus cost of natural gas and natural gas liquids, excluding depreciation and amortization.
LIBOR.	London Interbank Offered Rate.
MBbl/d.	Thousand barrels per day.
MFA.	Master Formation Agreement dated as of March 14, 2013.
MMcf.	Million cubic feet of natural gas.
MMcf/d.	Million cubic feet per day.
NGLs.	Natural gas liquids, which are the hydrocarbon liquids contained within natural gas including condensate.
NYMEX.	New York Mercantile Exchange.
Offering.	Initial public offering of Enable Midstream Partners, LP.
OGE Energy.	OGE Energy Corp., an Oklahoma corporation, and its subsidiaries.
Partnership.	Enable Midstream Partners, LP, and its subsidiaries.

1

Partnership Agreement	Third Amended and Restated Agreement of Limited Partnership of Enable Midstream Partners, LP dated as of February 18, 2016.
Purchase Agreement.	Purchase Agreement, dated January 28, 2016, by and between the Partnership and CenterPoint Energy, Inc. for the sale by the Partnership and purchase by CenterPoint Energy, Inc. of Series A Preferred Units.
Revolving Credit Facility.	$1.75 billion senior unsecured revolving credit facility.
SEC.	Securities and Exchange Commission.
Securities Act.	Securities Act of 1933, as amended.
Series A Preferred Units.	10% Series A Fixed-to-Floating Non-Cumulative Redeemable Perpetual Preferred Units representing limited partner interests in the Partnership.
SESH.	Southeast Supply Header, LLC, in which the Partnership owns a 50% interest, that operates an approximately 290-mile interstate natural gas pipeline from Perryville, Louisiana to southwestern Alabama near the Gulf Coast.
TBtu.	Trillion British thermal units.
TBtu/d.	Trillion British thermal units per day.
WTI.	West Texas Intermediate.
2015 Term Loan Agreement.	$450 million unsecured term loan agreement.
2019 Notes.	$500 million 2.400% senior notes due 2019.
2024 Notes.	$600 million 3.900% senior notes due 2024.
2044 Notes.	$550 million 5.000% senior notes due 2044.

2

FORWARD-LOOKING STATEMENTS

Some of the information in this report may contain forward-looking statements. Forward-looking statements give our current expectations, contain projections of results of operations or of financial condition, or forecasts of future events. Words such as “could,” “will,” “should,” “may,” “assume,” “forecast,” “position,” “predict,” “strategy,” “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe,” “project,” “budget,” “potential,” or “continue,” and similar expressions are used to identify forward-looking statements. Without limiting the generality of the foregoing, forward-looking statements contained in this report include our expectations of plans, strategies, objectives, growth and anticipated financial and operational performance, including revenue projections, capital expenditures and tax position. Forward-looking statements can be affected by assumptions used or by known or unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed.

A forward-looking statement may include a statement of the assumptions or bases underlying the forward-looking statement. We believe that we have chosen these assumptions or bases in good faith and that they are reasonable. However, when considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this report and in our Annual Report on Form 10-K for the year ended December 31, 2015 (Annual Report). Those risk factors and other factors noted throughout this report and in our Annual Report could cause our actual results to differ materially from those disclosed in any forward-looking statement. You are cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:

• changes in general economic conditions;

• competitive conditions in our industry;

• actions taken by our customers and competitors;

• the supply and demand for natural gas, NGLs, crude oil and midstream services;

• our ability to successfully implement our business plan;

• our ability to complete internal growth projects on time and on budget;

• the price and availability of debt and equity financing;

• operating hazards and other risks incidental to transporting, storing and gathering natural gas, NGLs, crude oil and midstream products;

• natural disasters, weather-related delays, casualty losses and other matters beyond our control;

• interest rates;

• labor relations;

• large customer defaults;

• changes in the availability and cost of capital;

• changes in tax status;

• the effects of existing and future laws and governmental regulations;

• changes in insurance markets impacting costs and the level and types of coverage available;

• the timing and extent of changes in commodity prices;

• the suspension, reduction or termination of our customers’ obligations under our commercial agreements;

• disruptions due to equipment interruption or failure at our facilities, or third-party facilities on which our business is dependent;

• the effects of future litigation; and

• other factors set forth in this report and our other filings with the SEC, including our Annual Report.

Forward-looking statements speak only as of the date on which they are made. We expressly disclaim any obligation to update or revise any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by law.

3

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

ENABLE MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)

	Three Months Ended   March 31,
	2016			2015
	(In millions, except per unit data)
Revenues (including revenues from affiliates (Note 11)):
Product sales	$	245		$	351
Service revenue	264			265
Total Revenues	509			616
Cost and Expenses (including expenses from affiliates (Note 11)):
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)	195			292
Operation and maintenance	95			104
General and Administrative	20			26
Depreciation and amortization	81			73
Taxes other than income taxes	15			17
Total Cost and Expenses	406			512
Operating Income	103			104
Other Income (Expense):
Interest expense (including expenses from affiliates (Note 11))	(23		)	(20		)
Equity in earnings of equity method affiliates	7			7
Other, net	—			1
Total Other Income (Expense)	(16		)	(12		)
Income Before Income Taxes	87			92
Income tax expense	1			1
Net Income	$	86		$	91
Less: Net income attributable to noncontrolling interest	—			—
Less: Series A Preferred Unit distributions (Note 4)	—			—
Net Income attributable to common and subordinated units (Note 3)	$	86		$	91
Basic earnings per unit (Note 3)
Common units	$	0.21		$	0.22
Subordinated units	$	0.20		$	0.21
Diluted earnings per unit (Note 3)
Common units	$	0.19		$	0.22
Subordinated units	$	0.20		$	0.21
Basic weighted average number of outstanding (Note 3)
Common units	214			214
Subordinated units	208			208
Diluted weighted average number of outstanding (Note 3)
Common units	235			214
Subordinated units	208			208

See Notes to the Unaudited Condensed Consolidated Financial Statements

4

ENABLE MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended   March 31,
	2016		2015
	(In millions)
Net income	$	86	$	91
Comprehensive income	86		91
Less: Comprehensive income attributable to noncontrolling interest	—		—
Comprehensive income attributable to Enable Midstream Partners, LP	$	86	$	91

See Notes to the Unaudited Condensed Consolidated Financial Statements

5

ENABLE MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	March 31, 2016		December 31, 2015
	(In millions)
Current Assets:
Cash and cash equivalents	$	38	$	4
Accounts receivable	226		245
Accounts receivable—affiliated companies	16		21
Inventory	45		53
Gas imbalances	20		23
Other current assets	35		35
Total current assets	380		381
Property, Plant and Equipment:
Property, plant and equipment	11,395		11,293
Less accumulated depreciation and amortization	1,219		1,162
Property, plant and equipment, net	10,176		10,131
Other Assets:
Intangible assets, net	327		333
Investment in equity method affiliates	331		344
Other	35		37
Total other assets	693		714
Total Assets	$	11,249	$	11,226
Current Liabilities:
Accounts payable	$	153	$	248
Accounts payable—affiliated companies	6		9
Short-term debt	—		236
Taxes accrued	29		30
Gas imbalances	7		25
Other	85		67
Total current liabilities	280		615
Other Liabilities:
Accumulated deferred income taxes, net	8		8
Notes payable—affiliated companies	—		363
Regulatory liabilities	18		18
Other	22		20
Total other liabilities	48		409
Long-Term Debt	3,074		2,671
Commitments and Contingencies (Note 12)
Partners’ Equity:
Series A Preferred Units (14,520,000 issued and outstanding at March 31, 2016 and 0 issued and outstanding at December 31, 2015)	362		—
Common units (214,467,409 issued and outstanding at March 31, 2016 and 214,541,422 issued and outstanding at December 31, 2015, respectively)	3,692		3,714
Subordinated units (207,855,430 issued and outstanding at March 31, 2016 and December 31, 2015, respectively)	3,781		3,805
Noncontrolling interest	12		12
Total Partners’ Equity	7,847		7,531
Total Liabilities and Partners’ Equity	$	11,249	$	11,226

See Notes to the Unaudited Condensed Consolidated Financial Statements

6

ENABLE MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended   March 31,
	2016			2015
	(In millions)
Cash Flows from Operating Activities:
Net income	$	86		$	91
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	81			73
Loss on sale/retirement of assets	1			—
Equity in earnings of equity method affiliates, net of distributions	—			5
Equity based compensation	2			3
Amortization of debt costs and discount (premium)	(1		)	(1		)
Changes in other assets and liabilities:
Accounts receivable, net	19			2
Accounts receivable—affiliated companies	5			(2		)
Inventory	8			13
Gas imbalance assets	3			8
Other current assets	—			6
Other assets	1			(2		)
Accounts payable	(84		)	18
Accounts payable—affiliated companies	(3		)	(21		)
Gas imbalance liabilities	(18		)	(5		)
Other current liabilities	15			2
Other liabilities	2			(2		)
Net cash provided by operating activities	117			188
Cash Flows from Investing Activities:
Capital expenditures	(130		)	(239		)
Investment in equity method affiliates	—			(6		)
Return of investment in equity method affiliates	13			—
Net cash used in investing activities	(117		)	(245		)
Cash Flows from Financing Activities:
Proceeds from revolving credit facility	495			—
Repayment of revolving credit facility	(90		)	—
Increase (decrease) in short-term debt	(236		)	183
Repayment of notes payable—affiliated companies	(363		)	—
Proceeds from issuance of Series A Preferred Units, net of issuance costs	362			—
Distributions	(134		)	(130		)
Net cash provided by financing activities	34			53
Net Increase (Decrease) in Cash and Cash Equivalents	34			(4		)
Cash and Cash Equivalents at Beginning of Period	4			12
Cash and Cash Equivalents at End of Period	$	38		$	8

See Notes to the Unaudited Condensed Consolidated Financial Statements

7

ENABLE MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS’ EQUITY

(Unaudited)

	Series A Preferred Units			Common Units				Subordinated  Units				Noncontrolling Interest		Total Partners’ Equity
	Units	Value		Units	Value			Units	Value			Value		Value
	(In millions)
Balance as of December 31, 2014	—	$	—	214	$	4,353		208	$	4,439		$	31	$	8,823
Net income	—	—		—	48			—	43			—		91
Distributions	—	—		—	(66		)	—	(64		)	—		$	(130	)
Equity based compensation	—	—		—	3			—	—			—		$	3
Balance as of March 31, 2015	—	$	—	214	$	4,338		208	$	4,418		$	31	$	8,787
Balance as of December 31, 2015	—	$	—	214	$	3,714		208	$	3,805		$	12	$	7,531
Net income	—	—		—	44			—	42			—		86
Issuance of Series A Preferred Units	15	362		—	—			—	—			—		362
Distributions	—	—		—	(68		)	—	(66		)	—		(134		)
Equity based compensation	—	—		—	2			—	—			$	—	2
Balance as of March 31, 2016	15	$	362	214	$	3,692		208	$	3,781		$	12	$	7,847

See Notes to the Unaudited Condensed Consolidated Financial Statements

8

ENABLE MIDSTREAM PARTNERS, LP

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(1) Summary of Significant Accounting Policies

Organization

Enable Midstream Partners, LP (Partnership), a Delaware limited partnership, is a large-scale, growth-oriented limited partnership formed to own, operate and develop strategically located natural gas and crude oil infrastructure assets. The Partnership’s assets and operations are organized into two reportable segments: (i) Gathering and Processing, which primarily provides natural gas gathering, processing and fractionation services and crude oil gathering for our producer customers, and (ii) Transportation and Storage, which provides interstate and intrastate natural gas pipeline transportation and storage services primarily to natural gas producers, utilities and industrial customers. The natural gas gathering and processing assets are located in five states and serve natural gas production in the Anadarko, Arkoma and Ark-La-Tex basins. This segment also includes a crude oil gathering business in the Bakken Shale formation, principally located in the Williston basin. The natural gas transportation and storage assets extend from western Oklahoma and the Texas Panhandle to Alabama and from Louisiana to Illinois.

The Partnership is controlled equally by CenterPoint Energy and OGE Energy, who each have 50% of the management rights of Enable GP. Enable GP was established by CenterPoint Energy and OGE Energy to govern the Partnership and has no other operating activities. Enable GP is governed by a board made up of an equal number of representatives designated by each of CenterPoint Energy and OGE Energy, along with the independent board members CenterPoint Energy and OGE Energy mutually agreed to appoint. Based on the 50/50 management ownership, with neither company having control, CenterPoint Energy and OGE Energy do not consolidate their interests in the Partnership. CenterPoint Energy and OGE Energy also own a 40% and 60% interest, respectively, in the incentive distribution rights held by Enable GP. As of March 31, 2016, CenterPoint Energy held approximately 55.4% of the common and subordinated units in the Partnership, or 94,151,707 common units and 139,704,916 subordinated units, and OGE Energy held approximately 26.3% of the common and subordinated units in the Partnership, or 42,832,291 common units and 68,150,514 subordinated units. Additionally, CenterPoint Energy holds 14,520,000 Series A Preferred Units. See Note 4 for further information related to the Series A Preferred Units.

For the period from December 31, 2014 through June 29, 2015, the financial statements reflect a 49.90% interest in SESH. On June 12, 2015, CenterPoint Energy exercised its put right with respect to a 0.1% interest in SESH. Pursuant to the put right, on June 30, 2015, CenterPoint Energy contributed its remaining 0.1% interest in SESH to the Partnership in exchange for 25,341 common units representing limited partner interests in the Partnership. As of March 31, 2016, the Partnership owned a 50% interest in SESH. See Note 6 for further discussion of SESH.

Basis of Presentation

The accompanying condensed consolidated financial statements and related notes of the Partnership have been prepared pursuant to the rules and regulations of the SEC and GAAP. Pursuant to such rules and regulations, certain disclosures normally included in financial statements prepared in accordance with GAAP have been omitted. The accompanying condensed consolidated financial statements and related notes should be read in conjunction with the combined and consolidated financial statements and related notes included in our Annual Report.  

 These condensed consolidated financial statements and the related financial statement disclosures reflect all normal recurring adjustments that are, in the opinion of management, necessary to present fairly the financial position and results of operations for the respective periods. Amounts reported in the Partnership’s Condensed Consolidated Statements of 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 the Partnership’s reportable segments, see Note 14.

Use of Estimates

The preparation of financial statements in conformity with GAAP 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.

9

Accounts Receivable and Allowance for Doubtful Accounts

Accounts receivable are recorded at the invoiced amount and do not bear interest. It is the policy of management to review the outstanding accounts receivable at least quarterly, as well as the bad debt write-offs experienced in the past. Based on this review, a $3 million allowance for doubtful accounts was recognized as of March 31, 2016. There was no allowance for doubtful accounts as of December 31, 2015.

Third Amended and Restated Agreement of Limited Partnership of Enable Midstream Partners, LP

On February 18, 2016, in connection with the closing of the private placement of 14,520,000 Series A Preferred Units and pursuant to the Purchase Agreement, the General partner adopted the Third Amended and Restated Agreement of Limited Partnership (the Partnership Agreement) which, among other things, authorized and established the terms of the Series A Preferred Units and the other series of preferred units that are issuable upon conversion of the Series A Preferred Units. For further information related to the issuance of the Series A Preferred Units, see Note 4.

(2) New Accounting Pronouncements

Revenue from Contracts with Customers

In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers,” which supersedes the revenue recognition requirements in “Revenue Recognition (Topic 605),” and requires entities to recognize revenue in a way that depicts the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to in exchange for those goods or services. ASU 2014-09 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, and is to be applied retrospectively, with early application not permitted.

In August 2015, the FASB issued ASU No. 2015-14, “Revenue from Contracts with Customers (Topic 606)—Deferral of the Effective Date,” which deferred the effective date of ASU 2014-09 by one year to December 15, 2017 for annual reporting periods beginning after that date. The FASB also proposed permitting early adoption of the standard, but not before the original effective date of December 15, 2016. The Partnership is currently evaluating the impact, if any, the adoption of this standard will have on our Condensed Consolidated Financial Statements and related disclosures.

In March 2016, the FASB issued ASU No. 2016-08, “Revenue from Contracts with Customers (Topic 606)-Principal versus Agent Considerations (Reporting Revenue Gross versus Net)”. ASU No. 2016-08 requires an entity to determine whether the nature of its promise is to provide the specified good or service itself (i.e., the entity is a principal) or to arrange for that good or service to be provided by the other party (i.e., the entity is an agent) when another party is involved in providing goods or services to a customer. Additionally, the amendments in this ASU require an entity that is a principal to recognize revenue in the gross amount of consideration to which it expects to be entitled in exchange for the specified good or service transferred to the customer, and require an entity that is an agent to recognize revenue in the amount of any fee or commission to which it expects to be entitled in exchange for arranging for the specified good or service to be provided by the other party. ASU 2016-08 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, and is to be applied retrospectively, with early application not permitted. The Partnership is currently evaluating the impact, if any, the adoption of this standard will have on our Condensed Consolidated Financial Statements and related disclosures.

In April 2016, the FASB issued ASU No. 2016-10, “Revenue from Contracts with Customers (Topic 606)-Identifying Performance Obligations and Licensing”. The amendments in ASU No. 2016-10 impact entities with transactions that include contracts with customers to transfer goods or services (that are an output of the entity’s ordinary activities) in exchange for consideration, and they require entities to recognize revenue by following certain steps, including (1) identifying the contract(s) with a customer; (2) identifying the performance obligations in a contract; (3) determining the transaction price; (4) allocating the transaction price to the performance obligations in the contract; and (5) recognizing revenue when, or as, the entity satisfies a performance obligation. Notably, ASU No. 2016-10 does not impact the core revenue recognition principles set forth in Topic 606, but rather clarifies the identification of performance obligations and the licensing implementation guidance, while retaining the related principles for those areas. ASU 2016-10 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, and is to be applied retrospectively, with early application not permitted. The Partnership is currently evaluating the impact, if any, the adoption of this standard will have on our Condensed Consolidated Financial Statements and related disclosures.

10

Consolidation

In February 2015, the FASB issued ASU No. 2015-02, “Consolidation,” to improve consolidation guidance for certain types of legal entities. The guidance modifies the evaluation of whether limited partnerships and similar legal entities are variable interest entities (VIEs) or voting interest entities, eliminates the presumption that a general partner should consolidate a limited partnership, affects the consolidation analysis of reporting entities that are involved with VIEs, particularly those that have fee arrangements and related party relationships, and provides a scope exception from consolidation guidance for certain money market funds. The Partnership adopted the amendment in the first quarter of 2016, which resulted in no impact to our Condensed Consolidated Financial Statements and related disclosures.

Presentation of Debt Issuance Costs

In April 2015, the FASB issued ASU No. 2015-03, “Simplifying the Presentation of Debt Issuance Costs.” This standard amends existing guidance to require the presentation of debt issuance costs in the balance sheet as a deduction from the carrying amount of the related debt liability instead of a deferred charge. The Partnership adopted the amendment in the first quarter of 2016 on a retrospective basis in order to conform the presentation of debt issuance costs on the Condensed Consolidated Balance Sheets. At each ofMarch 31, 2016 and December 31, 2015, the Partnership had unamortized debt expense of $12 millionclassified as a reduction of Long-Term Debt in the Condensed Consolidated Balance Sheets. Unamortized debt expense related to the Revolving Credit Facility of $5 million and $6 million as ofMarch 31, 2016 and December 31, 2015, respectively, is classified as Other Assets in the Condensed Consolidated Balance Sheets.

Balance Sheet Classification of Deferred Taxes

In November 2015, the FASB issued ASU No. 2015-17, “Income Taxes—Balance Sheet Classification of Deferred Taxes.” This ASU eliminates the requirement to present deferred tax liabilities and assets as current and non-current in a classified balance sheet. Instead, all deferred tax assets and liabilities will be classified as non-current. ASU 2015-17 is effective for all interim and annual periods beginning after December 16, 2016 and early application is permitted. The amendments in this update may be applied either prospectively to all deferred tax liabilities and assets or retrospectively to all periods presented. The Partnership adopted the amendment in the first quarter of 2016, which resulted in no impact to our Condensed Consolidated Financial Statements and related disclosures.

Leases

In February 2016, the FASB issued ASU 2016-02, “Leases”. The amendments in this update require, among other things, that lessees recognize the following for all leases (with the exception of short-term leases) at the commencement date: (1) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and (2) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The Partnership expects to adopt the amendments in the first quarter of 2019 and is currently evaluating the impacts of the amendments to our Condensed Consolidated Financial Statements and accounting practices for leases.

Share-Based Compensation

In March 2016, the FASB issued ASU No. 2016-09, “Compensation—Stock Compensation (Topic 718).” This standard makes several modifications to Topic 718 related to the accounting for forfeitures, employer tax withholding on share-based compensation and the financial statement presentation of excess tax benefits or deficiencies. ASU 2016-09 also clarifies the statement of cash flows presentation for certain components of share-based awards. The standard is effective for interim and annual reporting periods beginning after December 15, 2016, although early adoption is permitted. The Partnership is currently assessing how the adoption of this standard will impact our Condensed Consolidated Financial Statements and related disclosures.

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(3) Earnings Per Limited Partner Unit

The following table illustrates the Partnership’s calculation of earnings per unit for common and subordinated units:

	Three Months Ended   March 31,
	2016		2015
	(In millions, except per unit data)
Net income	$	86	$	91
Net income attributable to noncontrolling interest	—		—
Series A Preferred Unit distribution	—		—
General partner interest in net income	—		—
Net income available to common and subordinated unitholders	$	86	$	91
Net income allocable to common units	$	44	$	48
Net income allocable to subordinated units	42		43
Net income available to common and subordinated unitholders	$	86	$	91
Net income allocable to common units	$	44	$	48
Series A Preferred Unit Distribution	—		—
Diluted net income allocable to common units	44		48
Diluted net income allocable to subordinated units	42		43
Total	$	86	$	91
Basic weighted average number of outstanding
Common units	214		214
Subordinated units	208		208
Total	422		422
Basic earnings per unit
Common units	$	0.21	$	0.22
Subordinated units	$	0.20	$	0.21
Basic weighted average number of outstanding common units	214		214
Dilutive effect of Series A Preferred Units	21		—
Diluted weighted average number of outstanding common units	235		214
Diluted weighted average number of outstanding subordinated units	208		208
Total	443		422
Diluted earnings per unit
Common units	$	0.19	$	0.22
Subordinated units	$	0.20	$	0.21

There was no dilutive effect of equity based compensation during the three months ended March 31, 2016 and 2015.

(4) Partners’ Equity

The Partnership Agreement requires that, within 45 days subsequent to the end of each quarter, the Partnership distribute all of its available cash (as defined in the Partnership Agreement) to unitholders of record on the applicable record date.

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The Partnership paid or has authorized payment of the following cash distributions to common and subordinated unitholders during 2015 and 2016 (in millions, except for per unit amounts):

Quarter Ended	Record Date	Payment Date	Per Unit Distribution		Total Cash Distribution
March 31, 2016 (1)	May 6, 2016	May 13, 2016	$	0.318	$	134
December 31, 2015	February 2, 2016	February 12, 2016	$	0.318	$	134
September 30, 2015	November 3, 2015	November 13, 2015	$	0.318	$	134
June 30, 2015	August 3, 2015	August 13, 2015	$	0.316	$	134
March 31, 2015	May 5, 2015	May 15, 2015	$	0.3125	$	132

_____________________

(1) The board of directors of Enable GP declared this $0.318 per common unit cash distribution on April 26, 2016, to be paid on May 13, 2016, to common and subordinated unitholders of record at the close of business on May 6, 2016.

The board of directors of Enable GP declared a $0.2917 per Series A Preferred Unit prorated cash distribution on April 26, 2016, to be paid on May 13, 2016, to Series A Preferred unitholders of record at the close of business on May 6, 2016. The prorated quarterly distribution for the Series A Preferred Units is for a partial period beginning on February 18, 2016, and ending on March 31, 2016, which equates to $0.625 per unit on a full-quarter basis or $2.50 per unit on an annualized basis.

General Partner Interest and Incentive Distribution Rights

Enable GP owns a non-economic general partner interest in the Partnership and thus will not be entitled to distributions that the Partnership makes prior to the liquidation of the Partnership in respect of such general partner interest. Enable GP currently holds incentive distribution rights that entitle it to receive increasing percentages, up to a maximum of 50.0%, of the cash the Partnership distributes from operating surplus (as defined in the Partnership Agreement) in excess of $0.330625 per unit per quarter. The maximum distribution of 50.0% does not include any distributions that Enable GP or its affiliates may receive on common units or subordinated units that they own.

Subordinated Units

Subordinated Unit Ownership

All subordinated units are held by CenterPoint Energy and OGE Energy. These units are considered subordinated because during the subordination period (as defined in the Partnership Agreement), the common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $0.2875 per common unit, which amount is defined in the Partnership Agreement as the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. These units are deemed “subordinated” because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions until the common units have received the minimum quarterly distribution plus any arrearages from prior quarters. Furthermore, no arrearages will be paid on the subordinated units.

Subordination Period

The subordination period began on the closing date of the Offering and will extend until the first business day following which (1) distributions of available cash from operating surplus (as defined in the Partnership Agreement) on each of the outstanding common units and subordinated units equal or exceed $1.15 per unit (the annualized minimum quarterly distribution) for each of the three consecutive, non-overlapping four-quarter periods immediately preceding June 30, 2017 and (2) the adjusted operating surplus for each of the three consecutive, non-overlapping four-quarter periods immediately preceding such date equaled or exceeded the sum of the minimum quarterly distribution on all common units and subordinated units that were outstanding during such periods on a fully diluted weighted average basis. Also, if the Partnership has paid distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equal to or exceeding $1.725 per unit (150% of the annualized minimum quarterly distribution) and the related distribution on the incentive distribution rights, for any four-consecutive-quarter period ending on or after June 30, 2015, the subordination period will terminate.

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Series A Preferred Units

On February 18, 2016, the Partnership completed the private placement of 14,520,000 Series A Preferred Units representing limited partner interests in the Partnership for a cash purchase price of $25.00 per Series A Preferred Unit, resulting in proceeds of $362 million, net of issuance costs. The Partnership incurred approximately $1 million of expenses related to the offering, which is shown as an offset to the proceeds. In connection with the closing of the private placement, the Partnership redeemed approximately $363 million of notes scheduled to mature in 2017 payable to a wholly-owned subsidiary of CenterPoint Energy.

Pursuant to the Partnership Agreement, the Series A Preferred Units:

• rank senior to the Partnership’s common units with respect to the payment of distributions and distribution of assets upon liquidation, dissolution and winding up;

• have no stated maturity;

• are not subject to any sinking fund; and

• will remain outstanding indefinitely unless repurchased or redeemed by the Partnership or converted into its common units in connection with a change of control.

Holders of the Series A Preferred Units receive, on a non-cumulative basis and if and when declared by the General Partner, a quarterly cash distribution, subject to certain adjustments, equal to an annual rate of 10% on the stated liquidation preference from the date of original issue to, but not including, the five year anniversary of the original issue date and an annual rate of LIBOR plus a spread of 8.5% on the stated liquidation preference thereafter.

At any time on or after five years after the original issue date, the Partnership may redeem the Series A Preferred Units, in whole or in part, from any source of funds legally available for such purpose, by paying $25.50 per unit plus an amount equal to all accumulated and unpaid distributions thereon to the date of redemption, whether or not declared. In addition, the Partnership (or a third-party with its prior written consent) may redeem the Series A Preferred Units following certain changes in the methodology employed by ratings agencies, changes of control or fundamental transactions as set forth in the Partnership Agreement. If, upon a change of control or certain fundamental transactions, the Partnership (or a third-party with its prior written consent) does not exercise this option, then the holders of the Series A Preferred Units have the option to convert the Series A Preferred Units into a number of common units per Series A Preferred Unit as set forth in the Partnership Agreement. The Series A Preferred Units are also required to be redeemed in certain circumstances if they are not eligible for trading on the New York Stock Exchange.

Holders of Series A Preferred Units have no voting rights except for limited voting rights with respect to potential amendments to the Partnership Agreement that have a material adverse effect on the existing terms of the Series A Preferred Units, the issuance by the Partnership of certain securities, approval of certain fundamental transactions and as required by law.

Upon the transfer of any Series A Preferred Unit to a non-affiliate of CenterPoint Energy, the Series A Preferred Units will automatically convert into a new series of preferred units (the “Series B Preferred Units”) on the later of the date of transfer and the second anniversary of the date of issue. The Series B Preferred Units will have the same terms as the Series A Preferred Units except that unpaid distributions on the Series B Preferred Units will accrue on a cumulative basis until paid.

On February 18, 2016, the Partnership entered into a Registration Rights Agreement with CenterPoint Energy, pursuant to which, among other things, the Partnership gave CenterPoint Energy certain rights to require the Partnership to file and maintain a registration statement with respect to the resale of the Series A Preferred Units and any other series of preferred units or common units representing limited partner interests in the Partnership that are issuable upon conversion of the Series A Preferred Units.

(5) Assessing Impairment of Long-lived Assets (including Intangible Assets)

The Partnership periodically evaluates long-lived assets, including property, plant and equipment, and specifically identifiable intangibles other than goodwill, when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable. The determination of whether an impairment has occurred is based on an estimate of undiscounted cash flows attributable to the assets, as compared to the carrying value of the assets. The Partnership recorded no material impairments to long-lived assets in the three months ended March 31, 2016 or 2015. Based upon review of forecasted undiscounted cash flows, none of the asset groups were at risk of failing step one of the impairment test. Further price declines, throughput declines, cost increases, regulatory or political environment changes, and other changes in market conditions could reduce forecast undiscounted cash flows.

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(6) Investments in Equity Method Affiliates

The Partnership uses the equity method of accounting for investments in entities in which it has an ownership interest between 20% and 50% and exercises significant influence.

For the period from December 31, 2014 through June 29, 2015, the Partnership held a 49.90% interest in SESH. On June 12, 2015, CenterPoint Energy exercised its put right with respect to its remaining 0.1% interest in SESH. Pursuant to the put right, on June 30, 2015, CenterPoint Energy contributed a 0.1% interest in SESH to the Partnership in exchange for 25,341 common units representing limited partner interests in the Partnership, which had a fair value of $1 million based upon the closing market price of the Partnership’s common units. Spectra Energy Partners, LP owns the remaining 50% interest in SESH. Pursuant to the terms of the SESH LLC Agreement, if, at any time, CenterPoint Energy has a right to receive less than 50% of our distributions through its interest in the Partnership and its economic interest in Enable GP, or does not have the ability to exercise certain control rights, Spectra Energy Partners, LP may, under certain circumstances, have the right to purchase our interest in SESH at fair market value. As of March 31, 2016, the Partnership owned a 50% interest in SESH.

The Partnership shares operations of SESH with Spectra Energy Partners, LP under service agreements. The Partnership is responsible for the field operations of SESH. SESH reimburses each party for actual costs incurred, which are billed based upon a combination of direct charges and allocations. During the three months ended March 31, 2016 and 2015, the Partnership billed SESH $4 million and $2 million, respectively, associated with these service agreements.

Investment in Equity Method Affiliates:

	Three Months Ended   March 31,
	2016			2015
	(In millions)
Balance as of December 31	$	344		$	348
Equity in earnings of equity method affiliate	7			7
Contributions to equity method affiliate	—			6
Distributions from equity method affiliate(1)	(20		)	(12		)
Balance as of March 31	$	331		$	349

____________________

(1) Distributions from equity method affiliates includes a $7 million and $12 million return on investment and a $13 million and zero return of investment for the three months ended March 31, 2016 and 2015, respectively.

Equity in Earnings of Equity Method Affiliates:

	Three Months Ended   March 31,
	2016		2015
	(In millions)
SESH	$	7	$	7

Distributions from Equity Method Affiliates:

	Three Months Ended   March 31,
	2016		2015
	(In millions)
SESH	$	20	$	12

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Summarized financial information of SESH is presented below:

	Three Months Ended   March 31,
	2016		2015
	(In millions)
Income Statements:
Revenues	$	29	$	29
Operating income	19		18
Net income	14		14

(7) Debt

The following table presents the Partnership’s outstanding debt as of March 31, 2016 and December 31, 2015.

	March 31, 2016		December 31, 2015
	(In millions)
Commercial Paper	$	—	$	236
2015 Term Loan Agreement	450		450
Revolving Credit Facility	715		310
Notes payable — affiliated companies (Note 11)	—		363
2019 Notes	500		500
2024 Notes	600		600
2044 Notes	550		550
EOIT Senior Notes	250		250
Premium (Discount) on long-term debt	21		23
Total debt	3,086		3,282
Less: Short-term debt(1)	—		236
Less: Unamortized debt expense	12		12
Less: Notes payable—affiliated companies	—		363
Total long-term debt	$	3,074	$	2,671

___________________

(1) Short-term debt includes $236 million of commercial paper as of December 31, 2015. There were no commercial paper borrowings outstanding as of March 31, 2016.

Revolving Credit Facility

On June 18, 2015, the Partnership amended and restated its Revolving Credit Facility to, among other things, increase the borrowing capacity thereunder to $1.75 billion and extend its maturity date to June 18, 2020. As of March 31, 2016, there was $715 million of principal advances and $3 million in letters of credit outstanding under the Revolving Credit Facility. However, as discussed below, commercial paper borrowings effectively reduce our borrowing capacity under this Revolving Credit Facility. The weighted average interest rate of the Revolving Credit Facility was 1.97% as of March 31, 2016.

The Revolving Credit Facility provides that outstanding borrowings bear interest at the LIBOR and/or an alternate base rate, at the Partnership’s election, plus an applicable margin. The applicable margin is based on the Partnership’s applicable credit ratings. As of March 31, 2016, the applicable margin for LIBOR-based borrowings under the Revolving Credit Facility was 1.50% based on the Partnership’s credit ratings. In addition, the Revolving Credit Facility requires the Partnership to pay a fee on unused commitments. The commitment fee is based on the Partnership’s applicable credit rating from the rating agencies. As of March 31, 2016, the commitment fee under the Revolving Credit Facility was 0.20% per annum based on the Partnership’s credit ratings. The commitment fee is recorded as interest expense in the Partnership’s Condensed Consolidated Statements of Income.

16

Commercial Paper

The Partnership has a commercial paper program, pursuant to which the Partnership is authorized to issue up to $1.4 billion of commercial paper. The commercial paper program is supported by our Revolving Credit Facility, and outstanding commercial paper effectively reduces our borrowing capacity thereunder. There was $236 million outstanding under our commercial paper program as of December 31, 2015. On February 2, 2016, Standard & Poor’s Ratings Services lowered its credit rating on the Partnership from an investment grade rating to a non-investment grade rating. The short-term rating on the Partnership was also reduced from an investment grade rating to a non-investment grade rating. As a result of the downgrade, the Partnership repaid its outstanding borrowings under the commercial program upon maturity and did not issue any additional commercial paper. There was no outstanding commercial paper as of March 31, 2016.

Term Loan Agreement

On July 31, 2015, the Partnership entered into a Term Loan Agreement dated as of July 31, 2015, providing for an unsecured three-year $450 million term loan agreement (2015 Term Loan Agreement). The entire $450 million principal amount of the 2015 Term Loan Agreement was borrowed by Enable on July 31, 2015. The 2015 Term Loan Agreement contains an option, which may be exercised up to two times, to extend the term of the 2015 Term Loan Agreement, in each case, for an additional one-year term. The 2015 Term Loan Agreement provides an option to prepay, without penalty or premium, the amount outstanding, or any portion thereof, in a minimum amount of $1 million, or any multiple of $0.5 million in excess thereof. As of March 31, 2016, there was $450 million outstanding under the 2015 Term Loan Agreement. As of March 31, 2016, the weighted average interest rate of the 2015 Term Loan Agreement was 1.80%.

The 2015 Term Loan Agreement provides that outstanding borrowings bear interest at the LIBOR and/or an alternate base rate, at the Partnership’s election, plus an applicable margin. The applicable margin is based on our applicable credit ratings. As ofMarch 31, 2016, the applicable margin for LIBOR-based borrowings under the term loan agreement was 1.375% based on our credit ratings.

Senior Notes

In connection with the issuance of the 2019 Notes, 2024 Notes and 2044 Notes, the Partnership, CenterPoint Energy Resources Corp., as guarantor of the 2019 Notes and the 2024 Notes, and RBS Securities Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Credit Suisse Securities (USA) LLC, and RBC Capital Markets, LLC, as representatives of the initial purchasers, entered into a registration rights agreement whereby the Partnership and the guarantor agreed to file with the SEC a registration statement relating to a registered offer to exchange the 2019 Notes, 2024 Notes and 2044 Notes for new series of the Partnership’s notes in the same aggregate principal amount as, and with terms substantially identical in all respects to, the 2019 Notes, 2024 Notes and 2044 Notes. On December 29, 2015, the Partnership completed the exchange offer.

A wholly owned subsidiary of CenterPoint Energy guaranteed collection of the Partnership’s obligations under the 2019 Notes and the 2024 Notes, which expired on May 1, 2016.

As of March 31, 2016, the Partnership’s debt included EOIT’s $250 million6.25% senior notes due March 2020 (the EOIT Senior Notes). The EOIT Senior Notes have a $22 million unamortized premium at March 31, 2016, resulting in an effective interest rate of 5.7%, during the three months ended March 31, 2016. These senior notes do not contain any financial covenants other than a limitation on liens. This limitation on liens is subject to certain exceptions and qualifications.

Financing Costs

Unamortized debt expense of $17 million and $18 million as of March 31, 2016 and December 31, 2015, respectively, is classified as either a reduction to Long-Term Debt or Other Assets in the Condensed Consolidated Balance Sheets and is being amortized over the life of the respective debt. Unamortized premium on long-term debt of $21 million and $23 million at March 31, 2016 and December 31, 2015, respectively, is classified as either Long-Term Debt or Short-Term Debt, consistent with the underlying debt instrument, in the Condensed Consolidated Balance Sheets and is being amortized over the life of the respective debt.

 As of March 31, 2016, the Partnership and EOIT were in compliance with all of their debt agreements, including financial covenants.

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(8) Fair Value Measurements

Certain assets and liabilities are recorded at fair value in the Condensed Consolidated Balance Sheets and 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. Instruments classified as Level 1 include natural gas futures, swaps and options transactions for contracts traded on the NYMEX and settled through a NYMEX clearing broker.

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. Instruments classified as Level 2 include over-the-counter NYMEX natural gas swaps, natural gas basis swaps and natural gas purchase and sales transactions in markets such that the pricing is closely related to the NYMEX pricing, and over-the-counter WTI crude swaps for condensate sales.

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 the Partnership’s judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. The Partnership develops these inputs based on the best information available, including the Partnership’s own data.

The Partnership utilizes the market approach in determining the fair value of its derivative positions by using either NYMEX or WTI published market prices, independent broker pricing data or broker/dealer valuations. The valuations of derivatives with pricing based on NYMEX published market prices may be considered Level 1 if they are settled through a NYMEX clearing broker account with daily margining. Over-the-counter derivatives with NYMEX or WTI based prices are considered Level 2 due to the impact of counterparty credit risk. Valuations based on independent broker pricing or broker/dealer valuations may be classified as Level 2 only to the extent they may be validated by an additional source of independent market data for an identical or closely related active market. In certain less liquid markets or for longer-term contracts, forward prices are not as readily available. In these circumstances, contracts are valued using internally developed methodologies that consider historical relationships among various quoted prices in active markets that result in management’s best estimate of fair value. These contracts are classified as Level 3.

The Partnership 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 period ended March 31, 2016, there were no transfers between Level 1, 2, and 3 investments.

The impact to the fair value of derivatives due to credit risk is calculated using the probability of default based on Standard & Poor’s Ratings Services and/or internally generated ratings. The fair value of derivative assets is adjusted for credit risk. The fair value of derivative liabilities is adjusted for credit risk only if the impact is deemed material.

Contracts with Master Netting Arrangements

Fair value amounts recognized for forward, interest rate swap, option and other conditional or exchange contracts executed with the same counterparty under a master netting arrangement may be offset. The reporting entity’s choice to offset or not must be applied consistently. A master netting arrangement exists if the reporting entity has multiple contracts, whether for the same type of conditional or exchange contract or for different types of contracts, with a single counterparty that are subject to a contractual agreement that provides for the net settlement of all contracts through a single payment in a single currency in the event of default on or termination of any one contract. Offsetting the fair values recognized for forward, interest rate swap, option and other conditional or exchange contracts outstanding with a single counterparty results in the net fair value of the transactions being reported as an asset or a liability in the Condensed Consolidated Balance Sheets. The Partnership has presented the fair values of its derivative contracts under master netting agreements using a net fair value presentation.

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The following tables summarize the Partnership’s assets and liabilities that are measured at fair value on a recurring basis as of March 31, 2016 and December 31, 2015:

March 31, 2016	Commodity Contracts						Gas Imbalances (1)
	Assets			Liabilities			Assets (2)		Liabilities (3)
	(In millions)
Quoted market prices in active market for identical assets (Level 1)	$	17		$	3		$	—	$	—
Significant other observable inputs (Level 2)	7			—			11		$	7
Unobservable inputs (Level 3)	2			3			—		$	—
Total fair value	26			6			11		$	7
Netting adjustments	(5		)	(5		)	—		$	—
Total	$	21		$	1		$	11	$	7

December 31, 2015	Commodity Contracts						Gas Imbalances (1)
	Assets			Liabilities			Assets (2)		Liabilities (3)
	(In millions)
Quoted market prices in active market for identical assets (Level 1)	$	17		$	3		$	—	$	—
Significant other observable inputs (Level 2)	10			—			17		20
Unobservable inputs (Level 3)	4			—			—		—
Total fair value	31			3			17		20
Netting adjustments	(3		)	(3		)	—		—
Total	$	28		$	—		$	17	$	20

______________________

(1) The Partnership uses the market approach to fair value its gas imbalance assets and liabilities at individual, or where appropriate an average of, current market indices applicable to the Partnership’s operations, not to exceed net realizable value. Gas imbalances held by EOIT are valued using an average of the Inside FERC Gas Market Report for Panhandle Eastern Pipe Line Co. (Texas, Oklahoma Mainline), ONEOK (Oklahoma) and ANR Pipeline (Oklahoma) indices. There were no netting adjustments as of March 31, 2016 and December 31, 2015.

(2) Gas imbalance assets exclude fuel reserves for under retained fuel due from shippers of $10 million and $6 million at March 31, 2016 and December 31, 2015, respectively, which fuel reserves are based on the value of natural gas at the time the imbalance was created and which are not subject to revaluation at fair market value.

(3) Gas imbalance liabilities exclude fuel reserves for over retained fuel due to shippers of $0 million and $5 million at March 31, 2016 and December 31, 2015, respectively, which fuel reserves are based on the value of natural gas at the time the imbalance was created and which are not subject to revaluation at fair market value.

Changes in Level 3 Fair Value Measurements

The following tables provides a reconciliation of changes in the fair value of our Level 3 commodity contracts between the periods presented.

	Commodity Contracts
	Natural gas liquids  financial futures/swaps
	(In millions)
Balance as of December 31, 2015	$	4
Losses included in earnings	(4		)
Settlements	(1		)
Balance as of March 31, 2016	$	(1	)

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Quantitative Information on Level 3 Fair Value Measurements

The Partnership utilizes the market approach to measure the fair value of our commodity contracts. The significant unobservable inputs used in this approach to fair value are longer dated price quotes. Our sensitivity to these longer dated forward curve prices are presented in the table below. Significant changes in any of those inputs in isolation would result in significantly different fair value measurements, depending on our short or long position in contracts.

	March 31, 2016
Product Group	Fair Value			Forward Curve Range
	(In millions)			(Per gallon)
Natural gas liquids	$	(1	)	$0.441 - $0.495

Estimated Fair Value of Financial Instruments

The fair values of all accounts receivable, notes receivable, accounts payable, commercial paper, and other such financial instruments on the Condensed Consolidated Balance Sheets are estimated to be approximately equivalent to their carrying amounts and have been excluded from the table below. The following table summarizes the fair value and carrying amount of the Partnership’s financial instruments at March 31, 2016 and December 31, 2015.

	March 31, 2016				December 31, 2015
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)
Long-Term Debt
Long-term notes payable—affiliated companies (Level 2)	$	—	$	—	$	363	$	350
Revolving Credit Facility (Level 2)(1)	715		715		310		310
2015 Term Loan Agreement (Level 2)	450		450		450		450
EOIT Senior Notes (Level 2)	272		218		273		280
Enable Midstream Partners, LP 2019, 2024 and 2044 Notes (Level 2)	1,649		1,302		1,650		1,255

___________________

(1) Borrowing capacity is reduced by our borrowings outstanding under the commercial paper program. There was zero and $236 million of commercial paper outstanding as of March 31, 2016 and December 31, 2015, respectively.

The fair value of the Partnership’s Long-term notes payable—affiliated companies, Revolving Credit Facility, and 2015 Term Loan Agreement, along with the EOIT Senior Notes and Enable Midstream Partners, LP 2019, 2024 and 2044 Notes, is based on quoted market prices and estimates of current rates available for similar issues with similar maturities and is classified as Level 2 in the fair value hierarchy.

Non-Financial Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Certain assets and liabilities are measured at fair value on a nonrecurring basis; that is, the assets and liabilities are not measured at fair value on an ongoing basis, but are subject to fair value adjustments in certain circumstances (e.g., when there is evidence of impairment).

As of March 31, 2016, no material fair value adjustments or fair value measurements were required for these non-financial assets or liabilities.

(9) Derivative Instruments and Hedging Activities

The Partnership is exposed to certain risks relating to its ongoing business operations. The primary risk managed using derivative instruments is commodity price risk. The Partnership is also exposed to credit risk in its business operations.

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Commodity Price Risk

The Partnership has used forward physical contracts, commodity price swap contracts and commodity price option features to manage the Partnership’s commodity price risk exposures in the past. Commodity derivative instruments used by the Partnership are as follows:

• NGL put options, NGL futures and swaps, and WTI crude futures and swaps for condensate sales are used to manage the Partnership’s NGL and condensate exposure associated with its processing agreements;

• natural gas futures and swaps are used to manage the Partnership’s keep-whole natural gas exposure associated with its processing operations and the Partnership’s natural gas exposure associated with operating its gathering, transportation and storage assets; and

• natural gas futures and swaps, natural gas options and natural gas commodity purchases and sales are used to manage the Partnership’s natural gas exposure associated with its storage and transportation contracts and asset management activities.

Normal purchases and normal sales contracts are not recorded in Other Assets or Liabilities in the Condensed Consolidated Balance Sheets and earnings are recognized and recorded in the period in which physical delivery of the commodity occurs. Management applies normal purchases and normal sales treatment to: (i) commodity contracts for the purchase and sale of natural gas used in or produced by the Partnership’s operations and (ii) commodity contracts for the purchase and sale of NGLs produced by the Partnership’s gathering and processing business.

The Partnership recognizes its non-exchange traded derivative instruments as Other Assets or Liabilities in the Condensed Consolidated Balance Sheets at fair value with such amounts classified as current or long-term based on their anticipated settlement. Exchange traded transactions are settled on a net basis daily through margin accounts with a clearing broker and, therefore, are recorded at fair value on a net basis in Other Current Assets in the Condensed Consolidated Balance Sheets.

As of March 31, 2016 and December 31, 2015, the Partnership had no derivative instruments that were designated as cash flow or fair value hedges for accounting purposes.

Credit Risk

The Partnership is exposed to certain credit risks relating to its ongoing business operations. Credit risk includes the risk that counterparties that owe the Partnership money or energy will breach their obligations. If the counterparties to these arrangements fail to perform, the Partnership may be forced to enter into alternative arrangements. In that event, the Partnership’s financial results could be adversely affected, and the Partnership could incur losses.

Derivatives Not Designated As Hedging Instruments

Derivative instruments not designated as hedging instruments for accounting purposes are utilized in the Partnership’s asset management activities. For derivative instruments not designated as hedging instruments, the gain or loss on the derivative is recognized currently in earnings.

Quantitative Disclosures Related to Derivative Instruments

The majority of natural gas physical purchases and sales not designated as hedges for accounting purposes are priced based on a monthly or daily index, and the fair value is subject to little or no market price risk. Natural gas physical sales volumes exceed natural gas physical purchase volumes due to the marketing of natural gas volumes purchased via the Partnership’s processing contracts, which are not derivative instruments.

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As of March 31, 2016 and December 31, 2015, the Partnership had the following derivative instruments that were not designated as hedging instruments for accounting purposes:

	March 31, 2016		December 31, 2015
	Gross Notional Volume
	Purchases	Sales	Purchases	Sales
Natural gas—TBtu(1)
Physical purchases/sales	—	48	2	51
Financial fixed futures/swaps	3	44	1	37
Financial basis futures/swaps	5	47	4	38
Crude oil (for condensate)—MBbl(2)
Financial Futures/swaps	—	460	—	506
Natural gas liquids—MBbl(3)
Financial Futures/swaps	—	1,551	75	1,011

____________________

(1) As of March 31, 2016, 86.1% of the natural gas contracts had durations of one year or less and 13.9% had durations of more than one year and less than two years. As of December 31, 2015, 97.7% of the natural gas contracts had durations of one year or less and 2.3% had durations of more than one year and less than two years.

(2) As of March 31, 2016, 93.5% of the condensate contracts had durations of one year or less and 6.5% had durations of more than one year and less than two years. As of December 31, 2015, 100% of the crude oil (for condensate) contracts had durations of one year or less.

(3) As of March 31, 2016, 85.5% of the natural gas liquids contracts had durations of one year or less and 14.5% had durations of more than one year and less than two years. As of December 31, 2015, 100% of the natural gas liquid contracts had durations of one year or less.

Balance Sheet Presentation Related to Derivative Instruments

The fair value of the derivative instruments that are presented in the Partnership’s Condensed Consolidated Balance Sheets as of March 31, 2016 and December 31, 2015 that were not designated as hedging instruments for accounting purposes are as follows:

		March 31, 2016				December 31, 2015
		Fair Value
Instrument	Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
		(In millions)
Natural gas
Financial futures/swaps	Other Current	$	18	$	3	$	17	$	3
Physical purchases/sales	Other Current	—		—		1		—
Crude Oil (for condensate)
Financial futures/swaps	Other Current	6		—		9		—
Natural gas liquids
Financial Futures/swaps	Other Current	2		3		4		—
Total gross derivatives (1)		$	26	$	6	$	31	$	3

_____________________

(1) See Note 8 for a reconciliation of the Partnership’s total derivatives fair value to the Partnership’s Condensed Consolidated Balance Sheets as of March 31, 2016 and December 31, 2015.

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Income Statement Presentation Related to Derivative Instruments

The following tables present the effect of derivative instruments on the Partnership’s Condensed Consolidated Statements of Income for the three months ended March 31, 2016 and 2015.

	Amounts Recognized in Income
	Three Months Ended   March 31,
	2016			2015
	(In millions)
Natural gas financial futures/swaps gains (losses)	$	10		$	7
Natural gas physical purchases/sales gains (losses)	(4		)	(4		)
Crude Oil (for condensate) financial futures/swaps gains (losses)	1			4
Natural gas liquids financial futures/swaps gains (losses)	(4		)	—
Total	$	3		$	7

For derivatives not designated as hedges in the tables above, amounts recognized in income for the periods ended March 31, 2016 and 2015, if any, are reported in Product Sales.

Credit-Risk Related Contingent Features in Derivative Instruments

Based upon the Partnership’s senior unsecured debt rating with Moody’s Investors Services or Standard & Poor’s Ratings Services, the Partnership could be required to provide credit assurances to third parties, which could include letters of credit or cash collateral to satisfy its obligation under its financial and physical contracts relating to derivative instruments that are in a net liability position. As of March 31, 2016, under these obligations, no cash collateral has been posted. However, based on positions as of March 31, 2016, approximately $1 million of additional collateral may be required to be posted by the Partnership.

(10)Supplemental Disclosure of Cash Flow Information

The following table provides information regarding supplemental cash flow information:

	Three Months Ended   March 31,
	2016		2015
	(In millions)
Supplemental Disclosure of Cash Flow Information:
Cash Payments:
Interest, net of capitalized interest	$	15	$	9
Income taxes, net of refunds	1		—
Non-cash transactions:
Accounts payable related to capital expenditures	42		51

(11) Related Party Transactions

The material related party transactions with CenterPoint Energy, OGE Energy and their respective subsidiaries are summarized below. There were no material related party transactions with other affiliates.

23

The Partnership’s revenues from affiliated companies accounted for 9% and 8% of revenues during the three months ended March 31, 2016 and 2015, respectively. Amounts of revenues from affiliated companies included in the Partnership’s Condensed Consolidated Statements of Income are summarized as follows:

	Three Months Ended   March 31,
	2016		2015
	(In millions)
Gas transportation and storage service revenue — CenterPoint Energy	$	33	$	33
Natural gas product sales — CenterPoint Energy	1		6
Gas transportation and storage service revenue — OGE Energy	9		9
Natural gas product sales — OGE Energy	1		3
Total revenues — affiliated companies	$	44	$	51

Amounts of natural gas purchased from affiliated companies included in the Partnership’s Condensed Consolidated Statements of Income are summarized as follows:

	Three Months Ended   March 31,
	2016		2015
	(In millions)
Cost of natural gas purchases — CenterPoint Energy	$	—	$	1
Cost of natural gas purchases — OGE Energy	2		3
Total cost of natural gas purchases — affiliated companies	$	2	$	4

Prior to May 1, 2013, the Partnership had employees and reflected the associated benefit costs directly and not as corporate services. Under the terms of the MFA, effective May 1, 2013 the Partnership’s employees were seconded by CenterPoint Energy and OGE Energy, and the Partnership began reimbursing each of CenterPoint Energy and OGE Energy for all employee costs under the seconding agreements until the seconded employees transition from CenterPoint Energy and OGE Energy to the Partnership. The Partnership transitioned seconded employees from CenterPoint Energy and OGE Energy to the Partnership effective January 1, 2015, except for certain employees who are participants under OGE Energy’s defined benefit and retiree medical plans, who will remain seconded to the Partnership, subject to certain termination rights of the Partnership and OGE Energy. The Partnership’s reimbursement of OGE Energy for employee costs arising out of OGE Energy’s defined benefit and retiree medical plans is fixed at $6 million in 2016, $5 million in 2017, and at actual cost subject to a cap of $5 million in 2018 and thereafter, in the event of continued secondment.

Prior to May 1, 2013, the Partnership received certain services and support functions from CenterPoint Energy described below. Under the terms of the MFA, effective May 1, 2013, the Partnership receives services and support functions from each of CenterPoint Energy and OGE Energy under service agreements for an initial term ending on April 30, 2016. The service agreements automatically extend year-to-year at the end of the initial term, unless terminated by the Partnership with at least 90 days’ notice. Additionally, the Partnership may terminate these service agreements at any time with 180 days’ notice, if approved by the Board of Enable GP. The Partnership reimburses CenterPoint Energy and OGE Energy for these services up to annual caps, which for 2016 are $7 million and $3 million, respectively.

24

Amounts charged to the Partnership by affiliates for seconded employees and corporate services, included primarily in Operation and maintenance and General and administrative expenses in the Partnership’s Condensed Consolidated Statements of Income are as follows:

	Three Months Ended   March 31,
	2016		2015
	(In millions)
Corporate Services — CenterPoint Energy	2		4
Seconded Employee Costs — OGE Energy	9		9
Corporate Services — OGE Energy	2		3
Total corporate services and seconded employees expense	$	13	$	16

The Partnership had outstanding long-term notes payable—affiliated companies to CenterPoint Energy at December 31, 2015 of $363 million, which were scheduled to mature in 2017. On February 18, 2016, in connection with the Private Placement of the Series A Preferred Units, the Partnership redeemed the $363 million of notes payable—affiliated companies payable to a subsidiary of CenterPoint Energy.

The Partnership recorded affiliated interest expense to CenterPoint Energy on notes payable—affiliated companies of $1 million and $2 million during the three months ended March 31, 2016 and 2015, respectively.

On February 18, 2016, the Partnership completed the private placement, with CenterPoint Energy, of 14,520,000 Series A Preferred Units representing limited partner interests in the Partnership for a cash purchase price of $25.00 per Series A Preferred Unit, resulting in proceeds of $362 million, net of issuance costs. See Note 4 for further discussion.

(12) Commitments and Contingencies

The Partnership is involved in legal, environmental, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business. Some of these proceedings involve substantial amounts. The Partnership regularly analyzes current information and, as necessary, provides accruals for probable liabilities on the eventual disposition of these matters. The Partnership 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) Equity Based Compensation

The following table summarizes the Partnership’s compensation expense for the three months ended March 31, 2016 and 2015 related to performance units, restricted units, and phantom units for the Partnership’s employees and independent directors:

	Three Months Ended   March 31,
	2016		2015
	(In millions)
Performance units	$	1	$	1
Restricted units	1		2
Phantom units	—		—
Total compensation expense	$	2	$	3

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Units Outstanding

The Partnership periodically grants performance units, restricted units, and phantom units to certain employees under the Enable Midstream Partners, LP Long Term Incentive Plan. A summary of the activity for the Partnership’s performance units, restricted units, and phantom units applicable to the Partnership’s employees at March 31, 2016 and changes during 2016 are shown in the following table.

	Performance Units					Restricted Units					Phantom Units
	Number of Units			Weighted Average Grant-Date Fair Value, Per Unit		Number of Units			Weighted Average Grant-Date Fair Value, Per Unit		Number of Units		Weighted Average Grant-Date Fair Value, Per Unit
	(In millions, except unit data)
Units Outstanding at December 31, 2015	814,510			$	20.67	581,772			$	21.04	9,817		$	12.70
Granted	—			—		—			—		—		—
Vested	(1,685		)	20.72		(78,375		)	22.58		—		—
Forfeited	(44,408		)	17.69		(49,834		)	19.26		—		—
Units Outstanding at March 31, 2016	768,417			$	20.84	453,563			$	20.97	9,817		$	12.70
Aggregate Intrinsic Value of Units Outstanding at March 31, 2016	$	5				$	3				$	—

Unrecognized Compensation Cost

A summary of the Partnership’s unrecognized compensation cost for its non-vested performance units, restricted units, and phantom units, and the weighted-average periods over which the compensation cost is expected to be recognized are shown in the following table.

	March 31, 2016
	Unrecognized Compensation Cost (In millions)		Weighted Average to be Recognized (In years)
Performance Units	$	9	1.80
Restricted Units	8		1.78
Phantom Units	—		0.24
Total	$	17

As of March 31, 2016, there were 11,149,474 units available for issuance under the long term incentive plan.

(14) Reportable Segments

The Partnership’s determination of reportable segments considers the strategic operating units under which it manages sales, allocates resources and assesses performance of various products and services to customers in differing regulatory environments. The accounting policies of the reportable segments are the same as those described in the summary of significant accounting policies excerpt in the Partnership’s audited 2015 combined and consolidated financial statements included in the Annual Report. The Partnership uses operating income as the measure of profit or loss for its reportable segments.

The Partnership’s assets and operations are organized into two reportable segments: (i) Gathering and Processing, which primarily provides natural gas gathering, processing and fractionation services and crude oil gathering for our producer customers, and (ii) Transportation and Storage, which provides interstate and intrastate natural gas pipeline transportation and storage service primarily to natural gas producers, utilities and industrial customers.

26

Financial data for reportable segments are as follows:

Three Months Ended March 31, 2016	Gathering  and Processing		Transportation and Storage(1)		Eliminations			Total
	(In millions)
Revenues	$	333	$	246	$	(70	)	$	509
Cost of natural gas and natural gas liquids	165		99		(69		)	195
Operation and maintenance, General and administrative	75		41		(1		)	115
Depreciation and amortization	49		32		—			81
Impairments	—		—		—			—
Taxes other than income tax	8		7		—			15
Operating income	$	36	$	67	$	—		$	103
Total assets	$	7,543	$	4,888	$	(1,182	)	$	11,249
Capital expenditures	$	121	$	9	$	—		$	130
Three Months Ended March 31, 2015	Gathering and Processing		Transportation and Storage(1)		Eliminations			Total
	(In millions)
Revenues	$	401	$	308	$	(93	)	$	616
Cost of natural gas and natural gas liquids	222		163		(93		)	292
Operation and maintenance, General and administrative	76		54		—			130
Depreciation and amortization	43		30		—			73
Impairments	—		—		—			—
Taxes other than income tax	8		9		—			17
Operating income	$	52	$	52	$	—		$	104
Total assets as of December 31, 2015	$	7,536	$	4,976	$	(1,286	)	$	11,226
Capital expenditures	$	215	$	24	$	—		$	239

_____________________

(1) See Note 6 for discussion regarding ownership interests in SESH and related equity earnings included in the Transportation and Storage segment for the three months ended March 31, 2016 and 2015.

27

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with our unaudited condensed consolidated financial statements and the related notes included herein and our audited combined and consolidated financial statements for the year ended December 31, 2015, included in our Annual Report. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Please read “Forward-Looking Statements.” In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.

Overview

We are a large-scale, growth-oriented publicly traded Delaware limited partnership formed to own, operate and develop strategically located natural gas and crude oil infrastructure assets. We serve current and emerging production areas in the United States, including several unconventional shale resource plays and local and regional end-user markets in the United States. Our assets and operations are organized into two reportable segments: (i) Gathering and Processing, which primarily provides natural gas gathering, processing and fractionation services and crude oil gathering for our producer customers, and (ii) Transportation and Storage, which provides interstate and intrastate natural gas pipeline transportation and storage services primarily to natural gas producers, utilities and industrial customers.

Our natural gas gathering and processing assets are located in Oklahoma, Texas, Arkansas, Louisiana and Mississippi and serve natural gas production in the Anadarko, Arkoma and Ark-La-Tex basins. We also own a crude oil gathering business located in North Dakota to serve shale development in the Bakken Shale formation of the Williston Basin. Our natural gas transportation and storage assets extend from western Oklahoma and the Texas Panhandle to Alabama and from Louisiana to Illinois.

We expect our business to continue to be affected by the key trends included in our Annual Report. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about, or interpretations of, available information prove to be incorrect, our actual results may vary materially from our expected results.

Recent Developments

Construction update

The Bradley II Plant, a 200 MMcf/d cryogenic processing facility located in the Anadarko basin, is under construction and estimated to be in service in the second quarter of 2016.

The Partnership has commenced construction on the Wildhorse Plant, a 200 MMcf/d cryogenic processing facility located in the Anadarko basin, which is estimated to be in service no sooner than the second half of 2017.

Series A Preferred Units

On February 18, 2016, the Partnership completed the private placement of 14,520,000 Series A Preferred Units representing limited partner interests in the Partnership for a cash purchase price of $25.00 per Series A Preferred Unit, resulting in proceeds of $362 million, net of issuance costs. In connection with the closing of the private placement, the Partnership redeemed approximately $363 million of notes scheduled to mature in 2017 payable to a wholly-owned subsidiary of CenterPoint Energy.

Results of Operations

The following tables summarize the key components of our results of operations for the three months ended March 31, 2016 and 2015.

28

Three Months Ended March 31, 2016	Gathering and Processing		Transportation and Storage		Eliminations			Enable Midstream Partners, LP
	(In millions)
Revenues	$	333	$	246	$	(70	)	$	509
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)	165		99		(69		)	195
Gross margin (1)	168		147		(1		)	314
Operation and maintenance, General and administrative	75		41		(1		)	115
Depreciation and amortization	49		32		—			81
Taxes other than income tax	8		7		—			15
Operating income	$	36	$	67	$	—		$	103
Equity in earnings of equity method affiliates	$	—	$	7	$	—		$	7

Three Months Ended March 31, 2015	Gathering and Processing		Transportation and Storage		Eliminations			Enable Midstream Partners, LP
	(In millions)
Revenues	$	401	$	308	$	(93	)	$	616
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)	222		163		(93		)	292
Gross margin (1)	179		145		—			324
Operation and maintenance, General and administrative	76		54		—			130
Depreciation and amortization	43		30		—			73
Taxes other than income tax	8		9		—			17
Operating income	$	52	$	52	$	—		$	104
Equity in earnings of equity method affiliates	$	—	$	7	$	—		$	7

_____________________

(1) Gross margin is defined and reconciled to its most directly comparable financial measures calculated and presented below under the caption Non-GAAP Financial Measures.

	Three Months Ended   March 31,
	2016	2015
Operating Data:
Gathered volumes—TBtu	278	286
Gathered volumes—TBtu/d	3.05	3.18
Natural gas processed volumes—TBtu	162	151
Natural gas processed volumes—TBtu/d	1.78	1.68
NGLs produced—MBbl/d(1)	73.47	65.00
NGLs sold—MBbl/d(1)(2)	76.31	67.62
Condensate sold—MBbl/d	6.45	5.96
Crude Oil - Gathered volumes—MBbl/d	28.85	6.72
Transported volumes—TBtu	465	514
Transportation volumes—TBtu/d	5.11	5.72
Interstate firm contracted capacity—Bcf/d	7.17	7.82
Intrastate average deliveries—TBtu/d	1.68	1.84

 _____________________

(1) Excludes condensate.

(2) NGLs sold includes volumes of NGLs withdrawn from inventory or purchased for system balancing purposes.

29

Gathering and Processing

Three months ended March 31, 2016 compared to three months ended March 31, 2015. Our gathering and processing segment reported operating income of $36 million in the three months ended March 31, 2016 compared to operating income of $52 million in the three months ended March 31, 2015. Operating income decreased $16 million primarily from decreased gross margin of $11 million, and an increase in depreciation and amortization of $6 million, partially offset by a decrease in operation and maintenance expenses of $1 million, during the three months ended March 31, 2016.

Our gathering and processing segment gross margin decreased $11 million primarily due to a decrease in processing margins of $9 million resulting from lower average natural gas liquids prices and lower processed volumes in the Ark-La-Tex basin offset by higher processed volumes in the Anadarko basin, combined with a decrease in unrealized gains on condensate and NGL derivatives of $8 million. Additionally, gathering margins decreased $6 million due to reduced sales on natural gas length due to lower average natural gas prices, and lower revenues on third party measurement and communication services of $1 million. These decreases were partially offset by an increase in the imbalance receivable of $9 million associated with our annual fuel rate determination and an increase in gathering fees of $3 million as a result of higher gathered volumes in the Anadarko basin. Also, crude oil gathering increased $4 million due to higher volumes in the Williston basin, offset by a decrease of $3 million from one-time project reimbursements during the three months ended March 31, 2016.

Our gathering and processing segment operation and maintenance and general and administrative expenses decreased $1 million primarily due to a decrease in payroll related costs of $3 million and lower severance charges related to 2015 workforce reductions of $2 million. These decreases were partially offset by an increase in allowance for doubtful accounts of $3 million and higher losses on sale of assets of $1 million.

Our gathering and processing segment depreciation and amortization increased $6 million due to additional assets placed in service.

Transportation and Storage

Three months ended March 31, 2016 compared to three months ended March 31, 2015. Our transportation and storage segment reported operating income of $67 million in the three months ended March 31, 2016 compared to operating income of $52 million in the three months ended March 31, 2015. Operating income increased $15 million primarily resulting from an increase in gross margin of $2 million, a decrease of $13 million in operation and maintenance and general and administrative expenses, and a decrease in taxes other than income tax of $2 million, partially offset by a $2 millionincrease in depreciation and amortization expenses for the three months ended March 31, 2016.

Our transportation and storage segment gross margin increased $2 million primarily due to higher margins of $8 million related to unrealized gains on natural gas derivatives and an increase of $1 million in gains on system optimization activities. These increases were partially offset by lower firm transportation revenues of $5 million and decreased margins from off-system transportation revenues of $2 million for the three months ended March 31, 2016.

Our transportation and storage segment operation and maintenance and general and administrative expenses decreased $13 million due to a decrease in payroll related costs of $7 million, lower integration costs of $4 million, and lower severance charges related to 2015 workforce reductions of $2 million.

Our transportation and storage segment depreciation and amortization increased $2 million primarily due to additional assets placed in service.

Our transportation and storage segment taxes other than income tax decreased $2 million due to reduced ad valorem taxes.

Our transportation and storage segment recorded equity in earnings of equity method affiliates of $7 million for each of the three months ended March 31, 2016 and 2015 from our interest in SESH.

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Condensed Consolidated Interim Information

	Three Months Ended   March 31,
	2016			2015
	(In millions)
Operating Income	$	103		$	104
Other Income (Expense):
Interest expense	(23		)	(20		)
Equity in earnings of equity method affiliates	7			7
Other, net	—			1
Total Other Income (Expense)	(16		)	(12		)
Income Before Income Taxes	87			92
Income tax expense	1			1
Net Income	$	86		$	91
Less: Net income attributable to noncontrolling interest	—			—
Less: Series A Preferred Unit distributions	—			—
Net Income attributable to common and subordinated units	$	86		$	91

	Three Months Ended   March 31,
	2016		2015
	(In millions)
Other Financial Data:
Gross Margin (1)	$	314	$	324
Adjusted EBITDA (1)	215		207
Distributable cash flow (1)	174		145

_____________________

(1) Gross margin, Adjusted EBITDA and distributable cash flow are defined and reconciled to their most directly comparable financial measures calculated and presented below under the caption Non-GAAP Financial Measures within this Part I, Item 2.

Three Months Ended March 31, 2016 compared to Three Months Ended March 31, 2015

Net Income attributable to the Partnership. We reported net income attributable to the Partnership of $86 million in the three months ended March 31, 2016 compared to net income attributable to the Partnership of $91 million in the three months ended March 31, 2015. The decrease in net income attributable to the Partnership of $5 million was primarily attributable to an increase in interest expense of $3 million, a decrease in operating income of $1 million and a decrease in other income and expense of $1 million in the three months ended March 31, 2016.

Interest Expense. Interest expense increased $3 million due to higher interest rates on the Partnership’s outstanding debt and an increase in the amount of outstanding debt.

Non-GAAP Financial Measures

The Partnership has included the non-GAAP financial measures gross margin, Adjusted EBITDA and distributable cash flow in this report based on information in its condensed consolidated financial statements.

Gross margin, Adjusted EBITDA and distributable cash flow are supplemental financial measures that management and external users of the Partnership’s financial statements, such as industry analysts, investors, lenders and rating agencies may use, to assess:

• The Partnership’s operating performance as compared to those of other publicly traded partnerships in the midstream energy industry, without regard to capital structure or historical cost basis;

31

• The ability of the Partnership’s assets to generate sufficient cash flow to make distributions to its partners;

• The Partnership’s ability to incur and service debt and fund capital expenditures; and

• The viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.

This report includes a reconciliation of gross margin to revenues, Adjusted EBITDA and distributable cash flow to net income attributable to controlling interest, and Adjusted EBITDA to net cash provided by operating activities, the most directly comparable GAAP financial measures, on a historical basis, as applicable, for each of the periods indicated. The Partnership believes that the presentation of gross margin, Adjusted EBITDA and distributable cash flow provides information useful to investors in assessing its financial condition and results of operations. Gross margin, Adjusted EBITDA and distributable cash flow should not be considered as alternatives to net income, operating income, revenue, cash from operations or any other measure of financial performance or liquidity presented in accordance with GAAP. Gross margin, Adjusted EBITDA and distributable cash flow have important limitations as an analytical tool because they exclude some but not all items that affect the most directly comparable GAAP measures. Additionally, because gross margin, Adjusted EBITDA and distributable cash flow may be defined differently by other companies in the Partnership’s industry, its definitions of gross margin, Adjusted EBITDA and distributable cash flow may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.

	Three Months Ended   March 31,
	2016			2015
	(In millions)
Reconciliation of Gross Margin to Revenues:
Revenues	$	509		$	616
Cost of natural gas and natural gas liquids (excluding depreciation and amortization)	195			292
Gross margin	$	314		$	324
Reconciliation of Adjusted EBITDA and distributable cash flow to net income attributable to common and subordinated units:
Net income attributable to common and subordinated units	$	86		$	91
Add:
Depreciation and amortization expense	81			73
Interest expense, net of interest income	23			20
Income tax expense	1			1
EBITDA	$	191		$	185
Add:
Distributions from equity method affiliates(1)	20			12
Non-cash equity based compensation	2			3
Other non-cash losses	12			14
Less:
Other non-cash gains	(3		)	—
Equity in earnings of equity method affiliates	(7		)	(7		)
Adjusted EBITDA	$	215		$	207
Less:
Adjustment for Series A Preferred Unit distribution, net (2)	(4		)	—
Adjusted interest expense, net (3)	(23		)	(22		)
Maintenance capital expenditures	(13		)	(39		)
Current income taxes	(1		)	(1		)
Distributable cash flow	$	174		$	145

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	Three Months Ended   March 31,
	2016			2015
	(In millions)
Reconciliation of Adjusted EBITDA to net cash provided by operating activities:
Net cash provided by operating activities	$	117		$	188
Interest expense, net of interest income	23			20
Income tax expense	1			1
Equity in earnings of equity method affiliates, net of distributions(1)	—			(5		)
Non-cash equity based compensation	(2		)	(3		)
Other non-cash items	—			1
Changes in operating working capital which (provided) used cash:
Accounts receivable	(24		)	—
Accounts payable	87			9
Other, including changes in noncurrent assets and liabilities	(11		)	(26		)
EBITDA	$	191		$	185
Add:
Non-cash equity based compensation	2			3
Distributions from equity method affiliates(1)	20			12
Other non-cash losses	12			14
Less:
Other non-cash gains	(3		)	—
Equity in earnings of equity method affiliates	(7		)	(7		)
Adjusted EBITDA	$	215		$	207

____________________

(1) Distributions from equity method affiliates includes a $7 million and $12 million return on investment and a $13 million and zero return of investment for the three months ended March 31, 2016 and 2015, respectively. Equity in earnings of equity method affiliates, net of distributions only includes those distributions representing a return on investment.

(2) This amount represents the prorated quarterly cash distribution on the Series A Preferred Units declared on April 26, 2016. In accordance with the Partnership Agreement, the Series A Preferred Unit distributions are deemed to have been paid out of available cash with respect to the quarter immediately preceding the quarter in which the distribution is made. This amount is shown net of the amount of Series A Preferred Unit distributions recognized in the Condensed Consolidated Statements of Income.

(3) Adjusted interest expense, net excludes the effect of the amortization of the premium on EOIT’s fixed rate senior notes. This exclusion is the primary reason for the difference between “Interest expense, net” and “Adjusted interest expense, net.”

Liquidity and Capital Resources

Working Capital

Working capital is the difference in our current assets and our current liabilities. Working capital is an indication of liquidity and potential need for short-term funding. The change in our working capital requirements are driven generally by changes in accounts receivable, accounts payable, commodity prices, credit extended to, and the timing of collections from, customers, and the level and timing of spending for maintenance and expansion activity. As of March 31, 2016, we had a working capital surplus of $100 million. We utilize our revolving credit facility to manage the timing of cash flows and fund short-term working capital deficits.

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Cash Flows

The following tables reflect cash flows for the applicable periods:

	Three Months Ended   March 31,
	2016			2015
	(In millions)
Net cash provided by operating activities	$	117		$	188
Net cash used in investing activities	(117		)	(245		)
Net cash provided by financing activities	34			53

Operating Activities

The decrease of $71 million, or 38%, in net cash provided by operating activities for the three months ended March 31, 2016 as compared to the three months ended March 31, 2015 was primarily due to timing of payments to suppliers, receipts from customers, and changes in other working capital assets and liabilities.

Investing Activities

The decrease of $128 million, or 52%, in net cash used in investing activities for the three months ended March 31, 2016 as compared to the three months ended March 31, 2015 was primarily due to lower capital expenditures of $109 million.

Financing Activities

Net cash provided by financing activities decreased $19 million for the three months ended March 31, 2016 as compared to the three months ended March 31, 2015. Our primary financing activities consist of the following:

	Three Months Ended   March 31,
	2016		2015
	(In millions)
Net proceeds from Revolving Credit Facility	405		—
Proceeds (repayments) from commercial paper program	(236	)	183
Repayment of notes payable—affiliated companies	(363	)	—
Proceeds from issuance of Series A Preferred Units, net of issuance costs	362		—
Distributions to partners	(134	)	(130	)

Term Loan Agreement

On July 31, 2015, the Partnership entered into a Term Loan Agreement providing for an unsecured three-year $450 million term loan agreement (2015 Term Loan Agreement). The entire $450 million principal amount of the 2015 Term Loan Agreement was borrowed by Enable on July 31, 2015. The 2015 Term Loan Agreement contains an option, which may be exercised up to two times, to extend the term of the 2015 Term Loan Agreement, in each case, for an additional one-year term. The 2015 Term Loan Agreement provides an option to prepay, without penalty or premium, the amount outstanding, or any portion thereof, in a minimum amount of $1 million, or any multiple of $0.5 million in excess thereof. As of March 31, 2016 there was $450 million outstanding under the 2015 Term Loan Agreement.

The 2015 Term Loan Agreement provides that outstanding borrowings bear interest at the LIBOR and/or an alternate base rate, at the Partnership’s election, plus an applicable margin. The applicable margin is based on our applicable credit ratings. As ofMarch 31, 2016, the applicable margin for LIBOR-based borrowings under the term loan agreement was 1.375% based on our credit ratings. As of March 31, 2016, the weighted average interest rate of the 2015 Term Loan Agreement was 1.80%.

Revolving Credit Facility

On June 18, 2015, the Partnership amended and restated its Revolving Credit Facility to, among other things, increase the borrowing capacity thereunder to $1.75 billion and extend its maturity date to June 18, 2020. The Revolving Credit Facility is discussed in Note 7 of the condensed consolidated financial statements. As of March 31, 2016, there were $715 million of principal

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advances and $3 million in letters of credit outstanding under the Revolving Credit Facility. The weighted average interest rate of the Revolving Credit Facility was 1.97% as of March 31, 2016. Commercial paper borrowings effectively reduce our borrowing capacity under this Revolving Credit Facility. As of March 31, 2016, we had no outstanding borrowings under our commercial paper program.

The Revolving Credit Facility provides that outstanding borrowings bear interest at the LIBOR and/or an alternate base rate, at the Partnership’s election, plus an applicable margin. The applicable margin is based on the Partnership’s applicable credit ratings. As of March 31, 2016, the applicable margin for LIBOR-based borrowings under the Revolving Credit Facility was 1.50% based on the Partnership’s credit ratings. In addition, the Revolving Credit Facility requires the Partnership to pay a fee on unused commitments. The commitment fee is based on the Partnership’s applicable credit rating from the rating agencies. As of March 31, 2016, the commitment fee under the Revolving Credit Facility was 0.20% per annum based on the Partnership’s credit ratings. The commitment fee is recorded as interest expense in the Partnership’s Combined and Consolidated Statements of Income.

Preferred Equity Issuance

On February 18, 2016, the Partnership completed the private placement of 14,520,000 Series A Preferred Units representing limited partner interests in the Partnership for a cash purchase price of $25.00 per Series A Preferred Unit, with CenterPoint Energy, resulting in proceeds of $362 million, net of issuance costs. See Part 1, Note 4 for further discussion.

Sources of Liquidity

As of March 31, 2016, our sources of liquidity included:

• cash on hand;

• cash generated from operations;

• borrowings under our Revolving Credit Facility; and

• capital raised through debt and equity markets.

Capital Requirements

The midstream business is capital intensive and can require significant investment to maintain and upgrade existing operations, connect new wells to the system, organically grow into new areas and comply with environmental and safety regulations. Going forward, our capital requirements will consist of the following:

• maintenance capital expenditures, which are cash expenditures (including expenditures for the construction or development of new capital assets or the replacement, improvement or expansion of existing capital assets) made to maintain, over the long-term, our operating capacity or operating income; and

• expansion capital expenditures, which are cash expenditures incurred for acquisitions or capital improvements that we expect will increase our operating income or operating capacity over the long term.

Our future expansion capital expenditures may vary significantly from period to period based on commodity prices and the investment opportunities available to us. We expect to fund future capital expenditures from cash flow generated from our operations, borrowings under our Revolving Credit Facility, new debt offerings or the issuance of additional partnership units. Issuances of equity or debt in the capital markets may not, however, be available to us on acceptable terms.

Distributions

On April 26, 2016, the board of directors of Enable GP declared a quarterly cash distribution of $0.318 per common unit on all of the Partnership’s outstanding common and subordinated units for the period ended March 31, 2016. Additionally, the board of directors of Enable GP declared a prorated quarterly cash distribution of $0.2917 on the Partnership’s outstanding Series A Preferred Units. The distributions will be paid May 13, 2016 to unitholders of record as of the close of business on May 6, 2016.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements.

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Credit Risk

We are exposed to certain credit risks relating to our ongoing business operations. Credit risk includes the risk that counterparties that owe us money or energy will breach their obligations. If the counterparties to these arrangements fail to perform, we may be forced to enter into alternative arrangements. In that event, our financial results could be adversely affected, and we could incur losses. We examine the creditworthiness of third party customers to whom we extend credit and manage our exposure to credit risk through credit analysis, credit approval, credit limits and monitoring procedures, and for certain transactions, we may request letters of credit, prepayments or guarantees.

Critical Accounting Policies and Estimates

The Partnership’s critical accounting policies and estimates are described in Critical Accounting Policies and Estimates within Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 1 of the Notes to the Combined and Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” in our Annual Report on Form 10-K for the year ended December 31, 2015. The accounting policies and estimates used in preparing our interim Condensed Consolidated Financial Statements for the three months ended March 31, 2016 are the same as those described in our Annual Report on Form 10-K for the year ended December 31, 2015.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

We are exposed to various market risks, including volatility in commodity prices and interest rates.

Commodity Price Risk

While we generate a substantial portion of our gross margin pursuant to long-term, fee-based contracts that include minimum volume commitments and/or demand fees, we are also exposed to changes in the prices of natural gas and NGLs. The Partnership utilizes derivatives and forward commodity sales to mitigate the effects of price changes. We do not enter into risk management contracts for speculative purposes.

Based on our forecasted volumes, prices and contractual arrangements, we estimate approximately 15% of our total gross margin for the twelve months ending December 31, 2016 is directly exposed to changes in commodity prices, excluding the impact of hedges.

Commodity price risk is estimated as the potential loss in value resulting from a hypothetical 10% decline in prices over the next nine months. Based on a sensitivity analysis, a 10% decrease in prices from forecasted levels would decrease net income by approximately $5 million for natural gas and $6 million for condensate and NGLs, excluding the impact of hedges, for the remaining nine months ending December 31, 2016.

Interest Rate Risk

Our current interest rate risk exposure is related primarily to our debt portfolio. Our debt portfolio is substantially comprised of fixed rate debt, which mitigates the impact of fluctuations in interest rates. Future issuances of long-term debt could be impacted by increases in interest rates, which could result in higher interest costs. Borrowings under our Revolving Credit Facility, 2015 Term Loan Agreement and issuances under our commercial paper program are at a variable interest rate and expose us to the risk of increasing interest rates. Based upon the $1,165 million outstanding borrowings under the 2015 Term Loan Agreement and Revolving Credit Facility as of March 31, 2016, and holding all other variables constant, a 100 basis-point, or 1%, increase in interest rates would increase our annual interest expense by approximately $12 million.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Our management, with the participation of our chief executive officer and chief financial officer, has evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) as of March 31, 2016. Based on such evaluation, our management has concluded that, as of March 31, 2016, our disclosure controls and procedures are designed and effective to ensure that information required

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to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the SEC’s rules and forms and that information is accumulated and communicated to our management, including its principal executive officer and principal financial officer, or persons performing similar functions, as appropriate, to allow timely decisions regarding required disclosure.

In designing and evaluating our disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable, and not absolute, assurance that the objectives of the control system will be met. In addition, the design of any control system is based in part upon certain assumptions about the likelihood of future events and the application of judgment in evaluating the cost-benefit relationship of possible controls and procedures. Because of these and other inherent limitations of control systems, there is only reasonable assurance that our controls will succeed in achieving their goals under all potential future conditions.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal controls over financial reporting during the quarter ended March 31, 2016, that have materially affected, or that are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

Information regarding legal proceedings is set forth in Note 12 - Commitments and Contingencies to the Partnership’s condensed consolidated financial statements included in Item 1 of Part I of this Quarterly Report on Form 10-Q and is incorporated herein by reference.

Item 1A. Risk Factors

We are subject to various risks and uncertainties in the course of our business. Risk factors relating to the Partnership are set forth under “Risk Factors” in our Annual Report. No other material changes to such risk factors have occurred during the three months ended March 31, 2016 with the exception of the items discussed below.

Our Series A Preferred Units have rights, preferences and privileges that are not held by, and are preferential to the rights of, holders of our common units.

Our 10% Series A Fixed-to-Floating Non-Cumulative Redeemable Perpetual Preferred Units representing limited partner interests in the Partnership (our “Series A Preferred Units”), issued in February 2016, rank senior to all of our other classes or series of equity securities with respect to distribution rights and rights upon liquidation. We cannot declare or pay a distribution to our common or subordinated unitholders for any quarter unless full distributions have been or contemporaneously are being paid on all outstanding Series A Preferred Units for such quarter. These preferences could adversely affect the market price for our common units, or could make it more difficult for us to sell our common units in the future.

Holders of the Series A Preferred Units will receive, on a non-cumulative basis and if and when declared by our general partner, a quarterly cash distribution, subject to certain adjustments, equal to an annual rate of 10% on the stated liquidation preference from the date of original issue to, but not including, the five year anniversary of the original issue date, and an annual rate of LIBOR plus a spread of 850 bps on the stated liquidation preference thereafter. In connection with certain transfers of the Series A Preferred Units, the Series A Preferred Units will automatically convert into one or more new series of preferred units (the “other preferred units”) on the later of the date of transfer or the second anniversary of the date of issue. The other preferred units will have the same terms as our Series A Preferred Units except that unpaid distributions on the other preferred units will accrue from the date of their issuance on a cumulative basis until paid. Our Series A Preferred Units are convertible into common units by the holders of such units in certain circumstances. Payment of distributions on our Series A Preferred Units, or on the common units issued following the conversion of such Series A Preferred Units, could impact our liquidity and reduce the amount of cash flow available for working capital, capital expenditures, growth opportunities, acquisitions, and other general partnership purposes. Our obligations to the holders of Series A Preferred Units could also limit our ability to obtain additional financing or increase our borrowing costs, which could have an adverse effect on our financial condition.

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Our Series A Preferred Units contain covenants that may limit our business flexibility.

Our Series A Preferred Units contain covenants preventing us from taking certain actions without the approval of the holders of 66 2⁄3% of the Series A Preferred Units. The need to obtain the approval of holders of the Series A Preferred Units before taking these actions could impede our ability to take certain actions that management or our board of directors may consider to be in the best interests of our unitholders. The affirmative vote of 66 2⁄3% of the outstanding Series A Preferred Units, voting as a single class, is necessary to amend the Partnership Agreement in any manner that would or could reasonably be expected to have a material adverse effect on the rights, preferences, obligations or privileges of the Series A Preferred Units. The affirmative vote of 66 2⁄3% of the outstanding Series A Preferred Units and any outstanding series of other preferred units, voting as a single class, is necessary to (A) create or issue certain party securities with proceeds in an aggregate amount in excess of $700 million or create or issue any senior securities or (B) subject to our right to redeem the Series A Preferred Units, approve certain fundamental transactions.

Our Series A Preferred Units are required to be redeemed in certain circumstances if they are not eligible for trading on the NYSE, and we may not have sufficient funds to redeem our Series A Preferred Units if we are required to do so.

The holders of our Series A Preferred Units may request that we list those units for trading on the NYSE. If we are unable to list the Series A Preferred Units in certain circumstances, we will be required to redeem the Series A Preferred Units. There can be no assurance that we would have sufficient financial resources available to satisfy our obligation to redeem the Series A Preferred Units. In addition, mandatory redemption of our Series A Preferred Units could have a material adverse effect on our business, financial position, results of operations and ability to make quarterly cash distributions to our unitholders.

We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner and its affiliates, to enable us to pay the minimum quarterly distribution to holders of our common and subordinated units.

We may not have sufficient available cash each quarter to enable us to pay the minimum quarterly distribution. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

• the fees and gross margins we realize with respect to the volume of natural gas, NGLs and crude oil that we handle;

• the prices of, levels of production of, and demand for natural gas, NGLs and crude oil;

• the volume of natural gas, NGLs and crude oil we gather, compress, treat, dehydrate, process, fractionate, transport and store;

• the relationship among prices for natural gas, NGLs and crude oil;

• cash calls and settlements of hedging positions;

• margin requirements on open price risk management assets and liabilities;

• the level of competition from other midstream energy companies;

• adverse effects of governmental and environmental regulation;

• the level of our operation and maintenance expenses and general and administrative costs; and

• prevailing economic conditions.

In addition, the actual amount of cash we will have available for distribution will depend on other factors, including:

•the level and timing of capital expenditures we make;

•the cost of acquisitions;

•our debt service requirements and other liabilities;

•fluctuations in working capital needs;

•our ability to borrow funds and access capital markets;

•restrictions contained in our debt agreements;

•the amount of cash reserves established by our general partner

•distributions paid on our Series A Preferred Units; and

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•other business risks affecting our cash levels.

The amount of cash we have available for distribution to our limited partners depends primarily on our cash flow rather than on our profitability, which may prevent us from making distributions, even during periods in which we record net income.

The amount of cash we have available for distribution depends primarily upon our cash flows and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses for financial accounting purposes and may not make cash distributions during periods when we record net earnings for financial accounting purposes.

Our general partner and its affiliates, including CenterPoint Energy and OGE Energy, have conflicts of interest with us and limited duties to us and our unitholders, and they may favor their own interests to the detriment of us and our other common unitholders.

Affiliates of CenterPoint Energy and OGE Energy own and control our general partner and appoint all of the officers and directors of our general partner. Some of the directors of our general partner are also directors of CenterPoint Energy or OGE Energy. Although our general partner has a duty to manage us in a manner that is beneficial to us and our unitholders, the directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner that is beneficial to CenterPoint Energy and OGE Energy. Conflicts of interest will arise between CenterPoint Energy, OGE Energy and our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of CenterPoint Energy and OGE Energy over our interests and the interests of our unitholders. These conflicts include the following situations, among others:

• Neither the Partnership Agreement nor any other agreement requires CenterPoint Energy or OGE Energy to pursue a business strategy that favors us. The directors and officers of CenterPoint Energy and OGE Energy have a fiduciary duty to make decisions in the best interests of the stockholders of their respective companies, which may be contrary to our interests. CenterPoint Energy and OGE Energy may choose to shift the focus of their investment and growth to areas not served by our assets. In addition, CenterPoint Energy is the holder of our Series A Preferred Units and may favor its interests in voting in favor of actions relating to such units, including voting in favor of making distributions on such Series A Preferred Units even if no distributions are made on the common units.

• Our general partner is allowed to take into account the interests of parties other than us, such as CenterPoint Energy and OGE Energy, in resolving conflicts of interest.

• Some of the directors of our general partner are also directors of CenterPoint Energy or OGE Energy and will owe fiduciary duties to their respective companies. These individuals may also devote significant time to the business of CenterPoint Energy and OGE Energy.

• The Partnership Agreement replaces the fiduciary duties that would otherwise be owed to us by our general partner with contractual standards governing its duties, limits our general partner’s liabilities and restricts the remedies available to our unitholders for actions that, without such limitations, might constitute breaches of fiduciary duty.

• Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.

• Disputes may arise under our commercial agreements with CenterPoint Energy and OGE Energy.

• Our general partner determines the amount and timing of asset purchases and sales, borrowings, issuances of additional partnership units and the creation, reduction or increase of cash reserves, each of which can affect the amount of distributable cash flow.

• Our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion or investment capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and the ability of the subordinated units to convert to common units.

• Our general partner determines which costs incurred by it and its affiliates are reimbursable by us.

• Our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of the subordination period.

• The Partnership Agreement permits us to classify up to $300 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash

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may be used to fund distributions on our subordinated or general partner units or to our general partner in respect of the incentive distribution rights.

• The Partnership Agreement does not prohibit our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf.

• Our general partner intends to limit its liability regarding our contractual and other obligations.

• Our general partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if they own more than 90% of the common units. If our general partner and its affiliates reduce their ownership percentage to below 70% of the outstanding units, the ownership threshold to exercise the call right will be permanently reduced to 80%.

• Our general partner controls the enforcement of the obligations that it and its affiliates owe to us.

• Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

• Our general partner may transfer its incentive distribution rights without unitholder approval.

• Our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner’s incentive distribution rights without the approval of the conflicts committee of the Board of Directors or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.

We may issue additional units without your approval, which would dilute your existing ownership interests.

The Partnership Agreement does not limit the number of additional limited partner interests, including limited partner interests that rank senior to the common units, that we may issue at any time without the approval of our unitholders. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

• our existing unitholders’ proportionate ownership interest in us will decrease;

• the amount of distributable cash flow on each unit may decrease;

• because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;

• because the amount payable to holders of incentive distribution rights is based on a percentage of the total distributable cash flow, the distributions to holders of incentive distribution rights will increase even if the per unit distribution on common units remains the same;

• the ratio of taxable income to distributions may increase;

• the relative voting strength of each previously outstanding unit may be diminished; and

• the market price of the common units may decline.

In addition, upon a change of control, our Series A Preferred Units are convertible into common units at the option of the holders of such units. If a substantial portion of the Series A Preferred Units were converted into common units, common unitholders could experience significant dilution. In addition, if holders of such converted Series A Preferred Units were to dispose of a substantial portion of these common units in the public market, whether in a single transaction or series of transactions, it could adversely affect the market price for our common units. In addition, these sales, or the possibility that these sales may occur, could make it more difficult for us to sell our common units in the future.

Affiliates of our general partner may sell common units in the public or private markets, which could have an adverse impact on the trading price of the common units.

As of March 31, 2016, subsidiaries of CenterPoint Energy and OGE Energy hold an aggregate of 136,983,998 common units and 207,855,430subordinated units, and CenterPoint Energy holds 14,520,000 Series A Preferred Units. Upon a change of control, our Series A Preferred Units are convertible into common units at the option of the holders of such units. All of the subordinated units will convert into common units at the end of the subordination period and some may convert earlier under certain circumstances. In addition, we have agreed to provide CenterPoint Energy, OGE Energy and ArcLight with certain registration rights. The sale of these units in the public or private markets could have an adverse impact on the price of the common units or on any trading market that may develop.

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Our general partner has a limited call right that may require our unitholders to sell their units at an undesirable time or price.

If at any time our general partner and its affiliates own more than 90% of the common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price, as calculated pursuant to the terms of the Partnership Agreement. If our general partner and its affiliates reduce their ownership percentage to below 70% of the outstanding units, the ownership threshold to exercise the call right will be permanently reduced to 80%. As a result, our unitholders may be required to sell their common units at an undesirable time or price and may not receive any positive return on their investment. Our unitholders may also incur a tax liability upon any such sale of their units. As of March 31, 2016, affiliates of our general partner owned approximately 32.4% of our outstanding common units. At the end of the subordination period, assuming no additional issuances of common units (other than upon the conversion of the subordinated units), affiliates of our general partner will own approximately 81.7% of our aggregate outstanding common units. If we assume the conversion of our Series A Preferred Units, affiliates of our general partner will own an additional 83.4% of our aggregate outstanding common units. Affiliates of our general partner may acquire additional common units from us in connection with future transactions or through open-market or negotiated purchases.

We may incur significant costs and liabilities resulting from pipeline integrity and other similar programs and related repairs.

The U.S. Department of Transportation, or DOT, has adopted regulations requiring pipeline operators to develop integrity management programs for transportation pipelines located in “high consequence areas,” which are those areas where a leak or rupture could do the most harm. The regulations require operators, including us, to, among other things:

•develop a baseline plan to prioritize the assessment of a covered pipeline segment;

• identify and characterize applicable threats that could impact a high consequence area;

• improve data collection, integration, and analysis;

• repair and remediate pipelines as necessary; and

• implement preventive and mitigating action.

Changes to pipeline safety laws and regulations that result in more stringent or costly safety standards could have a significant adverse effect on us and similarly situated midstream operators. For example, in August 2011, PHMSA published an advance notice of proposed rulemaking (ANPRM) in which the agency was seeking public comment on a number of changes to regulations governing the safety of gas transmission pipelines and gathering lines, including, for example, revising the definitions of “high consequence areas” and “gathering lines” and strengthening integrity management requirements as they apply to existing regulated operators and to currently exempt operators should certain exemptions be removed. On April 8, 2016, the Pipeline and Hazardous Materials Safety Administration published a notice of proposed rulemaking (NPRM) responding to several of the integrity management topics raised in the August 2011 ANPRM and proposing new requirements to address safety issues for natural gas transmission and gathering lines that have arisen since the issuance of the ANPRM. The proposed rule would strengthen existing integrity management requirements, expand assessment and repair requirements to pipelines in areas with medium population densities, and extend regulatory requirements to onshore gas gathering lines that are currently exempt. Comments on the April 8, 2016 NPRM are currently due by June 7, 2016. PHMSA published a similar NPRM for hazardous liquids (including oil) pipelines on October 13, 2015. That proposed rule would extend regulatory reporting requirements to all liquid gathering lines, require additional event-driven and periodic inspections, require use of leak detection systems on all hazardous liquid pipelines, modify repair criteria, and require certain pipelines to eventually accommodate inline inspection tools. Comments were due by January 8, 2016, and further action is pending. We are still monitoring and evaluating the effect of these proposed requirements on our operations.

Although many of our pipelines fall within a class that is currently not subject to these requirements, we may incur significant cost and liabilities associated with repair, remediation, preventive or mitigation measures associated with our non-exempt pipelines. This work is part of our normal integrity management program and we do not expect to incur any extraordinary costs during 2016 to complete the testing required by existing DOT regulations and their state counterparts. We have not estimated the costs for any repair, remediation, preventive or mitigation actions that may be determined to be necessary as a result of the testing program, which could be substantial, or any lost cash flows resulting from shutting down our pipelines during the pendency of such repairs. Should we fail to comply with DOT or comparable state regulations, we could be subject to penalties and fines. In addition, rulemakings such as the ones discussed in the October 13, 2015 and April 8, 2016 NPRMs could expand the scope of the integrity management program and other related pipeline safety programs to include additional requirements or previously exempt pipelines. We have not estimated the cost of complying with such future requirements.

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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 Enable Midstream Partners, LP, any other persons, any state of affairs or other matters.

Exhibit Number	Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference
2.1	Master Formation Agreement dated as of March 14, 2013 by and among CenterPoint Energy, Inc., OGE Energy Corp., Bronco Midstream Holdings, LLC and Bronco Midstream Holdings II, LLC	Registrant’s registration statement on Form S-1, filed on November 26, 2013	File No. 333-192545	Exhibit 2.1
3.1	Certificate of Limited Partnership of CenterPoint Energy Field Services LP, as amended	Registrant’s registration statement on Form S-1, filed on November 26, 2013	File No. 333-192545	Exhibit 3.1
3.2	Third Amended and Restated Agreement of Limited Partnership of Enable Midstream Partners, LP	Registrant’s Form 8-K filed February 19, 2016	File No. 001-36413	Exhibit 3.1
4.1	Specimen Unit Certificate representing common units (included with Second Amended and Restated Agreement of Limited Partnership of Enable Midstream Partners, LP as Exhibit A thereto)	Registrant’s Form 8-K filed April 22, 2014	File No. 001-36413	Exhibit 3.1
4.2	Indenture, dated as of May 27, 2014, between Enable Midstream Partners, LP and U.S. Bank National Association, as trustee.	Registrant’s Form 8-K filed May 29, 2014	File No. 001-36413	Exhibit 4.1
4.3	First Supplemental Indenture, dated as of May 27, 2014, by and among Enable Midstream Partners, LP, CenterPoint Energy Resources Corp., as guarantor, and U.S. Bank National Association, as trustee.	Registrant’s Form 8-K filed May 29, 2014	File No. 001-36413	Exhibit 4.2
4.4	Registration Rights Agreement, dated as of May 27, 2014, by and among Enable Midstream Partners, LP, CenterPoint Energy Resources Corp., as guarantor, and RBS Securities Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Credit Suisse Securities (USA) LLC, and RBC Capital Markets, LLC, as representatives of the initial purchasers.	Registrant’s Form 8-K filed May 29, 2014	File No. 001-36413	Exhibit 4.3
4.5	Registration Rights Agreement, dated as of February 18, 2016, by and between Enable Midstream Partners, LP and CenterPoint Energy, Inc.	Registrant’s Form 8-K filed February 19, 2016	File No. 001-36413	Exhibit 4.1
10.1	Purchase Agreement by and between Enable Midstream Partners, LP and CenterPoint Energy, Inc. dated January 28, 2016	Registrant’s Form 8-K filed February 1, 2016	File No. 001-36413	Exhibit 10.1
+10.2	Special Severance Agreement and General Release by and between Enable Midstream Services, LLC and Paul A. Weissgarber
+31.1	Rule 13a-14(a)/15d-14(a) Certification of principal executive officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
+31.2	Rule 13a-14(a)/15d-14(a) Certification of principal financial officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
+32.1	Section 1350 Certification of principal executive officer
+32.2	Section 1350 Certification of principal financial officer
+99.1	Guarantee Agreement dated as of May 1, 2013 among CenterPoint Energy Field Services LP and Enogex LLC
+101.INS	XBRL Instance Document.
+101.SCH	XBRL Taxonomy Schema Document.
+101.PRE	XBRL Taxonomy Presentation Linkbase Document.
+101.LAB	XBRL Taxonomy Label Linkbase Document.
+101.CAL	XBRL Taxonomy Calculation Linkbase Document.
+101.DEF	XBRL Definition Linkbase Document.

42

SIGNATURE

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

		ENABLE MIDSTREAM PARTNERS, LP
		(Registrant)
		By: ENABLE GP, LLC
		Its general partner
Date:	May 4, 2016	By:	/s/ Tom Levescy
			Tom Levescy
			Senior Vice President, Chief Accounting Officer and Controller
			(Principal Accounting Officer)

EX-10.2

Exhibit 10.2

SPECIAL SEVERANCE AGREEMENT AND GENERAL RELEASE

THIS SPECIAL SEVERANCE AGREEMENT AND GENERAL RELEASE ("Agreement") is entered into by and between Enable Midstream Services, LLC (the “Company”) and Paul A. Weissgarber, an individual (hereafter referenced as the "Executive"), and provided to Executive on February 11, 2016(the “Delivery Date”) with respect to the following:

WHEREAS, Executive will be or has been separated from employment per his resignation with the Company as of February 12, 2016 (the “Termination Date”);

WHEREAS, the Company desires to provide Executive certain benefits upon his separation from employment in recognition of Executive's service to the Company and to make Executive’s transition as smooth as possible;

WHEREAS, Executive desires to receive the benefits described herein in exchange for certain promises and other consideration, including a waiver and general release of all claims against the parties set forth in the Waiver and General Release attached hereto and incorporated herein by reference as Exhibit “A”;

WHEREAS, Executive understands that he has twenty-one (21) days after the Delivery Date to consider this Agreement and understands that he must sign this Agreement (and the Waiver and General Release) by the end of the 21-day period;

WHEREAS, Executive is hereby advised by the Company that he should consult with an attorney prior to signing this Agreement and the Waiver and General Release; and

WHEREAS, Executive desires to sign this Agreement and the Waiver and General Release, and receive benefits as described in this Agreement in exchange for certain promises and other consideration.

NOW, THEREFORE, BE IT RESOLVED, that the Company and Executive, in consideration of the covenants herein set forth, agree as follows:

1.Definitions. For purposes of this Agreement, the following terms shall have the meanings provided below:

a.Affiliate means, with respect to any Person, any other Person that directly or indirectly through one or more intermediaries controls, is controlled by or is under common control with the person in question. As used herein, the term “control” means the possession, direct or indirect, of the power to direct or cause the direction of the management and policies of a Person, whether through ownership of voting securities, by contact or otherwise. Notwithstanding the foregoing, the term “Affiliate” with respect to the Company, means (i) OGE Energy Corp. and each of its wholly owned subsidiaries, so long as OGE Energy Corp., or one of its wholly owned subsidiaries, has the power to designate one or more individuals to serve on the Board of Directors of the General Partner (the “Board”), and (ii) CenterPoint Energy, Inc. and each of its wholly owned subsidiaries, so long as CenterPoint Energy, Inc., or one of its wholly owned subsidiaries, has the power to designate one or more individuals to serve on the Board.

b.Agreement means this Special Severance Agreement and General Release, which includes the Waiver and General Release attached hereto as Exhibit “A” and incorporated herein by reference.

Exhibit 10.2

c.Cause: Termination from employment due to unacceptable performance, misconduct, gross negligence, dishonesty, any violation of the policies of the Company, the Partnership, the General Partner, or any Affiliates, or acts detrimental to the Company, the Partnership, the General Partner, or to an Affiliate or to employees, property or the reputation of the foregoing parties as stated in this paragraph as determined in the Company’s sole discretion.

d.General Partner means Enable GP, LLC.

e.LTI means the Enable Midstream Partners, LP Long-Term Incentive Plan.

f.Partnership means Enable Midstream Partners, LP.

g.Person means a “Person” as defined in Section 3(a)(9) of the Securities Exchange Act of 1934, and the rules and regulations thereunder, as such law, rules and regulations may be amended from time to time, and used in Sections 13(d) and 14(d) thereof, including a “group” as defined in Section 13(d) thereof.

h.STI means the Enable Midstream Partners, LP Short Term Incentive Plan, effective January 1, 2014.

i.Subsequent Disqualifying Events mean any of the following events which may occur before or after the Termination Date:

i. acts which are detrimental or destructive to the General Partner, the Partnership, the Company, or an Affiliate (as determined in the sole discretion of the General Partner, the Partnership, or the Company);

ii. any breach of the material terms of this Agreement, including but not limited to engaging in any Unauthorized Communication or breach of the confidentiality provisions of this Agreement; and/or

iii. Executive accepts employment with the Company or an Affiliate prior to signing the Waiver and General Release.

j.Severance Benefit Payment means the sum of the severance benefits payable to Executive as described in Paragraph 4.

k.Signature Date means the date Executive signs and returns this Agreement and the Waiver and General Release.

l.Unauthorized Communication means disclosure, dissemination or duplication of the Agreement (including the Waiver and General Release) and/or any letters accompanying the Agreement by Executive to third parties (other than an Exempt Individual as defined under Paragraph 16) or to the media.

m.Waiver and General Release means the waiver and general release of claims attached hereto as Exhibit “A”.

Exhibit 10.2

2.Work through Termination Date. If Executive has not already been released by the Company as of the Delivery Date, he will continue to faithfully and competently perform his job duties through the Termination Date unless the Company otherwise indicates or is otherwise mutually agreed upon by the Company and Executive. If Executive voluntarily resigns from employment with the Company prior to his Termination Date or is terminated from employment by the Company for Cause, death or any other reason other than by the Company without Cause prior to his Termination Date, the Company’s obligations under this Agreement shall become null and void.

3.Resignation. Effective on the Termination Date the employment relationship between the Company and Executive will be terminated per Executive’s resignation from employment, and the Company will be relieved of Executive’s duties in all respects. Executive resigns from any position as an officer of the Company and if applicable, as a director, officer, manager, partner or similar position of each subsidiary or affiliate of the Company.

4.Severance Benefit Payment. Provided Executive complies with the terms of this Agreement (including the Waiver and General Release), the Company agrees to pay Executive the following severance benefits:

a.A lump-sum cash payment of one year of Executive’s annual base salary equal to $345,000.

b.A lump-sum cash payment equal to $425,100, which represents the approximate value as determined by the Company of (i) one-half of Executive’s new hire award of Restricted Units (as defined under the LTI) granted on January 5, 2015; and (ii) one-third of Executive’s Performance Units (as defined under the LTI) granted on June 1, 2015, calculated at target, and (iii) which represents your share of the Company performance portion of the STI grant as determined by the Company.

c.A lump-sum cash payment of $15,400 to be used for payment of COBRA premiums after the Termination Date.

d.A lump-sum cash payment of $5,000 to be used for outplacement services.

For avoidance of doubt, as of the Termination Date, Executive is not vested in any award under the LTI or STI and forfeits any right to future payment under the LTI and STI, including but not limited to any payment which Executive may otherwise be eligible to receive if continuously employed.

The total payments described in this Paragraph 4 constitute the Severance Benefit Payment. The Severance Benefit Payment shall be reduced by any monies owed by Executive to the Company, the General Partner, and/or the Partnership, including, but not limited to, any overpayments made to Executive by the Company, the General Partner, and/or the Partnership and the balance of any loan by the Company, the General Partner, and/or the Partnership to Executive that is outstanding at the time that the benefits are paid.

5.Payment Form, Time. The Severance Benefit Payment, less applicable withholding, shall be paid in a lump sum no later than 30 days after the Signature Date and expiration of the seven-day revocation period (as described in Paragraph 24), provided that Executive has not revoked his signed Agreement (including the Waiver and General Release) as described below by the close of business on the seventh (7^th) day after the Signature Date. The Severance Benefit Payment will not otherwise be “benefit bearing” and will not be considered as compensation for purposes of the Company’s qualified retirement plan(s) or for

Exhibit 10.2

accrual of paid time off or other leaves. Executive represents that this payment constitutes monies to which he would not otherwise be entitled but for this Agreement.

6.Withholding. The Company shall withhold from the Severance Benefit Payment all federal, state, city or other taxes and any other withholding as may be required pursuant to any law or governmental regulation or ruling at the time payment is received.

7.Waiver and General Release. In consideration of the Company’s promises in this Agreement, Executive agrees to execute the Waiver and General Release attached hereto as Exhibit “A” no sooner than his Termination Date and no later than the conclusion of the twenty-first (21^st) day after the Delivery Date. By signing this Agreement, Executive is agreeing that once seven (7) days have passed from the date he signs the Waiver and General Release, he will not attempt to revoke or rescind the Waiver and General Release at any time in the future. In addition, Executive is representing that he fully understands the terms of this Agreement and the Waiver and General Release and that he has had an opportunity to seek legal advice regarding the Waiver and General Release under this Agreement, if he desires to do so, before signing these documents. Executive is also representing to the Company that he has not commenced any action or filed any administrative charge or complaint against the Company in regard to his employment between the Termination Date and the date he signs the Agreement and Waiver and General Release.

8.Non-Solicitation. Executive agrees that for a period of six (6) months following the Termination Date, Executive shall not directly solicit the sale of goods, services or a combination of goods and services from any established customers of the Company or its Affiliates. As used in this paragraph, an “established customer” is a customer of the Company or an Affiliate at any time during the one (1) year period prior to the Termination Date who continues to be a customer following the Termination Date, regardless of where the customer is located. Executive further agrees that for a period of one (1) year following the Termination Date Executive shall not solicit, directly or indirectly, actively or inactively, the employees or independent contractors of the Company or its Affiliates to become employees or independent contractors of another person or business.

9.No Right to Re-employment. In consideration of the Company’s promises in this Agreement, Executive agrees that his relationship with the Company, the General Partner, the Partnership, and its successors, and Affiliates has been severed such that the foregoing entities shall have no obligation to reemploy Executive in the future. Executive further agrees that this paragraph represents a valid, non-discriminatory, non-retaliatory reason to decline to consider his application or terminate any employment arrangement contrary to this Agreement.

10.Commitment to Preserve Good Name. Executive agrees that he will not at any time in the future defame, disparage or make statements which could embarrass or cause harm to the Company, the General Partner, the Partnership, an Affiliate, or any successor thereto or the names and reputations of any of their owners, officers and/or directors, to any of their current, former or prospective customers, industry organizations, Executives or contractors, to any governmental or regulatory agency, or to the press or media. Nothing in this paragraph or elsewhere in this Agreement is intended to prevent or prohibit Executive from communicating with the Equal Employment Opportunity Commission (or any government agency), as set out in Paragraph 18 below.

11.Subsequent Disqualifying Events. Notwithstanding anything stated elsewhere in the Agreement, if Executive engages in a Subsequent Disqualifying Event, the Company shall not be obligated to provide any of the severance benefits described in this Agreement, and shall have the right to be immediately reimbursed by Executive for the value of the entire Severance Benefit Payment already provided to Executive

Exhibit 10.2

by the Company under this Agreement. Executive further agrees that in the event he may attempt to revoke, repudiate or rescind this Agreement (including the Waiver and General Release) or engage in any Unauthorized Communication at any time in the future, repayment and reimbursement to the Company for the value of the entire Severance Benefit Payment paid to Executive described in this Agreement shall be a contractual prerequisite to any legal action brought or arbitration sought by Executive in connection with his separation from employment from the Company or otherwise arising out of the employment or other relationship with the Company or an Affiliate.

12.Return of Company Property. Executive agrees that, on or before his Termination Date or such other date as the Company shall instruct, whichever is earlier, he will return all Company property and the originals and all copies of any records, files, computer disc or other materials which contain information about the General Partner’s, the Partnership’s, the Company’s, or an Affiliate’s business.

13.Confidentiality of Information. Executive agrees that, except with the prior written consent of the Company, he will not, at any time after the date of this Agreement, make any independent use of or disclose to any other person or organization any of the Company’s confidential, proprietary information or trade secrets. This shall apply to any information which is of a special and unique value and includes, without limitation, both written and unwritten information relating to operations; business planning and strategies; finance; accounting; costs of providing service; operating and maintenance costs; and pricing matters. This obligation regarding the Company’s confidential, proprietary information or trade secrets is in addition to, but does not replace, any prior agreement between Executive and the Company regarding confidentiality. It shall be a breach of this paragraph for Executive to engage in any Unauthorized Communication.

14.Severability. If any term, provision, covenant or restriction of this Agreement (including the Waiver and General Release) is held by a court of competent jurisdiction or other tribunal to be invalid, void or unenforceable, the remainder of the terms, provisions, covenants and restrictions of this Agreement shall remain in full force and effect and shall in no way be affected, impaired or invalidated.

15.Arbitration of Disputes. The parties agree that the subject matter of this Agreement relates to interstate commerce.  All disputes, claims or controversies between the Executive and the Company arising out of an alleged breach of this Agreement and any disputes, claims or controversies allegedly not waived and released by the Waiver and General Release attached hereto as Exhibit “A” arising out of the parties' prior employment relationship or otherwise, including without limitation, any claims identified in Paragraph 1 of the Waiver and General Release (which is incorporated herein by reference) shall, to the extent such disputes, claims or controversies relate to the severance benefits under this Agreement, be settled by arbitration as provided herein. This agreement to arbitrate, however, shall not preclude the Company from obtaining injunctive or other equitable relief from a court of competent jurisdiction to prevent on-going breaches of this Agreement or any other on-going obligations the Executive may have to the Company pending arbitration. This agreement to arbitrate shall survive the termination or rescission of this Agreement. All arbitration shall be before a single arbitrator in accordance with the American Arbitration Association’s National Rules for the Resolution of Employment Disputes pertaining to individually-negotiated contracts and shall be undertaken pursuant to the Federal Arbitration Act; provided, however, Executive agrees that he shall have no right or authority for any dispute to be brought, heard or arbitrated as a class or collective action, or in a representative or a private attorney general capacity on behalf of a class of persons or the general public. Unless the parties mutually agree to self-administer the arbitration or to use a different arbitration service, it will be administered by the Dallas, Texas office of the American Arbitration Association. Unless the parties have previously agreed to a different location in a separate, individual employment agreement between the Company and Executive or the parties hereafter mutually agree to another location, any arbitration under this Agreement will be held in Oklahoma City, Oklahoma. The decision of the arbitrator will be enforceable

Exhibit 10.2

in any court of competent jurisdiction. The arbitrator shall have the discretion and authority to award such legal and equitable relief as is appropriate upon the evidence and the applicable law. The arbitrator shall also have the discretion and authority to award costs and attorney fees to the prevailing party or, alternatively, may order each party to bear its/his or her own costs and attorney fees in connection with the arbitration to the extent permitted by applicable law. The parties agree that punitive, liquidated or indirect damages shall not be awarded by the arbitrator except to the extent such damages would have been awarded in a court of competent jurisdiction. Finally, the parties agree that this Paragraph 15 shall supersede the arbitration provisions contained in any separate individual employment agreement signed by Executive and/or any agreement signed by Executive pursuant to any Company policy. To the extent there is any inconsistency between this Paragraph 15 and such agreement(s), the provisions of this Paragraph 15 shall control.

16.Miscellaneous. No provisions of this Agreement may be modified, waived or discharged unless such waiver, modification or discharge is agreed to in writing signed by Executive and the Company. No waiver by either party hereto at any time of any breach by the other party hereto of, or compliance with any condition or provision of this Agreement to be performed by such other party shall be deemed a waiver of similar or dissimilar provisions or conditions at the same or at any prior or subsequent time. No agreements or representations, oral or otherwise, express or implied, with respect to the subject matter hereof have been made by either party which are not set forth expressly in this Agreement. The validity, interpretation, construction and performance of this Agreement shall be governed by the laws of the State of Oklahoma, excluding any conflicts or choice of law, rule or principle that might otherwise refer construction or interpretation to the substantive law of another jurisdiction, except as provided in Paragraph 15 regarding arbitration of disputes pursuant to the Federal Arbitration Act, or except as preempted by federal law.

17.Confidentiality. Executive shall not disclose, nor have disclosed, directly or indirectly, the existence of this Agreement or the contents of this Agreement to any person until such time the Company discloses this Agreement as required under applicable law. Executive may disclose the terms of this Agreement to an “Exempt Individual,” which includes: a) his spouse, b) his attorney for purposes of obtaining legal advice, and c) his accountant or other financial advisor for purposes of obtaining tax advice, d) the Equal Employment Opportunity Commission (or any government agency) as more set out in Paragraph 17 below, or e) as otherwise required by law. Executive shall advise any Exempt Individual to whom he makes such disclosure of the confidentiality provisions of this Agreement and any disclosure by such Exempt Individual shall be considered a disclosure by Executive. A violation of this provision would include any disclosure, dissemination or duplication of this Agreement or any documents provided with it, to any third party (except an Exempt Individual) including the media as well as any disclosure or publication via the internet or social media.

18.Government Agencies. This Agreement (including the Waiver and General Release) will not prevent Executive from filing a charge, giving testimony or participating in any investigation conducted by the Equal Employment Opportunity Commission or any duly authorized agency of the United States or any state. However, to the fullest extent permitted by law, Executive is waiving the right to receive any personal monetary recovery or other personal relief should the Equal Employment Opportunity Commission (or any government agency) pursue any class or individual charges in part or entirely on Executive’s behalf. Nothing in this Agreement is intended to prohibit Executive from reporting possible violations of federal law or regulation to any governmental agency or entity, including but not limited to the Department of Justice, the Securities and Exchange Commission, Congress, and any agency Inspector General, or making other disclosures that are protected under the whistleblower provisions of federal law or regulation. In addition, Executive does not need the prior authorization of the Company to make any such reports or disclosures, nor is Executive required to notify the Company that Executive has made such reports or disclosures. Further,

Exhibit 10.2

nothing in this Agreement prevents or prohibits Executive from communicating with the Equal Employment Opportunity Commission or other government agency.

19.Section 409A. It is intended that this Agreement comply with Section 409A of the Internal Revenue Code of 1986, as amended (the “Code”), the Treasury regulations and other guidance promulgated or issued thereunder (“Section 409A”), to the extent that the requirements of Section 409A are applicable thereto, and after application of all available exemptions, including but not limited to, the “short-term deferral rule” and the “involuntary separation pay plan exception,” and the provisions of this Agreement shall be construed in a manner consistent with that intention. Any provision required for compliance with Section 409A that is omitted from this Agreement shall be incorporated herein by reference and shall apply retroactively, if necessary, and be deemed a part of this Agreement to the same extent as though expressly set forth herein. To the extent Section 409A is determined to apply to this Agreement, any reference to the Executive’s termination of employment will mean a cessation of the employment relationship between the Executive and the Company which constitutes a “separation from service” as determined in accordance with Section 409A. If Executive is deemed on the date of termination to be a “specified employee,” within the meaning of that term under Section 409A(a)(2)(B) of the Code and using the identification methodology selected by the Company from time to time, or if none, the default methodology, then with regard to any payment or the providing of any benefit made under this Agreement, to the extent required to be delayed in compliance with Section 409A(a)(2)(B) of the Code, and any other payment or the provision of any other benefit that is required to be delayed in compliance with Section 409A(a)(2)(B) of the Code, such payment or benefit shall not be made or provided prior to the earlier of (i) the expiration of the six-month period measured from the date of Executive’s “separation from service” or (ii) the date of death. On the first day of the seventh month following the date of “separation from service,” or if earlier, on the date of death, all payments delayed pursuant to this subparagraph and Section 409A (whether they would have otherwise been payable in a single sum or in installments in the absence of such delay) shall be paid or reimbursed to Executive in a lump sum, and any remaining payments and benefits due under this Agreement shall be paid or provided in accordance with the normal payment dates specified for them herein.

20.Entire Agreement/Binding Effect. This Agreement (including the Waiver and General Release) contains the entire understanding of the parties with respect to its subject matter. This Agreement supersedes all prior policies, practices, communications, agreements and understandings between the parties with respect to its subject matter. This Agreement shall be binding upon the parties hereto and their respective heirs, legal representatives, successors and assigns.

21.No Admissions. Executive acknowledges that the consideration given by the Company in this Agreement is made solely to facilitate their transition into future employment and for settlement purposes. This Agreement (including the Waiver and General Release) is not an admission by the Company of any wrongdoing, guilt or liability of any kind. The Company acknowledges that, as of the date of this Agreement, it has no knowledge that Executive did not perform his duties at the Company in accordance with applicable law, or that Executive violated any fiduciary duties to the Company.

22.Parties in Interest and Intended Third-Party Beneficiaries.    All provisions of this Agreement shall be binding upon and inure to the benefit of the parties and their respective heirs, successors and assigns, including but not limited to the Company’s predecessors, assigns, successors, parent, sub-parent, members, partnerships, and affiliated companies. The General Partner, the Partnership, and Affiliates are third-party beneficiaries under this Agreement.

23.Acknowledgement of Receipt of Agreement (including Waiver and General Release). Executive acknowledges to the Company that he has received this Agreement and the Waiver and

Exhibit 10.2

General Release (attached hereto as Exhibit “A”) and has had at least twenty-one (21) days after the Delivery Date to consider acceptance of this Agreement and the Severance Benefit Payment provided hereunder in exchange for the Waiver and General Release and Executive’s other promises in this Agreement. Executive represents that he has carefully reviewed the Agreement and the Waiver and General Release and understands them.

24.Acknowledgement of Consideration Time and Opportunity to Seek Counsel. Executive has twenty-one (21) days commencing on the Delivery Date in which to consider whether to enter into this Agreement (and the Waiver and General Release). Both the Agreement and the Waiver and General Release must be executed to receive the Severance Benefit Payment. If this Agreement and the Waiver and General Release are not signed by Executive by the conclusion of the twenty-one (21) day period, then the Agreement (including the Waiver and General Release) becomes void and will have no force or effect. If the Agreement and this Waiver and General Release are signed by Executive prior to the expiration of the twenty-one (21) days, Executive certifies and agrees that the decision is knowing and voluntary and is not induced by the Company through (i) fraud, misrepresentation, or a threat to withdraw or alter the offer, or (ii) an offer to provide different terms in exchange for signing the Agreement and this Waiver and General Release before the end of such twenty-one (21) day period. Executive acknowledges to the Company that he has had sufficient time and opportunity to consider this Agreement and the Waiver and General Release and represents that he is signing this Agreement (and the Waiver and General Release) voluntarily and with full understanding and knowledge of their effects and consequences. Executive further acknowledges that he has had sufficient opportunity to consult with an attorney regarding this Agreement (including the Waiver and General Release) and its effects and consequences before signing the Agreement (and the Waiver and General Release).

25.Acknowledgement of Revocation Rights.Executive acknowledges that he has a right to revoke this Agreement (including the Waiver and General Release) within seven (7) days commencing on the day after the Signature Date and that if he does revoke the Agreement within that seven-day period, this Agreement (including the Waiver and General Release) will be null and void and he will not be eligible for any severance pay or benefits under this Agreement. Any such revocation must be in writing and must be received within the seven-day period following execution of the Agreement. Any revocation must be sent or delivered to Lori Rose, Director of Employee Relations, by facsimile to 405-557-6830 or by regular mail or express mail or private overnight delivery service to Enable Midstream Services, LLC, Attn: Lori Rose, Director of Employee Relations, 211 N. Robinson Ave. #950, Oklahoma City, Oklahoma, 73102. If the Agreement and the Waiver and General Release are timely executed by Executive and not revoked within the seven (7) day revocation period, then the Agreement and the Waiver and General Release will become fully binding upon the Company and Executive.

SIGNATURES CONTAINED ON THE FOLLOWING PAGE

Exhibit 10.2

CAUTION: THIS AGREEMENT AFFECTS IMPORTANT LEGAL RIGHTS AND CONTAINS A WAIVER AND GENERAL RELEASE OF ALL OF EXECUTIVE’S KNOWN AND UNKNOWN CLAIMS. PLEASE READ THIS AGREEMENT AND WAIVER AND GENERAL RELEASE CAREFULLY AND CONSULT WITH AN ATTORNEY BEFORE SIGNING.

“COMPANY”	Enable Midstream Services, LLC, an Oklahoma limited liability company.
	By:
	Name:
	Title:
“EXECUTIVE”	Signature:
	Printed Name:
	Signature Date:

RETURN THE SIGNED AGREEMENT ALONG WITH THE SIGNED WAIVER AND GENERAL RELEASE TO THE FOLLOWING ADDRESS OR FAX NUMBER ON OR BEFORE TWENTY-ONE (21) DAYS AFTER THE DELIVERY DATE:

Enable Midstream Services, LLC

Attn: Lori Rose, Director of Employee Relations

211 N. Robinson Ave. #150

Oklahoma City, OK 73102

Fax: 405-557-6830

Exhibit 10.2

Exhibit A

WAIVER AND GENERAL RELEASE

1.Scope of Waiver and General Release. In consideration of the severance benefits offered to Executive by Enable Midstream Services, LLC under Executive’s Special Severance Agreement and General Release attached hereto and incorporated herein by reference (the “Agreement”), Executive hereby RELEASES, WAIVES, SETTLES, ACQUITS, and FOREVER DISCHARGES Enable Midstream Services, LLC, Enable Midstream Partners, LP, Enable GP, LLC, Affiliates and each of those entities’ predecessors, successors, affiliates, parents, subsidiaries, partners, members, owners, managers, attorneys, plan administrators, employees, officers, directors and agents (hereafter collectively referred to as the “Enable Parties”) from all claims, debts, demands, obligations, liabilities, suits, liens, rights, offsets, and/or causes of action or other similar items, of whatever nature, for damages or costs of any kind, including but not limited to actual damages, additional damages, exemplary damages, punitive damages, liquidated damages, emotional distress and/or consequential damages, interest, costs of court, and/or attorneys’ fees, alleged upon any legal or equitable theory whatsoever, whether or not previously asserted, whether now known or unknown to Executive, except as set out in Paragraph 2 below.

Executive represents that he or she understands that this Waiver and General Release forfeits all rights to sue the Enable Parties for any reason related to his or her former employment, including but not limited to claims that he or she was discriminated against or harassed because of race, gender, age, religion, national origin, military status, workers’ compensation retaliation claims, FMLA claims, sexual orientation, disability or any other status protected by law. This Waiver and General Release also forfeits all rights to allege that Executive was retaliated against for any reason, or denied any money, benefits, leave, or any other term of employment, or that the Enable Parties breached any contract with Executive (including any alleged employment contract or other prior severance agreements). Further, Executive represents that he or she understands that this Waiver and General Release forfeits any future right to payment under the STI or LTI as of the Termination Date, including any right to payment which Executive may otherwise be eligible to receive if continuously employed and all rights to sue the Enable Parties for any reason related to payments made under the Plan.

This Waiver and General Release includes, but is not limited to, claims arising under express or implied contracts of employment, the Age Discrimination in Employment Act of 1967, the Older Workers Benefit Protection Act of 1990, Title VII of the Civil Rights Act of 1964, the Civil Rights Act of 1866, the Pregnancy Discrimination Act of 1978, the Equal Pay Act, the Civil Rights Act of 1991, the Rehabilitation Act of 1973, the Americans With Disabilities Act, the Employee Retirement Income Security Act of 1974, the Uniformed Services Employment and Reemployment Rights Act of 1994 and the Veterans Reemployment Rights Act (all as amended from time to time).  This Waiver and General Release also includes, but is not limited to, any rights Executive may have under the Worker Adjustment and Retraining Act of 1988, the Fair Labor Standards Act, the Family and Medical Leave Act, the Occupational Safety and Health Act, and any other federal, state and/or municipal statutes, orders or regulations pertaining to labor, employment and/or employee benefits. This Waiver and General Release also applies to all tort claims including exposure, “public policy” claims, and to any claims Executive may have against the Enable Parties for fraudulent inducement or misrepresentation, defamation, wrongful termination, infliction of emotional distress, negligent supervision, negligent hiring and retaliation claims in connection with workers’ compensation or alleged “whistleblower” status or on any other basis whatsoever.

Exhibit 10.2

2.Claims that are Not Released. This Waiver and General Release does not waive claims that arise after the date of Executive’s execution of this Waiver and General Release and does not release any claims that may not be released as a matter of law.  This Waiver and General Release does not release claims for benefits promised in the Agreement or the Plan.  This Waiver and General Release will not prevent Executive from doing any of the following:

a.Seeking unemployment compensation, disability insurance, or workers’ compensation benefits from the appropriate agency of the state in which Executive lives and works; or

b.Filing a charge, giving testimony or participating in any investigation conducted by the Equal Employment Opportunity Commission or any other government agency.  However, to the fullest extent permitted by law, Executive is hereby waiving the right to receive any personal monetary recovery or other personal relief should the Equal Employment Opportunity Commission (or other government agency) pursue any class or individual charges in part or entirely on Executive’s behalf.  Executive will not seek, will not be entitled to recover, and agrees to waive any monetary benefits or recovery against the Enable Parties in connection with any such claim, charge or proceeding from any action against the Enable Parties before any federal, state, or local administrative agency or before any federal, state, or local court, for allegations arising up to and through the date of his or her signature on this Waiver and General Release, without regard to who has brought such complaint, lawsuit, or charge.

3.Representation Regarding Pending Claims. Executive represents that, notwithstanding the scope of this Waiver and General Release, he has not filed any claims against the Enable Parties with any court and no such claims are currently pending.

4.Attorneys.Executive represents that he has been advised that the Agreement, including this Waiver and General Release, is a binding legal document with legal consequences, and that he should, within the time limits identified herein, and to the extent he deems necessary, seek competent legal counsel to determine the legal effect of the Agreement.

5.Time for Consideration and Execution.Executive has twenty-one (21) days commencing on the Delivery Date in which to consider whether to enter into the Agreement (and this Waiver and General Release). If the Agreement and this Waiver and General Release is not signed by Executive by the conclusion of the twenty-one (21) day period, then the Agreement (including the Waiver and General Release) becomes void and will have no force or effect. If the Agreement (and this Waiver and General Release) is signed by Executive prior to the expiration of the twenty-one (21) days, Executive certifies and agrees that the decision is knowing and voluntary and is not induced by the Enable Parties through (i) fraud, misrepresentation, or a threat to withdraw or alter the offer, or (ii) an offer to provide different terms in exchange for signing the Agreement and this Waiver and General Release before the end of such twenty-one (21) day period. Additionally, if executed by Executive prior to the expiration of the twenty-one (21) days, Executive will be considered to have voluntarily waived any remaining time otherwise available in which to consider the Agreement and this Waiver and General Release. The parties agree that any changes made to the Agreement and this Waiver and General Release from the version originally presented to Executive, whether those changes are deemed material or non-material, do not extend the twenty-one (21) day period Executive has been given to consider the Agreement.

6.Revocation.For a period of seven (7) days following Executive’s execution of the Agreement and this Waiver and General Release, Executive may revoke the Agreement and this Waiver and General Release for any reason by delivering written notice of such revocation to Lori Rose, Director of Employee

Exhibit 10.2

Relations, by facsimile to 405-557-6830 or by regular mail or express mail or private overnight delivery service to Enable Midstream Services, LLC, Attn: Lori Rose, Director of Employee Relations, 211 N. Robinson Ave. #150, Oklahoma City, Oklahoma, 73102. Executive acknowledges that should he decide to revoke the Agreement (including this Waiver and General Release), the Agreement will be null and void, and he will not be entitled to any severance payments or other benefits provided by the Agreement.

7.Effective Date.Executive acknowledges that the Agreement (including this Waiver and General Release) will not take effect until the seven (7) day revocation period has expired without the Agreement having been revoked. As a result, until the Agreement (including this Waiver and General Release) becomes irrevocable, the Company shall have no obligation to make any of the payments or take any of the other actions required by the Agreement. If the Agreement and this Waiver and General Release are timely executed by Executive and not revoked within the seven (7) day revocation period, then the Agreement and this Waiver and General Release will become fully binding upon the Company and Executive.

CAUTION: THIS AGREEMENT AFFECTS IMPORTANT LEGAL RIGHTS AND CONTAINS A WAIVER AND GENERAL RELEASE OF ALL OF EXECUTIVE’S KNOWN AND UNKNOWN CLAIMS. PLEASE READ THIS CAREFULLY AND CONSULT WITH AN ATTORNEY BEFORE SIGNING.

“EXECUTIVE”	Signature:
	Printed Name:
	Signature Date:

RETURN THE SIGNED AGREEMENT ALONG WITH THE SIGNED WAIVER AND GENERAL RELEASE TO THE FOLLOWING ADDRESS OR FAX NUMBER ON OR BEFORE TWENTY-ONE (21) DAYS AFTER THE DELIVERY DATE:

Enable Midstream Services, LLC

Attn: Lori Rose, Director of Employee Relations

211 N. Robinson Ave. #150

Oklahoma City, OK 73102

Fax: 405-557-6830

EX-31.1

Exhibit 31.1

CERTIFICATIONS

I, Rodney J. Sailor, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Enable Midstream Partners, LP;

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 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)) 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) 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

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

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

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

Date: May 4, 2016

  /s/ Rodney J. Sailor

       Rodney J. Sailor

President and Chief Executive Officer, Enable GP, LLC, the General Partner of Enable Midstream Partners, LP

(Principal Executive Officer)

EX-31.2

Exhibit 31.2

CERTIFICATIONS

I, John P. Laws, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Enable Midstream Partners, LP;

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 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)) 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) 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

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

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

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

Date: May 4, 2016

  /s/ John P. Laws

       John P. Laws

Executive Vice President, Chief Financial Officer and Treasurer, Enable GP, LLC, the General Partner of Enable Midstream Partners, LP

(Principal 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 Enable Midstream Partners, LP (the Partnership) on Form 10-Q for the period ended March 31, 2016, as filed with the Securities and Exchange Commission (the Report), each of the undersigned does hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

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

Date: May 4, 2016

          /s/ Rodney J. Sailor

               Rodney J. Sailor

President and Chief Executive Officer, Enable GP, LLC, the General Partner of Enable Midstream Partners, LP

(Principal Executive Officer)

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 Enable Midstream Partners, LP (the Partnership) on Form 10-Q for the period ended March 31, 2016, as filed with the Securities and Exchange Commission (the Report), each of the undersigned does hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

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

Date: May 4, 2016

          /s/ John P. Laws

               John P. Laws

Executive Vice President, Chief Financial Officer and Treasurer, Enable GP, LLC, the General Partner of Enable Midstream Partners, LP

(Principal Financial Officer)

EX-99.1

Exhibit 99.1

GUARANTEE AGREEMENT

dated as of

May 1, 2013

among

CENTERPOINT ENERGY FIELD SERVICES LP

and

ENOGEX LLC

in favor of

THE GUARANTEED PARTY

Exhibit 99.1

This GUARANTEE AGREEMENT dated as of May 1, 2013 (as the same may be amended, restated, supplemented or otherwise modified from time to time, this “Agreement”), is executed and delivered by CENTERPOINT ENERGY FIELD SERVICES LP, a Delaware limited partnership, in its capacity as guarantor (in such capacity, the “Parent Guarantor”), and ENOGEX LLC, a Delaware limited liability company (“Enogex”), in favor of the Guaranteed Party, as defined below.

ARTICLE I

Definitions

SECTION 1.01 Defined Terms. As used in this Agreement, the following terms have the meanings specified below:

“Debt Documents” means, collectively, (x) that certain Issuing and Paying Agency Agreement dated as of November 15, 2009 between Enogex and the Enogex 2020 Note Trustee and (y) the Enogex 2020 Senior Notes.

“Enogex 2020 Note Trustee” means the issuing and paying agent under the Enogex 2020 Senior Notes, which issuing and paying agent is UMB Bank, N.A. on the date hereof.

“Enogex 2020 Senior Notes” means the 6.25% Senior Notes due 2020 issued by Enogex pursuant to that certain Issuing and Paying Agency Agreement dated as of November 15, 2009 between Enogex and the Enogex 2020 Note Trustee.

“General Partner” means CNP OGE GP LLC, a Delaware limited liability company.

“Guaranteed Obligations” all amounts owing or payable by Enogex under and pursuant to the Debt Documents, including all interest, principal, premium or penalties and all indemnities and reimbursements owing or becoming due thereunder (including any of the foregoing accruing after the commencement of any bankruptcy or insolvency proceeding with respect to Enogex, whether or not allowed as a claim in such proceeding).

“Guaranteed Party” means the Enogex 2020 Note Trustee, for and on behalf of each of the holders from time to time of the Enogex 2020 Senior Notes, together with its permitted successors and assigns.

ARTICLE II

Guarantee

SECTION 2.01Guarantee. The Parent Guarantor hereby unconditionally guarantees the due and punctual payment and performance by Enogex of the Guaranteed Obligations. The Parent Guarantor further agrees that the Guaranteed Obligations may be extended or renewed, in whole or in part, without notice to or further assent from it, and that it will remain bound upon its guarantee notwithstanding any extension or renewal of any Guaranteed Obligation. The Parent Guarantor waives presentment to, demand of payment from and protest to Enogex of, any of the Guaranteed Obligations, and also waives notice of acceptance of its guarantee and notice of protest for nonpayment.

Exhibit 99.1

SECTION 2.02Guarantee of Payment. The Parent Guarantor further agrees that its guarantee hereunder constitutes a guarantee of payment when due and not of collection.

SECTION 2.03No Limitations. (a) The obligations of the Parent Guarantor hereunder shall not be subject to any reduction, limitation, impairment or termination for any reason (other than the payment in full in cash of the Guaranteed Obligations (other than contingent indemnification obligations), “Payment in Full”), including any claim of waiver, release, surrender, alteration or compromise, and shall not be subject to any defense or set-off, counterclaim, recoupment or termination whatsoever by reason of the invalidity, illegality or unenforceability of the Guaranteed Obligations or otherwise. Without limiting the generality of the foregoing, the obligations of the Parent Guarantor hereunder shall not be discharged or impaired or otherwise affected by (i) the failure of the Guaranteed Party to assert any claim or demand or to enforce any right or remedy under the provisions of any Debt Document or otherwise; (ii) any rescission, waiver, amendment or modification of, or any release from any of the terms or provisions of, any Debt Document or any other agreement, including with respect to any other guarantor of the Guaranteed Obligations; (iii) the release of any security, if any, held by the Guaranteed Party for the Guaranteed Obligations; (iv) any default, failure or delay, willful or otherwise, in the performance of the Guaranteed Obligations; or (v) any other act or omission that may or might in any manner or to any extent vary the risk of the Parent Guarantor or otherwise operate as a discharge of the Parent Guarantor as a matter of law or equity other than the Payment in Full of all of the Guaranteed Obligations.

SECTION 2.04Reinstatement. The Parent Guarantor agrees that its guarantee hereunder shall continue to be effective or be reinstated, as the case may be, if and to the extent that any payment, or any part thereof, of any Guaranteed Obligation is rescinded or must otherwise be restored by the Guaranteed Party upon the bankruptcy or reorganization of Enogex, the Parent Guarantor or otherwise.

SECTION 2.05Information. The Parent Guarantor assumes all responsibility for being and keeping itself informed of Enogex’s financial condition and assets, and of all other circumstances bearing upon the risk of nonpayment of the Guaranteed Obligations and the nature, scope and extent of the risks that the Parent Guarantor assumes and incurs hereunder, and agrees that the Guaranteed Party will have no duty to advise the Parent Guarantor of information known to it regarding such circumstances or risks.

ARTICLE III

Indemnity, Subrogation and Subordination

SECTION 3.01Indemnity and Subrogation. In addition to all such rights of indemnity and subrogation as the Parent Guarantor may have under applicable law (but subject to Section 3.02), Enogex agrees that in the event a payment of a Guaranteed Obligation shall be made by the Parent Guarantor under this Agreement, Enogex shall indemnify the Parent Guarantor for the full amount of such payment and the Parent Guarantor shall be subrogated to the rights of the Person to whom such payment shall have been made to the extent of such payment.

SECTION 3.02Subordination. Notwithstanding any provision of this Agreement to the contrary, all rights of the Parent Guarantor to indemnity, contribution or subrogation under applicable law or otherwise shall be fully subordinated to the Payment in Full of the Guaranteed Obligations. No failure on the part of Enogex to make the payments required by Sections 3.01 (or any other payments required under applicable law or otherwise) shall in any respect limit the obligations and liabilities of the Parent Guarantor with respect to its obligations hereunder, and the Parent Guarantor shall remain liable for the full amount of the Guaranteed Obligations hereunder.

Exhibit 99.1

ARTICLE IV

Miscellaneous

SECTION 4.01Notices. All communications and notices hereunder shall (except as otherwise expressly permitted herein) be in writing and (a) if to Enogex or the Enogex 2020 Note Trustee, shall be given as provided in the Debt Documents and (b) if to the Parent Guarantor, shall be given to it in care of Enogex as provided in the Debt Documents.

SECTION 4.02Cumulative Rights and Remedies; Amendments. No failure or delay by the Guaranteed Party in exercising any right or power hereunder or under any Debt Document shall operate as a waiver thereof, nor shall any single or partial exercise of any such right or power, or any abandonment or discontinuance of steps to enforce such a right or power, preclude any other or further exercise thereof or the exercise of any other right or power. The rights and remedies of the Guaranteed Party hereunder and under the Debt Documents are cumulative and are not exclusive of any rights or remedies that it otherwise has.

This Agreement shall be construed as a separate agreement with respect to the Parent Guarantor and may be amended, modified, supplemented, waived or released with respect to the Parent Guarantor without the approval of Enogex and without affecting the obligations of Enogex hereunder or under the Debt Documents.

SECTION 4.03Successors and Assigns. Whenever in this Agreement any of the parties hereto is referred to, such reference shall be deemed to include the permitted successors and assigns of such party; and all covenants, promises and agreements by or on behalf of the Parent Guarantor that are contained in this Agreement shall bind and inure to the benefit of such permitted successors and assigns.

SECTION 4.04Counterparts; Effectiveness. This Agreement may be executed in counterparts, each of which shall constitute an original but all of which when taken together shall constitute a single contract. Delivery of an executed signature page to this Agreement by facsimile or electronic transmission shall be as effective as delivery of a manually signed counterpart of this Agreement. This Agreement shall become effective as to the Parent Guarantor when a counterpart hereof executed by the Parent Guarantor, shall have been delivered to the Guaranteed Party, and thereafter shall be binding upon the Parent Guarantor, and shall inure to the benefit of the Parent Guarantor and its respective successors and assigns.

SECTION 4.05Severability. Any provision of this Agreement held to be invalid, illegal or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such invalidity, illegality or unenforceability without affecting the validity, legality and enforceability of the remaining provisions hereof; and the invalidity of a particular provision in a particular jurisdiction shall not invalidate such provision in any other jurisdiction. The parties shall endeavor in good‑faith negotiations to replace the invalid, illegal or unenforceable provisions with valid provisions the economic effect of which comes as close as possible to that of the invalid, illegal or unenforceable provisions.

SECTION 4.06Governing Law; Consent to Service of Process. (a) This Agreement shall be construed in accordance with and governed by the law of the State of New York.

Exhibit 99.1

(b)Each party to this Agreement irrevocably consents to service of process in the manner provided for notices in Section 4.01. Nothing in this Agreement or any Debt Document will affect the right of any party to this Agreement to serve process in any other manner permitted by law.

SECTION 4.07WAIVER OF JURY TRIAL; INDUCEMENT. EACH PARTY HERETO AND THE GUARANTEED PARTY WAIVE, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, ANY RIGHT IT MAY HAVE TO A TRIAL BY JURY IN ANY LEGAL PROCEEDING DIRECTLY OR INDIRECTLY ARISING OUT OF OR RELATING TO THIS AGREEMENT (WHETHER BASED ON CONTRACT, TORT OR ANY OTHER THEORY). EACH PARTY HERETO AND THE GUARANTEED PARTY (A) CERTIFIES THAT NO REPRESENTATIVE, AGENT OR ATTORNEY OF ANY OTHER PARTY HAS REPRESENTED, EXPRESSLY OR OTHERWISE TO SUCH PERSON, THAT SUCH OTHER PARTY WOULD NOT, IN THE EVENT OF LITIGATION, SEEK TO ENFORCE THE FOREGOING WAIVER AND (B) ACKNOWLEDGES THAT IT AND THE OTHER PARTIES HERETO HAVE BEEN INDUCED TO ENTER INTO THIS AGREEMENT BY, AMONG OTHER THINGS, THE MUTUAL WAIVERS AND CERTIFICATIONS IN THIS ARTICLE IV, INCLUDING THIS SECTION 4.07.

SECTION 4.08Headings. Article and Section headings used herein are for convenience of reference only, are not part of this Agreement and are not to affect the construction of, or to be taken into consideration in interpreting, this Agreement.

SECTION 4.09Guarantee Absolute. All rights of the Guaranteed Party hereunder and all obligations of the Parent Guarantor hereunder shall be absolute and unconditional irrespective of (a) any lack of validity or enforceability of the Debt Documents or any other agreement or instrument relating to any of the foregoing, (b) any change in the time, manner or place of payment of, or in any other term of, all or any of the Guaranteed Obligations, or any other amendment or waiver of or any consent to any departure from any of the Debt Documents or any other agreement or instrument, (c) any release or amendment or waiver of or consent under or departure from any guarantee guaranteeing all or any of the Guaranteed Obligations or (d) any other circumstance that might otherwise constitute a defense available to, or a discharge of, the Parent Guarantor in respect of the Guaranteed Obligations or this Agreement (other than the Payment in Full of the Guaranteed Obligations).

SECTION 4.10Termination or Release. (a) This Agreement and the guarantee made herein shall automatically terminate and be released when all the Guaranteed Obligations have been Paid in Full and the Debt Documents have been discharged in accordance with the terms thereof.

(b)In connection with any termination or release pursuant to paragraph (a) of this Section 4.10, the Guaranteed Party shall upon the request of the Parent Guarantor or Enogex execute and deliver to the Parent Guarantor, at the Parent Guarantor’s expense, all documents that the Parent Guarantor shall reasonably request to evidence such termination or release. Any execution and delivery of documents pursuant to this Section 4.10 shall be without recourse to or warranty by the applicable Guaranteed Party.

SECTION 4.11No Liability of General Partner. It is hereby understood and agreed that the General Partner shall have no personal liability, as general partner or otherwise, for the payment of any amount owing or to be owing hereunder or under the Debt Documents. As a condition to the effectiveness of this Agreement, the Guaranteed Party shall be deemed to have agreed for themselves and all other holders of the Guaranteed Obligations (together in each case, with each such person’s respective successors and assigns) that no claim arising against Enogex under any Debt Document or against the Parent Guarantor in respect of the Guaranteed Obligations shall be asserted against the General Partner (in its individual capacity).

Exhibit 99.1

SECTION 4.12Failure to Perform by Parent Guarantor or Enogex. No failure of the Parent Guarantor or Enogex to perform any of its obligations or undertakings hereunder shall give rise to any default or event of default under the Debt Documents or otherwise constitute a breach by any of Enogex or its subsidiaries of or under the Debt Documents or give rise to any rights or remedies as against Enogex or any of its subsidiaries under or pursuant to any Debt Document.

SECTION 4.13Enforceable Against Parent Guarantor. This Agreement shall be deemed enforceable against the Parent Guarantor and, to the extent applicable, Enogex, upon the execution hereof, in the case of the Parent Guarantor, by the Parent Guarantor, and in the case of Enogex, by the Parent Guarantor and Enogex, in each case, whether or not so executed by the Guaranteed Party

[Signature Pages Follow]

Exhibit 99.1

IN WITNESS WHEREOF, the parties hereto have duly executed this Agreement as of the day and year first above written.

CENTERPOINT ENERGY FIELD SERVICES LP, as the Parent Guarantor,
By: CNP OGE GP LLC, its general partner
By	/s/ Gary Whitlock
	Name: Gary Whitlock
	Title: Acting Chief Financial Officer
ENOGEX LLC,
By	/s/ Sean Trauschke
	Name: Sean Trauschke
	Title: Chief Financial Officer

Exhibit 99.1

Acknowledged and agreed to:
UMB BANK, N.A.
By	/s/ Sean Trauschke
	Name: Sean Trauschke
	Title: Chief Financial Officer

XML

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2016	Apr. 15, 2016
Document and Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2016
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	Q1
Entity Registrant Name	Enable Midstream Partners, LP
Entity Central Index Key	0001591763
Entity Filer Category	Large Accelerated Filer
Current Fiscal Year End Date	--12-31
Entity Common Stock, Shares Outstanding		214,467,409

XML

Condensed Consolidated Statements of Income (Unaudited) - USD ($) shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Revenues (including revenues from affiliates (Note 11)):
Product sales	$ 245	$ 351
Service revenue	264	265
Total Revenues	509	616
Cost and Expenses (including expenses from affiliates (Note 11)):
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)	195	292
Operation and maintenance	95	104
General and Administrative	20	26
Depreciation and amortization	81	73
Taxes other than income taxes	15	17
Total Cost and Expenses	406	512
Operating Income	103	104
Other Income (Expense):
Interest expense (including expenses from affiliates (Note 11))	(23)	(20)
Equity in earnings of equity method affiliates	7	7
Other, net	0	1
Total Other Income (Expense)	(16)	(12)
Income Before Income Taxes	87	92
Income tax expense	1	1
Net Income	86	91
Less: Net income attributable to noncontrolling interest	0	0
Less: Series A Preferred Unit distributions (Note 4)	0	0
Net Income attributable to common and subordinated units (Note 3)	$ 86	$ 91
Basic and Diluted earnings per unit and weighted average number of units outstanding
Basic weighted average number of outstanding (Note 3)	422	422
Diluted weighted average number of outstanding (Note 3)	443	422
Common Units
Basic and Diluted earnings per unit and weighted average number of units outstanding
Basic earnings per unit (Note 3)	$ 0.21	$ 0.22
Diluted earnings per unit (Note 3)	$ 0.19	$ 0.22
Basic weighted average number of outstanding (Note 3)	214	214
Diluted weighted average number of outstanding (Note 3)	235	214
Subordinated Units
Basic and Diluted earnings per unit and weighted average number of units outstanding
Basic earnings per unit (Note 3)	$ 0.20	$ 0.21
Diluted earnings per unit (Note 3)	$ 0.20	$ 0.21
Basic weighted average number of outstanding (Note 3)	208	208
Diluted weighted average number of outstanding (Note 3)	208	208

XML

Condensed Consolidated Statements of Comprehensive Income (Unaudited) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Statement of Comprehensive Income [Abstract]
Net income	$ 86	$ 91
Comprehensive income	86	91
Less: Comprehensive income attributable to noncontrolling interest	0	0
Comprehensive income attributable to Enable Midstream Partners, LP	$ 86	$ 91

XML

Condensed Consolidated Balance Sheets (Unaudited) - USD ($) $ in Millions		Mar. 31, 2016	Dec. 31, 2015
Current Assets:
Cash and cash equivalents		$ 38	$ 4
Accounts receivable		226	245
Accounts receivable—affiliated companies		16	21
Inventory		45	53
Gas imbalances		20	23
Other current assets		35	35
Total current assets		380	381
Property, Plant and Equipment:
Property, plant and equipment		11,395	11,293
Less accumulated depreciation and amortization		1,219	1,162
Property, plant and equipment, net		10,176	10,131
Other Assets:
Intangible assets, net		327	333
Investment in equity method affiliates		331	344
Other		35	37
Total other assets		693	714
Total Assets		11,249	11,226
Current Liabilities:
Accounts payable		153	248
Accounts payable—affiliated companies		6	9
Short-term debt	[1]	0	236
Taxes accrued		29	30
Gas imbalances		7	25
Other		85	67
Total current liabilities		280	615
Other Liabilities:
Accumulated deferred income taxes, net		8	8
Notes payable—affiliated companies		0	363
Regulatory liabilities		18	18
Other		22	20
Total other liabilities		48	409
Long-Term Debt		$ 3,074	$ 2,671
Commitments and Contingencies (Note 12)
Partners' Equity:
Common units		$ 3,692	$ 3,714
Subordinated units		3,781	3,805
Noncontrolling interest		12	12
Total Partners' Equity		7,847	7,531
Total Liabilities and Partners' Equity		11,249	11,226
Series A Preferred Units
Partners' Equity:
Series A Preferred Units (14,520,000 issued and outstanding at March 31, 2016 and 0 issued and outstanding at December 31, 2015)		$ 362	$ 0

[1] Short-term debt includes $236 million of commercial paper as of December 31, 2015. There were no commercial paper borrowings outstanding as of March 31, 2016.

XML

Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) - shares	Mar. 31, 2016	Dec. 31, 2015
Common Units
Common and Subordinated units issued	214,467,409	214,541,422
Common units and Subordinated units outstanding	214,467,409	214,541,422
Subordinated Units
Common and Subordinated units issued	207,855,430	207,855,430
Common units and Subordinated units outstanding	207,855,430	207,855,430
Series A Preferred Units
Preferred units issued	14,520,000	0
Preferred units outstanding	14,520,000	0

XML

Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Cash Flows from Operating Activities:
Net income	$ 86	$ 91
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	81	73
Loss on sale/retirement of assets	1	0
Equity in earnings of equity method affiliates, net of distributions	0	5
Equity based compensation	2	3
Amortization of debt costs and discount (premium)	(1)	(1)
Changes in other assets and liabilities:
Accounts receivable, net	19	2
Accounts receivable—affiliated companies	5	(2)
Inventory	8	13
Gas imbalance assets	3	8
Other current assets	0	6
Other assets	1	(2)
Accounts payable	(84)	18
Accounts payable—affiliated companies	(3)	(21)
Gas imbalance liabilities	(18)	(5)
Other current liabilities	15	2
Other liabilities	2	(2)
Net cash provided by operating activities	117	188
Cash Flows from Investing Activities:
Capital expenditures	(130)	(239)
Investment in equity method affiliates	0	(6)
Return of investment in equity method affiliates	13	0
Net cash used in investing activities	(117)	(245)
Cash Flows from Financing Activities:
Proceeds from revolving credit facility	495	0
Repayment of revolving credit facility	(90)	0
Increase (decrease) in short-term debt	(236)	183
Repayment of notes payable—affiliated companies	(363)	0
Proceeds from issuance of Series A Preferred Units, net of issuance costs	362	0
Distributions	(134)	(130)
Net cash provided by financing activities	34	53
Net Increase (Decrease) in Cash and Cash Equivalents	34	(4)
Cash and Cash Equivalents at Beginning of Period	4	12
Cash and Cash Equivalents at End of Period	$ 38	$ 8

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Condensed Consolidated Statements of Partners' Equity (Unaudited) - USD ($) shares in Millions, $ in Millions	Total	Noncontrolling Interest	Series A Preferred Units Preferred Units	Common Units Partners' Capital	Subordinated Units Partners' Capital
Balance, beginning of period at Dec. 31, 2014	$ 8,823	$ 31	$ 0	$ 4,353	$ 4,439
Balance, beginning of period, units at Dec. 31, 2014			0	214	208
Changes in Partners' Capital
Net income	91			$ 48	$ 43
Distributions	(130)			(66)	(64)
Equity based compensation	3			3
Balance, end of period at Mar. 31, 2015	8,787	31	$ 0	$ 4,338	$ 4,418
Balance, end of period, units at Mar. 31, 2015			0	214	208
Balance, beginning of period at Dec. 31, 2015	7,531	12	$ 0	$ 3,714	$ 3,805
Balance, beginning of period, units at Dec. 31, 2015			0	214	208
Changes in Partners' Capital
Net income	86			$ 44	$ 42
Issuance of Series A Preferred Units	362		$ 362
Issuance of Series A Preferred Units, units			15
Distributions	(134)			(68)	(66)
Equity based compensation	2			2
Balance, end of period at Mar. 31, 2016	$ 7,847	$ 12	$ 362	$ 3,692	$ 3,781
Balance, end of period, units at Mar. 31, 2016			15	214	208

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Summary of Significant Accounting Policies

3 Months Ended

Mar. 31, 2016

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Summary of Significant Accounting Policies

Summary of Significant Accounting Policies

Organization

Enable Midstream Partners, LP (Partnership), a Delaware limited partnership, is a large-scale, growth-oriented limited partnership formed to own, operate and develop strategically located natural gas and crude oil infrastructure assets. The Partnership’s assets and operations are organized into two reportable segments: (i) Gathering and Processing, which primarily provides natural gas gathering, processing and fractionation services and crude oil gathering for our producer customers, and (ii) Transportation and Storage, which provides interstate and intrastate natural gas pipeline transportation and storage services primarily to natural gas producers, utilities and industrial customers. The natural gas gathering and processing assets are located in five states and serve natural gas production in the Anadarko, Arkoma and Ark-La-Tex basins. This segment also includes a crude oil gathering business in the Bakken Shale formation, principally located in the Williston basin. The natural gas transportation and storage assets extend from western Oklahoma and the Texas Panhandle to Alabama and from Louisiana to Illinois.

The Partnership is controlled equally by CenterPoint Energy and OGE Energy, who each have 50% of the management rights of Enable GP. Enable GP was established by CenterPoint Energy and OGE Energy to govern the Partnership and has no other operating activities. Enable GP is governed by a board made up of an equal number of representatives designated by each of CenterPoint Energy and OGE Energy, along with the independent board members CenterPoint Energy and OGE Energy mutually agreed to appoint. Based on the 50/50 management ownership, with neither company having control, CenterPoint Energy and OGE Energy do not consolidate their interests in the Partnership. CenterPoint Energy and OGE Energy also own a 40% and 60% interest, respectively, in the incentive distribution rights held by Enable GP. As of March 31, 2016, CenterPoint Energy held approximately 55.4% of the common and subordinated units in the Partnership, or 94,151,707 common units and 139,704,916 subordinated units, and OGE Energy held approximately 26.3% of the common and subordinated units in the Partnership, or 42,832,291 common units and 68,150,514 subordinated units. Additionally, CenterPoint Energy holds 14,520,000 Series A Preferred Units. See Note 4 for further information related to the Series A Preferred Units.

For the period from December 31, 2014 through June 29, 2015, the financial statements reflect a 49.90% interest in SESH. On June 12, 2015, CenterPoint Energy exercised its put right with respect to a 0.1% interest in SESH. Pursuant to the put right, on June 30, 2015, CenterPoint Energy contributed its remaining 0.1% interest in SESH to the Partnership in exchange for 25,341 common units representing limited partner interests in the Partnership. As of March 31, 2016, the Partnership owned a 50% interest in SESH. See Note 6 for further discussion of SESH.

Basis of Presentation

The accompanying condensed consolidated financial statements and related notes of the Partnership have been prepared pursuant to the rules and regulations of the SEC and GAAP. Pursuant to such rules and regulations, certain disclosures normally included in financial statements prepared in accordance with GAAP have been omitted. The accompanying condensed consolidated financial statements and related notes should be read in conjunction with the combined and consolidated financial statements and related notes included in our Annual Report.  

 These condensed consolidated financial statements and the related financial statement disclosures reflect all normal recurring adjustments that are, in the opinion of management, necessary to present fairly the financial position and results of operations for the respective periods. Amounts reported in the Partnership’s Condensed Consolidated Statements of 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 the Partnership’s reportable segments, see Note 14.

Use of Estimates

The preparation of financial statements in conformity with GAAP 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.

Accounts Receivable and Allowance for Doubtful Accounts

Accounts receivable are recorded at the invoiced amount and do not bear interest. It is the policy of management to review the outstanding accounts receivable at least quarterly, as well as the bad debt write-offs experienced in the past. Based on this review, a $3 million allowance for doubtful accounts was recognized as of March 31, 2016. There was no allowance for doubtful accounts as of December 31, 2015.

Third Amended and Restated Agreement of Limited Partnership of Enable Midstream Partners, LP

On February 18, 2016, in connection with the closing of the private placement of 14,520,000 Series A Preferred Units and pursuant to the Purchase Agreement, the General partner adopted the Third Amended and Restated Agreement of Limited Partnership (the Partnership Agreement) which, among other things, authorized and established the terms of the Series A Preferred Units and the other series of preferred units that are issuable upon conversion of the Series A Preferred Units. For further information related to the issuance of the Series A Preferred Units, see Note 4.

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New Accounting Pronouncements

3 Months Ended

Mar. 31, 2016

Accounting Changes and Error Corrections [Abstract]

New Accounting Pronouncements

New Accounting Pronouncements

Revenue from Contracts with Customers

In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers,” which supersedes the revenue recognition requirements in “Revenue Recognition (Topic 605),” and requires entities to recognize revenue in a way that depicts the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to in exchange for those goods or services. ASU 2014-09 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, and is to be applied retrospectively, with early application not permitted.

In August 2015, the FASB issued ASU No. 2015-14, “Revenue from Contracts with Customers (Topic 606)—Deferral of the Effective Date,” which deferred the effective date of ASU 2014-09 by one year to December 15, 2017 for annual reporting periods beginning after that date. The FASB also proposed permitting early adoption of the standard, but not before the original effective date of December 15, 2016. The Partnership is currently evaluating the impact, if any, the adoption of this standard will have on our Condensed Consolidated Financial Statements and related disclosures.

In March 2016, the FASB issued ASU No. 2016-08, “Revenue from Contracts with Customers (Topic 606)-Principal versus Agent Considerations (Reporting Revenue Gross versus Net)”. ASU No. 2016-08 requires an entity to determine whether the nature of its promise is to provide the specified good or service itself (i.e., the entity is a principal) or to arrange for that good or service to be provided by the other party (i.e., the entity is an agent) when another party is involved in providing goods or services to a customer. Additionally, the amendments in this ASU require an entity that is a principal to recognize revenue in the gross amount of consideration to which it expects to be entitled in exchange for the specified good or service transferred to the customer, and require an entity that is an agent to recognize revenue in the amount of any fee or commission to which it expects to be entitled in exchange for arranging for the specified good or service to be provided by the other party. ASU 2016-08 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, and is to be applied retrospectively, with early application not permitted. The Partnership is currently evaluating the impact, if any, the adoption of this standard will have on our Condensed Consolidated Financial Statements and related disclosures.

In April 2016, the FASB issued ASU No. 2016-10, “Revenue from Contracts with Customers (Topic 606)-Identifying Performance Obligations and Licensing”. The amendments in ASU No. 2016-10 impact entities with transactions that include contracts with customers to transfer goods or services (that are an output of the entity’s ordinary activities) in exchange for consideration, and they require entities to recognize revenue by following certain steps, including (1) identifying the contract(s) with a customer; (2) identifying the performance obligations in a contract; (3) determining the transaction price; (4) allocating the transaction price to the performance obligations in the contract; and (5) recognizing revenue when, or as, the entity satisfies a performance obligation. Notably, ASU No. 2016-10 does not impact the core revenue recognition principles set forth in Topic 606, but rather clarifies the identification of performance obligations and the licensing implementation guidance, while retaining the related principles for those areas. ASU 2016-10 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, and is to be applied retrospectively, with early application not permitted. The Partnership is currently evaluating the impact, if any, the adoption of this standard will have on our Condensed Consolidated Financial Statements and related disclosures.

Consolidation

In February 2015, the FASB issued ASU No. 2015-02, “Consolidation,” to improve consolidation guidance for certain types of legal entities. The guidance modifies the evaluation of whether limited partnerships and similar legal entities are variable interest entities (VIEs) or voting interest entities, eliminates the presumption that a general partner should consolidate a limited partnership, affects the consolidation analysis of reporting entities that are involved with VIEs, particularly those that have fee arrangements and related party relationships, and provides a scope exception from consolidation guidance for certain money market funds. The Partnership adopted the amendment in the first quarter of 2016, which resulted in no impact to our Condensed Consolidated Financial Statements and related disclosures.

Presentation of Debt Issuance Costs

In April 2015, the FASB issued ASU No. 2015-03, “Simplifying the Presentation of Debt Issuance Costs.” This standard amends existing guidance to require the presentation of debt issuance costs in the balance sheet as a deduction from the carrying amount of the related debt liability instead of a deferred charge. The Partnership adopted the amendment in the first quarter of 2016 on a retrospective basis in order to conform the presentation of debt issuance costs on the Condensed Consolidated Balance Sheets. At each ofMarch 31, 2016 and December 31, 2015, the Partnership had unamortized debt expense of $12 millionclassified as a reduction of Long-Term Debt in the Condensed Consolidated Balance Sheets. Unamortized debt expense related to the Revolving Credit Facility of $5 million and $6 million as ofMarch 31, 2016 and December 31, 2015, respectively, is classified as Other Assets in the Condensed Consolidated Balance Sheets.

Balance Sheet Classification of Deferred Taxes

In November 2015, the FASB issued ASU No. 2015-17, “Income Taxes—Balance Sheet Classification of Deferred Taxes.” This ASU eliminates the requirement to present deferred tax liabilities and assets as current and non-current in a classified balance sheet. Instead, all deferred tax assets and liabilities will be classified as non-current. ASU 2015-17 is effective for all interim and annual periods beginning after December 16, 2016 and early application is permitted. The amendments in this update may be applied either prospectively to all deferred tax liabilities and assets or retrospectively to all periods presented. The Partnership adopted the amendment in the first quarter of 2016, which resulted in no impact to our Condensed Consolidated Financial Statements and related disclosures.

Leases

In February 2016, the FASB issued ASU 2016-02, “Leases”. The amendments in this update require, among other things, that lessees recognize the following for all leases (with the exception of short-term leases) at the commencement date: (1) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and (2) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The Partnership expects to adopt the amendments in the first quarter of 2019 and is currently evaluating the impacts of the amendments to our Condensed Consolidated Financial Statements and accounting practices for leases.

Share-Based Compensation

In March 2016, the FASB issued ASU No. 2016-09, “Compensation—Stock Compensation (Topic 718).” This standard makes several modifications to Topic 718 related to the accounting for forfeitures, employer tax withholding on share-based compensation and the financial statement presentation of excess tax benefits or deficiencies. ASU 2016-09 also clarifies the statement of cash flows presentation for certain components of share-based awards. The standard is effective for interim and annual reporting periods beginning after December 15, 2016, although early adoption is permitted. The Partnership is currently assessing how the adoption of this standard will impact our Condensed Consolidated Financial Statements and related disclosures.

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Earnings Per Limited Partner Unit

3 Months Ended

Mar. 31, 2016

Earnings Per Share [Abstract]

Earnings Per Limited Partner Unit

Earnings Per Limited Partner Unit

The following table illustrates the Partnership’s calculation of earnings per unit for common and subordinated units:

	Three Months Ended   March 31,
	2016		2015
	(In millions, except per unit data)
Net income	$	86	$	91
Net income attributable to noncontrolling interest	—		—
Series A Preferred Unit distribution	—		—
General partner interest in net income	—		—
Net income available to common and subordinated unitholders	$	86	$	91
Net income allocable to common units	$	44	$	48
Net income allocable to subordinated units	42		43
Net income available to common and subordinated unitholders	$	86	$	91
Net income allocable to common units	$	44	$	48
Series A Preferred Unit Distribution	—		—
Diluted net income allocable to common units	44		48
Diluted net income allocable to subordinated units	42		43
Total	$	86	$	91
Basic weighted average number of outstanding
Common units	214		214
Subordinated units	208		208
Total	422		422
Basic earnings per unit
Common units	$	0.21	$	0.22
Subordinated units	$	0.20	$	0.21
Basic weighted average number of outstanding common units	214		214
Dilutive effect of Series A Preferred Units	21		—
Diluted weighted average number of outstanding common units	235		214
Diluted weighted average number of outstanding subordinated units	208		208
Total	443		422
Diluted earnings per unit
Common units	$	0.19	$	0.22
Subordinated units	$	0.20	$	0.21

There was no dilutive effect of equity based compensation during the three months ended March 31, 2016 and 2015.

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Partners' Equity

3 Months Ended

Mar. 31, 2016

Equity [Abstract]

Partners' Equity

Partners’ Equity

The Partnership Agreement requires that, within 45 days subsequent to the end of each quarter, the Partnership distribute all of its available cash (as defined in the Partnership Agreement) to unitholders of record on the applicable record date.

The Partnership paid or has authorized payment of the following cash distributions to common and subordinated unitholders during 2015 and 2016 (in millions, except for per unit amounts):

Quarter Ended	Record Date	Payment Date	Per Unit Distribution		Total Cash Distribution
March 31, 2016 (1)	May 6, 2016	May 13, 2016	$	0.318	$	134
December 31, 2015	February 2, 2016	February 12, 2016	$	0.318	$	134
September 30, 2015	November 3, 2015	November 13, 2015	$	0.318	$	134
June 30, 2015	August 3, 2015	August 13, 2015	$	0.316	$	134
March 31, 2015	May 5, 2015	May 15, 2015	$	0.3125	$	132

_____________________

(1) The board of directors of Enable GP declared this $0.318 per common unit cash distribution on April 26, 2016, to be paid on May 13, 2016, to common and subordinated unitholders of record at the close of business on May 6, 2016.

The board of directors of Enable GP declared a $0.2917 per Series A Preferred Unit prorated cash distribution on April 26, 2016, to be paid on May 13, 2016, to Series A Preferred unitholders of record at the close of business on May 6, 2016. The prorated quarterly distribution for the Series A Preferred Units is for a partial period beginning on February 18, 2016, and ending on March 31, 2016, which equates to $0.625 per unit on a full-quarter basis or $2.50 per unit on an annualized basis.

General Partner Interest and Incentive Distribution Rights

Enable GP owns a non-economic general partner interest in the Partnership and thus will not be entitled to distributions that the Partnership makes prior to the liquidation of the Partnership in respect of such general partner interest. Enable GP currently holds incentive distribution rights that entitle it to receive increasing percentages, up to a maximum of 50.0%, of the cash the Partnership distributes from operating surplus (as defined in the Partnership Agreement) in excess of $0.330625 per unit per quarter. The maximum distribution of 50.0% does not include any distributions that Enable GP or its affiliates may receive on common units or subordinated units that they own.

Subordinated Units

Subordinated Unit Ownership

All subordinated units are held by CenterPoint Energy and OGE Energy. These units are considered subordinated because during the subordination period (as defined in the Partnership Agreement), the common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $0.2875 per common unit, which amount is defined in the Partnership Agreement as the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. These units are deemed “subordinated” because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions until the common units have received the minimum quarterly distribution plus any arrearages from prior quarters. Furthermore, no arrearages will be paid on the subordinated units.

Subordination Period

The subordination period began on the closing date of the Offering and will extend until the first business day following which (1) distributions of available cash from operating surplus (as defined in the Partnership Agreement) on each of the outstanding common units and subordinated units equal or exceed $1.15 per unit (the annualized minimum quarterly distribution) for each of the three consecutive, non-overlapping four-quarter periods immediately preceding June 30, 2017 and (2) the adjusted operating surplus for each of the three consecutive, non-overlapping four-quarter periods immediately preceding such date equaled or exceeded the sum of the minimum quarterly distribution on all common units and subordinated units that were outstanding during such periods on a fully diluted weighted average basis. Also, if the Partnership has paid distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equal to or exceeding $1.725 per unit (150% of the annualized minimum quarterly distribution) and the related distribution on the incentive distribution rights, for any four-consecutive-quarter period ending on or after June 30, 2015, the subordination period will terminate.

Series A Preferred Units

On February 18, 2016, the Partnership completed the private placement of 14,520,000 Series A Preferred Units representing limited partner interests in the Partnership for a cash purchase price of $25.00 per Series A Preferred Unit, resulting in proceeds of $362 million, net of issuance costs. The Partnership incurred approximately $1 million of expenses related to the offering, which is shown as an offset to the proceeds. In connection with the closing of the private placement, the Partnership redeemed approximately $363 million of notes scheduled to mature in 2017 payable to a wholly-owned subsidiary of CenterPoint Energy.

Pursuant to the Partnership Agreement, the Series A Preferred Units:

• rank senior to the Partnership’s common units with respect to the payment of distributions and distribution of assets upon liquidation, dissolution and winding up;

• have no stated maturity;

• are not subject to any sinking fund; and

• will remain outstanding indefinitely unless repurchased or redeemed by the Partnership or converted into its common units in connection with a change of control.

Holders of the Series A Preferred Units receive, on a non-cumulative basis and if and when declared by the General Partner, a quarterly cash distribution, subject to certain adjustments, equal to an annual rate of 10% on the stated liquidation preference from the date of original issue to, but not including, the five year anniversary of the original issue date and an annual rate of LIBOR plus a spread of 8.5% on the stated liquidation preference thereafter.

At any time on or after five years after the original issue date, the Partnership may redeem the Series A Preferred Units, in whole or in part, from any source of funds legally available for such purpose, by paying $25.50 per unit plus an amount equal to all accumulated and unpaid distributions thereon to the date of redemption, whether or not declared. In addition, the Partnership (or a third-party with its prior written consent) may redeem the Series A Preferred Units following certain changes in the methodology employed by ratings agencies, changes of control or fundamental transactions as set forth in the Partnership Agreement. If, upon a change of control or certain fundamental transactions, the Partnership (or a third-party with its prior written consent) does not exercise this option, then the holders of the Series A Preferred Units have the option to convert the Series A Preferred Units into a number of common units per Series A Preferred Unit as set forth in the Partnership Agreement. The Series A Preferred Units are also required to be redeemed in certain circumstances if they are not eligible for trading on the New York Stock Exchange.

Holders of Series A Preferred Units have no voting rights except for limited voting rights with respect to potential amendments to the Partnership Agreement that have a material adverse effect on the existing terms of the Series A Preferred Units, the issuance by the Partnership of certain securities, approval of certain fundamental transactions and as required by law.

Upon the transfer of any Series A Preferred Unit to a non-affiliate of CenterPoint Energy, the Series A Preferred Units will automatically convert into a new series of preferred units (the “Series B Preferred Units”) on the later of the date of transfer and the second anniversary of the date of issue. The Series B Preferred Units will have the same terms as the Series A Preferred Units except that unpaid distributions on the Series B Preferred Units will accrue on a cumulative basis until paid.

On February 18, 2016, the Partnership entered into a Registration Rights Agreement with CenterPoint Energy, pursuant to which, among other things, the Partnership gave CenterPoint Energy certain rights to require the Partnership to file and maintain a registration statement with respect to the resale of the Series A Preferred Units and any other series of preferred units or common units representing limited partner interests in the Partnership that are issuable upon conversion of the Series A Preferred Units.

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Assessing Impairment of Long-lived Assets (including Intangible Assets)

3 Months Ended

Mar. 31, 2016

Goodwill and Intangible Assets Disclosure [Abstract]

Assessing Impairment of Long-lived Assets (including Intangible Assets)

Assessing Impairment of Long-lived Assets (including Intangible Assets)

The Partnership periodically evaluates long-lived assets, including property, plant and equipment, and specifically identifiable intangibles other than goodwill, when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable. The determination of whether an impairment has occurred is based on an estimate of undiscounted cash flows attributable to the assets, as compared to the carrying value of the assets. The Partnership recorded no material impairments to long-lived assets in the three months ended March 31, 2016 or 2015. Based upon review of forecasted undiscounted cash flows, none of the asset groups were at risk of failing step one of the impairment test. Further price declines, throughput declines, cost increases, regulatory or political environment changes, and other changes in market conditions could reduce forecast undiscounted cash flows.

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Investment in Equity Method Affiliates

3 Months Ended

Mar. 31, 2016

Equity Method Investments and Joint Ventures [Abstract]

Investments in Equity Method Affiliates

Investments in Equity Method Affiliates

The Partnership uses the equity method of accounting for investments in entities in which it has an ownership interest between 20% and 50% and exercises significant influence.

For the period from December 31, 2014 through June 29, 2015, the Partnership held a 49.90% interest in SESH. On June 12, 2015, CenterPoint Energy exercised its put right with respect to its remaining 0.1% interest in SESH. Pursuant to the put right, on June 30, 2015, CenterPoint Energy contributed a 0.1% interest in SESH to the Partnership in exchange for 25,341 common units representing limited partner interests in the Partnership, which had a fair value of $1 million based upon the closing market price of the Partnership’s common units. Spectra Energy Partners, LP owns the remaining 50% interest in SESH. Pursuant to the terms of the SESH LLC Agreement, if, at any time, CenterPoint Energy has a right to receive less than 50% of our distributions through its interest in the Partnership and its economic interest in Enable GP, or does not have the ability to exercise certain control rights, Spectra Energy Partners, LP may, under certain circumstances, have the right to purchase our interest in SESH at fair market value. As of March 31, 2016, the Partnership owned a 50% interest in SESH.

The Partnership shares operations of SESH with Spectra Energy Partners, LP under service agreements. The Partnership is responsible for the field operations of SESH. SESH reimburses each party for actual costs incurred, which are billed based upon a combination of direct charges and allocations. During the three months ended March 31, 2016 and 2015, the Partnership billed SESH $4 million and $2 million, respectively, associated with these service agreements.

Investment in Equity Method Affiliates:

	Three Months Ended   March 31,
	2016			2015
	(In millions)
Balance as of December 31	$	344		$	348
Equity in earnings of equity method affiliate	7			7
Contributions to equity method affiliate	—			6
Distributions from equity method affiliate(1)	(20		)	(12		)
Balance as of March 31	$	331		$	349

____________________

(1) Distributions from equity method affiliates includes a $7 million and $12 million return on investment and a $13 million and zero return of investment for the three months ended March 31, 2016 and 2015, respectively.

Equity in Earnings of Equity Method Affiliates:

	Three Months Ended   March 31,
	2016		2015
	(In millions)
SESH	$	7	$	7

Distributions from Equity Method Affiliates:

	Three Months Ended   March 31,
	2016		2015
	(In millions)
SESH	$	20	$	12

Summarized financial information of SESH is presented below:

	Three Months Ended   March 31,
	2016		2015
	(In millions)
Income Statements:
Revenues	$	29	$	29
Operating income	19		18
Net income	14		14

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Debt

3 Months Ended

Mar. 31, 2016

Debt Disclosure [Abstract]

Debt

Debt

The following table presents the Partnership’s outstanding debt as of March 31, 2016 and December 31, 2015.

	March 31, 2016		December 31, 2015
	(In millions)
Commercial Paper	$	—	$	236
2015 Term Loan Agreement	450		450
Revolving Credit Facility	715		310
Notes payable — affiliated companies (Note 11)	—		363
2019 Notes	500		500
2024 Notes	600		600
2044 Notes	550		550
EOIT Senior Notes	250		250
Premium (Discount) on long-term debt	21		23
Total debt	3,086		3,282
Less: Short-term debt(1)	—		236
Less: Unamortized debt expense	12		12
Less: Notes payable—affiliated companies	—		363
Total long-term debt	$	3,074	$	2,671

___________________

(1) Short-term debt includes $236 million of commercial paper as of December 31, 2015. There were no commercial paper borrowings outstanding as of March 31, 2016.

Revolving Credit Facility

On June 18, 2015, the Partnership amended and restated its Revolving Credit Facility to, among other things, increase the borrowing capacity thereunder to $1.75 billion and extend its maturity date to June 18, 2020. As of March 31, 2016, there was $715 million of principal advances and $3 million in letters of credit outstanding under the Revolving Credit Facility. However, as discussed below, commercial paper borrowings effectively reduce our borrowing capacity under this Revolving Credit Facility. The weighted average interest rate of the Revolving Credit Facility was 1.97% as of March 31, 2016.

The Revolving Credit Facility provides that outstanding borrowings bear interest at the LIBOR and/or an alternate base rate, at the Partnership’s election, plus an applicable margin. The applicable margin is based on the Partnership’s applicable credit ratings. As of March 31, 2016, the applicable margin for LIBOR-based borrowings under the Revolving Credit Facility was 1.50% based on the Partnership’s credit ratings. In addition, the Revolving Credit Facility requires the Partnership to pay a fee on unused commitments. The commitment fee is based on the Partnership’s applicable credit rating from the rating agencies. As of March 31, 2016, the commitment fee under the Revolving Credit Facility was 0.20% per annum based on the Partnership’s credit ratings. The commitment fee is recorded as interest expense in the Partnership’s Condensed Consolidated Statements of Income.

Commercial Paper

The Partnership has a commercial paper program, pursuant to which the Partnership is authorized to issue up to $1.4 billion of commercial paper. The commercial paper program is supported by our Revolving Credit Facility, and outstanding commercial paper effectively reduces our borrowing capacity thereunder. There was $236 million outstanding under our commercial paper program as of December 31, 2015. On February 2, 2016, Standard & Poor’s Ratings Services lowered its credit rating on the Partnership from an investment grade rating to a non-investment grade rating. The short-term rating on the Partnership was also reduced from an investment grade rating to a non-investment grade rating. As a result of the downgrade, the Partnership repaid its outstanding borrowings under the commercial program upon maturity and did not issue any additional commercial paper. There was no outstanding commercial paper as of March 31, 2016.

Term Loan Agreement

On July 31, 2015, the Partnership entered into a Term Loan Agreement dated as of July 31, 2015, providing for an unsecured three-year $450 million term loan agreement (2015 Term Loan Agreement). The entire $450 million principal amount of the 2015 Term Loan Agreement was borrowed by Enable on July 31, 2015. The 2015 Term Loan Agreement contains an option, which may be exercised up to two times, to extend the term of the 2015 Term Loan Agreement, in each case, for an additional one-year term. The 2015 Term Loan Agreement provides an option to prepay, without penalty or premium, the amount outstanding, or any portion thereof, in a minimum amount of $1 million, or any multiple of $0.5 million in excess thereof. As of March 31, 2016, there was $450 million outstanding under the 2015 Term Loan Agreement. As of March 31, 2016, the weighted average interest rate of the 2015 Term Loan Agreement was 1.80%.

The 2015 Term Loan Agreement provides that outstanding borrowings bear interest at the LIBOR and/or an alternate base rate, at the Partnership’s election, plus an applicable margin. The applicable margin is based on our applicable credit ratings. As ofMarch 31, 2016, the applicable margin for LIBOR-based borrowings under the term loan agreement was 1.375% based on our credit ratings.

Senior Notes

In connection with the issuance of the 2019 Notes, 2024 Notes and 2044 Notes, the Partnership, CenterPoint Energy Resources Corp., as guarantor of the 2019 Notes and the 2024 Notes, and RBS Securities Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Credit Suisse Securities (USA) LLC, and RBC Capital Markets, LLC, as representatives of the initial purchasers, entered into a registration rights agreement whereby the Partnership and the guarantor agreed to file with the SEC a registration statement relating to a registered offer to exchange the 2019 Notes, 2024 Notes and 2044 Notes for new series of the Partnership’s notes in the same aggregate principal amount as, and with terms substantially identical in all respects to, the 2019 Notes, 2024 Notes and 2044 Notes. On December 29, 2015, the Partnership completed the exchange offer.

A wholly owned subsidiary of CenterPoint Energy guaranteed collection of the Partnership’s obligations under the 2019 Notes and the 2024 Notes, which expired on May 1, 2016.

As of March 31, 2016, the Partnership’s debt included EOIT’s $250 million6.25% senior notes due March 2020 (the EOIT Senior Notes). The EOIT Senior Notes have a $22 million unamortized premium at March 31, 2016, resulting in an effective interest rate of 5.7%, during the three months ended March 31, 2016. These senior notes do not contain any financial covenants other than a limitation on liens. This limitation on liens is subject to certain exceptions and qualifications.

Financing Costs

Unamortized debt expense of $17 million and $18 million as of March 31, 2016 and December 31, 2015, respectively, is classified as either a reduction to Long-Term Debt or Other Assets in the Condensed Consolidated Balance Sheets and is being amortized over the life of the respective debt. Unamortized premium on long-term debt of $21 million and $23 million at March 31, 2016 and December 31, 2015, respectively, is classified as either Long-Term Debt or Short-Term Debt, consistent with the underlying debt instrument, in the Condensed Consolidated Balance Sheets and is being amortized over the life of the respective debt.

 As of March 31, 2016, the Partnership and EOIT were in compliance with all of their debt agreements, including financial covenants.

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Fair Value Measurements

3 Months Ended

Mar. 31, 2016

Fair Value Disclosures [Abstract]

Fair Value Measurements

Fair Value Measurements

Certain assets and liabilities are recorded at fair value in the Condensed Consolidated Balance Sheets and 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. Instruments classified as Level 1 include natural gas futures, swaps and options transactions for contracts traded on the NYMEX and settled through a NYMEX clearing broker.

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. Instruments classified as Level 2 include over-the-counter NYMEX natural gas swaps, natural gas basis swaps and natural gas purchase and sales transactions in markets such that the pricing is closely related to the NYMEX pricing, and over-the-counter WTI crude swaps for condensate sales.

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 the Partnership’s judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. The Partnership develops these inputs based on the best information available, including the Partnership’s own data.

The Partnership utilizes the market approach in determining the fair value of its derivative positions by using either NYMEX or WTI published market prices, independent broker pricing data or broker/dealer valuations. The valuations of derivatives with pricing based on NYMEX published market prices may be considered Level 1 if they are settled through a NYMEX clearing broker account with daily margining. Over-the-counter derivatives with NYMEX or WTI based prices are considered Level 2 due to the impact of counterparty credit risk. Valuations based on independent broker pricing or broker/dealer valuations may be classified as Level 2 only to the extent they may be validated by an additional source of independent market data for an identical or closely related active market. In certain less liquid markets or for longer-term contracts, forward prices are not as readily available. In these circumstances, contracts are valued using internally developed methodologies that consider historical relationships among various quoted prices in active markets that result in management’s best estimate of fair value. These contracts are classified as Level 3.

The Partnership 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 period ended March 31, 2016, there were no transfers between Level 1, 2, and 3 investments.

The impact to the fair value of derivatives due to credit risk is calculated using the probability of default based on Standard & Poor’s Ratings Services and/or internally generated ratings. The fair value of derivative assets is adjusted for credit risk. The fair value of derivative liabilities is adjusted for credit risk only if the impact is deemed material.

Contracts with Master Netting Arrangements

Fair value amounts recognized for forward, interest rate swap, option and other conditional or exchange contracts executed with the same counterparty under a master netting arrangement may be offset. The reporting entity’s choice to offset or not must be applied consistently. A master netting arrangement exists if the reporting entity has multiple contracts, whether for the same type of conditional or exchange contract or for different types of contracts, with a single counterparty that are subject to a contractual agreement that provides for the net settlement of all contracts through a single payment in a single currency in the event of default on or termination of any one contract. Offsetting the fair values recognized for forward, interest rate swap, option and other conditional or exchange contracts outstanding with a single counterparty results in the net fair value of the transactions being reported as an asset or a liability in the Condensed Consolidated Balance Sheets. The Partnership has presented the fair values of its derivative contracts under master netting agreements using a net fair value presentation.

The following tables summarize the Partnership’s assets and liabilities that are measured at fair value on a recurring basis as of March 31, 2016 and December 31, 2015:

March 31, 2016	Commodity Contracts						Gas Imbalances (1)
	Assets			Liabilities			Assets (2)		Liabilities (3)
	(In millions)
Quoted market prices in active market for identical assets (Level 1)	$	17		$	3		$	—	$	—
Significant other observable inputs (Level 2)	7			—			11		$	7
Unobservable inputs (Level 3)	2			3			—		$	—
Total fair value	26			6			11		$	7
Netting adjustments	(5		)	(5		)	—		$	—
Total	$	21		$	1		$	11	$	7

December 31, 2015	Commodity Contracts						Gas Imbalances (1)
	Assets			Liabilities			Assets (2)		Liabilities (3)
	(In millions)
Quoted market prices in active market for identical assets (Level 1)	$	17		$	3		$	—	$	—
Significant other observable inputs (Level 2)	10			—			17		20
Unobservable inputs (Level 3)	4			—			—		—
Total fair value	31			3			17		20
Netting adjustments	(3		)	(3		)	—		—
Total	$	28		$	—		$	17	$	20

______________________

(1) The Partnership uses the market approach to fair value its gas imbalance assets and liabilities at individual, or where appropriate an average of, current market indices applicable to the Partnership’s operations, not to exceed net realizable value. Gas imbalances held by EOIT are valued using an average of the Inside FERC Gas Market Report for Panhandle Eastern Pipe Line Co. (Texas, Oklahoma Mainline), ONEOK (Oklahoma) and ANR Pipeline (Oklahoma) indices. There were no netting adjustments as of March 31, 2016 and December 31, 2015.

(2) Gas imbalance assets exclude fuel reserves for under retained fuel due from shippers of $10 million and $6 million at March 31, 2016 and December 31, 2015, respectively, which fuel reserves are based on the value of natural gas at the time the imbalance was created and which are not subject to revaluation at fair market value.

(3) Gas imbalance liabilities exclude fuel reserves for over retained fuel due to shippers of $0 million and $5 million at March 31, 2016 and December 31, 2015, respectively, which fuel reserves are based on the value of natural gas at the time the imbalance was created and which are not subject to revaluation at fair market value.

Changes in Level 3 Fair Value Measurements

The following tables provides a reconciliation of changes in the fair value of our Level 3 commodity contracts between the periods presented.

	Commodity Contracts
	Natural gas liquids  financial futures/swaps
	(In millions)
Balance as of December 31, 2015	$	4
Losses included in earnings	(4		)
Settlements	(1		)
Balance as of March 31, 2016	$	(1	)

Quantitative Information on Level 3 Fair Value Measurements

The Partnership utilizes the market approach to measure the fair value of our commodity contracts. The significant unobservable inputs used in this approach to fair value are longer dated price quotes. Our sensitivity to these longer dated forward curve prices are presented in the table below. Significant changes in any of those inputs in isolation would result in significantly different fair value measurements, depending on our short or long position in contracts.

	March 31, 2016
Product Group	Fair Value			Forward Curve Range
	(In millions)			(Per gallon)
Natural gas liquids	$	(1	)	$0.441 - $0.495

Estimated Fair Value of Financial Instruments

The fair values of all accounts receivable, notes receivable, accounts payable, commercial paper, and other such financial instruments on the Condensed Consolidated Balance Sheets are estimated to be approximately equivalent to their carrying amounts and have been excluded from the table below. The following table summarizes the fair value and carrying amount of the Partnership’s financial instruments at March 31, 2016 and December 31, 2015.

	March 31, 2016				December 31, 2015
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)
Long-Term Debt
Long-term notes payable—affiliated companies (Level 2)	$	—	$	—	$	363	$	350
Revolving Credit Facility (Level 2)(1)	715		715		310		310
2015 Term Loan Agreement (Level 2)	450		450		450		450
EOIT Senior Notes (Level 2)	272		218		273		280
Enable Midstream Partners, LP 2019, 2024 and 2044 Notes (Level 2)	1,649		1,302		1,650		1,255

___________________

(1) Borrowing capacity is reduced by our borrowings outstanding under the commercial paper program. There was zero and $236 million of commercial paper outstanding as of March 31, 2016 and December 31, 2015, respectively.

The fair value of the Partnership’s Long-term notes payable—affiliated companies, Revolving Credit Facility, and 2015 Term Loan Agreement, along with the EOIT Senior Notes and Enable Midstream Partners, LP 2019, 2024 and 2044 Notes, is based on quoted market prices and estimates of current rates available for similar issues with similar maturities and is classified as Level 2 in the fair value hierarchy.

Non-Financial Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Certain assets and liabilities are measured at fair value on a nonrecurring basis; that is, the assets and liabilities are not measured at fair value on an ongoing basis, but are subject to fair value adjustments in certain circumstances (e.g., when there is evidence of impairment).

As of March 31, 2016, no material fair value adjustments or fair value measurements were required for these non-financial assets or liabilities.

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Derivative Instruments and Hedging Activities

3 Months Ended

Mar. 31, 2016

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments and Hedging Activities

Derivative Instruments and Hedging Activities

The Partnership is exposed to certain risks relating to its ongoing business operations. The primary risk managed using derivative instruments is commodity price risk. The Partnership is also exposed to credit risk in its business operations.

Commodity Price Risk

The Partnership has used forward physical contracts, commodity price swap contracts and commodity price option features to manage the Partnership’s commodity price risk exposures in the past. Commodity derivative instruments used by the Partnership are as follows:

• NGL put options, NGL futures and swaps, and WTI crude futures and swaps for condensate sales are used to manage the Partnership’s NGL and condensate exposure associated with its processing agreements;

• natural gas futures and swaps are used to manage the Partnership’s keep-whole natural gas exposure associated with its processing operations and the Partnership’s natural gas exposure associated with operating its gathering, transportation and storage assets; and

• natural gas futures and swaps, natural gas options and natural gas commodity purchases and sales are used to manage the Partnership’s natural gas exposure associated with its storage and transportation contracts and asset management activities.

Normal purchases and normal sales contracts are not recorded in Other Assets or Liabilities in the Condensed Consolidated Balance Sheets and earnings are recognized and recorded in the period in which physical delivery of the commodity occurs. Management applies normal purchases and normal sales treatment to: (i) commodity contracts for the purchase and sale of natural gas used in or produced by the Partnership’s operations and (ii) commodity contracts for the purchase and sale of NGLs produced by the Partnership’s gathering and processing business.

The Partnership recognizes its non-exchange traded derivative instruments as Other Assets or Liabilities in the Condensed Consolidated Balance Sheets at fair value with such amounts classified as current or long-term based on their anticipated settlement. Exchange traded transactions are settled on a net basis daily through margin accounts with a clearing broker and, therefore, are recorded at fair value on a net basis in Other Current Assets in the Condensed Consolidated Balance Sheets.

As of March 31, 2016 and December 31, 2015, the Partnership had no derivative instruments that were designated as cash flow or fair value hedges for accounting purposes.

Credit Risk

The Partnership is exposed to certain credit risks relating to its ongoing business operations. Credit risk includes the risk that counterparties that owe the Partnership money or energy will breach their obligations. If the counterparties to these arrangements fail to perform, the Partnership may be forced to enter into alternative arrangements. In that event, the Partnership’s financial results could be adversely affected, and the Partnership could incur losses.

Derivatives Not Designated As Hedging Instruments

Derivative instruments not designated as hedging instruments for accounting purposes are utilized in the Partnership’s asset management activities. For derivative instruments not designated as hedging instruments, the gain or loss on the derivative is recognized currently in earnings.

Quantitative Disclosures Related to Derivative Instruments

The majority of natural gas physical purchases and sales not designated as hedges for accounting purposes are priced based on a monthly or daily index, and the fair value is subject to little or no market price risk. Natural gas physical sales volumes exceed natural gas physical purchase volumes due to the marketing of natural gas volumes purchased via the Partnership’s processing contracts, which are not derivative instruments.

As of March 31, 2016 and December 31, 2015, the Partnership had the following derivative instruments that were not designated as hedging instruments for accounting purposes:

	March 31, 2016		December 31, 2015
	Gross Notional Volume
	Purchases	Sales	Purchases	Sales
Natural gas—TBtu(1)
Physical purchases/sales	—	48	2	51
Financial fixed futures/swaps	3	44	1	37
Financial basis futures/swaps	5	47	4	38
Crude oil (for condensate)—MBbl(2)
Financial Futures/swaps	—	460	—	506
Natural gas liquids—MBbl(3)
Financial Futures/swaps	—	1,551	75	1,011

____________________

(1) As of March 31, 2016, 86.1% of the natural gas contracts had durations of one year or less and 13.9% had durations of more than one year and less than two years. As of December 31, 2015, 97.7% of the natural gas contracts had durations of one year or less and 2.3% had durations of more than one year and less than two years.

(2) As of March 31, 2016, 93.5% of the condensate contracts had durations of one year or less and 6.5% had durations of more than one year and less than two years. As of December 31, 2015, 100% of the crude oil (for condensate) contracts had durations of one year or less.

(3) As of March 31, 2016, 85.5% of the natural gas liquids contracts had durations of one year or less and 14.5% had durations of more than one year and less than two years. As of December 31, 2015, 100% of the natural gas liquid contracts had durations of one year or less.

Balance Sheet Presentation Related to Derivative Instruments

The fair value of the derivative instruments that are presented in the Partnership’s Condensed Consolidated Balance Sheets as of March 31, 2016 and December 31, 2015 that were not designated as hedging instruments for accounting purposes are as follows:

		March 31, 2016				December 31, 2015
		Fair Value
Instrument	Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
		(In millions)
Natural gas
Financial futures/swaps	Other Current	$	18	$	3	$	17	$	3
Physical purchases/sales	Other Current	—		—		1		—
Crude Oil (for condensate)
Financial futures/swaps	Other Current	6		—		9		—
Natural gas liquids
Financial Futures/swaps	Other Current	2		3		4		—
Total gross derivatives (1)		$	26	$	6	$	31	$	3

_____________________

(1) See Note 8 for a reconciliation of the Partnership’s total derivatives fair value to the Partnership’s Condensed Consolidated Balance Sheets as of March 31, 2016 and December 31, 2015.

Income Statement Presentation Related to Derivative Instruments

The following tables present the effect of derivative instruments on the Partnership’s Condensed Consolidated Statements of Income for the three months ended March 31, 2016 and 2015.

	Amounts Recognized in Income
	Three Months Ended   March 31,
	2016			2015
	(In millions)
Natural gas financial futures/swaps gains (losses)	$	10		$	7
Natural gas physical purchases/sales gains (losses)	(4		)	(4		)
Crude Oil (for condensate) financial futures/swaps gains (losses)	1			4
Natural gas liquids financial futures/swaps gains (losses)	(4		)	—
Total	$	3		$	7

For derivatives not designated as hedges in the tables above, amounts recognized in income for the periods ended March 31, 2016 and 2015, if any, are reported in Product Sales.

Credit-Risk Related Contingent Features in Derivative Instruments

Based upon the Partnership’s senior unsecured debt rating with Moody’s Investors Services or Standard & Poor’s Ratings Services, the Partnership could be required to provide credit assurances to third parties, which could include letters of credit or cash collateral to satisfy its obligation under its financial and physical contracts relating to derivative instruments that are in a net liability position. As of March 31, 2016, under these obligations, no cash collateral has been posted. However, based on positions as of March 31, 2016, approximately $1 million of additional collateral may be required to be posted by the Partnership.

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Supplemental Disclosure of Cash Flow Information

3 Months Ended

Mar. 31, 2016

Supplemental Cash Flow Information [Abstract]

Supplemental Disclosure of Cash Flow Information

Supplemental Disclosure of Cash Flow Information

The following table provides information regarding supplemental cash flow information:

	Three Months Ended   March 31,
	2016		2015
	(In millions)
Supplemental Disclosure of Cash Flow Information:
Cash Payments:
Interest, net of capitalized interest	$	15	$	9
Income taxes, net of refunds	1		—
Non-cash transactions:
Accounts payable related to capital expenditures	42		51

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Related Party Transactions

3 Months Ended

Mar. 31, 2016

Related Party Transactions [Abstract]

Related Party Transactions

Related Party Transactions

The material related party transactions with CenterPoint Energy, OGE Energy and their respective subsidiaries are summarized below. There were no material related party transactions with other affiliates.

The Partnership’s revenues from affiliated companies accounted for 9% and 8% of revenues during the three months ended March 31, 2016 and 2015, respectively. Amounts of revenues from affiliated companies included in the Partnership’s Condensed Consolidated Statements of Income are summarized as follows:

	Three Months Ended   March 31,
	2016		2015
	(In millions)
Gas transportation and storage service revenue — CenterPoint Energy	$	33	$	33
Natural gas product sales — CenterPoint Energy	1		6
Gas transportation and storage service revenue — OGE Energy	9		9
Natural gas product sales — OGE Energy	1		3
Total revenues — affiliated companies	$	44	$	51

Amounts of natural gas purchased from affiliated companies included in the Partnership’s Condensed Consolidated Statements of Income are summarized as follows:

	Three Months Ended   March 31,
	2016		2015
	(In millions)
Cost of natural gas purchases — CenterPoint Energy	$	—	$	1
Cost of natural gas purchases — OGE Energy	2		3
Total cost of natural gas purchases — affiliated companies	$	2	$	4

Prior to May 1, 2013, the Partnership had employees and reflected the associated benefit costs directly and not as corporate services. Under the terms of the MFA, effective May 1, 2013 the Partnership’s employees were seconded by CenterPoint Energy and OGE Energy, and the Partnership began reimbursing each of CenterPoint Energy and OGE Energy for all employee costs under the seconding agreements until the seconded employees transition from CenterPoint Energy and OGE Energy to the Partnership. The Partnership transitioned seconded employees from CenterPoint Energy and OGE Energy to the Partnership effective January 1, 2015, except for certain employees who are participants under OGE Energy’s defined benefit and retiree medical plans, who will remain seconded to the Partnership, subject to certain termination rights of the Partnership and OGE Energy. The Partnership’s reimbursement of OGE Energy for employee costs arising out of OGE Energy’s defined benefit and retiree medical plans is fixed at $6 million in 2016, $5 million in 2017, and at actual cost subject to a cap of $5 million in 2018 and thereafter, in the event of continued secondment.

Prior to May 1, 2013, the Partnership received certain services and support functions from CenterPoint Energy described below. Under the terms of the MFA, effective May 1, 2013, the Partnership receives services and support functions from each of CenterPoint Energy and OGE Energy under service agreements for an initial term ending on April 30, 2016. The service agreements automatically extend year-to-year at the end of the initial term, unless terminated by the Partnership with at least 90 days’ notice. Additionally, the Partnership may terminate these service agreements at any time with 180 days’ notice, if approved by the Board of Enable GP. The Partnership reimburses CenterPoint Energy and OGE Energy for these services up to annual caps, which for 2016 are $7 million and $3 million, respectively.

Amounts charged to the Partnership by affiliates for seconded employees and corporate services, included primarily in Operation and maintenance and General and administrative expenses in the Partnership’s Condensed Consolidated Statements of Income are as follows:

	Three Months Ended   March 31,
	2016		2015
	(In millions)
Corporate Services — CenterPoint Energy	2		4
Seconded Employee Costs — OGE Energy	9		9
Corporate Services — OGE Energy	2		3
Total corporate services and seconded employees expense	$	13	$	16

The Partnership had outstanding long-term notes payable—affiliated companies to CenterPoint Energy at December 31, 2015 of $363 million, which were scheduled to mature in 2017. On February 18, 2016, in connection with the Private Placement of the Series A Preferred Units, the Partnership redeemed the $363 million of notes payable—affiliated companies payable to a subsidiary of CenterPoint Energy.

The Partnership recorded affiliated interest expense to CenterPoint Energy on notes payable—affiliated companies of $1 million and $2 million during the three months ended March 31, 2016 and 2015, respectively.

On February 18, 2016, the Partnership completed the private placement, with CenterPoint Energy, of 14,520,000 Series A Preferred Units representing limited partner interests in the Partnership for a cash purchase price of $25.00 per Series A Preferred Unit, resulting in proceeds of $362 million, net of issuance costs. See Note 4 for further discussion.

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Commitments and Contingencies

3 Months Ended

Mar. 31, 2016

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

The Partnership is involved in legal, environmental, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business. Some of these proceedings involve substantial amounts. The Partnership regularly analyzes current information and, as necessary, provides accruals for probable liabilities on the eventual disposition of these matters. The Partnership 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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Equity Based Compensation

3 Months Ended

Mar. 31, 2016

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Equity Based Compensation

Equity Based Compensation

The following table summarizes the Partnership’s compensation expense for the three months ended March 31, 2016 and 2015 related to performance units, restricted units, and phantom units for the Partnership’s employees and independent directors:

	Three Months Ended   March 31,
	2016		2015
	(In millions)
Performance units	$	1	$	1
Restricted units	1		2
Phantom units	—		—
Total compensation expense	$	2	$	3

Units Outstanding

The Partnership periodically grants performance units, restricted units, and phantom units to certain employees under the Enable Midstream Partners, LP Long Term Incentive Plan. A summary of the activity for the Partnership’s performance units, restricted units, and phantom units applicable to the Partnership’s employees at March 31, 2016 and changes during 2016 are shown in the following table.

	Performance Units					Restricted Units					Phantom Units
	Number of Units			Weighted Average Grant-Date Fair Value, Per Unit		Number of Units			Weighted Average Grant-Date Fair Value, Per Unit		Number of Units		Weighted Average Grant-Date Fair Value, Per Unit
	(In millions, except unit data)
Units Outstanding at December 31, 2015	814,510			$	20.67	581,772			$	21.04	9,817		$	12.70
Granted	—			—		—			—		—		—
Vested	(1,685		)	20.72		(78,375		)	22.58		—		—
Forfeited	(44,408		)	17.69		(49,834		)	19.26		—		—
Units Outstanding at March 31, 2016	768,417			$	20.84	453,563			$	20.97	9,817		$	12.70
Aggregate Intrinsic Value of Units Outstanding at March 31, 2016	$	5				$	3				$	—

Unrecognized Compensation Cost

A summary of the Partnership’s unrecognized compensation cost for its non-vested performance units, restricted units, and phantom units, and the weighted-average periods over which the compensation cost is expected to be recognized are shown in the following table.

	March 31, 2016
	Unrecognized Compensation Cost (In millions)		Weighted Average to be Recognized (In years)
Performance Units	$	9	1.80
Restricted Units	8		1.78
Phantom Units	—		0.24
Total	$	17

As of March 31, 2016, there were 11,149,474 units available for issuance under the long term incentive plan.

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Reportable Segments

3 Months Ended

Mar. 31, 2016

Segment Reporting [Abstract]

Reportable Segments

Reportable Segments

The Partnership’s determination of reportable segments considers the strategic operating units under which it manages sales, allocates resources and assesses performance of various products and services to customers in differing regulatory environments. The accounting policies of the reportable segments are the same as those described in the summary of significant accounting policies excerpt in the Partnership’s audited 2015 combined and consolidated financial statements included in the Annual Report. The Partnership uses operating income as the measure of profit or loss for its reportable segments.

The Partnership’s assets and operations are organized into two reportable segments: (i) Gathering and Processing, which primarily provides natural gas gathering, processing and fractionation services and crude oil gathering for our producer customers, and (ii) Transportation and Storage, which provides interstate and intrastate natural gas pipeline transportation and storage service primarily to natural gas producers, utilities and industrial customers.

Financial data for reportable segments are as follows:

Three Months Ended March 31, 2016	Gathering  and Processing		Transportation and Storage(1)		Eliminations			Total
	(In millions)
Revenues	$	333	$	246	$	(70	)	$	509
Cost of natural gas and natural gas liquids	165		99		(69		)	195
Operation and maintenance, General and administrative	75		41		(1		)	115
Depreciation and amortization	49		32		—			81
Impairments	—		—		—			—
Taxes other than income tax	8		7		—			15
Operating income	$	36	$	67	$	—		$	103
Total assets	$	7,543	$	4,888	$	(1,182	)	$	11,249
Capital expenditures	$	121	$	9	$	—		$	130
Three Months Ended March 31, 2015	Gathering and Processing		Transportation and Storage(1)		Eliminations			Total
	(In millions)
Revenues	$	401	$	308	$	(93	)	$	616
Cost of natural gas and natural gas liquids	222		163		(93		)	292
Operation and maintenance, General and administrative	76		54		—			130
Depreciation and amortization	43		30		—			73
Impairments	—		—		—			—
Taxes other than income tax	8		9		—			17
Operating income	$	52	$	52	$	—		$	104
Total assets as of December 31, 2015	$	7,536	$	4,976	$	(1,286	)	$	11,226
Capital expenditures	$	215	$	24	$	—		$	239

_____________________

(1) See Note 6 for discussion regarding ownership interests in SESH and related equity earnings included in the Transportation and Storage segment for the three months ended March 31, 2016 and 2015.

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Summary of Significant Accounting Policies (Policies)

3 Months Ended

Mar. 31, 2016

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization

Organization

Enable Midstream Partners, LP (Partnership), a Delaware limited partnership, is a large-scale, growth-oriented limited partnership formed to own, operate and develop strategically located natural gas and crude oil infrastructure assets. The Partnership’s assets and operations are organized into two reportable segments: (i) Gathering and Processing, which primarily provides natural gas gathering, processing and fractionation services and crude oil gathering for our producer customers, and (ii) Transportation and Storage, which provides interstate and intrastate natural gas pipeline transportation and storage services primarily to natural gas producers, utilities and industrial customers. The natural gas gathering and processing assets are located in five states and serve natural gas production in the Anadarko, Arkoma and Ark-La-Tex basins. This segment also includes a crude oil gathering business in the Bakken Shale formation, principally located in the Williston basin. The natural gas transportation and storage assets extend from western Oklahoma and the Texas Panhandle to Alabama and from Louisiana to Illinois.

The Partnership is controlled equally by CenterPoint Energy and OGE Energy, who each have 50% of the management rights of Enable GP. Enable GP was established by CenterPoint Energy and OGE Energy to govern the Partnership and has no other operating activities. Enable GP is governed by a board made up of an equal number of representatives designated by each of CenterPoint Energy and OGE Energy, along with the independent board members CenterPoint Energy and OGE Energy mutually agreed to appoint. Based on the 50/50 management ownership, with neither company having control, CenterPoint Energy and OGE Energy do not consolidate their interests in the Partnership. CenterPoint Energy and OGE Energy also own a 40% and 60% interest, respectively, in the incentive distribution rights held by Enable GP. As of March 31, 2016, CenterPoint Energy held approximately 55.4% of the common and subordinated units in the Partnership, or 94,151,707 common units and 139,704,916 subordinated units, and OGE Energy held approximately 26.3% of the common and subordinated units in the Partnership, or 42,832,291 common units and 68,150,514 subordinated units. Additionally, CenterPoint Energy holds 14,520,000 Series A Preferred Units. See Note 4 for further information related to the Series A Preferred Units.

For the period from December 31, 2014 through June 29, 2015, the financial statements reflect a 49.90% interest in SESH. On June 12, 2015, CenterPoint Energy exercised its put right with respect to a 0.1% interest in SESH. Pursuant to the put right, on June 30, 2015, CenterPoint Energy contributed its remaining 0.1% interest in SESH to the Partnership in exchange for 25,341 common units representing limited partner interests in the Partnership. As of March 31, 2016, the Partnership owned a 50% interest in SESH. See Note 6 for further discussion of SESH.

Basis of Presentation

Basis of Presentation

The accompanying condensed consolidated financial statements and related notes of the Partnership have been prepared pursuant to the rules and regulations of the SEC and GAAP. Pursuant to such rules and regulations, certain disclosures normally included in financial statements prepared in accordance with GAAP have been omitted. The accompanying condensed consolidated financial statements and related notes should be read in conjunction with the combined and consolidated financial statements and related notes included in our Annual Report.  

 These condensed consolidated financial statements and the related financial statement disclosures reflect all normal recurring adjustments that are, in the opinion of management, necessary to present fairly the financial position and results of operations for the respective periods. Amounts reported in the Partnership’s Condensed Consolidated Statements of 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.

Use of Estimates

Use of Estimates

The preparation of financial statements in conformity with GAAP 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.

Accounts Receivable and Allowance for Doubtful Accounts

Accounts Receivable and Allowance for Doubtful Accounts

Accounts receivable are recorded at the invoiced amount and do not bear interest. It is the policy of management to review the outstanding accounts receivable at least quarterly, as well as the bad debt write-offs experienced in the past.

New Accounting Pronouncements

Revenue from Contracts with Customers

In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers,” which supersedes the revenue recognition requirements in “Revenue Recognition (Topic 605),” and requires entities to recognize revenue in a way that depicts the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to in exchange for those goods or services. ASU 2014-09 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, and is to be applied retrospectively, with early application not permitted.

In August 2015, the FASB issued ASU No. 2015-14, “Revenue from Contracts with Customers (Topic 606)—Deferral of the Effective Date,” which deferred the effective date of ASU 2014-09 by one year to December 15, 2017 for annual reporting periods beginning after that date. The FASB also proposed permitting early adoption of the standard, but not before the original effective date of December 15, 2016. The Partnership is currently evaluating the impact, if any, the adoption of this standard will have on our Condensed Consolidated Financial Statements and related disclosures.

In March 2016, the FASB issued ASU No. 2016-08, “Revenue from Contracts with Customers (Topic 606)-Principal versus Agent Considerations (Reporting Revenue Gross versus Net)”. ASU No. 2016-08 requires an entity to determine whether the nature of its promise is to provide the specified good or service itself (i.e., the entity is a principal) or to arrange for that good or service to be provided by the other party (i.e., the entity is an agent) when another party is involved in providing goods or services to a customer. Additionally, the amendments in this ASU require an entity that is a principal to recognize revenue in the gross amount of consideration to which it expects to be entitled in exchange for the specified good or service transferred to the customer, and require an entity that is an agent to recognize revenue in the amount of any fee or commission to which it expects to be entitled in exchange for arranging for the specified good or service to be provided by the other party. ASU 2016-08 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, and is to be applied retrospectively, with early application not permitted. The Partnership is currently evaluating the impact, if any, the adoption of this standard will have on our Condensed Consolidated Financial Statements and related disclosures.

In April 2016, the FASB issued ASU No. 2016-10, “Revenue from Contracts with Customers (Topic 606)-Identifying Performance Obligations and Licensing”. The amendments in ASU No. 2016-10 impact entities with transactions that include contracts with customers to transfer goods or services (that are an output of the entity’s ordinary activities) in exchange for consideration, and they require entities to recognize revenue by following certain steps, including (1) identifying the contract(s) with a customer; (2) identifying the performance obligations in a contract; (3) determining the transaction price; (4) allocating the transaction price to the performance obligations in the contract; and (5) recognizing revenue when, or as, the entity satisfies a performance obligation. Notably, ASU No. 2016-10 does not impact the core revenue recognition principles set forth in Topic 606, but rather clarifies the identification of performance obligations and the licensing implementation guidance, while retaining the related principles for those areas. ASU 2016-10 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, and is to be applied retrospectively, with early application not permitted. The Partnership is currently evaluating the impact, if any, the adoption of this standard will have on our Condensed Consolidated Financial Statements and related disclosures.

Consolidation

In February 2015, the FASB issued ASU No. 2015-02, “Consolidation,” to improve consolidation guidance for certain types of legal entities. The guidance modifies the evaluation of whether limited partnerships and similar legal entities are variable interest entities (VIEs) or voting interest entities, eliminates the presumption that a general partner should consolidate a limited partnership, affects the consolidation analysis of reporting entities that are involved with VIEs, particularly those that have fee arrangements and related party relationships, and provides a scope exception from consolidation guidance for certain money market funds. The Partnership adopted the amendment in the first quarter of 2016, which resulted in no impact to our Condensed Consolidated Financial Statements and related disclosures.

Presentation of Debt Issuance Costs

In April 2015, the FASB issued ASU No. 2015-03, “Simplifying the Presentation of Debt Issuance Costs.” This standard amends existing guidance to require the presentation of debt issuance costs in the balance sheet as a deduction from the carrying amount of the related debt liability instead of a deferred charge. The Partnership adopted the amendment in the first quarter of 2016 on a retrospective basis in order to conform the presentation of debt issuance costs on the Condensed Consolidated Balance Sheets. At each ofMarch 31, 2016 and December 31, 2015, the Partnership had unamortized debt expense of $12 millionclassified as a reduction of Long-Term Debt in the Condensed Consolidated Balance Sheets. Unamortized debt expense related to the Revolving Credit Facility of $5 million and $6 million as ofMarch 31, 2016 and December 31, 2015, respectively, is classified as Other Assets in the Condensed Consolidated Balance Sheets.

Balance Sheet Classification of Deferred Taxes

In November 2015, the FASB issued ASU No. 2015-17, “Income Taxes—Balance Sheet Classification of Deferred Taxes.” This ASU eliminates the requirement to present deferred tax liabilities and assets as current and non-current in a classified balance sheet. Instead, all deferred tax assets and liabilities will be classified as non-current. ASU 2015-17 is effective for all interim and annual periods beginning after December 16, 2016 and early application is permitted. The amendments in this update may be applied either prospectively to all deferred tax liabilities and assets or retrospectively to all periods presented. The Partnership adopted the amendment in the first quarter of 2016, which resulted in no impact to our Condensed Consolidated Financial Statements and related disclosures.

Leases

In February 2016, the FASB issued ASU 2016-02, “Leases”. The amendments in this update require, among other things, that lessees recognize the following for all leases (with the exception of short-term leases) at the commencement date: (1) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and (2) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The Partnership expects to adopt the amendments in the first quarter of 2019 and is currently evaluating the impacts of the amendments to our Condensed Consolidated Financial Statements and accounting practices for leases.

Share-Based Compensation

In March 2016, the FASB issued ASU No. 2016-09, “Compensation—Stock Compensation (Topic 718).” This standard makes several modifications to Topic 718 related to the accounting for forfeitures, employer tax withholding on share-based compensation and the financial statement presentation of excess tax benefits or deficiencies. ASU 2016-09 also clarifies the statement of cash flows presentation for certain components of share-based awards. The standard is effective for interim and annual reporting periods beginning after December 15, 2016, although early adoption is permitted. The Partnership is currently assessing how the adoption of this standard will impact our Condensed Consolidated Financial Statements and related disclosures.

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Earnings Per Limited Partner Unit (Tables)

3 Months Ended

Mar. 31, 2016

Earnings Per Share [Abstract]

Schedule Of Earnings Per Unit For Common And Subordinated Limited Partner Units

The following table illustrates the Partnership’s calculation of earnings per unit for common and subordinated units:

	Three Months Ended   March 31,
	2016		2015
	(In millions, except per unit data)
Net income	$	86	$	91
Net income attributable to noncontrolling interest	—		—
Series A Preferred Unit distribution	—		—
General partner interest in net income	—		—
Net income available to common and subordinated unitholders	$	86	$	91
Net income allocable to common units	$	44	$	48
Net income allocable to subordinated units	42		43
Net income available to common and subordinated unitholders	$	86	$	91
Net income allocable to common units	$	44	$	48
Series A Preferred Unit Distribution	—		—
Diluted net income allocable to common units	44		48
Diluted net income allocable to subordinated units	42		43
Total	$	86	$	91
Basic weighted average number of outstanding
Common units	214		214
Subordinated units	208		208
Total	422		422
Basic earnings per unit
Common units	$	0.21	$	0.22
Subordinated units	$	0.20	$	0.21
Basic weighted average number of outstanding common units	214		214
Dilutive effect of Series A Preferred Units	21		—
Diluted weighted average number of outstanding common units	235		214
Diluted weighted average number of outstanding subordinated units	208		208
Total	443		422
Diluted earnings per unit
Common units	$	0.19	$	0.22
Subordinated units	$	0.20	$	0.21

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Partners' Equity (Tables)

3 Months Ended

Mar. 31, 2016

Equity [Abstract]

Schedule Of Equity Transactions With Limited Partner

The Partnership paid or has authorized payment of the following cash distributions to common and subordinated unitholders during 2015 and 2016 (in millions, except for per unit amounts):

Quarter Ended	Record Date	Payment Date	Per Unit Distribution		Total Cash Distribution
March 31, 2016 (1)	May 6, 2016	May 13, 2016	$	0.318	$	134
December 31, 2015	February 2, 2016	February 12, 2016	$	0.318	$	134
September 30, 2015	November 3, 2015	November 13, 2015	$	0.318	$	134
June 30, 2015	August 3, 2015	August 13, 2015	$	0.316	$	134
March 31, 2015	May 5, 2015	May 15, 2015	$	0.3125	$	132

_____________________

(1) The board of directors of Enable GP declared this $0.318 per common unit cash distribution on April 26, 2016, to be paid on May 13, 2016, to common and subordinated unitholders of record at the close of business on May 6, 2016.

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Investment in Unconsolidated Affiliates (Tables)

3 Months Ended

Mar. 31, 2016

Equity Method Investments and Joint Ventures [Abstract]

Schedule of Investments Detail

Investment in Equity Method Affiliates:

	Three Months Ended   March 31,
	2016			2015
	(In millions)
Balance as of December 31	$	344		$	348
Equity in earnings of equity method affiliate	7			7
Contributions to equity method affiliate	—			6
Distributions from equity method affiliate(1)	(20		)	(12		)
Balance as of March 31	$	331		$	349

____________________

(1) Distributions from equity method affiliates includes a $7 million and $12 million return on investment and a $13 million and zero return of investment for the three months ended March 31, 2016 and 2015, respectively.

Equity in Earnings of Equity Method Affiliates:

	Three Months Ended   March 31,
	2016		2015
	(In millions)
SESH	$	7	$	7

Distributions from Equity Method Affiliates:

	Three Months Ended   March 31,
	2016		2015
	(In millions)
SESH	$	20	$	12

Summarized financial information of SESH is presented below:

	Three Months Ended   March 31,
	2016		2015
	(In millions)
Income Statements:
Revenues	$	29	$	29
Operating income	19		18
Net income	14		14

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Debt (Tables)

3 Months Ended

Mar. 31, 2016

Debt Disclosure [Abstract]

Schedule of Debt

The following table presents the Partnership’s outstanding debt as of March 31, 2016 and December 31, 2015.

	March 31, 2016		December 31, 2015
	(In millions)
Commercial Paper	$	—	$	236
2015 Term Loan Agreement	450		450
Revolving Credit Facility	715		310
Notes payable — affiliated companies (Note 11)	—		363
2019 Notes	500		500
2024 Notes	600		600
2044 Notes	550		550
EOIT Senior Notes	250		250
Premium (Discount) on long-term debt	21		23
Total debt	3,086		3,282
Less: Short-term debt(1)	—		236
Less: Unamortized debt expense	12		12
Less: Notes payable—affiliated companies	—		363
Total long-term debt	$	3,074	$	2,671

___________________

(1) Short-term debt includes $236 million of commercial paper as of December 31, 2015. There were no commercial paper borrowings outstanding as of March 31, 2016.

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Fair Value Measurements (Tables)

3 Months Ended

Mar. 31, 2016

Fair Value Disclosures [Abstract]

Schedule of Assets and Liabilities Measured at Fair Value on a Recurring Basis

The following tables summarize the Partnership’s assets and liabilities that are measured at fair value on a recurring basis as of March 31, 2016 and December 31, 2015:

March 31, 2016	Commodity Contracts						Gas Imbalances (1)
	Assets			Liabilities			Assets (2)		Liabilities (3)
	(In millions)
Quoted market prices in active market for identical assets (Level 1)	$	17		$	3		$	—	$	—
Significant other observable inputs (Level 2)	7			—			11		$	7
Unobservable inputs (Level 3)	2			3			—		$	—
Total fair value	26			6			11		$	7
Netting adjustments	(5		)	(5		)	—		$	—
Total	$	21		$	1		$	11	$	7

December 31, 2015	Commodity Contracts						Gas Imbalances (1)
	Assets			Liabilities			Assets (2)		Liabilities (3)
	(In millions)
Quoted market prices in active market for identical assets (Level 1)	$	17		$	3		$	—	$	—
Significant other observable inputs (Level 2)	10			—			17		20
Unobservable inputs (Level 3)	4			—			—		—
Total fair value	31			3			17		20
Netting adjustments	(3		)	(3		)	—		—
Total	$	28		$	—		$	17	$	20

______________________

(1) The Partnership uses the market approach to fair value its gas imbalance assets and liabilities at individual, or where appropriate an average of, current market indices applicable to the Partnership’s operations, not to exceed net realizable value. Gas imbalances held by EOIT are valued using an average of the Inside FERC Gas Market Report for Panhandle Eastern Pipe Line Co. (Texas, Oklahoma Mainline), ONEOK (Oklahoma) and ANR Pipeline (Oklahoma) indices. There were no netting adjustments as of March 31, 2016 and December 31, 2015.

(2) Gas imbalance assets exclude fuel reserves for under retained fuel due from shippers of $10 million and $6 million at March 31, 2016 and December 31, 2015, respectively, which fuel reserves are based on the value of natural gas at the time the imbalance was created and which are not subject to revaluation at fair market value.

(3) Gas imbalance liabilities exclude fuel reserves for over retained fuel due to shippers of $0 million and $5 million at March 31, 2016 and December 31, 2015, respectively, which fuel reserves are based on the value of natural gas at the time the imbalance was created and which are not subject to revaluation at fair market value.

Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation

The following tables provides a reconciliation of changes in the fair value of our Level 3 commodity contracts between the periods presented.

	Commodity Contracts
	Natural gas liquids  financial futures/swaps
	(In millions)
Balance as of December 31, 2015	$	4
Losses included in earnings	(4		)
Settlements	(1		)
Balance as of March 31, 2016	$	(1	)

Schedule of Fair Value and Carrying Amount of Financial Instruments

The following table summarizes the fair value and carrying amount of the Partnership’s financial instruments at March 31, 2016 and December 31, 2015.

	March 31, 2016				December 31, 2015
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)
Long-Term Debt
Long-term notes payable—affiliated companies (Level 2)	$	—	$	—	$	363	$	350
Revolving Credit Facility (Level 2)(1)	715		715		310		310
2015 Term Loan Agreement (Level 2)	450		450		450		450
EOIT Senior Notes (Level 2)	272		218		273		280
Enable Midstream Partners, LP 2019, 2024 and 2044 Notes (Level 2)	1,649		1,302		1,650		1,255

___________________

(1) Borrowing capacity is reduced by our borrowings outstanding under the commercial paper program. There was zero and $236 million of commercial paper outstanding as of March 31, 2016 and December 31, 2015, respectively.

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Derivative Instruments and Hedging Activities (Tables)

3 Months Ended

Mar. 31, 2016

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Derivative Instruments

As of March 31, 2016 and December 31, 2015, the Partnership had the following derivative instruments that were not designated as hedging instruments for accounting purposes:

	March 31, 2016		December 31, 2015
	Gross Notional Volume
	Purchases	Sales	Purchases	Sales
Natural gas—TBtu(1)
Physical purchases/sales	—	48	2	51
Financial fixed futures/swaps	3	44	1	37
Financial basis futures/swaps	5	47	4	38
Crude oil (for condensate)—MBbl(2)
Financial Futures/swaps	—	460	—	506
Natural gas liquids—MBbl(3)
Financial Futures/swaps	—	1,551	75	1,011

____________________

(1) As of March 31, 2016, 86.1% of the natural gas contracts had durations of one year or less and 13.9% had durations of more than one year and less than two years. As of December 31, 2015, 97.7% of the natural gas contracts had durations of one year or less and 2.3% had durations of more than one year and less than two years.

(2) As of March 31, 2016, 93.5% of the condensate contracts had durations of one year or less and 6.5% had durations of more than one year and less than two years. As of December 31, 2015, 100% of the crude oil (for condensate) contracts had durations of one year or less.

(3) As of March 31, 2016, 85.5% of the natural gas liquids contracts had durations of one year or less and 14.5% had durations of more than one year and less than two years. As of December 31, 2015, 100% of the natural gas liquid contracts had durations of one year or less.

Schedule of Derivative Assets at Fair Value

The fair value of the derivative instruments that are presented in the Partnership’s Condensed Consolidated Balance Sheets as of March 31, 2016 and December 31, 2015 that were not designated as hedging instruments for accounting purposes are as follows:

		March 31, 2016				December 31, 2015
		Fair Value
Instrument	Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
		(In millions)
Natural gas
Financial futures/swaps	Other Current	$	18	$	3	$	17	$	3
Physical purchases/sales	Other Current	—		—		1		—
Crude Oil (for condensate)
Financial futures/swaps	Other Current	6		—		9		—
Natural gas liquids
Financial Futures/swaps	Other Current	2		3		4		—
Total gross derivatives (1)		$	26	$	6	$	31	$	3

_____________________

(1) See Note 8 for a reconciliation of the Partnership’s total derivatives fair value to the Partnership’s Condensed Consolidated Balance Sheets as of March 31, 2016 and December 31, 2015.

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value

The following tables present the effect of derivative instruments on the Partnership’s Condensed Consolidated Statements of Income for the three months ended March 31, 2016 and 2015.

	Amounts Recognized in Income
	Three Months Ended   March 31,
	2016			2015
	(In millions)
Natural gas financial futures/swaps gains (losses)	$	10		$	7
Natural gas physical purchases/sales gains (losses)	(4		)	(4		)
Crude Oil (for condensate) financial futures/swaps gains (losses)	1			4
Natural gas liquids financial futures/swaps gains (losses)	(4		)	—
Total	$	3		$	7

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Supplemental Disclosure of Cash Flow Information (Tables)

3 Months Ended

Mar. 31, 2016

Supplemental Cash Flow Information [Abstract]

Schedule of Cash Flow, Supplemental Disclosures

The following table provides information regarding supplemental cash flow information:

	Three Months Ended   March 31,
	2016		2015
	(In millions)
Supplemental Disclosure of Cash Flow Information:
Cash Payments:
Interest, net of capitalized interest	$	15	$	9
Income taxes, net of refunds	1		—
Non-cash transactions:
Accounts payable related to capital expenditures	42		51

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Related Party Transactions (Tables)

3 Months Ended

Mar. 31, 2016

Related Party Transactions [Abstract]

Schedule of Revenues from Related Parties

Amounts of revenues from affiliated companies included in the Partnership’s Condensed Consolidated Statements of Income are summarized as follows:

	Three Months Ended   March 31,
	2016		2015
	(In millions)
Gas transportation and storage service revenue — CenterPoint Energy	$	33	$	33
Natural gas product sales — CenterPoint Energy	1		6
Gas transportation and storage service revenue — OGE Energy	9		9
Natural gas product sales — OGE Energy	1		3
Total revenues — affiliated companies	$	44	$	51

Schedule of Natural Gas Purchased From Related Parties

Amounts of natural gas purchased from affiliated companies included in the Partnership’s Condensed Consolidated Statements of Income are summarized as follows:

	Three Months Ended   March 31,
	2016		2015
	(In millions)
Cost of natural gas purchases — CenterPoint Energy	$	—	$	1
Cost of natural gas purchases — OGE Energy	2		3
Total cost of natural gas purchases — affiliated companies	$	2	$	4

Schedule of Amounts Charged to Partnership by Related Parties

Amounts charged to the Partnership by affiliates for seconded employees and corporate services, included primarily in Operation and maintenance and General and administrative expenses in the Partnership’s Condensed Consolidated Statements of Income are as follows:

	Three Months Ended   March 31,
	2016		2015
	(In millions)
Corporate Services — CenterPoint Energy	2		4
Seconded Employee Costs — OGE Energy	9		9
Corporate Services — OGE Energy	2		3
Total corporate services and seconded employees expense	$	13	$	16

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Equity Based Compensation (Tables)

3 Months Ended

Mar. 31, 2016

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Disclosure of Share-based Compensation Arrangements by Share-based Payment Award

The following table summarizes the Partnership’s compensation expense for the three months ended March 31, 2016 and 2015 related to performance units, restricted units, and phantom units for the Partnership’s employees and independent directors:

	Three Months Ended   March 31,
	2016		2015
	(In millions)
Performance units	$	1	$	1
Restricted units	1		2
Phantom units	—		—
Total compensation expense	$	2	$	3

Schedule of Share-based Compensation, Activity

A summary of the activity for the Partnership’s performance units, restricted units, and phantom units applicable to the Partnership’s employees at March 31, 2016 and changes during 2016 are shown in the following table.

	Performance Units					Restricted Units					Phantom Units
	Number of Units			Weighted Average Grant-Date Fair Value, Per Unit		Number of Units			Weighted Average Grant-Date Fair Value, Per Unit		Number of Units		Weighted Average Grant-Date Fair Value, Per Unit
	(In millions, except unit data)
Units Outstanding at December 31, 2015	814,510			$	20.67	581,772			$	21.04	9,817		$	12.70
Granted	—			—		—			—		—		—
Vested	(1,685		)	20.72		(78,375		)	22.58		—		—
Forfeited	(44,408		)	17.69		(49,834		)	19.26		—		—
Units Outstanding at March 31, 2016	768,417			$	20.84	453,563			$	20.97	9,817		$	12.70
Aggregate Intrinsic Value of Units Outstanding at March 31, 2016	$	5				$	3				$	—

Schedule of Unrecognized Compensation Cost, Nonvested Awards

A summary of the Partnership’s unrecognized compensation cost for its non-vested performance units, restricted units, and phantom units, and the weighted-average periods over which the compensation cost is expected to be recognized are shown in the following table.

	March 31, 2016
	Unrecognized Compensation Cost (In millions)		Weighted Average to be Recognized (In years)
Performance Units	$	9	1.80
Restricted Units	8		1.78
Phantom Units	—		0.24
Total	$	17

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Reportable Segments (Tables)

3 Months Ended

Mar. 31, 2016

Segment Reporting [Abstract]

Schedule of Financial Data for Business Segments and Services

Financial data for reportable segments are as follows:

Three Months Ended March 31, 2016	Gathering  and Processing		Transportation and Storage(1)		Eliminations			Total
	(In millions)
Revenues	$	333	$	246	$	(70	)	$	509
Cost of natural gas and natural gas liquids	165		99		(69		)	195
Operation and maintenance, General and administrative	75		41		(1		)	115
Depreciation and amortization	49		32		—			81
Impairments	—		—		—			—
Taxes other than income tax	8		7		—			15
Operating income	$	36	$	67	$	—		$	103
Total assets	$	7,543	$	4,888	$	(1,182	)	$	11,249
Capital expenditures	$	121	$	9	$	—		$	130
Three Months Ended March 31, 2015	Gathering and Processing		Transportation and Storage(1)		Eliminations			Total
	(In millions)
Revenues	$	401	$	308	$	(93	)	$	616
Cost of natural gas and natural gas liquids	222		163		(93		)	292
Operation and maintenance, General and administrative	76		54		—			130
Depreciation and amortization	43		30		—			73
Impairments	—		—		—			—
Taxes other than income tax	8		9		—			17
Operating income	$	52	$	52	$	—		$	104
Total assets as of December 31, 2015	$	7,536	$	4,976	$	(1,286	)	$	11,226
Capital expenditures	$	215	$	24	$	—		$	239

_____________________

(1) See Note 6 for discussion regarding ownership interests in SESH and related equity earnings included in the Transportation and Storage segment for the three months ended March 31, 2016 and 2015.

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Summary of Significant Accounting Policies - Narrative (Details)		3 Months Ended	6 Months Ended
	Jun. 12, 2015	Mar. 31, 2016 USD ($) state segment shares	Jun. 29, 2015	Dec. 31, 2015 USD ($)
Number of reportable segments | segment		2
Number of states | state		5
Allowance for doubtful accounts | $		$ 3,000,000		$ 0
Series A 10% Fixed to Floating Non Cumulative Redeemable Perpetual Preferred Units
Issuance of Series A Preferred Units, units		14,520,000
SESH
Ownership percentage		50.00%
SESH | Put Option
Limited partner ownership interest			49.90%
CenterPoint | Limited Partner | Series A 10% Fixed to Floating Non Cumulative Redeemable Perpetual Preferred Units
Series A preferred units held by CenterPoint Energy		14,520,000
CenterPoint
Percentage share of management rights		50.00%
Percentage share of incentive distribution rights		40.00%
Limited partner ownership interest		55.40%
OGE Energy
Percentage share of management rights		50.00%
Percentage share of incentive distribution rights		60.00%
Limited partner ownership interest		26.30%
SESH | SESH | Put Option
Limited partner ownership interest, exercisable as early as May 2015	0.10%
Limited partner units that may be issued, exercisable as early as May 2015		25,341
Common Units | CenterPoint
Units outstanding		94,151,707
Common Units | OGE Energy
Units outstanding		42,832,291
Subordinated Units | CenterPoint
Units outstanding		139,704,916
Subordinated Units | OGE Energy
Units outstanding		68,150,514

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New Accounting Pronouncements (Narrative) (Details) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Less: Unamortized debt expense	$ 12	$ 12
Other Assets | Revolving Credit Facility
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Debt Issuance Costs, Line of Credit Arrangements, Net	$ 5
Accounting Standards Update 2015-03 | Long-term Debt
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Less: Unamortized debt expense		12
Accounting Standards Update 2015-03 | Other Assets | Revolving Credit Facility
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Debt Issuance Costs, Line of Credit Arrangements, Net		$ 6

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Earnings Per Limited Partner Unit (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net income	$ 86	$ 91
Net income attributable to noncontrolling interest	0	0
Series A Preferred Unit distribution	0	0
Diluted net income	86	91
General partner interest in net income	0	0
Net income attributable to common limited partners (Note 3)	$ 86	$ 91
Basic weighted average number of outstanding
Basic weighted average number of outstanding	422	422
Basic earnings per unit
Dilutive effect of Series A Preferred Units	21	0
Diluted weighted average number of outstanding units	443	422
Dilutive effect of unit-based awards	$ 0	$ 0
Common Units
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Diluted net income	$ 44	$ 48
Net income attributable to common limited partners (Note 3)	$ 44	$ 48
Basic weighted average number of outstanding
Basic weighted average number of outstanding	214	214
Basic earnings per unit
Basic earnings per unit	$ 0.21	$ 0.22
Diluted weighted average number of outstanding units	235	214
Diluted earnings per unit	$ 0.19	$ 0.22
Subordinated Units
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Diluted net income	$ 42	$ 43
Net income attributable to common limited partners (Note 3)	$ 42	$ 43
Basic weighted average number of outstanding
Basic weighted average number of outstanding	208	208
Basic earnings per unit
Basic earnings per unit	$ 0.20	$ 0.21
Diluted weighted average number of outstanding units	208	208
Diluted earnings per unit	$ 0.20	$ 0.21

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Partners' Equity -Schedule of Cash Distributions (Details) - USD ($) $ / shares in Units, $ in Millions		May. 13, 2016	May. 06, 2016	Apr. 26, 2016	Feb. 12, 2016	Feb. 02, 2016	Nov. 13, 2015	Nov. 03, 2015	Aug. 13, 2015	Aug. 03, 2015	May. 15, 2015	May. 05, 2015
Distribution Made to Limited Partner [Line Items]
Record Date						Feb. 02, 2016		Nov. 03, 2015		Aug. 03, 2015		May 05, 2015
Payment Date					Feb. 12, 2016		Nov. 13, 2015		Aug. 13, 2015		May 15, 2015
Cash Distribution
Distribution Made to Limited Partner [Line Items]
Per unit distribution, paid (per common unit)					$ 0.318		$ 0.318		$ 0.316		$ 0.3125
Distribution made to unitholders					$ 134		$ 134		$ 134		$ 132
Subsequent Event | Cash Distribution
Distribution Made to Limited Partner [Line Items]
Per common unit cash distribution declared				$ 0.318
Subsequent Event | Scenario, Forecast
Distribution Made to Limited Partner [Line Items]
Record Date	[1]		May 06, 2016
Payment Date	[1]	May 13, 2016
Subsequent Event | Scenario, Forecast | Cash Distribution
Distribution Made to Limited Partner [Line Items]
Per unit distribution, paid (per common unit)	[1]	$ 0.318
Distribution made to unitholders	[1]	$ 134

[1] The board of directors of Enable GP declared this $0.318 per common unit cash distribution on April 26, 2016, to be paid on May 13, 2016, to common and subordinated unitholders of record at the close of business on May 6, 2016.

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Partners' Equity Textual (Details) - USD ($) $ / shares in Units, $ in Millions			3 Months Ended
	Apr. 26, 2016	Feb. 18, 2016	Mar. 31, 2016	Mar. 31, 2015
Distribution Made to Limited Partner [Line Items]
Limited partners' capital account, required quarterly distribution period			45 days
Incentive distribution, distribution per unit			$ 0.330625
Limited partners capital account, minimum quarterly distribution, annualized			150.00%
Proceeds from issuance of Series A Preferred Units, net of issuance costs			$ 362	$ 0
Repayment of notes payable—affiliated companies			$ 363	$ 0
CenterPoint | Limited Partner
Distribution Made to Limited Partner [Line Items]
Repayment of notes payable—affiliated companies		$ 363
Subordinated Units
Distribution Made to Limited Partner [Line Items]
Minimum quarterly distribution per common unit			$ 0.2875
Distribution Subordination Period 1
Distribution Made to Limited Partner [Line Items]
Limited partners' capital account, minimum annualized quarterly distribution per unit			1.15
Distribution Subordination Period 2
Distribution Made to Limited Partner [Line Items]
Limited partners' capital account, maximum annualized quarterly distribution per unit			$ 1.725
Maximum
Distribution Made to Limited Partner [Line Items]
Limited partners' capital account, incentive distribution rights, percentage			50.00%
Subsequent Event | Cash Distribution
Distribution Made to Limited Partner [Line Items]
Per common unit cash distribution declared	$ 0.318
Series A 10% Fixed to Floating Non Cumulative Redeemable Perpetual Preferred Units
Distribution Made to Limited Partner [Line Items]
Issuance of Series A Preferred Units, units			14,520,000
Annual distribution rate		10.00%
Period after date of original issue		5 years
Redemption price per share		$ 25.50
Series A 10% Fixed to Floating Non Cumulative Redeemable Perpetual Preferred Units | LIBOR
Distribution Made to Limited Partner [Line Items]
Annual distribution rate		8.50%
Series A 10% Fixed to Floating Non Cumulative Redeemable Perpetual Preferred Units | Private Placement
Distribution Made to Limited Partner [Line Items]
Issuance of Series A Preferred Units, units		14,520,000
Cash purchase price per unit		$ 25.00
Proceeds from issuance of Series A Preferred Units, net of issuance costs		$ 362
Expenses related to the offering		$ 1
Series A 10% Fixed to Floating Non Cumulative Redeemable Perpetual Preferred Units | Private Placement | CenterPoint | Limited Partner
Distribution Made to Limited Partner [Line Items]
Issuance of Series A Preferred Units, units		14,520,000
Cash purchase price per unit		$ 25.00
Proceeds from issuance of Series A Preferred Units, net of issuance costs		$ 362
Series A 10% Fixed to Floating Non Cumulative Redeemable Perpetual Preferred Units | Subsequent Event | Cash Distribution | Preferred Partner
Distribution Made to Limited Partner [Line Items]
Per common unit cash distribution declared	0.2917000000
Full quarter equivalent distribution declared per unit	0.625
Annualized distribution declared per unit	$ 2.50

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Investment in Equity Method Affiliates - Narrative (Details) - SESH - USD ($) $ in Millions		3 Months Ended		6 Months Ended
	Jun. 12, 2015	Mar. 31, 2016	Mar. 31, 2015	Jun. 29, 2015
Fair value of limited partner interests		$ 1
Ownership percentage		50.00%
Percentage of distributions through limited partner interest		50.00%
Shared Operations Service Agreements | Equity Method Investee
Amount billed associated with service agreements		$ 4	$ 2
Put Option
Limited partner ownership interest				49.90%
SESH | Put Option
Limited partner ownership interest, exercisable as early as May 2015	0.10%
Limited partner units that may be issued, exercisable as early as May 2015		25,341

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Investment in Equity Method Affiliates - Schedule of Investments (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2016	Mar. 31, 2015
Investments in and Advances to Affiliates, at Fair Value [Roll Forward]
Balance as of December 31		$ 344
Balance as of March 31		331
Return of investment in equity method affiliates		13	$ 0
Equity in Earnings of Equity Method Affiliates:
Equity in earnings of equity method affiliates		7	7
SESH
Investments in and Advances to Affiliates, at Fair Value [Roll Forward]
Distributions from equity method affiliate		(20)	(12)
Distributions from Equity method affiliates		7	12
Return of investment in equity method affiliates		13	0
Distributions from Equity Method Affiliates:
Distributions from equity method affiliate		20	12
Operating revenues		29	29
Operating income		19	18
Net income		14	14
SESH | Other Income (Expense)
Equity in Earnings of Equity Method Affiliates:
Equity in earnings of equity method affiliates		7	7
SESH | Investments in Equity Method Affiliates
Investments in and Advances to Affiliates, at Fair Value [Roll Forward]
Balance as of December 31		344	348
Capital contributions from partners		0	6
Distributions from equity method affiliate	[1]	(20)	(12)
Balance as of March 31		331	349
Equity in Earnings of Equity Method Affiliates:
Equity in earnings of equity method affiliates		7	7
Distributions from Equity Method Affiliates:
Distributions from equity method affiliate	[1]	$ 20	$ 12

[1] Distributions from equity method affiliates includes a $7 million and $12 million return on investment and a $13 million and zero return of investment for the three months ended March 31, 2016 and 2015, respectively.

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- Narrative (Details)			3 Months Ended
		Jul. 31, 2015 USD ($) time	Mar. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)
Debt Instrument [Line Items]
Total debt			$ 3,086,000,000	$ 3,282,000,000
Notes payable — affiliated companies (Note 11)			0	363,000,000
Premium (Discount) on long-term debt			21,000,000	23,000,000
Short-term debt	[1]		0	236,000,000
Less: Unamortized debt expense			12,000,000	12,000,000
Total long-term debt			3,074,000,000	2,671,000,000
Commercial paper, authorized			1,400,000,000
Other Assets
Debt Instrument [Line Items]
Unamortized debt expense			17,000,000	18,000,000
2015 Term Loan Agreement
Debt Instrument [Line Items]
Total debt			450,000,000	450,000,000
Revolving Credit Facility
Debt Instrument [Line Items]
Total debt			715,000,000	310,000,000
Maximum borrowing capacity			1,750,000,000
Letters of credit principal advances			715,000,000
Letters of credit outstanding amount			$ 3,000,000
weighted average interest rate			1.97%
Commitment fee percentage			0.20%
Revolving Credit Facility | LIBOR
Debt Instrument [Line Items]
Applicable margin percentage			1.50%
Commercial Paper
Debt Instrument [Line Items]
Total debt			$ 0	236,000,000
Unsecured term loan facility | 2015 Term Loan Agreement
Debt Instrument [Line Items]
weighted average interest rate			1.80%
Duration of term loan facility		3 years
Unsecured term loan facility		$ 450,000,000
Number of times option maybe exercised to extend term of Term Loan Facility | time		2
Extension period		1 year
Minimum prepayment amount of option to prepay without penalty or premium (minimum amount of $1 million)		$ 1,000,000
Multiple amount of prepayment in excess of minimum prepayment		$ 500,000
Unsecured term loan facility | LIBOR | 2015 Term Loan Agreement
Debt Instrument [Line Items]
Applicable margin percentage			1.375%
Senior Notes
Debt Instrument [Line Items]
Premium (Discount) on long-term debt			$ 21,000,000	23,000,000
Senior Notes | 2.400% Senior Notes
Debt Instrument [Line Items]
Total debt			500,000,000	500,000,000
Senior Notes | 3.900% Senior Notes
Debt Instrument [Line Items]
Total debt			600,000,000	600,000,000
Senior Notes | 5.000% Senior Notes
Debt Instrument [Line Items]
Total debt			550,000,000	550,000,000
Senior Notes | 6.25% Senior Notes
Debt Instrument [Line Items]
Total debt			250,000,000	$ 250,000,000
Premium (Discount) on long-term debt			$ 22,000,000
Fixed interest rate			6.25%
Effective interest rate			5.70%

[1] Short-term debt includes $236 million of commercial paper as of December 31, 2015. There were no commercial paper borrowings outstanding as of March 31, 2016.

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Fair Value Measurements - Fair Value Hierarchy (Details) - USD ($) $ in Millions		Mar. 31, 2016	Dec. 31, 2015
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Retained fuel due from shippers		$ 10	$ 6
Over retained fuel due from shippers		0	5
Commodity Contracts | Recurring Measurement
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, total fair value		26	31
Liabilities, total fair value		6	3
Assets		(5)	(3)
Liabilities		(5)	(3)
Assets		21	28
Liabilities		1	0
Commodity Contracts | Recurring Measurement | Quoted market prices in active market for identical assets (Level 1)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets		17	17
Liabilities		3	3
Commodity Contracts | Recurring Measurement | Significant other observable inputs (Level 2)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets		7	10
Liabilities		0	0
Commodity Contracts | Recurring Measurement | Unobservable inputs (Level 3)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets		2	4
Liabilities		3	0
Gas Imbalances | Recurring Measurement
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, total fair value	[1],[2]	11	17
Liabilities, total fair value	[2],[3]	7	20
Assets	[1],[2]	0	0
Liabilities	[2],[3]	0	0
Assets	[1],[2]	11	17
Liabilities	[2],[3]	7	20
Gas Imbalances | Recurring Measurement | Quoted market prices in active market for identical assets (Level 1)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets	[1],[2]	0	0
Liabilities	[2],[3]	0	0
Gas Imbalances | Recurring Measurement | Significant other observable inputs (Level 2)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets	[1],[2]	11	17
Liabilities	[2],[3]	7	20
Gas Imbalances | Recurring Measurement | Unobservable inputs (Level 3)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets	[1],[2]	0	0
Liabilities	[2],[3]	$ 0	$ 0

[1] Gas imbalance assets exclude fuel reserves for under retained fuel due from shippers of $10 million and $6 million at March 31, 2016 and December 31, 2015, respectively, which fuel reserves are based on the value of natural gas at the time the imbalance was created and which are not subject to revaluation at fair market value.

[2] The Partnership uses the market approach to fair value its gas imbalance assets and liabilities at individual, or where appropriate an average of, current market indices applicable to the Partnership’s operations, not to exceed net realizable value. Gas imbalances held by EOIT are valued using an average of the Inside FERC Gas Market Report for Panhandle Eastern Pipe Line Co. (Texas, Oklahoma Mainline), ONEOK (Oklahoma) and ANR Pipeline (Oklahoma) indices. There were no netting adjustments as of March 31, 2016 and December 31, 2015.

[3] Gas imbalance liabilities exclude fuel reserves for over retained fuel due to shippers of $0 million and $5 million at March 31, 2016 and December 31, 2015, respectively, which fuel reserves are based on the value of natural gas at the time the imbalance was created and which are not subject to revaluation at fair market value.

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Fair Value Measurements - Schedule of Changes in Fair Value of Level 3 Financial Instruments (Details) - Financial Instruments, Assets - Commodity Contracts - Natural gas liquids financial futures/swaps $ in Millions	3 Months Ended
	Mar. 31, 2016 USD ($)
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance as of December 31, 2015	$ 4
Losses included in earnings	(4)
Settlements	(1)
Balance as of March 31, 2016	$ (1)

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Fair Value Measurements - Schedule of Quantitative Information of Level 3 Inputs (Details) - Commodity Contracts - Natural gas liquids - Financial Instruments, Assets - Market Approach Valuation Technique - Unobservable inputs (Level 3) $ in Millions	3 Months Ended
	Mar. 31, 2016 USD ($) $ / gal
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Fair Value | $	$ (1)
Minimum
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Forward Curve Range	0.441
Maximum
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Forward Curve Range	0.495

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Fair Value Measurements - Carrying and Fair Value Amounts (Details) - USD ($) $ in Millions		Mar. 31, 2016	Dec. 31, 2015
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount		$ 3,086	$ 3,282
Carrying value		0	236
Carrying Amount | Significant other observable inputs (Level 2) | Long-term notes payable—affiliated companies (Level 2) | Affiliated Companies
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount		0	363
Carrying Amount | Significant other observable inputs (Level 2) | Revolving Credit Facility (Level 2)
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount	[1]	715	310
Carrying Amount | Significant other observable inputs (Level 2) | 2015 Term Loan Agreement (Level 2)
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount		450	450
Carrying Amount | Significant other observable inputs (Level 2) | EOIT Senior Notes (Level 2)
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount		272	273
Carrying Amount | Significant other observable inputs (Level 2) | Enable Midstream Partners, LP 2019, 2024 and 2044 Notes (Level 2)
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount		1,649	1,650
Fair Value | Significant other observable inputs (Level 2) | Long-term notes payable—affiliated companies (Level 2) | Affiliated Companies
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value		0	350
Fair Value | Significant other observable inputs (Level 2) | Revolving Credit Facility (Level 2)
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value	[1]	715	310
Fair Value | Significant other observable inputs (Level 2) | 2015 Term Loan Agreement (Level 2)
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value		450	450
Fair Value | Significant other observable inputs (Level 2) | EOIT Senior Notes (Level 2)
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value		218	280
Fair Value | Significant other observable inputs (Level 2) | Enable Midstream Partners, LP 2019, 2024 and 2044 Notes (Level 2)
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value		$ 1,302	$ 1,255

[1] Borrowing capacity is reduced by our borrowings outstanding under the commercial paper program. There was zero and $236 million of commercial paper outstanding as of March 31, 2016 and December 31, 2015, respectively.

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Derivative Instruments and Hedging Activities (Details) - Not Designated as Hedging Instrument bbl in Thousands, MMBTU in Millions		3 Months Ended
		Mar. 31, 2016 MMBTU bbl	Mar. 31, 2015 MMBTU bbl	Dec. 31, 2015
Natural gas
Derivative [Line Items]
Percent of contract with durations of one year or less		86.10%		97.70%
Percent of contracts with durations of more than one year and less than two years		13.90%		2.30%
Natural gas | Physical | Purchases
Derivative [Line Items]
Derivative, gross notional volume (TBtu)	[1]	0	2
Natural gas | Physical | Sales
Derivative [Line Items]
Derivative, gross notional volume (TBtu)	[1]	48	51
Natural gas | Financial fixed futures/swaps | Purchases
Derivative [Line Items]
Derivative, gross notional volume (TBtu)	[1]	3	1
Natural gas | Financial fixed futures/swaps | Sales
Derivative [Line Items]
Derivative, gross notional volume (TBtu)	[1]	44	37
Natural gas | Financial basis futures/swaps | Purchases
Derivative [Line Items]
Derivative, gross notional volume (TBtu)	[1]	5	4
Natural gas | Financial basis futures/swaps | Sales
Derivative [Line Items]
Derivative, gross notional volume (TBtu)	[1]	47	38
Condensate
Derivative [Line Items]
Percent of contract with durations of one year or less		93.50%		100.00%
Percent of contracts with durations of more than one year and less than two years		6.50%
Condensate | Financial Futures/swaps | Purchases
Derivative [Line Items]
Derivative, gross notional volume (MMbl) | bbl	[2]	0	0
Condensate | Financial Futures/swaps | Sales
Derivative [Line Items]
Derivative, gross notional volume (MMbl) | bbl	[2]	460	506
Natural gas liquids
Derivative [Line Items]
Percent of contract with durations of one year or less		85.50%		100.00%
Percent of contracts with durations of more than one year and less than two years		14.50%
Natural gas liquids | Financial Futures/swaps | Purchases
Derivative [Line Items]
Derivative, gross notional volume (MMbl) | bbl	[3]	0	75
Natural gas liquids | Financial Futures/swaps | Sales
Derivative [Line Items]
Derivative, gross notional volume (MMbl) | bbl	[3]	1,551	1,011

[1] As of March 31, 2016, 86.1% of the natural gas contracts had durations of one year or less and 13.9% had durations of more than one year and less than two years. As of December 31, 2015, 97.7% of the natural gas contracts had durations of one year or less and 2.3% had durations of more than one year and less than two years.

[2] As of March 31, 2016, 93.5% of the condensate contracts had durations of one year or less and 6.5% had durations of more than one year and less than two years. As of December 31, 2015, 100% of the crude oil (for condensate) contracts had durations of one year or less.

[3] As of March 31, 2016, 85.5% of the natural gas liquids contracts had durations of one year or less and 14.5% had durations of more than one year and less than two years. As of December 31, 2015, 100% of the natural gas liquid contracts had durations of one year or less.

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Derivative Instruments and Hedging Activities - Balance Sheet Location (Details) - Not Designated as Hedging Instrument - USD ($)		Mar. 31, 2016	Dec. 31, 2015
Derivatives, Fair Value [Line Items]
Derivative instruments designated as cash flow hedges or fair value hedges		$ 0	$ 0
Assets	[1]	26,000,000	31,000,000
Liabilities	[1]	6,000,000	3,000,000
Natural gas | Financial futures/swaps | Other Current, Assets
Derivatives, Fair Value [Line Items]
Assets		18,000,000	17,000,000
Natural gas | Financial futures/swaps | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Liabilities		3,000,000	3,000,000
Natural gas | Physical purchases/sales | Other Current, Assets
Derivatives, Fair Value [Line Items]
Assets		0	1,000,000
Natural gas | Physical purchases/sales | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Liabilities		0	0
Crude Oil (for condensate) | Financial futures/swaps | Other Current, Assets
Derivatives, Fair Value [Line Items]
Assets		6,000,000	9,000,000
Crude Oil (for condensate) | Financial futures/swaps | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Liabilities		0	0
Natural gas liquids | Financial futures/swaps | Other Current, Assets
Derivatives, Fair Value [Line Items]
Assets		2,000,000	4,000,000
Natural gas liquids | Financial futures/swaps | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Liabilities		$ 3,000,000	$ 0

[1] See Note 8 for a reconciliation of the Partnership’s total derivatives fair value to the Partnership’s Condensed Consolidated Balance Sheets as of March 31, 2016 and December 31, 2015.

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Derivative Instruments and Hedging Activities - Amounts Recognized in Income (Details) - USD ($)	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivative, net	$ 3,000,000	$ 7,000,000
Cash collateral required if ratings are lowered	1,000,000
Natural gas | Financial futures/swaps
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivative, net	10,000,000	7,000,000
Natural gas | Physical purchases/sales
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivative, net	(4,000,000)	(4,000,000)
Condensate | Financial futures/swaps
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivative, net	1,000,000	4,000,000
Natural gas liquids | Financial futures/swaps
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivative, net	$ (4,000,000)	$ 0

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Supplemental Disclosure of Cash Flow Information - (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Supplemental Cash Flow Information [Abstract]
Interest, net of capitalized interest	$ 15	$ 9
Income taxes, net of refunds	1	0
Accounts payable related to capital expenditures	$ 42	$ 51

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Related Party Transactions (Details) - USD ($) $ / shares in Units, $ in Millions		3 Months Ended
	Feb. 18, 2016	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
Related Party Transaction [Line Items]
Partnership's revenues from affiliated companies as a percent of total revenues		9.00%	8.00%
Notes payable — affiliated companies (Note 11)		$ 0		$ 363
Notes payable—affiliated companies		0		363
Proceeds from issuance of Series A Preferred Units, net of issuance costs		$ 362	$ 0
Series A 10% Fixed to Floating Non Cumulative Redeemable Perpetual Preferred Units
Related Party Transaction [Line Items]
Issuance of Series A Preferred Units, units		14,520,000
Private Placement | Series A 10% Fixed to Floating Non Cumulative Redeemable Perpetual Preferred Units
Related Party Transaction [Line Items]
Issuance of Series A Preferred Units, units	14,520,000
Cash purchase price per unit	$ 25.00
Proceeds from issuance of Series A Preferred Units, net of issuance costs	$ 362
OGE Energy
Related Party Transaction [Line Items]
Period notice of termination prior to commencement of succeeding annual period		180 days
OGE Energy | Defined Benefit and Retiree Medical Plans
Related Party Transaction [Line Items]
Expense reimbursement, remainder of fiscal year		$ 6
Expense reimbursement, second year		6
Expense reimbursement, third year		5
Expense reimbursement, fourth year		5
Expense reimbursement, thereafter		5
OGE Energy | Certain Services and Support Functions
Related Party Transaction [Line Items]
Expense reimbursement annual caps		$ 3
CenterPoint and OGE Energy
Related Party Transaction [Line Items]
Period notice of termination for reimbursements for all employee costs		90 days
CenterPoint
Related Party Transaction [Line Items]
Notes payable — affiliated companies (Note 11)				$ 363
Affiliate interest expense		$ 1	$ 2
CenterPoint | Certain Services and Support Functions
Related Party Transaction [Line Items]
Expense reimbursement annual caps		$ 7
Limited Partner | Private Placement | Series A 10% Fixed to Floating Non Cumulative Redeemable Perpetual Preferred Units | CenterPoint
Related Party Transaction [Line Items]
Issuance of Series A Preferred Units, units	14,520,000
Cash purchase price per unit	$ 25.00
Proceeds from issuance of Series A Preferred Units, net of issuance costs	$ 362

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Related Party Activity (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Related Party Transaction [Line Items]
Revenues from affiliated companies	$ 44	$ 51
Cost of goods sold from affiliate	2	4
Charges to the Partnership by affiliates	13	16
CenterPoint
Related Party Transaction [Line Items]
Cost of goods sold from affiliate	0	1
CenterPoint | Gas Transportation and Storage
Related Party Transaction [Line Items]
Revenues from affiliated companies	33	33
CenterPoint | Gas Sales
Related Party Transaction [Line Items]
Revenues from affiliated companies	1	6
CenterPoint | Corporate Services
Related Party Transaction [Line Items]
Charges to the Partnership by affiliates	2	4
OGE Energy
Related Party Transaction [Line Items]
Cost of goods sold from affiliate	2	3
OGE Energy | Gas Transportation and Storage
Related Party Transaction [Line Items]
Revenues from affiliated companies	9	9
OGE Energy | Gas Sales
Related Party Transaction [Line Items]
Revenues from affiliated companies	1	3
OGE Energy | Seconded Employee Costs
Related Party Transaction [Line Items]
Charges to the Partnership by affiliates	9	9
OGE Energy | Corporate Services
Related Party Transaction [Line Items]
Charges to the Partnership by affiliates	$ 2	$ 3

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Equity Based Compensation (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	$ 2	$ 3
Performance units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	1	1
Restricted units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	1	2
Phantom units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	$ 0	$ 0

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Equity Based Compensation - Equity Units Activity (Details) $ / shares in Units, $ in Millions	3 Months Ended
	Mar. 31, 2016 USD ($) $ / shares shares
Performance units
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Units Outstanding at December 31, 2015 | shares	814,510
Granted | shares	0
Vested | shares	(1,685)
Forfeited | shares	(44,408)
March 31, 2016 | shares	768,417
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Units Outstanding at December 31, 2015 | $ / shares	$ 20.67
Granted | $ / shares	0.00
Vested | $ / shares	20.72
Forfeited | $ / shares	17.69
March 31, 2016 | $ / shares	$ 20.84
Aggregate Intrinsic Value of Units Outstanding at March 31, 2016 | $	$ 5
Restricted units
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Units Outstanding at December 31, 2015 | shares	581,772
Granted | shares	0
Vested | shares	(78,375)
Forfeited | shares	(49,834)
March 31, 2016 | shares	453,563
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Units Outstanding at December 31, 2015 | $ / shares	$ 21.04
Granted | $ / shares	0.00
Vested | $ / shares	22.58
Forfeited | $ / shares	19.26
March 31, 2016 | $ / shares	$ 20.97
Aggregate Intrinsic Value of Units Outstanding at March 31, 2016 | $	$ 3
Phantom units
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Units Outstanding at December 31, 2015 | shares	9,817
Granted | shares	0
Vested | shares	0
Forfeited | shares	0
March 31, 2016 | shares	9,817
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Units Outstanding at December 31, 2015 | $ / shares	$ 12.70
Granted | $ / shares	0.00
Vested | $ / shares	0.00
Forfeited | $ / shares	0.00
March 31, 2016 | $ / shares	$ 12.70
Aggregate Intrinsic Value of Units Outstanding at March 31, 2016 | $	$ 0

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Equity Based Compensation - Unrecognized Compensation Cost (Details) $ in Millions	3 Months Ended
	Mar. 31, 2016 USD ($) shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized Compensation Cost (In millions)	$ 17
Performance units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized Compensation Cost (In millions)	$ 9
Weighted Average to be Recognized (In years)	1 year 9 months 18 days
Restricted units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized Compensation Cost (In millions)	$ 8
Weighted Average to be Recognized (In years)	1 year 9 months 11 days
Phantom units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized Compensation Cost (In millions)	$ 0
Weighted Average to be Recognized (In years)	2 months 27 days
Long Term Incentive Plan | Common Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares available for issuance | shares	11,149,474

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- Schedule of Financial Data for Business Segments and Services (Details) $ in Millions		3 Months Ended
		Mar. 31, 2016 USD ($) segment	Mar. 31, 2015 USD ($)	Dec. 31, 2015 USD ($)
Segment Reporting Information [Line Items]
Number of reportable segments | segment		2
Total revenues		$ 509	$ 616
Cost of goods sold, excluding depreciation and amortization		195	292
Operation and maintenance, General and administrative		115	130
Depreciation and amortization		81	73
Impairments		0	0
Taxes other than income tax		15	17
Operating Income		103	104
Total assets		11,249		$ 11,226
Capital expenditures		130	239
Gathering and Processing
Segment Reporting Information [Line Items]
Total revenues		333	401
Cost of goods sold, excluding depreciation and amortization		165	222
Operation and maintenance, General and administrative		75	76
Depreciation and amortization		49	43
Impairments		0	0
Taxes other than income tax		8	8
Operating Income		36	52
Total assets		7,543		7,536
Capital expenditures		121	215
Transportation and Storage
Segment Reporting Information [Line Items]
Total revenues	[1]	246	308
Cost of goods sold, excluding depreciation and amortization	[1]	99	163
Operation and maintenance, General and administrative	[1]	41	54
Depreciation and amortization	[1]	32	30
Impairments	[1]	0	0
Taxes other than income tax	[1]	7	9
Operating Income	[1]	67	52
Total assets	[1]	4,888		4,976
Capital expenditures	[1]	9	24
Eliminations
Segment Reporting Information [Line Items]
Total revenues		(70)	(93)
Cost of goods sold, excluding depreciation and amortization		(69)	(93)
Operation and maintenance, General and administrative		(1)	0
Depreciation and amortization		0	0
Impairments		0	0
Taxes other than income tax		0	0
Operating Income		0	0
Total assets		(1,182)		$ (1,286)
Capital expenditures		$ 0	$ 0

[1] See Note 6 for discussion regarding ownership interests in SESH and related equity earnings included in the Transportation and Storage segment for the three months ended March 31, 2016 and 2015.