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Document and Entity Information - shares	6 Months Ended
Document and Entity Information - shares	Jun. 30, 2016	Jul. 15, 2016
Document and Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2016
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	Q2
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		214,461,682

Condensed Consolidated Statements of Income (Unaudited) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Revenues (including revenues from affiliates (Note 11)):
Product sales	$ 266	$ 335	$ 511	$ 686
Service revenue	263	255	527	520
Total Revenues	529	590	1,038	1,206
Cost and Expenses (including expenses from affiliates (Note 11)):
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)	254	277	449	569
Operation and maintenance	93	108	188	212
General and Administrative	27	23	47	49
Depreciation and amortization	83	76	164	149
Taxes other than income taxes	15	13	30	30
Total Cost and Expenses	472	497	878	1,009
Operating Income	57	93	160	197
Other Income (Expense):
Interest expense (including expenses from affiliates (Note 11))	(25)	(23)	(48)	(43)
Equity in earnings of equity method affiliates	7	7	14	14
Other, net	0	1	0	2
Total Other Income (Expense)	(18)	(15)	(34)	(27)
Income Before Income Taxes
Income Before Income Taxes	39	78	126	170
Income tax expense	0	1	1	2
Net Income
Net Income	39	77	125	168
Less: Net income attributable to noncontrolling interest
Less: Net income attributable to noncontrolling interest	0	0	0	0
Net Income attributable to limited partners
Net Income attributable to limited partners	39	77	125	168
Less: Series A Preferred Unit distributions (Note 4)
Less: Series A Preferred Unit distributions (Note 4)	4	0	4	0
Net Income attributable to common and subordinated units (Note 3)
Net Income attributable to common and subordinated units (Note 3)	35	77	121	168
Common Units
Net Income attributable to common and subordinated units (Note 3)
Net Income attributable to common and subordinated units (Note 3)	$ 18	$ 39	$ 61	$ 85
Basic and Diluted earnings per unit and weighted average number of units outstanding
Basic earnings per unit (Note 3)	$ 0.08	$ 0.18	$ 0.29	$ 0.40
Diluted earnings per unit (Note 3)	$ 0.08	$ 0.18	$ 0.28	$ 0.40
Subordinated Units
Net Income attributable to common and subordinated units (Note 3)
Net Income attributable to common and subordinated units (Note 3)	$ 17	$ 38	$ 60	$ 83
Basic and Diluted earnings per unit and weighted average number of units outstanding
Basic earnings per unit (Note 3)	$ 0.08	$ 0.18	$ 0.29	$ 0.40
Diluted earnings per unit (Note 3)	$ 0.08	$ 0.18	$ 0.29	$ 0.40

Condensed Consolidated Statements of Comprehensive Income (Unaudited) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Statement of Comprehensive Income [Abstract]
Net income	$ 39	$ 77	$ 125	$ 168
Comprehensive income	39	77	125	168
Less: Comprehensive income attributable to noncontrolling interest	0	0	0	0
Comprehensive income attributable to Enable Midstream Partners, LP	$ 39	$ 77	$ 125	$ 168

Condensed Consolidated Balance Sheets (Unaudited) - USD ($)
$ in Millions

Jun. 30, 2016

Dec. 31, 2015

Current Assets:

Cash and cash equivalents

$ 6

$ 4

Accounts receivable, net of allowance for doubtful accounts

225

245

Accounts receivable—affiliated companies

349

381

Property, Plant and Equipment:

Property, plant and equipment

11,456

11,293

Less accumulated depreciation and amortization

1,291

1,162

Property, plant and equipment, net

10,165

10,131

Other Assets:

Intangible assets, net

320

333

Investment in equity method affiliates

331

344

Other

Total other assets

686

714

Total Assets

11,200

11,226

Current Liabilities:

Accounts payable

141

248

Accounts payable—affiliated companies

Short-term debt

^[1]

236

Taxes accrued

Gas imbalances

Other

103

Total current liabilities

301

615

Other Liabilities:

Accumulated deferred income taxes, net

Notes payable—affiliated companies

363

Regulatory liabilities

Other

Total other liabilities

409

Long-Term Debt

3,101

2,671

Commitments and Contingencies (Note 12)

Partners’ Equity:

Common units

3,644

3,714

Subordinated units

3,732

3,805

Noncontrolling interest

Total Partners’ Equity

7,749

7,531

Total Liabilities and Partners’ Equity

11,200

11,226

Series A Preferred Units

Partners’ Equity:

Series A Preferred Units (14,520,000 issued and outstanding at June 30, 2016 and 0 issued and outstanding at December 31, 2015)

$ 362

$ 0

[1]	There were no commercial paper borrowings outstanding as of June 30, 2016. Short-term debt includes $236 million of commercial paper as of December 31, 2015.

Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) - shares	Jun. 30, 2016	Dec. 31, 2015
Common Units
Common and Subordinated units issued	214,462,878	214,541,422
Common units and Subordinated units outstanding	214,462,878	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

Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Cash Flows from Operating Activities:
Net income	$ 125	$ 168
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	164	149
Deferred income taxes	0	1
Loss on sale/retirement of assets	7	2
Equity in earnings of equity method affiliates, net of distributions	0	5
Equity based compensation	5	6
Amortization of debt costs and discount (premium)	(1)	(1)
Changes in other assets and liabilities:
Accounts receivable, net	20	(3)
Accounts receivable—affiliated companies	2	5
Inventory	9	10
Gas imbalance assets	4	6
Other current assets	(1)	2
Other assets	1	(6)
Accounts payable	(79)	(45)
Accounts payable—affiliated companies	(5)	(25)
Gas imbalance liabilities	(15)	3
Other current liabilities	48	13
Other liabilities	5	(6)
Net cash provided by operating activities	289	284
Cash Flows from Investing Activities:
Capital expenditures	(221)	(456)
Acquisitions, net of cash acquired	0	(80)
Investment in equity method affiliates	0	(7)
Return of investment in equity method affiliates	13	8
Net cash used in investing activities	(208)	(535)
Cash Flows from Financing Activities:
Proceeds from revolving credit facility	693	425
Repayment of revolving credit facility	(261)	(150)
Increase (decrease) in short-term debt	(236)	235
Repayment of notes payable—affiliated companies	(363)	0
Proceeds from issuance of Series A Preferred Units, net of issuance costs	362	0
Distributions	(274)	(263)
Net cash provided by (used in) financing activities	(79)	247
Net Increase (Decrease) in Cash and Cash Equivalents	2	(4)
Cash and Cash Equivalents at Beginning of Period	4	12
Cash and Cash Equivalents at End of Period	$ 6	$ 8

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	168			$ 88	$ 80
Issuance of common units upon interest acquisition of SESH	1			1
Distributions	(263)			(133)	(130)
Equity based compensation	6			6
Balance, end of period at Jun. 30, 2015	8,735	31	$ 0	$ 4,315	$ 4,389
Balance, end of period, units at Jun. 30, 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	125		$ 4	$ 62	$ 59
Issuance of Series A Preferred Units	362		$ 362
Issuance of Series A Preferred Units, units			15
Distributions	(274)	(1)	$ (4)	(137)	(132)
Equity based compensation	5			5
Balance, end of period at Jun. 30, 2016	$ 7,749	$ 11	$ 362	$ 3,644	$ 3,732
Balance, end of period, units at Jun. 30, 2016			15	214	208

Summary of Significant Accounting Policies	6 Months Ended
Summary of Significant Accounting Policies	Jun. 30, 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) is a large-scale, growth-oriented Delaware 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 June 30, 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 June 30, 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 $2 million allowance for doubtful accounts was recognized as of June 30, 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 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. Fourth Amended and Restated Agreement of Limited Partnership of Enable Midstream Partners, LP On June 22, 2016, the General Partner adopted the Fourth Amended and Restated Agreement of Limited Partnership (the Partnership Agreement), which changed the last permitted distribution date with respect to each fiscal quarter from 45 days following the close of such quarter to 60 days following the close of such quarter.

New Accounting Pronouncements	6 Months Ended
New Accounting Pronouncements	Jun. 30, 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 (Topic 606),” 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. 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. 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. 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. The Partnership is currently evaluating the impact, if any, the adoption of these revenue standards will have on our Condensed Consolidated Financial Statements and related disclosures. Leases In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842).” 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 impact 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 evaluating the impact, if any, the adoption of this standard will have on our Condensed Consolidated Financial Statements and related disclosures. Financial Instruments—Credit Losses In June 2016, the FASB issued ASU No. 2016-13, “Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments.” The amendment in this update requires entities to measure all expected credit losses of financial assets held at a reporting date based on historical experience, current conditions, and reasonable and supportable forecasts in order to record credit losses in a more timely matter. ASU 2016-13 also amends the accounting for credit losses on available-for-sale debt securities and purchased financial assets with credit deterioration. The standard is effective for interim and annual reporting periods beginning after December 15, 2019, although early adoption is permitted for interim and annual periods beginning after December 15, 2018. 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.

- Definition

The entire disclosure of changes in accounting principles, including adoption of new accounting pronouncements, that describes the new methods, amount and effects on financial statement line items.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Change in Accounting Principle
-URI http://asc.fasb.org/extlink&oid=6507316

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Direct Effects of a Change in Accounting Principle
-URI http://asc.fasb.org/extlink&oid=66092750

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 250
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=64853466&loc=d3e22583-107794

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Indirect Effects of a Change in Accounting Principle
-URI http://asc.fasb.org/extlink&oid=6515603

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 250
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=64853466&loc=d3e22580-107794

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-Publisher FASB
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-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.10-01.(b)(6))
-URI http://asc.fasb.org/extlink&oid=27015980&loc=d3e46468-122699

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Accounting Change
-URI http://asc.fasb.org/extlink&oid=6503790

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 250
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=64853466&loc=d3e22499-107794

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Retrospective Application
-URI http://asc.fasb.org/extlink&oid=6523989

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 270
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-Section 45
-Paragraph 13
-URI http://asc.fasb.org/extlink&oid=68064558&loc=d3e765-108305

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 270
-SubTopic 10
-Section 45
-Paragraph 12
-URI http://asc.fasb.org/extlink&oid=68064558&loc=d3e725-108305

+ Details

Earnings Per Limited Partner Unit

6 Months Ended

Jun. 30, 2016

Earnings Per Share [Abstract]

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 June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
	(In millions, except per unit data)
Net income	$	39	$	77	$	125	$	168
Net income attributable to noncontrolling interest	—		—		—		—
Series A Preferred Unit distribution	4		—		4		—
General partner interest in net income	—		—		—		—
Net income available to common and subordinated unitholders	$	35	$	77	$	121	$	168

Net income allocable to common units	$	18	$	39	$	61	$	85
Net income allocable to subordinated units	17		38		60		83
Net income available to common and subordinated unitholders	$	35	$	77	$	121	$	168

Net income allocable to common units	$	18	$	39	$	61	$	85
Dilutive effect of Series A Preferred Unit distribution	—		—		4		—
Dilutive effect of performance units	—		—		—		—
Diluted net income allocable to common units	18		39		65		85
Diluted net income allocable to subordinated units	17		38		60		83
Total	$	35	$	77	$	125	$	168

Basic weighted average number of outstanding
Common units	214		214		214		214
Subordinated units	208		208		208		208
Total	422		422		422		422

Basic earnings per unit
Common units	$	0.08	$	0.18	$	0.29	$	0.40
Subordinated units	$	0.08	$	0.18	$	0.29	$	0.40

Basic weighted average number of outstanding common units	214		214		214		214
Dilutive effect of Series A Preferred Units	—		—		20		—
Dilutive effect of performance units	1		—		—		—
Diluted weighted average number of outstanding common units	215		214		234		214
Diluted weighted average number of outstanding subordinated units	208		208		208		208
Total	423		422		442		422

Diluted earnings per unit
Common units	$	0.08	$	0.18	$	0.28	$	0.40
Subordinated units	$	0.08	$	0.18	$	0.29	$	0.40

Partners' Equity

6 Months Ended

Jun. 30, 2016

Equity [Abstract]

Partners' Equity

Partners’ Equity

The Partnership Agreement requires that, within 60 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
June 30, 2016⁽¹⁾	August 16, 2016	August 23, 2016	$	0.318	$	134
March 31, 2016	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 August 2, 2016, to be paid on August 23, 2016, to common and subordinated unitholders of record at the close of business on August 16, 2016.

The Partnership paid or has authorized payment of the following cash distributions to holders of the Series A Preferred Units during 2016 (in millions, except for per unit amounts):



Quarter Ended	Record Date	Payment Date	Per Unit Distribution		Total Cash Distribution
June 30, 2016⁽¹⁾	August 2, 2016	August 12, 2016	$	0.625	$	9
March 31, 2016 ⁽²⁾	May 6, 2016	May 13, 2016	$	0.2917	$	4

_____________________


(1)	The board of directors of Enable GP declared a $0.625 per Series A Preferred Unit cash distribution on August 2, 2016, to be paid on August 12, 2016, to Series A Preferred unitholders of record at the close of business on August 2, 2016.


(2)	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 the date on which the following tests are met: (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 of $25.00 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.

Assessing Impairment of Long-lived Assets (including Intangible Assets)	6 Months Ended
	Jun. 30, 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 and six months ended June 30, 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.

Investment in Equity Method Affiliates

6 Months Ended

Jun. 30, 2016

Equity Method Investments and Joint Ventures [Abstract]

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 June 30, 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. The Partnership billed SESH $5 million and $2 million during the three months ended June 30, 2016 and 2015, respectively, and $9 million and $4 million during the six months ended June 30, 2016 and 2015, respectively, associated with these service agreements.

Investment in Equity Method Affiliates:



	Six Months Ended June 30,
	2016			2015
	(In millions)
Balance as of December 31,	$	344		$	348
Interest acquisition of SESH	—			1
Equity in earnings of equity method affiliate	14			14
Contributions to equity method affiliate	—			7
Distributions from equity method affiliate⁽¹⁾	(27		)	(27		)
Balance as of June 30,	$	331		$	343

____________________


(1)	Distributions from equity method affiliates includes a $14 million and $19 million return on investment and a $13 million and $8 million return of investment for the six months ended June 30, 2016 and 2015, respectively.

Equity in Earnings of Equity Method Affiliates:



	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
	(In millions)
SESH	$	7	$	7	$	14	$	14

Distributions from Equity Method Affiliates:



	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
	(In millions)
SESH	$	7	$	15	$	27	$	27

Summarized financial information of SESH:



	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
	(In millions)
Income Statements:
Revenues	$	28	$	28	$	57	$	57
Operating income	18		18		37		36
Net income	14		14		28		28

Debt

6 Months Ended

Jun. 30, 2016

Debt Disclosure [Abstract]

Debt

The following table presents the Partnership’s outstanding debt as of June 30, 2016 and December 31, 2015.



	June 30, 2016		December 31, 2015
	(In millions)
Commercial Paper	$	—	$	236
2015 Term Loan Agreement	450		450
Revolving Credit Facility	742		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	20		23
Total debt	3,112		3,282
Less: Short-term debt⁽¹⁾	—		236
Less: Unamortized debt expense	11		12
Less: Notes payable—affiliated companies	—		363
Total long-term debt	$	3,101	$	2,671

___________________


(1)	There were no commercial paper borrowings outstanding as of June 30, 2016. Short-term debt includes $236 million of commercial paper as of December 31, 2015.

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 June 30, 2016, there was $742 million of principal 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 1.95% as of June 30, 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 June 30, 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 June 30, 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 zero and $236 million outstanding under our commercial paper program as of June 30, 2016 and December 31, 2015, respectively. 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.

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 the Partnership 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 June 30, 2016, there was $450 million outstanding under the 2015 Term Loan Agreement. As of June 30, 2016, the weighted average interest rate of the 2015 Term Loan Agreement was 1.83%.

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 of June 30, 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 June 30, 2016, the Partnership’s debt included EOIT’s $250 million 6.25% senior notes due March 2020 (the EOIT Senior Notes). The EOIT Senior Notes have a $21 million unamortized premium at June 30, 2016, resulting in an effective interest rate of 5.77%, during the six months ended June 30, 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 $16 million and $18 million as of June 30, 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, net of unamortized discount on long-term debt of $20 million and $23 million at June 30, 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 June 30, 2016, the Partnership and EOIT were in compliance with all of their debt agreements, including financial covenants.

Fair Value Measurements

6 Months Ended

Jun. 30, 2016

Fair Value Disclosures [Abstract]

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 June 30, 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 June 30, 2016 and December 31, 2015:



June 30, 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)	$	2		$	15		$	—	$	—
Significant other observable inputs (Level 2)	2			3			13		10
Unobservable inputs (Level 3)	1			6			—		—
Total fair value	5			24			13		10
Netting adjustments	(1		)	(1		)	—		—
Total	$	4		$	23		$	13	$	10



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 June 30, 2016 and December 31, 2015.


(2)	Gas imbalance assets exclude fuel reserves for under retained fuel due from shippers of $6 million and $6 million at June 30, 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 zero and $5 million at June 30, 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 table 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	(9		)
Settlements	(1		)
Balance as of June 30, 2016	$	(6	)

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.



	June 30, 2016
Product Group	Fair Value			Forward Curve Range
	(In millions)			(Per gallon)
Natural gas liquids	$	(5	)	$0.521 - $0.575

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 as of June 30, 2016 and December 31, 2015.



	June 30, 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⁾	742		742		310		310
2015 Term Loan Agreement (Level 2)	450		450		450		450
EOIT Senior Notes (Level 2)	271		273		273		280
Enable Midstream Partners, LP 2019, 2024 and 2044 Notes (Level 2)	1,649		1,431		1,650		1,255

___________________


(1)	Borrowing capacity is effectively reduced by our borrowings outstanding under the commercial paper program. There was zero and $236 million of commercial paper outstanding as of June 30, 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 June 30, 2016, no material fair value adjustments or fair value measurements were required for these non-financial assets or liabilities.

- Definition

The entire disclosure for the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments as well as disclosures related to the fair value of non-financial assets and liabilities. Such disclosures about the financial instruments, assets, and liabilities would include: (1) the fair value of the required items together with their carrying amounts (as appropriate); (2) for items for which it is not practicable to estimate fair value, disclosure would include: (a) information pertinent to estimating fair value (including, carrying amount, effective interest rate, and maturity, and (b) the reasons why it is not practicable to estimate fair value; (3) significant concentrations of credit risk including: (a) information about the activity, region, or economic characteristics identifying a concentration, (b) the maximum amount of loss the entity is exposed to based on the gross fair value of the related item, (c) policy for requiring collateral or other security and information as to accessing such collateral or security, and (d) the nature and brief description of such collateral or security; (4) quantitative information about market risks and how such risks are managed; (5) for items measured on both a recurring and nonrecurring basis information regarding the inputs used to develop the fair value measurement; and (6) for items presented in the financial statement for which fair value measurement is elected: (a) information necessary to understand the reasons for the election, (b) discussion of the effect of fair value changes on earnings, (c) a description of [similar groups] items for which the election is made and the relation thereof to the balance sheet, the aggregate carrying value of items included in the balance sheet that are not eligible for the election; (7) all other required (as defined) and desired information.

+ References + Details

Derivative Instruments and Hedging Activities

6 Months Ended

Jun. 30, 2016

Derivative Instruments and Hedging Activities Disclosure [Abstract]

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 natural gas exposure associated with its gathering, processing and 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 June 30, 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 June 30, 2016 and December 31, 2015, the Partnership had the following derivative instruments that were not designated as hedging instruments for accounting purposes:



	June 30, 2016		December 31, 2015
	Gross Notional Volume
	Purchases	Sales	Purchases	Sales
Natural gas—TBtu⁽¹⁾
Physical purchases/sales	1	37	2	51
Financial fixed futures/swaps	2	41	1	37
Financial basis futures/swaps	3	43	4	38
Crude oil (for condensate)—MBbl⁽²⁾
Financial Futures/swaps	—	550	—	506
Natural gas liquids—MBbl⁽³⁾
Financial Futures/swaps	—	1,656	75	1,011

____________________


(1)	As of June 30, 2016, 89.0% of the natural gas contracts had durations of one year or less and 11.0% 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 June 30, 2016, 80.9% of the condensate contracts had durations of one year or less and 19.1% 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 June 30, 2016, 82.8% of the natural gas liquids contracts had durations of one year or less and 17.2% 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 June 30, 2016 and December 31, 2015 that were not designated as hedging instruments for accounting purposes are as follows:



		June 30, 2016				December 31, 2015
		Fair Value
Instrument	Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
		(In millions)
Natural gas
Financial futures/swaps	Other Current	$	2	$	15	$	17	$	3
Physical purchases/sales	Other Current	1		1		1		—
Crude Oil (for condensate)
Financial futures/swaps	Other Current	2		2		9		—
Natural gas liquids
Financial Futures/swaps	Other Current	—		6		4		—
Total gross derivatives ⁽¹⁾		$	5	$	24	$	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 June 30, 2016 and December 31, 2015.

Income Statement Presentation Related to Derivative Instruments

The following table presents the effect of derivative instruments on the Partnership’s Condensed Consolidated Statements of Income for the three and six months ended June 30, 2016 and 2015.



	Amounts Recognized in Income
	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
	(In millions)
Natural gas financial futures/swaps gains (losses)	$	(21	)	$	(2	)	$	(11	)	$	5
Natural gas physical purchases/sales gains (losses)	(4		)	—			(8		)	(4		)
Crude Oil (for condensate) financial futures/swaps gains (losses)	(4		)	(7		)	(3		)	(3		)
Natural gas liquids financial futures/swaps gains (losses)	(5		)	6			(9		)	6
Total	$	(34	)	$	(3	)	$	(31	)	$	4

For derivatives not designated as hedges in the tables above, amounts recognized in income for the periods ended June 30, 2016 and 2015, if any, are reported in Product Sales.

The following table presents the components of gain (loss) on derivative activity in the Partnership’s Condensed Consolidated Statements of Income for the three and six months ended June 30, 2016 and 2015.



	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
	(In millions)
Change in fair value of derivatives	$	(39	)	$	(10	)	$	(47	)	$	(17	)
Realized gain on derivatives	5			7			16			21
Gain (loss) on derivative activity	$	(34	)	$	(3	)	$	(31	)	$	4

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 June 30, 2016, under these obligations, $1 million of cash collateral has been posted. However, based on positions as of June 30, 2016, approximately $4 million of additional collateral may be required to be posted by the Partnership.

- Definition

The entire disclosure for derivative instruments and hedging activities including, but not limited to, risk management strategies, non-hedging derivative instruments, assets, liabilities, revenue and expenses, and methodologies and assumptions used in determining the amounts.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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+ Details

Supplemental Disclosure of Cash Flow Information

6 Months Ended

Jun. 30, 2016

Supplemental Cash Flow Information [Abstract]

Supplemental Disclosure of Cash Flow Information

The following table provides information regarding supplemental cash flow information:



	Six Months Ended June 30,
	2016		2015
	(In millions)
Supplemental Disclosure of Cash Flow Information:
Cash Payments:
Interest, net of capitalized interest	$	51	$	44
Income taxes, net of refunds	1		2
Non-cash transactions:
Accounts payable related to capital expenditures	24		62
Issuance of common units upon interest acquisition of SESH (Note 6)	—		1

Related Party Transactions

6 Months Ended

Jun. 30, 2016

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 7% and 6% of revenues during the three months ended June 30, 2016 and 2015, respectively, and 8% and 7% of revenues during the six months ended June 30, 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 June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
	(In millions)
Gas transportation and storage service revenue — CenterPoint Energy	$	24	$	23	$	57	$	56
Natural gas product sales — CenterPoint Energy	—		1		1		7
Gas transportation and storage service revenue — OGE Energy	9		9		18		18
Natural gas product sales — OGE Energy	5		1		6		4
Total revenues — affiliated companies	$	38	$	34	$	82	$	85

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 June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
	(In millions)
Cost of natural gas purchases — CenterPoint Energy	$	—	$	—	$	—	$	1
Cost of natural gas purchases — OGE Energy	3		4		5		7
Total cost of natural gas purchases — affiliated companies	$	3	$	4	$	5	$	8

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 that ended 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 $5 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 June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
	(In millions)
Corporate Services — CenterPoint Energy	$	3	$	4	$	5	$	8
Seconded Employee Costs — OGE Energy	8		8		17		17
Corporate Services — OGE Energy	1		3		3		6
Total corporate services and seconded employees expense	$	12	$	15	$	25	$	31

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 zero and $2 million during the three months ended June 30, 2016 and 2015, respectively, and $1 million and $4 million during the six months ended June 30, 2016 and 2015, respectively.

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.

Commitments and Contingencies	6 Months Ended
Commitments and Contingencies	Jun. 30, 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.

Equity Based Compensation

6 Months Ended

Jun. 30, 2016

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

Equity Based Compensation

The following table summarizes the Partnership’s compensation expense for the three and six months ended June 30, 2016 and 2015 related to performance units, restricted units, and phantom units for the Partnership’s employees and independent directors:



	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
	(In millions)
Performance units	$	2	$	1	$	3	$	2
Restricted units	1		1		1		3
Phantom units	—		1		1		1
Total compensation expense	$	3	$	3	$	5	$	6

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 June 30, 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	1,208,443			7.88		—			—		621,537			8.12
Vested	(3,027		)	18.56		(78,707		)	22.55		(168		)	8.12
Forfeited	(50,658		)	15.39		(54,647		)	19.28		(3,858		)	8.12
Units Outstanding at June 30, 2016	1,969,268			$	12.42	448,418			$	20.99	627,328			$	8.19
Aggregate Intrinsic Value of Units Outstanding at June 30, 2016	$	27				$	6				$	8

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.



	June 30, 2016
	Unrecognized Compensation Cost (In millions)		Weighted Average to be Recognized (In years)
Performance Units	$	15	2.34
Restricted Units	4		1.53
Phantom Units	5		2.80
Total	$	24

As of June 30, 2016, there were 9,335,547 units available for issuance under the long term incentive plan.

Reportable Segments

6 Months Ended

Jun. 30, 2016

Segment Reporting [Abstract]

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 June 30, 2016	Gathering and Processing		Transportation and Storage⁽¹⁾		Eliminations			Total
	(In millions)
Revenues	$	387	$	225	$	(83	)	$	529
Cost of natural gas and natural gas liquids	231		106		(83		)	254
Operation and maintenance, General and administrative	67		53		—			120
Depreciation and amortization	52		31		—			83
Taxes other than income tax	8		7		—			15
Operating income	$	29	$	28	$	—		$	57
Total assets	$	7,494	$	4,926	$	(1,220	)	$	11,200
Capital expenditures	$	79	$	12	$	—		$	91


Three Months Ended June 30, 2015	Gathering and Processing		Transportation and Storage⁽¹⁾		Eliminations			Total
	(In millions)
Revenues	$	422	$	268	$	(100	)	$	590
Cost of natural gas and natural gas liquids	241		135		(99		)	277
Operation and maintenance, General and administrative	78		54		(1		)	131
Depreciation and amortization	45		31		—			76
Taxes other than income tax	7		6		—			13
Operating income	$	51	$	42	$	—		$	93
Total assets as of December 31, 2015	$	7,536	$	4,976	$	(1,286	)	$	11,226
Capital expenditures	$	275	$	22	$	—		$	297



Six Months Ended June 30, 2016	Gathering and Processing		Transportation and Storage⁽¹⁾		Eliminations			Total
	(In millions)
Revenues	$	720	$	471	$	(153	)	$	1,038
Cost of natural gas and natural gas liquids	396		205		(152		)	449
Operation and maintenance, General and administrative	142		94		(1		)	235
Depreciation and amortization	101		63		—			164
Impairments	—		—		—			—
Taxes other than income tax	16		14		—			30
Operating income	$	65	$	95	$	—		$	160
Total assets	$	7,494	$	4,926	$	(1,220	)	$	11,200
Capital expenditures	$	200	$	21	$	—		$	221


Six Months Ended June 30, 2015	Gathering and Processing		Transportation and Storage⁽¹⁾		Eliminations			Total
	(In millions)
Revenues	$	823	$	576	$	(193	)	$	1,206
Cost of natural gas and natural gas liquids	463		298		(192		)	569
Operation and maintenance, General and administrative	154		108		(1		)	261
Depreciation and amortization	88		61		—			149
Impairments	—		—		—			—
Taxes other than income tax	15		15		—			30
Operating income	$	103	$	94	$	—		$	197
Total assets as of December 31, 2015	$	7,536	$	4,976	$	(1,286	)	$	11,226
Capital expenditures	$	490	$	46	$	—		$	536

_____________________


(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 and six months ended June 30, 2016 and 2015.

- Definition

The entire disclosure for reporting segments including data and tables. Reportable segments include those that meet any of the following quantitative thresholds a) it's reported revenue, including sales to external customers and intersegment sales or transfers is 10 percent or more of the combined revenue, internal and external, of all operating segments b) the absolute amount of its reported profit or loss is 10 percent or more of the greater, in absolute amount of 1) the combined reported profit of all operating segments that did not report a loss or 2) the combined reported loss of all operating segments that did report a loss c) its assets are 10 percent or more of the combined assets of all operating segments.

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+ Details

Summary of Significant Accounting Policies (Policies)	6 Months Ended
Summary of Significant Accounting Policies (Policies)	Jun. 30, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization	Organization Enable Midstream Partners, LP (Partnership) is a large-scale, growth-oriented Delaware 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 June 30, 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 June 30, 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 (Topic 606),” 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. 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. 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. 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. The Partnership is currently evaluating the impact, if any, the adoption of these revenue standards will have on our Condensed Consolidated Financial Statements and related disclosures. Leases In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842).” 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 impact 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 evaluating the impact, if any, the adoption of this standard will have on our Condensed Consolidated Financial Statements and related disclosures. Financial Instruments—Credit Losses In June 2016, the FASB issued ASU No. 2016-13, “Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments.” The amendment in this update requires entities to measure all expected credit losses of financial assets held at a reporting date based on historical experience, current conditions, and reasonable and supportable forecasts in order to record credit losses in a more timely matter. ASU 2016-13 also amends the accounting for credit losses on available-for-sale debt securities and purchased financial assets with credit deterioration. The standard is effective for interim and annual reporting periods beginning after December 15, 2019, although early adoption is permitted for interim and annual periods beginning after December 15, 2018. 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.

- Definition

Disclosure of accounting policy for trade and other accounts receivables. This disclosure may include the basis at which such receivables are carried in the entity's statements of financial position (for example, net realizable value), how the entity determines the level of its allowance for doubtful accounts, when impairments, charge-offs or recoveries are recognized, and the entity's income recognition policies for such receivables, including its treatment of related fees and costs, its treatment of premiums, discounts or unearned income, when accrual of interest is discontinued, how the entity records payments received on nonaccrual receivables and its policy for resuming accrual of interest on such receivables. If the enterprise holds a large number of similar loans, disclosure may include the accounting policy for the anticipation of prepayments and significant assumptions underlying prepayment estimates for amortization of premiums, discounts, and nonrefundable fees and costs.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 310
-SubTopic 10
-Section 50
-Paragraph 11B
-Subparagraph (b)
-URI http://asc.fasb.org/extlink&oid=66008989&loc=SL6953423-111524

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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-Subparagraph (SX 210.9-03(9))
-URI http://asc.fasb.org/extlink&oid=6876686&loc=d3e534808-122878

Reference 3: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
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Reference 5: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 944
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-Section S99
-Paragraph 1
-Subparagraph (SX 210.7-03(a)(5))
-URI http://asc.fasb.org/extlink&oid=6879938&loc=d3e572229-122910

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02(4))
-URI http://asc.fasb.org/extlink&oid=6877327&loc=d3e13212-122682

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 310
-SubTopic 10
-Section 50
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-URI http://asc.fasb.org/extlink&oid=66008989&loc=d3e5212-111524

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 310
-SubTopic 10
-Section 50
-Paragraph 6
-URI http://asc.fasb.org/extlink&oid=66008989&loc=d3e5093-111524

+ Details

Earnings Per Limited Partner Unit (Tables)

6 Months Ended

Jun. 30, 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 June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
	(In millions, except per unit data)
Net income	$	39	$	77	$	125	$	168
Net income attributable to noncontrolling interest	—		—		—		—
Series A Preferred Unit distribution	4		—		4		—
General partner interest in net income	—		—		—		—
Net income available to common and subordinated unitholders	$	35	$	77	$	121	$	168

Net income allocable to common units	$	18	$	39	$	61	$	85
Net income allocable to subordinated units	17		38		60		83
Net income available to common and subordinated unitholders	$	35	$	77	$	121	$	168

Net income allocable to common units	$	18	$	39	$	61	$	85
Dilutive effect of Series A Preferred Unit distribution	—		—		4		—
Dilutive effect of performance units	—		—		—		—
Diluted net income allocable to common units	18		39		65		85
Diluted net income allocable to subordinated units	17		38		60		83
Total	$	35	$	77	$	125	$	168

Basic weighted average number of outstanding
Common units	214		214		214		214
Subordinated units	208		208		208		208
Total	422		422		422		422

Basic earnings per unit
Common units	$	0.08	$	0.18	$	0.29	$	0.40
Subordinated units	$	0.08	$	0.18	$	0.29	$	0.40

Basic weighted average number of outstanding common units	214		214		214		214
Dilutive effect of Series A Preferred Units	—		—		20		—
Dilutive effect of performance units	1		—		—		—
Diluted weighted average number of outstanding common units	215		214		234		214
Diluted weighted average number of outstanding subordinated units	208		208		208		208
Total	423		422		442		422

Diluted earnings per unit
Common units	$	0.08	$	0.18	$	0.28	$	0.40
Subordinated units	$	0.08	$	0.18	$	0.29	$	0.40

Partners' Equity (Tables)

6 Months Ended

Jun. 30, 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
June 30, 2016⁽¹⁾	August 16, 2016	August 23, 2016	$	0.318	$	134
March 31, 2016	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 August 2, 2016, to be paid on August 23, 2016, to common and subordinated unitholders of record at the close of business on August 16, 2016.

Schedule of Cash Distributions to Series A Preferred Unitholders

The Partnership paid or has authorized payment of the following cash distributions to holders of the Series A Preferred Units during 2016 (in millions, except for per unit amounts):



Quarter Ended	Record Date	Payment Date	Per Unit Distribution		Total Cash Distribution
June 30, 2016⁽¹⁾	August 2, 2016	August 12, 2016	$	0.625	$	9
March 31, 2016 ⁽²⁾	May 6, 2016	May 13, 2016	$	0.2917	$	4

_____________________


(1)	The board of directors of Enable GP declared a $0.625 per Series A Preferred Unit cash distribution on August 2, 2016, to be paid on August 12, 2016, to Series A Preferred unitholders of record at the close of business on August 2, 2016.


(2)	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.

Investment in Unconsolidated Affiliates (Tables)

6 Months Ended

Jun. 30, 2016

Equity Method Investments and Joint Ventures [Abstract]

Schedule of Investments Detail

Investment in Equity Method Affiliates:



	Six Months Ended June 30,
	2016			2015
	(In millions)
Balance as of December 31,	$	344		$	348
Interest acquisition of SESH	—			1
Equity in earnings of equity method affiliate	14			14
Contributions to equity method affiliate	—			7
Distributions from equity method affiliate⁽¹⁾	(27		)	(27		)
Balance as of June 30,	$	331		$	343

____________________


(1)	Distributions from equity method affiliates includes a $14 million and $19 million return on investment and a $13 million and $8 million return of investment for the six months ended June 30, 2016 and 2015, respectively.

Equity in Earnings of Equity Method Affiliates:



	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
	(In millions)
SESH	$	7	$	7	$	14	$	14

Distributions from Equity Method Affiliates:



	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
	(In millions)
SESH	$	7	$	15	$	27	$	27

Summarized financial information of SESH:



	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
	(In millions)
Income Statements:
Revenues	$	28	$	28	$	57	$	57
Operating income	18		18		37		36
Net income	14		14		28		28

Debt (Tables)

6 Months Ended

Jun. 30, 2016

Debt Disclosure [Abstract]

Schedule of Debt

The following table presents the Partnership’s outstanding debt as of June 30, 2016 and December 31, 2015.



	June 30, 2016		December 31, 2015
	(In millions)
Commercial Paper	$	—	$	236
2015 Term Loan Agreement	450		450
Revolving Credit Facility	742		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	20		23
Total debt	3,112		3,282
Less: Short-term debt⁽¹⁾	—		236
Less: Unamortized debt expense	11		12
Less: Notes payable—affiliated companies	—		363
Total long-term debt	$	3,101	$	2,671

___________________


(1)	There were no commercial paper borrowings outstanding as of June 30, 2016. Short-term debt includes $236 million of commercial paper as of December 31, 2015.

Fair Value Measurements (Tables)

6 Months Ended

Jun. 30, 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 June 30, 2016 and December 31, 2015:



June 30, 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)	$	2		$	15		$	—	$	—
Significant other observable inputs (Level 2)	2			3			13		10
Unobservable inputs (Level 3)	1			6			—		—
Total fair value	5			24			13		10
Netting adjustments	(1		)	(1		)	—		—
Total	$	4		$	23		$	13	$	10



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)


(2)	Gas imbalance assets exclude fuel reserves for under retained fuel due from shippers of $6 million and $6 million at June 30, 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 zero and $5 million at June 30, 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 table 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	(9		)
Settlements	(1		)
Balance as of June 30, 2016	$	(6	)

Fair Value Inputs, Quantitative Information



	June 30, 2016
Product Group	Fair Value			Forward Curve Range
	(In millions)			(Per gallon)
Natural gas liquids	$	(5	)	$0.521 - $0.575

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 as of June 30, 2016 and December 31, 2015.



	June 30, 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⁾	742		742		310		310
2015 Term Loan Agreement (Level 2)	450		450		450		450
EOIT Senior Notes (Level 2)	271		273		273		280
Enable Midstream Partners, LP 2019, 2024 and 2044 Notes (Level 2)	1,649		1,431		1,650		1,255

___________________


(1)	Borrowing capacity is effectively reduced by our borrowings outstanding under the commercial paper program. There was zero and $236 million of commercial paper outstanding as of June 30, 2016 and December 31, 2015, respectively.

Derivative Instruments and Hedging Activities (Tables)

6 Months Ended

Jun. 30, 2016

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Derivative Instruments

As of June 30, 2016 and December 31, 2015, the Partnership had the following derivative instruments that were not designated as hedging instruments for accounting purposes:



	June 30, 2016		December 31, 2015
	Gross Notional Volume
	Purchases	Sales	Purchases	Sales
Natural gas—TBtu⁽¹⁾
Physical purchases/sales	1	37	2	51
Financial fixed futures/swaps	2	41	1	37
Financial basis futures/swaps	3	43	4	38
Crude oil (for condensate)—MBbl⁽²⁾
Financial Futures/swaps	—	550	—	506
Natural gas liquids—MBbl⁽³⁾
Financial Futures/swaps	—	1,656	75	1,011

____________________


(1)	As of June 30, 2016, 89.0% of the natural gas contracts had durations of one year or less and 11.0% 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 June 30, 2016, 80.9% of the condensate contracts had durations of one year or less and 19.1% 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 June 30, 2016, 82.8% of the natural gas liquids contracts had durations of one year or less and 17.2% 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



		June 30, 2016				December 31, 2015
		Fair Value
Instrument	Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
		(In millions)
Natural gas
Financial futures/swaps	Other Current	$	2	$	15	$	17	$	3
Physical purchases/sales	Other Current	1		1		1		—
Crude Oil (for condensate)
Financial futures/swaps	Other Current	2		2		9		—
Natural gas liquids
Financial Futures/swaps	Other Current	—		6		4		—
Total gross derivatives ⁽¹⁾		$	5	$	24	$	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 June 30, 2016 and December 31, 2015.

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

The following table presents the effect of derivative instruments on the Partnership’s Condensed Consolidated Statements of Income for the three and six months ended June 30, 2016 and 2015.



	Amounts Recognized in Income
	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
	(In millions)
Natural gas financial futures/swaps gains (losses)	$	(21	)	$	(2	)	$	(11	)	$	5
Natural gas physical purchases/sales gains (losses)	(4		)	—			(8		)	(4		)
Crude Oil (for condensate) financial futures/swaps gains (losses)	(4		)	(7		)	(3		)	(3		)
Natural gas liquids financial futures/swaps gains (losses)	(5		)	6			(9		)	6
Total	$	(34	)	$	(3	)	$	(31	)	$	4

Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location



	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
	(In millions)
Change in fair value of derivatives	$	(39	)	$	(10	)	$	(47	)	$	(17	)
Realized gain on derivatives	5			7			16			21
Gain (loss) on derivative activity	$	(34	)	$	(3	)	$	(31	)	$	4

- Definition

Tabular disclosure of pertinent information about a derivative or group of derivatives on a disaggregated basis, such as for individual instruments, or small groups of similar instruments. May include a combination of the type of instrument, risks being hedged, notional amount, hedge designation, related hedged item, inception date, maturity date, or other relevant item.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=64837297&loc=d3e41641-113959

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4B
-URI http://asc.fasb.org/extlink&oid=64837297&loc=SL5624163-113959

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=64837297&loc=d3e41678-113959

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=64837297&loc=d3e41638-113959

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1B
-URI http://asc.fasb.org/extlink&oid=64837297&loc=SL5580258-113959

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1A
-URI http://asc.fasb.org/extlink&oid=64837297&loc=SL5579245-113959

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4C
-URI http://asc.fasb.org/extlink&oid=64837297&loc=SL5624171-113959

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=64837297&loc=SL5579240-113959

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=64837297&loc=d3e41620-113959

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(n)(2))
-URI http://asc.fasb.org/extlink&oid=26873400&loc=d3e23780-122690

+ Details

Supplemental Disclosure of Cash Flow Information (Tables)

6 Months Ended

Jun. 30, 2016

Supplemental Cash Flow Information [Abstract]

Schedule of Cash Flow, Supplemental Disclosures

The following table provides information regarding supplemental cash flow information:



	Six Months Ended June 30,
	2016		2015
	(In millions)
Supplemental Disclosure of Cash Flow Information:
Cash Payments:
Interest, net of capitalized interest	$	51	$	44
Income taxes, net of refunds	1		2
Non-cash transactions:
Accounts payable related to capital expenditures	24		62
Issuance of common units upon interest acquisition of SESH (Note 6)	—		1

Related Party Transactions (Tables)

6 Months Ended

Jun. 30, 2016

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 June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
	(In millions)
Gas transportation and storage service revenue — CenterPoint Energy	$	24	$	23	$	57	$	56
Natural gas product sales — CenterPoint Energy	—		1		1		7
Gas transportation and storage service revenue — OGE Energy	9		9		18		18
Natural gas product sales — OGE Energy	5		1		6		4
Total revenues — affiliated companies	$	38	$	34	$	82	$	85

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 June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
	(In millions)
Cost of natural gas purchases — CenterPoint Energy	$	—	$	—	$	—	$	1
Cost of natural gas purchases — OGE Energy	3		4		5		7
Total cost of natural gas purchases — affiliated companies	$	3	$	4	$	5	$	8

Schedule of Amounts Charged to Partnership by Related Parties



	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
	(In millions)
Corporate Services — CenterPoint Energy	$	3	$	4	$	5	$	8
Seconded Employee Costs — OGE Energy	8		8		17		17
Corporate Services — OGE Energy	1		3		3		6
Total corporate services and seconded employees expense	$	12	$	15	$	25	$	31

Equity Based Compensation (Tables)

6 Months Ended

Jun. 30, 2016

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

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



	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
	(In millions)
Performance units	$	2	$	1	$	3	$	2
Restricted units	1		1		1		3
Phantom units	—		1		1		1
Total compensation expense	$	3	$	3	$	5	$	6

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 June 30, 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	1,208,443			7.88		—			—		621,537			8.12
Vested	(3,027		)	18.56		(78,707		)	22.55		(168		)	8.12
Forfeited	(50,658		)	15.39		(54,647		)	19.28		(3,858		)	8.12
Units Outstanding at June 30, 2016	1,969,268			$	12.42	448,418			$	20.99	627,328			$	8.19
Aggregate Intrinsic Value of Units Outstanding at June 30, 2016	$	27				$	6				$	8

Schedule of Unrecognized Compensation Cost, Nonvested Awards



	June 30, 2016
	Unrecognized Compensation Cost (In millions)		Weighted Average to be Recognized (In years)
Performance Units	$	15	2.34
Restricted Units	4		1.53
Phantom Units	5		2.80
Total	$	24

Reportable Segments (Tables)

6 Months Ended

Jun. 30, 2016

Segment Reporting [Abstract]

Schedule of Financial Data for Business Segments and Services

Financial data for reportable segments are as follows:



Three Months Ended June 30, 2016	Gathering and Processing		Transportation and Storage⁽¹⁾		Eliminations			Total
	(In millions)
Revenues	$	387	$	225	$	(83	)	$	529
Cost of natural gas and natural gas liquids	231		106		(83		)	254
Operation and maintenance, General and administrative	67		53		—			120
Depreciation and amortization	52		31		—			83
Taxes other than income tax	8		7		—			15
Operating income	$	29	$	28	$	—		$	57
Total assets	$	7,494	$	4,926	$	(1,220	)	$	11,200
Capital expenditures	$	79	$	12	$	—		$	91


Three Months Ended June 30, 2015	Gathering and Processing		Transportation and Storage⁽¹⁾		Eliminations			Total
	(In millions)
Revenues	$	422	$	268	$	(100	)	$	590
Cost of natural gas and natural gas liquids	241		135		(99		)	277
Operation and maintenance, General and administrative	78		54		(1		)	131
Depreciation and amortization	45		31		—			76
Taxes other than income tax	7		6		—			13
Operating income	$	51	$	42	$	—		$	93
Total assets as of December 31, 2015	$	7,536	$	4,976	$	(1,286	)	$	11,226
Capital expenditures	$	275	$	22	$	—		$	297



Six Months Ended June 30, 2016	Gathering and Processing		Transportation and Storage⁽¹⁾		Eliminations			Total
	(In millions)
Revenues	$	720	$	471	$	(153	)	$	1,038
Cost of natural gas and natural gas liquids	396		205		(152		)	449
Operation and maintenance, General and administrative	142		94		(1		)	235
Depreciation and amortization	101		63		—			164
Impairments	—		—		—			—
Taxes other than income tax	16		14		—			30
Operating income	$	65	$	95	$	—		$	160
Total assets	$	7,494	$	4,926	$	(1,220	)	$	11,200
Capital expenditures	$	200	$	21	$	—		$	221


Six Months Ended June 30, 2015	Gathering and Processing		Transportation and Storage⁽¹⁾		Eliminations			Total
	(In millions)
Revenues	$	823	$	576	$	(193	)	$	1,206
Cost of natural gas and natural gas liquids	463		298		(192		)	569
Operation and maintenance, General and administrative	154		108		(1		)	261
Depreciation and amortization	88		61		—			149
Impairments	—		—		—			—
Taxes other than income tax	15		15		—			30
Operating income	$	103	$	94	$	—		$	197
Total assets as of December 31, 2015	$	7,536	$	4,976	$	(1,286	)	$	11,226
Capital expenditures	$	490	$	46	$	—		$	536

_____________________


(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 and six months ended June 30, 2016 and 2015.

Summary of Significant Accounting Policies - Narrative (Details)					6 Months Ended
	Jun. 22, 2016	Jun. 21, 2016	Feb. 18, 2016 shares	Jun. 12, 2015	Jun. 30, 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 \| $					$ 2,000,000		$ 0
Limited partners' capital account, required quarterly distribution period	60 days	45 days			60 days
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				0.10%
Limited partner units that may be issued					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

Earnings Per Limited Partner Unit (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net income	$ 39	$ 77	$ 125	$ 168
Net income attributable to noncontrolling interest	0	0	0	0
Series A Preferred Unit distribution	4	0	4	0
General partner interest in net income	0	0	0	0
Net Income attributable to common and subordinated units (Note 3)	35	77	121	168
Dilutive effect of Series A Preferred Unit distribution	0	0	4	0
Dilutive effect of performance units	0	0	0	0
Diluted net income	$ 35	$ 77	$ 125	$ 168
Basic weighted average number of outstanding
Basic weighted average number of outstanding	422	422	422	422
Basic earnings per unit
Dilutive effect of Series A Preferred Units	0	0	20	0
Dilutive effect of performance units	1	0	0	0
Diluted weighted average number of outstanding units	423	422	442	422
Common Units
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net Income attributable to common and subordinated units (Note 3)	$ 18	$ 39	$ 61	$ 85
Diluted net income	$ 18	$ 39	$ 65	$ 85
Basic weighted average number of outstanding
Basic weighted average number of outstanding	214	214	214	214
Basic earnings per unit
Basic earnings per unit	$ 0.08	$ 0.18	$ 0.29	$ 0.40
Diluted weighted average number of outstanding units	215	214	234	214
Diluted earnings per unit	$ 0.08	$ 0.18	$ 0.28	$ 0.40
Subordinated Units
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net Income attributable to common and subordinated units (Note 3)	$ 17	$ 38	$ 60	$ 83
Diluted net income	$ 17	$ 38	$ 60	$ 83
Basic weighted average number of outstanding
Basic weighted average number of outstanding	208	208	208	208
Basic earnings per unit
Basic earnings per unit	$ 0.08	$ 0.18	$ 0.29	$ 0.40
Diluted weighted average number of outstanding units	208	208	208	208
Diluted earnings per unit	$ 0.08	$ 0.18	$ 0.29	$ 0.40

Partners' Equity -Schedule of Cash Distributions (Details) - USD ($)
$ / shares in Units, $ in Millions

Aug. 23, 2016

Aug. 16, 2016

Aug. 12, 2016

Aug. 02, 2016

May 13, 2016

May 06, 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

May 06, 2016

Feb. 02, 2016

Nov. 03, 2015

Aug. 03, 2015

May 05, 2015

Payment Date

May 13, 2016

Feb. 12, 2016

Nov. 13, 2015

Aug. 13, 2015

May 15, 2015

Series A 10% Fixed to Floating Non Cumulative Redeemable Perpetual Preferred Units | Preferred Units

Distribution Made to Limited Partner [Line Items]

Record Date

^[1]

May 06, 2016

Payment Date

^[1]

May 13, 2016

Cash Distribution

Distribution Made to Limited Partner [Line Items]

Per unit distribution, paid (per common unit)

$ 0.318

$ 0.316

$ 0.3125

Distribution made to unitholders

$ 134

$ 132

Cash Distribution | Series A 10% Fixed to Floating Non Cumulative Redeemable Perpetual Preferred Units | Preferred Units

Distribution Made to Limited Partner [Line Items]

Per unit distribution, paid (per common unit)

^[1]

$ 0.2917

Distribution made to unitholders

^[1]

$ 4

Full quarter equivalent distribution declared per unit

$ 0.625

Annualized distribution declared per unit

$ 2.50

Subsequent Event | Cash Distribution

Distribution Made to Limited Partner [Line Items]

Per common unit cash distribution declared

$ 0.318

Subsequent Event | Cash Distribution | Series A 10% Fixed to Floating Non Cumulative Redeemable Perpetual Preferred Units | Preferred Units

Distribution Made to Limited Partner [Line Items]

Per common unit cash distribution declared

$ 0.625000000

Subsequent Event | Scenario, Forecast

Distribution Made to Limited Partner [Line Items]

Record Date

^[2]

Aug. 16, 2016

Aug. 02, 2016

Payment Date

^[2]

Aug. 23, 2016

Subsequent Event | Scenario, Forecast | Series A 10% Fixed to Floating Non Cumulative Redeemable Perpetual Preferred Units | Preferred Units

Distribution Made to Limited Partner [Line Items]

Record Date

^[3]

Aug. 02, 2016

Payment Date

^[3]

Aug. 12, 2016

Subsequent Event | Scenario, Forecast | Cash Distribution

Distribution Made to Limited Partner [Line Items]

Per unit distribution, paid (per common unit)

^[2]

$ 0.318

Distribution made to unitholders

^[2]

$ 134

Subsequent Event | Scenario, Forecast | Cash Distribution | Series A 10% Fixed to Floating Non Cumulative Redeemable Perpetual Preferred Units | Preferred Units

Distribution Made to Limited Partner [Line Items]

Per unit distribution, paid (per common unit)

^[3]

$ 0.625

Distribution made to unitholders

^[3]

$ 9

[1]	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.
[2]	The board of directors of Enable GP declared this $0.318 per common unit cash distribution on August 2, 2016, to be paid on August 23, 2016, to common and subordinated unitholders of record at the close of business on August 16, 2016.
[3]	The board of directors of Enable GP declared a $0.625 per Series A Preferred Unit cash distribution on August 2, 2016, to be paid on August 12, 2016, to Series A Preferred unitholders of record at the close of business on August 2, 2016.

Partners' Equity Textual (Details) - USD ($) $ / shares in Units, $ in Millions				6 Months Ended
	Jun. 22, 2016	Jun. 21, 2016	Feb. 18, 2016	Jun. 30, 2016	Jun. 30, 2015
Distribution Made to Limited Partner [Line Items]
Limited partners' capital account, required quarterly distribution period	60 days	45 days		60 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
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%
Liquidation preference per unit			$ 25.00
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
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%

Investment in Equity Method Affiliates - Narrative (Details) - SESH - USD ($) $ in Millions		3 Months Ended		6 Months Ended
	Jun. 12, 2015	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Jun. 29, 2015
Fair value of limited partner interests		$ 1		$ 1
Ownership percentage		50.00%		50.00%
Percentage of distributions through limited partner interest				50.00%
Shared Operations Service Agreements \| Equity Method Investee
Amount billed associated with service agreements		$ 5	$ 2	$ 9	$ 4
Put Option
Limited partner ownership interest						49.90%
SESH \| Put Option
Limited partner ownership interest	0.10%
Limited partner units that may be issued		25,341		25,341

Investment in Equity Method Affiliates - Schedule of Investments (Details) - USD ($)
$ in Millions

3 Months Ended

6 Months Ended

Jun. 30, 2016

Jun. 30, 2015

Jun. 30, 2016

Jun. 30, 2015

Investments in and Advances to Affiliates, at Fair Value [Roll Forward]

Balance as of December 31,

$ 344

June 30,

$ 331

331

Return of investment in equity method affiliates

$ 8

Equity in Earnings of Equity Method Affiliates:

Equity in earnings of equity method affiliates

$ 7

SESH

Investments in and Advances to Affiliates, at Fair Value [Roll Forward]

Distributions from equity method affiliate

(7)

(15)

(27)

Return on investment in equity method affiliates

Return of investment in equity method affiliates

Distributions from Equity Method Affiliates:

Distributions from equity method affiliate

Operating revenues

Operating income

Net income

SESH | Other Income (Expense)

Equity in Earnings of Equity Method Affiliates:

Equity in earnings of equity method affiliates

SESH | Investments in Equity Method Affiliates

Investments in and Advances to Affiliates, at Fair Value [Roll Forward]

Balance as of December 31,

344

348

Interest acquisition of SESH

Capital contributions from partners

Distributions from equity method affiliate

^[1]

(27)

June 30,

$ 331

$ 343

331

343

Equity in Earnings of Equity Method Affiliates:

Equity in earnings of equity method affiliates

Distributions from Equity Method Affiliates:

Distributions from equity method affiliate

^[1]

$ 27

[1]	Distributions from equity method affiliates includes a $14 million and $19 million return on investment and a $13 million and $8 million return of investment for the six months ended June 30, 2016 and 2015, respectively.

- Narrative (Details)

6 Months Ended

Jul. 31, 2015

USD ($)

time

Jun. 30, 2016

USD ($)

Dec. 31, 2015

USD ($)

Debt Instrument [Line Items]

Total debt

$ 3,112,000,000

$ 3,282,000,000

Notes payable — affiliated companies (Note 11)

363,000,000

Premium (Discount) on long-term debt

20,000,000

23,000,000

Short-term debt

^[1]

236,000,000

Less: Unamortized debt expense

11,000,000

12,000,000

Total long-term debt

3,101,000,000

2,671,000,000

Commercial paper, authorized

1,400,000,000

Other Assets

Debt Instrument [Line Items]

Unamortized debt expense

16,000,000

18,000,000

2015 Term Loan Agreement

Debt Instrument [Line Items]

Total debt

450,000,000

Revolving Credit Facility

Debt Instrument [Line Items]

Total debt

742,000,000

310,000,000

Maximum borrowing capacity

1,750,000,000

Letters of credit principal advances

742,000,000

Letters of credit outstanding amount

$ 3,000,000

weighted average interest rate

1.95%

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

1.83%

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

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

$ 20,000,000

23,000,000

Senior Notes | 2019 Notes

Debt Instrument [Line Items]

Total debt

500,000,000

Senior Notes | 2024 Notes

Debt Instrument [Line Items]

Total debt

600,000,000

Senior Notes | 2044 Notes

Debt Instrument [Line Items]

Total debt

550,000,000

Senior Notes | EOIT Senior Notes

Debt Instrument [Line Items]

Total debt

250,000,000

$ 250,000,000

Premium (Discount) on long-term debt

$ 21,000,000

Fixed interest rate

6.25%

Effective interest rate

5.77%

[1]	There were no commercial paper borrowings outstanding as of June 30, 2016. Short-term debt includes $236 million of commercial paper as of December 31, 2015.

Fair Value Measurements - Fair Value Hierarchy (Details) - USD ($)
$ in Millions

Jun. 30, 2016

Dec. 31, 2015

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Retained fuel due from shippers

$ 6

Over retained fuel due from shippers

Commodity Contracts | Recurring Measurement

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Assets, total fair value

Liabilities, total fair value

Assets

(1)

(3)

Liabilities

(1)

(3)

Assets

Liabilities

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

Liabilities

Commodity Contracts | Recurring Measurement | Significant other observable inputs (Level 2)

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Assets

Liabilities

Commodity Contracts | Recurring Measurement | Unobservable inputs (Level 3)

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Assets

Liabilities

Gas Imbalances | Recurring Measurement

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Assets, total fair value

^[1],[2]

Liabilities, total fair value

^[2],[3]

^[1],[2]

^[2],[3]

^[1],[2]

^[2],[3]

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]

Liabilities

^[2],[3]

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]

Liabilities

^[2],[3]

Gas Imbalances | Recurring Measurement | Unobservable inputs (Level 3)

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Assets

^[1],[2]

Liabilities

^[2],[3]

$ 0

[1]	Gas imbalance assets exclude fuel reserves for under retained fuel due from shippers of $6 million and $6 million at June 30, 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 June 30, 2016 and December 31, 2015.
[3]	Gas imbalance liabilities exclude fuel reserves for over retained fuel due to shippers of zero and $5 million at June 30, 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 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	6 Months Ended
	Jun. 30, 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	(9)
Settlements	(1)
Balance as of June 30, 2016	$ (6)

Fair Value Measurements - Schedule of Quantitative Information of Level 3 Inputs (Details) - Commodity Contracts - Natural gas liquids - Market Approach Valuation Technique - Unobservable inputs (Level 3) $ in Millions	6 Months Ended
	Jun. 30, 2016 USD ($) $ / gal
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Fair Value \| $	$ (5)
Minimum
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Forward Curve Range	0.521
Maximum
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Forward Curve Range	0.575

Fair Value Measurements - Carrying and Fair Value Amounts (Details) - USD ($)
$ in Millions

Jun. 30, 2016

Dec. 31, 2015

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Carrying Amount

$ 3,112

$ 3,282

Carrying value

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

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]

742

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

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

271

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

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]

742

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

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

273

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

$ 1,431

$ 1,255

[1]	Borrowing capacity is effectively reduced by our borrowings outstanding under the commercial paper program. There was zero and $236 million of commercial paper outstanding as of June 30, 2016 and December 31, 2015, respectively.

Derivative Instruments and Hedging Activities (Details) - Not Designated as Hedging Instrument
bbl in Thousands, MMBTU in Millions

6 Months Ended

Jun. 30, 2016

MMBTU

bbl

Jun. 30, 2015

MMBTU

bbl

Dec. 31, 2015

Natural gas

Derivative [Line Items]

Percent of contract with durations of one year or less

89.00%

97.70%

Percent of contracts with durations of more than one year and less than two years

11.00%

2.30%

Natural gas | Physical | Purchases

Derivative [Line Items]

Derivative, gross notional volume (TBtu)

^[1]

Natural gas | Physical | Sales

Derivative [Line Items]

Derivative, gross notional volume (TBtu)

^[1]

Natural gas | Financial fixed futures/swaps | Purchases

Derivative [Line Items]

Derivative, gross notional volume (TBtu)

^[1]

Natural gas | Financial fixed futures/swaps | Sales

Derivative [Line Items]

Derivative, gross notional volume (TBtu)

^[1]

Natural gas | Financial basis futures/swaps | Purchases

Derivative [Line Items]

Derivative, gross notional volume (TBtu)

^[1]

Natural gas | Financial basis futures/swaps | Sales

Derivative [Line Items]

Derivative, gross notional volume (TBtu)

^[1]

Condensate

Derivative [Line Items]

Percent of contract with durations of one year or less

80.90%

100.00%

Percent of contracts with durations of more than one year and less than two years

19.10%

Condensate | Financial Futures/swaps | Purchases

Derivative [Line Items]

Derivative, gross notional volume (MMbl) | bbl

^[2]

Condensate | Financial Futures/swaps | Sales

Derivative [Line Items]

Derivative, gross notional volume (MMbl) | bbl

^[2]

550

506

Natural gas liquids

Derivative [Line Items]

Percent of contract with durations of one year or less

82.80%

100.00%

Percent of contracts with durations of more than one year and less than two years

17.20%

Natural gas liquids | Financial Futures/swaps | Purchases

Derivative [Line Items]

Derivative, gross notional volume (MMbl) | bbl

^[3]

Natural gas liquids | Financial Futures/swaps | Sales

Derivative [Line Items]

Derivative, gross notional volume (MMbl) | bbl

^[3]

1,656

1,011

[1]	As of June 30, 2016, 89.0% of the natural gas contracts had durations of one year or less and 11.0% 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 June 30, 2016, 80.9% of the condensate contracts had durations of one year or less and 19.1% 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 June 30, 2016, 82.8% of the natural gas liquids contracts had durations of one year or less and 17.2% 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.

Derivative Instruments and Hedging Activities - Balance Sheet Location (Details) - USD ($)

Jun. 30, 2016

Dec. 31, 2015

Designated as Hedging Instrument

Derivatives, Fair Value [Line Items]

Derivative instruments designated as cash flow hedges or fair value hedges

$ 0

Not Designated as Hedging Instrument

Derivatives, Fair Value [Line Items]

Assets

^[1]

5,000,000

31,000,000

Liabilities

^[1]

24,000,000

3,000,000

Natural gas | Financial futures/swaps | Not Designated as Hedging Instrument | Other Current, Assets

Derivatives, Fair Value [Line Items]

Assets

2,000,000

17,000,000

Natural gas | Financial futures/swaps | Not Designated as Hedging Instrument | Other Current Liabilities

Derivatives, Fair Value [Line Items]

Liabilities

15,000,000

3,000,000

Natural gas | Physical purchases/sales | Not Designated as Hedging Instrument | Other Current, Assets

Derivatives, Fair Value [Line Items]

Assets

1,000,000

Natural gas | Physical purchases/sales | Not Designated as Hedging Instrument | Other Current Liabilities

Derivatives, Fair Value [Line Items]

Liabilities

1,000,000

Crude Oil (for condensate) | Financial futures/swaps | Not Designated as Hedging Instrument | Other Current, Assets

Derivatives, Fair Value [Line Items]

Assets

2,000,000

9,000,000

Crude Oil (for condensate) | Financial futures/swaps | Not Designated as Hedging Instrument | Other Current Liabilities

Derivatives, Fair Value [Line Items]

Liabilities

2,000,000

Natural gas liquids | Financial futures/swaps | Not Designated as Hedging Instrument | Other Current, Assets

Derivatives, Fair Value [Line Items]

Assets

4,000,000

Natural gas liquids | Financial futures/swaps | Not Designated as Hedging Instrument | Other Current Liabilities

Derivatives, Fair Value [Line Items]

Liabilities

$ 6,000,000

$ 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 June 30, 2016 and December 31, 2015.

Derivative Instruments and Hedging Activities - Amounts Recognized in Income (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivative, net	$ (34)	$ (3)	$ (31)	$ 4
Change in fair value of derivatives	(39)	(10)	(47)	(17)
Realized gain on derivatives	5	7	16	21
Gain (loss) on derivative activity	(34)	(3)	(31)	4
Cash collateral posted	1		1
Cash collateral required if ratings are lowered	4		4
Natural gas \| Financial futures/swaps
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivative, net	(21)	(2)	(11)	5
Natural gas \| Physical purchases/sales
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivative, net	(4)	0	(8)	(4)
Condensate \| Financial futures/swaps
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivative, net	(4)	(7)	(3)	(3)
Natural gas liquids \| Financial futures/swaps
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivative, net	$ (5)	$ 6	$ (9)	$ 6

Supplemental Disclosure of Cash Flow Information - (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Supplemental Cash Flow Information [Abstract]
Interest, net of capitalized interest	$ 51	$ 44
Income taxes, net of refunds	1	2
Accounts payable related to capital expenditures	24	62
Issuance of common units upon interest acquisition of SESH (Note 6)	$ 0	$ 1

Related Party Transactions (Details) - USD ($) $ / shares in Units, $ in Millions		3 Months Ended		6 Months Ended
	Feb. 18, 2016	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Related Party Transaction [Line Items]
Partnership's revenues from affiliated companies as a percent of total revenues		7.00%	6.00%	8.00%	7.00%
Notes payable — affiliated companies (Note 11)		$ 0		$ 0		$ 363
Notes payable—affiliated companies		0		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				5
Expense reimbursement, third year				5
Expense reimbursement, thereafter				5
OGE Energy \| Certain Services and Support Functions
Related Party Transaction [Line Items]
Expense reimbursement annual caps				$ 5
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		$ 0	$ 2	$ 1	$ 4
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

Related Party Activity (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
Related Party Activity (Details) - USD ($) $ in Millions	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Related Party Transaction [Line Items]
Revenues from affiliated companies	$ 38	$ 34	$ 82	$ 85
Cost of goods sold from affiliate	3	4	5	8
Charges to the Partnership by affiliates	12	15	25	31
CenterPoint
Related Party Transaction [Line Items]
Cost of goods sold from affiliate	0	0	0	1
CenterPoint \| Gas Transportation and Storage
Related Party Transaction [Line Items]
Revenues from affiliated companies	24	23	57	56
CenterPoint \| Gas Sales
Related Party Transaction [Line Items]
Revenues from affiliated companies	0	1	1	7
CenterPoint \| Corporate Services
Related Party Transaction [Line Items]
Charges to the Partnership by affiliates	3	4	5	8
OGE Energy
Related Party Transaction [Line Items]
Cost of goods sold from affiliate	3	4	5	7
OGE Energy \| Gas Transportation and Storage
Related Party Transaction [Line Items]
Revenues from affiliated companies	9	9	18	18
OGE Energy \| Gas Sales
Related Party Transaction [Line Items]
Revenues from affiliated companies	5	1	6	4
OGE Energy \| Seconded Employee Costs
Related Party Transaction [Line Items]
Charges to the Partnership by affiliates	8	8	17	17
OGE Energy \| Corporate Services
Related Party Transaction [Line Items]
Charges to the Partnership by affiliates	$ 1	$ 3	$ 3	$ 6

Equity Based Compensation (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
Equity Based Compensation (Details) - USD ($) $ in Millions	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	$ 3	$ 3	$ 5	$ 6
Performance units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	2	1	3	2
Restricted units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	1	1	1	3
Phantom units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	$ 0	$ 1	$ 1	$ 1

Equity Based Compensation - Equity Units Activity (Details) $ / shares in Units, $ in Millions	6 Months Ended
	Jun. 30, 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	1,208,443
Vested \| shares	(3,027)
Forfeited \| shares	(50,658)
June 30, 2016 \| shares	1,969,268
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	7.88
Vested \| $ / shares	18.56
Forfeited \| $ / shares	15.39
June 30, 2016 \| $ / shares	$ 12.42
Aggregate Intrinsic Value of Units Outstanding at June 30, 2016 \| $	$ 27
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	(78,707)
Forfeited \| shares	(54,647)
June 30, 2016 \| shares	448,418
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	22.55
Forfeited \| $ / shares	19.28
June 30, 2016 \| $ / shares	$ 20.99
Aggregate Intrinsic Value of Units Outstanding at June 30, 2016 \| $	$ 6
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	621,537
Vested \| shares	(168)
Forfeited \| shares	(3,858)
June 30, 2016 \| shares	627,328
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	8.12
Vested \| $ / shares	8.12
Forfeited \| $ / shares	8.12
June 30, 2016 \| $ / shares	$ 8.19
Aggregate Intrinsic Value of Units Outstanding at June 30, 2016 \| $	$ 8

Equity Based Compensation - Unrecognized Compensation Cost (Details) $ in Millions	6 Months Ended
	Jun. 30, 2016 USD ($) shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized Compensation Cost (In millions)	$ 24
Performance units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized Compensation Cost (In millions)	$ 15
Weighted Average to be Recognized (In years)	2 years 4 months 2 days
Restricted units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized Compensation Cost (In millions)	$ 4
Weighted Average to be Recognized (In years)	1 year 6 months 11 days
Phantom units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized Compensation Cost (In millions)	$ 5
Weighted Average to be Recognized (In years)	2 years 9 months 18 days
Long Term Incentive Plan \| Common Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares available for issuance \| shares	9,335,547

- Schedule of Financial Data for Business Segments and Services (Details)
$ in Millions

3 Months Ended

6 Months Ended

Jun. 30, 2016

USD ($)

Jun. 30, 2015

USD ($)

Jun. 30, 2016

USD ($)

segment

Jun. 30, 2015

USD ($)

Dec. 31, 2015

USD ($)

Segment Reporting Information [Line Items]

Number of reportable segments | segment

Total revenues

$ 529

$ 590

$ 1,038

$ 1,206

Cost of goods sold, excluding depreciation and amortization

254

277

449

569

Operation and maintenance, General and administrative

120

131

235

261

Depreciation and amortization

164

149

Impairments

Taxes other than income tax

Operating Income

160

197

Total assets

11,200

$ 11,226

Capital expenditures

297

221

456

Capital expenditures

536

Gathering and Processing

Segment Reporting Information [Line Items]

Total revenues

387

422

720

823

Cost of goods sold, excluding depreciation and amortization

231

241

396

463

Operation and maintenance, General and administrative

142

154

Depreciation and amortization

101

Impairments

Taxes other than income tax

Operating Income

103

Total assets

7,494

7,536

Capital expenditures

275

200

Capital expenditures

490

Transportation and Storage

Segment Reporting Information [Line Items]

Total revenues

^[1]

225

268

471

576

Cost of goods sold, excluding depreciation and amortization

^[1]

106

135

205

298

Operation and maintenance, General and administrative

^[1]

108

Depreciation and amortization

^[1]

Impairments

^[1]

Taxes other than income tax

^[1]

Operating Income

^[1]

Total assets

^[1]

4,926

4,976

Capital expenditures

^[1]

Capital expenditures

^[1]

Eliminations

Segment Reporting Information [Line Items]

Total revenues

(83)

(100)

(153)

(193)

Cost of goods sold, excluding depreciation and amortization

(83)

(99)

(152)

(192)

Operation and maintenance, General and administrative

(1)

Depreciation and amortization

Impairments

Taxes other than income tax

Operating Income

Total assets

(1,220)

$ (1,286)

Capital expenditures

$ 0

Capital expenditures

$ 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 and six months ended June 30, 2016 and 2015.