Enable Midstream Partners (ENBL) 10-Q 1 Aug 17 2017 Q2 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2017	Jul. 14, 2017
Document and Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2017
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	Q2
Entity Registrant Name	Enable Midstream Partners, LP
Entity Central Index Key	1,591,763
Entity Filer Category	Large Accelerated Filer
Current Fiscal Year End Date	--12-31
Entity Common Stock, Shares Outstanding		224,702,072

Condensed Consolidated Statemen

Condensed Consolidated Statements of Income (Unaudited) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Revenues (including revenues from affiliates (Note 11)):
Product sales	$ 354	$ 266	$ 740	$ 511
Service revenue	272	263	552	527
Total Revenues	626	529	1,292	1,038
Cost and Expenses (including expenses from affiliates (Note 11)):
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)	279	254	587	449
Operation and maintenance	97	93	186	188
General and administrative	23	27	48	47
Depreciation and amortization	89	83	177	164
Taxes other than income taxes	16	15	32	30
Total Cost and Expenses	504	472	1,030	878
Operating Income	122	57	262	160
Other Income (Expense):
Interest expense (including expenses from affiliates (Note 11))	(31)	(25)	(58)	(48)
Equity in earnings of equity method affiliate	7	7	14	14
Other, net	(1)	0	0	0
Total Other Expense	(25)	(18)	(44)	(34)
Income Before Income Taxes
Income Before Income Taxes	97	39	218	126
Income tax expense	1	0	2	1
Net Income
Net Income	96	39	216	125
Less: Net income attributable to noncontrolling interest
Less: Net income attributable to noncontrolling interest	1	0	1	0
Net Income Attributable to Limited Partners
Net Income Attributable to Limited Partners	95	39	215	125
Less: Series A Preferred Unit distributions (Note 4)
Less: Series A Preferred Unit distributions (Note 4)	9	4	18	4
Net Income Attributable to Common and Subordinated Units (Note 3)
Net Income Attributable to Common and Subordinated Units (Note 3)	86	35	197	121
Common Units
Net Income Attributable to Common and Subordinated Units (Note 3)
Net Income Attributable to Common and Subordinated Units (Note 3)	$ 45	$ 18	$ 102	$ 61
Basic and Diluted earnings (loss) per unit and weighted average number of units outstanding
Basic earnings per unit (Note 3)	$ 0.20	$ 0.08	$ 0.45	$ 0.29
Diluted earnings per unit (Note 3)	$ 0.20	$ 0.08	$ 0.45	$ 0.28
Subordinated Units
Net Income Attributable to Common and Subordinated Units (Note 3)
Net Income Attributable to Common and Subordinated Units (Note 3)	$ 41	$ 17	$ 95	$ 60
Basic and Diluted earnings (loss) per unit and weighted average number of units outstanding
Basic earnings per unit (Note 3)	$ 0.20	$ 0.08	$ 0.46	$ 0.29
Diluted earnings per unit (Note 3)	$ 0.20	$ 0.08	$ 0.46	$ 0.29

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets (Unaudited) - USD ($) $ in Millions	Jun. 30, 2017	Dec. 31, 2016
Current Assets:
Cash and cash equivalents	$ 7	$ 6
Restricted cash	14	17
Accounts receivable, net of allowance for doubtful accounts	220	249
Accounts receivable—affiliated companies	14	13
Inventory	42	41
Gas imbalances	23	41
Other current assets	31	29
Total current assets	351	396
Property, Plant and Equipment:
Property, plant and equipment	11,699	11,567
Less accumulated depreciation and amortization	1,571	1,424
Property, plant and equipment, net	10,128	10,143
Other Assets:
Intangible assets, net	293	306
Investment in equity method affiliate	324	329
Other	35	38
Total other assets	652	673
Total Assets	11,131	11,212
Current Liabilities:
Accounts payable	140	181
Accounts payable—affiliated companies	3	3
Taxes accrued	38	30
Gas imbalances	9	35
Other	108	113
Total current liabilities	298	362
Other Liabilities:
Accumulated deferred income taxes, net	11	10
Regulatory liabilities	20	19
Other	34	34
Total other liabilities	65	63
Long-Term Debt	3,046	2,993
Commitments and Contingencies (Note 12)
Partners’ Equity:
Series A Preferred Units (14,520,000 issued and outstanding at June 30, 2017 and December 31, 2016)	362	362
Common units	3,702	3,737
Subordinated units	3,646	3,683
Noncontrolling interest	12	12
Total Partners’ Equity	7,722	7,794
Total Liabilities and Partners’ Equity	$ 11,131	$ 11,212

Condensed Consolidated Balance4

Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) - shares	Jun. 30, 2017	Dec. 31, 2016
Common Units
Common and Subordinated units issued	224,700,966	224,535,454
Common units and Subordinated units outstanding	224,700,966	224,535,454
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	14,520,000
Preferred units outstanding	14,520,000	14,520,000

Condensed Consolidated Stateme5

Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016
Cash Flows from Operating Activities:
Net income	$ 216	$ 125
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	177	164
Deferred income taxes	2	0
Loss on sale/retirement of assets	5	7
Equity in earnings of equity method affiliate	(14)	(14)
Return on investment in equity method affiliate	14	14
Equity-based compensation	8	5
Amortization of debt costs and discount (premium)	(1)	(1)
Changes in other assets and liabilities:
Accounts receivable, net	29	20
Accounts receivable—affiliated companies	(1)	2
Inventory	(1)	9
Gas imbalance assets	18	4
Other current assets	(2)	(1)
Other assets	3	1
Accounts payable	(46)	(79)
Accounts payable—affiliated companies	0	(5)
Gas imbalance liabilities	(26)	(15)
Other current liabilities	3	48
Other liabilities	(2)	5
Net cash provided by operating activities	382	289
Cash Flows from Investing Activities:
Capital expenditures	(148)	(221)
Proceeds from sale of assets	1	0
Return of investment in equity method affiliate	5	13
Net cash used in investing activities	(142)	(208)
Cash Flows from Financing Activities:
Proceeds from long term debt, net of issuance costs	691	0
Proceeds from revolving credit facility	394	693
Repayment of revolving credit facility	(1,030)	(261)
Decrease in short-term debt	0	(236)
Repayment of notes payable—affiliated companies	0	(363)
Proceeds from issuance of Series A Preferred Units, net of issuance costs	0	362
Distributions	(296)	(274)
Cash taxes paid for employee equity-based compensation	(1)	0
Net cash used in financing activities	(242)	(79)
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	(2)	2
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	23	4
Cash, Cash Equivalents and Restricted Cash at End of Period	$ 21	$ 6

Condensed Consolidated Stateme6

Condensed Consolidated Statements of Partners' Equity (Unaudited) - USD ($) shares in Millions, $ in Millions	Total	Noncontrolling Interest	Series A Preferred UnitsPreferred Units	Common UnitsPartners' Capital	Subordinated UnitsPartners' Capital
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	0	$ 4	$ 62	$ 59
Issuance of Series A Preferred Units	362		$ 362	0
Issuance of Series A Preferred Units, units			15
Distributions	(274)	(1)	$ (4)	(137)	(132)
Equity-based compensation, net of units for employee taxes	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
Balance, beginning of period at Dec. 31, 2016	7,794	12	$ 362	$ 3,737	$ 3,683
Balance, beginning of period, units at Dec. 31, 2016			15	224	208
Changes in Partners' Capital
Net Income	216	1	$ 18	$ 102	$ 95
Distributions	(295)	(1)	(18)	(144)	(132)
Equity-based compensation, net of units for employee taxes	7			7
Balance, end of period at Jun. 30, 2017	$ 7,722	$ 12	$ 362	$ 3,702	$ 3,646
Balance, end of period, units at Jun. 30, 2017			15	224	208

Summary of Significant Accounti

Summary of Significant Accounting Policies	6 Months Ended
	Jun. 30, 2017
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 Delaware limited partnership formed on May 1, 2013 by CenterPoint Energy, OGE Energy and ArcLight. The Partnership’s assets and operations are organized into two reportable segments: (i) gathering and processing and (ii) transportation and storage. The gathering and processing segment primarily provides natural gas and crude oil gathering and natural gas processing services to our producer customers. The transportation and storage segment provides interstate and intrastate natural gas pipeline transportation and storage services primarily to our producer, power plant, LDC and industrial end-user customers. The Partnership’s natural gas gathering and processing assets are primarily located in Oklahoma, Texas, Arkansas and Louisiana and serve natural gas production in the Anadarko, Arkoma and Ark-La-Tex Basins. Crude oil gathering assets are located in North Dakota and serve crude oil production in the Bakken Shale formation of the Williston Basin. The Partnership’s natural gas transportation and storage assets consist primarily of an interstate pipeline system extending from western Oklahoma and the Texas Panhandle to Louisiana, an interstate pipeline system extending from Louisiana to Illinois, an intrastate pipeline system in Oklahoma, and our investment in SESH, an interstate pipeline extending from Louisiana to Alabama. CenterPoint Energy and OGE Energy each have 50% of the management interests in Enable GP. Enable GP is the general partner of the Partnership and has no other operating activities. Enable GP is governed by a board made up of two representatives designated by each of CenterPoint Energy and OGE Energy, along with the Partnership’s Chief Executive Officer and three independent board members CenterPoint Energy and OGE Energy mutually agreed to appoint. 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, 2017 , CenterPoint Energy held approximately 54.1% of the Partnership’s common and subordinated units, or 94,151,707 common units and 139,704,916 subordinated units, and OGE Energy held approximately 25.7% of the Partnership’s common and subordinated units, 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. The limited partner interests of the Partnership have limited voting rights on matters affecting the business. As such, limited partners do not have rights to elect the Partnership’s General Partner (Enable GP) on an annual or continuing basis and may not remove Enable GP without at least a 75% vote by all unitholders, including all units held by the Partnership’s limited partners, and Enable GP and its affiliates, voting together as a single class. As of June 30, 2017 , 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 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. Restricted Cash Restricted cash consists of cash which is restricted by agreements with third parties. The Condensed Consolidated Balance Sheets have $14 million and $17 million of restricted cash as of June 30, 2017 and December 31, 2016 , respectively. Accounts Receivable and Allowance for Doubtful Accounts Accounts receivable are recorded at the invoiced amount and do not typically bear interest. The determination of the allowance for doubtful accounts requires management to make estimates and judgments regarding our customers’ ability to pay. The allowance for doubtful accounts is determined based upon specific identification and estimates of future uncollectable amounts. On an ongoing basis, management evaluates our customers’ financial strength based on aging of accounts receivable, payment history, and review of other relevant information, including ratings agency credit ratings and alerts, publicly available reports and news releases, and bank and trade references. It is the policy of management to review the outstanding accounts receivable at least quarterly, giving consideration to historical bad debt write-offs, the aging of receivables and specific customer circumstances that may impact their ability to pay the amounts due. Based on this review, management determined that a $4 million and $3 million allowance for doubtful accounts was required as of June 30, 2017 and December 31, 2016 , respectively.

New Accounting Pronouncements

New Accounting Pronouncements	6 Months Ended
	Jun. 30, 2017
Accounting Changes and Error Corrections [Abstract]
New Accounting Pronouncements	New Accounting Pronouncements Accounting Standards to be Adopted in Future Periods 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).” Topic 606 is based on the core principle that revenue is recognized to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Topic 606 also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers, including significant judgments and changes in judgments and assets recognized from costs incurred to obtain or fulfill a contract. Topic 606 is effective for fiscal years beginning after December 15, 2017, and interim periods within those years, with early adoption permitted in 2017. However, we do not plan to adopt the standard early. Entities will have the option to apply the standard using a full retrospective or modified retrospective adoption method. The Partnership expects to adopt this ASU using the modified retrospective method. Our evaluation of the impact on our Consolidated Financial Statements and related disclosures is ongoing and not complete. In connection with our assessment work, we formed an implementation work team, completed training on the Topic 606 revenue recognition model and are continuing our review of contracts relative to the provisions of Topic 606. Leases In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842).” This standard requires, 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 this standard by the first quarter of 2019 and is currently evaluating the impact of this standard on our Condensed Consolidated Financial Statements and related disclosures. In connection with our assessment work, we formed an implementation work team and are continuing our review of our contracts relative to the provisions of the lease standard. 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.” This standard 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 does not expect the adoption of this standard to have a material impact on our Condensed Consolidated Financial Statements and related disclosures. Income Taxes In October 2016, the FASB issued ASU No. 2016-16, “Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory.” This standard requires entities to recognize the tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. The standard is effective for interim and annual reporting periods beginning after December 15, 2017, although early adoption is permitted as of the beginning of an annual period (i.e., only in the first interim period). The guidance requires application using a modified retrospective approach. The Partnership does not expect the adoption of this standard to have a material impact on our Condensed Consolidated Financial Statements and related disclosures.

Earnings Per Limited Partner Un

Earnings Per Limited Partner Unit	6 Months Ended
	Jun. 30, 2017
Earnings Per Share [Abstract]
Earnings Per Limited Partner Unit	Earnings Per Limited Partner Unit The following table illustrates the Partnership’s calculation of earnings per unit for common and subordinated units: Three Months Ended Six Months Ended 2017 2016 2017 2016 (In millions, except per unit data) Net income $ 96 $ 39 $ 216 $ 125 Net income attributable to noncontrolling interest 1 — 1 — Series A Preferred Unit distribution 9 4 18 4 General partner interest in net income — — — — Net income available to common and subordinated unitholders $ 86 $ 35 $ 197 $ 121 Net income allocable to common units $ 45 $ 18 $ 102 $ 61 Net income allocable to subordinated units 41 17 95 60 Net income available to common and subordinated unitholders $ 86 $ 35 $ 197 $ 121 Net income allocable to common units $ 45 $ 18 $ 102 $ 61 Dilutive effect of Series A Preferred Unit distributions — — — 4 Diluted net income allocable to common units 45 18 102 65 Diluted net income allocable to subordinated units 41 17 95 60 Total $ 86 $ 35 $ 197 $ 125 Basic weighted average number of outstanding Common units (1) 225 214 225 214 Subordinated units 208 208 208 208 Total 433 422 433 422 Basic earnings per unit Common units $ 0.20 $ 0.08 $ 0.45 $ 0.29 Subordinated units $ 0.20 $ 0.08 $ 0.46 $ 0.29 Basic weighted average number of outstanding common units 225 214 225 214 Dilutive effect of Series A Preferred Units — — — 20 Dilutive effect of performance units 1 1 1 — Diluted weighted average number of outstanding common units 226 215 226 234 Diluted weighted average number of outstanding subordinated units 208 208 208 208 Total 434 423 434 442 Diluted earnings per unit Common units $ 0.20 $ 0.08 $ 0.45 $ 0.28 Subordinated units $ 0.20 $ 0.08 $ 0.46 $ 0.29 ____________________ (1) Basic weighted average number of outstanding common units for the three and six months ended June 30, 2017 includes approximately one million time-based phantom units. The dilutive effect of the unit-based awards discussed in Note 13 was less than $0.01 per unit during each of the three and six months ended June 30, 2017 and 2016 .

Partners' Equity

Partners' Equity	6 Months Ended
	Jun. 30, 2017
Equity [Abstract]
Partners' Equity	Partners’ Equity The Partnership Agreement requires that, within 60 days after 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 2016 and 2017 (in millions, except for per unit amounts): Quarter Ended Record Date Payment Date Per Unit Distribution Total Cash Distribution June 30, 2017 (1) August 22, 2017 August 29, 2017 $ 0.318 $ 138 March 31, 2017 May 23, 2017 May 30, 2017 $ 0.318 $ 137 December 31, 2016 February 21, 2017 February 28, 2017 $ 0.318 $ 137 September 30, 2016 November 14, 2016 November 22, 2016 $ 0.318 $ 134 June 30, 2016 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 _____________________ (1) The board of directors of Enable GP declared this $0.318 per common unit cash distribution on July 31, 2017 , to be paid on August 29, 2017 , to common and subordinated unitholders of record at the close of business on August 22, 2017 . The Partnership paid or has authorized payment of the following cash distributions to holders of the Series A Preferred Units during 2016 and 2017 (in millions, except for per unit amounts): Quarter Ended Record Date Payment Date Per Unit Distribution Total Cash Distribution June 30, 2017 (1) July 31, 2017 August 14, 2017 $ 0.625 $ 9 March 31, 2017 May 2, 2017 May 12, 2017 $ 0.625 $ 9 December 31, 2016 February 10, 2017 February 15, 2017 $ 0.625 $ 9 September 30, 2016 November 1, 2016 November 14, 2016 $ 0.625 $ 9 June 30, 2016 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 July 31, 2017 , to be paid on August 14, 2017 , to Series A Preferred unitholders of record at the close of business on July 31, 2017 . (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 General As of June 30, 2017 , all subordinated units are held by CenterPoint Energy and OGE Energy. These units are considered subordinated because for a period of time, defined by the Partnership Agreement as the subordination period, the subordinated units will not be entitled to receive any distributions until the common units have received distributions of available cash each quarter from operating surplus in an amount equal to the minimum quarterly distribution, plus any arrearages on minimum quarterly distributions on the common units from prior quarters. In addition, the subordinated units are not entitled to arrearages on minimum quarterly distributions. On the expiration of the subordination period, the subordinated units will convert to common units on a one-for-one basis. Subordination Period The subordination period began on the closing date of the IPO and expires on the first to occur of the following dates: (1) the first business day following the distribution of available cash in respect of any quarter beginning with the quarter ending June 30, 2017 that the following tests are met: (a) distributions of available cash from operating surplus 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 that date; (b) the adjusted operating surplus generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum $1.15 (the annualized minimum quarterly distribution) on all of the common units and subordinated units outstanding during those periods on a fully diluted weighted average basis; and (c) there are no arrearages in the payment of the minimum quarterly distributions on the common units or (2) the first business day following the distribution of available cash in respect of any quarter beginning with the quarter ending June 30, 2015 that the following tests are met: (a) 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) for the four consecutive quarter period immediately preceding that date; (b) the adjusted operating surplus generated during the four consecutive quarter period immediately preceding that date equaled or exceed $1.725 per unit ( 150% of the annualized minimum quarterly distribution) on all of the common units and subordinated units outstanding during that period on a fully diluted weighted average basis plus the corresponding incentive distribution rights; and (c) there are no arrearages in the payment of the minimum quarterly distributions on the common units. Expiration of Subordination Period The Partnership expects that the financial tests required for conversion of all subordinated units will have been met, the subordination period will end and all subordinated units will convert into common units on the first business day following the payment of the cash distribution for common and subordinated units for the second quarter of 2017. Accordingly, the 207,855,430 outstanding subordinated units will convert into common units on a one -for-one basis on August 30, 2017. At conversion, holders of common units resulting from the conversion of subordinated units will have all the rights and obligations of unitholders holding all other common units, including the right to receive pro rata distributions made with respect to common units. The conversion of the subordinated units will not change the aggregate amount of outstanding units, and the Partnership does not anticipate that the conversion of the subordinated units will impact the amount of cash available for distribution by the Partnership. 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 a quarterly cash distribution on a non-cumulative basis if and when declared by the General Partner, and 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 thereafter a percentage of the stated liquidation preference equal to the sum of the three-month LIBOR plus 8.5% . 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. ATM Program On May 12, 2017, the Partnership entered into an ATM Equity Offering Sales Agreement in connection with an at-the-market program (the “ATM Program”). Pursuant to the ATM Program, the Partnership may issue and sell common units having an aggregate offering price of up to $200 million, by sales methods and at prices determined by market conditions and other factors at the time of our offerings. The Partnership has no obligation to sell any common units under the ATM Program and the Partnership may suspend sales under the ATM Program at any time. For the three and six months ended June 30, 2017, the Partnership sold an aggregate of 18,500 common units under the ATM Program, which generated proceeds of approximately $303,000 (net of approximately $3,000 of commissions). The Partnership incurred approximately $345,000 of expenses associated with the filing of the registration statements for the ATM Program. The proceeds were used for general partnership purposes. 2016 Equity Issuance On November 29, 2016, the Partnership closed a public offering of 10,000,000 common units at a price to the public of $14.00 per common unit. In connection with the offering, the Partnership, the underwriters and an affiliate of ArcLight entered into an underwriting agreement that provided an option for the underwriters to purchase up to an additional 1,500,000 common units, with 75,719 common units to be sold by the Partnership and 1,424,281 to be sold by the affiliate of ArcLight. The underwriters exercised the option to purchase all of the additional common units, and the Partnership received proceeds (net of underwriting discounts, structuring fees and offering expenses) of $137 million from the offering.

Assessing Impairment of Long-li

Assessing Impairment of Long-lived Assets (including Intangible Assets)	6 Months Ended
	Jun. 30, 2017
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 impairments to long-lived assets in the three and six months ended June 30, 2017 or 2016 . Based upon review of forecasted undiscounted cash flows, none of the asset groups were at risk of failing step one of the impairment test. Commodity 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 Aff

Investment in Equity Method Affiliate	6 Months Ended
	Jun. 30, 2017
Equity Method Investments and Joint Ventures [Abstract]
Investment in Equity Method Affiliate	Investment in Equity Method Affiliate 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. SESH is owned 50% by Spectra Energy Partners, LP and 50% by the Partnership. 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 the Partnership’s interest in SESH at fair market value, subject to certain exceptions. 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 $6 million and $5 million during the three months ended June 30, 2017 and 2016 , respectively, and $11 million and $9 million during the six months ended June 30, 2017 and 2016 , respectively, associated with these service agreements. Equity in Earnings of Equity Method Affiliate: Three Months Ended Six Months Ended 2017 2016 2017 2016 (In millions) SESH $ 7 $ 7 $ 14 $ 14 Distributions from Equity Method Affiliate: Three Months Ended Six Months Ended 2017 2016 2017 2016 (In millions) SESH (1) $ 8 $ 7 $ 19 $ 27 ___________________ (1) Distributions from equity method affiliate includes a $7 million and $7 million return on investment and a $1 million and zero return of investment for the three months ended June 30, 2017 and 2016 , respectively. Distributions from equity method affiliate includes a $14 million and $14 million return on investment and a $5 million and $13 million return of investment for the six months ended June 30, 2017 and 2016 , respectively. Summarized financial information of SESH: Three Months Ended Six Months Ended 2017 2016 2017 2016 (In millions) Income Statements: Revenues $ 28 $ 28 $ 56 $ 57 Operating income $ 18 $ 18 $ 35 $ 37 Net income $ 13 $ 14 $ 26 $ 28

Debt

Debt	6 Months Ended
	Jun. 30, 2017
Debt Disclosure [Abstract]
Debt	Debt The following table presents the Partnership’s outstanding debt as of June 30, 2017 and December 31, 2016 . June 30, 2017 December 31, 2016 Outstanding Principal Premium (Discount) Total Debt Outstanding Principal Premium (Discount) Total Debt (In millions) Revolving Credit Facility $ — $ — $ — $ 636 $ — $ 636 2015 Term Loan Agreement 450 — 450 450 — 450 2019 Notes 500 — 500 500 — 500 2024 Notes 600 — 600 600 (1 ) 599 2027 Notes 700 (3 ) 697 — — — 2044 Notes 550 — 550 550 — 550 EOIT Senior Notes 250 15 265 250 18 268 Total debt $ 3,050 $ 12 $ 3,062 $ 2,986 $ 17 $ 3,003 Less: Unamortized debt expense (1) 16 10 Total long-term debt $ 3,046 $ 2,993 ____________________ (1) As of June 30, 2017 and December 31, 2016 , there was an additional $4 million and $5 million , respectively, of unamortized debt expense related to the Revolving Credit Facility included in Other long-term assets, not included above. Revolving Credit Facility On June 18, 2015, the Partnership entered into the $1.75 billion Revolving Credit Facility, which matures on June 18, 2020, subject to an extension option, which may be exercised two times to extend the term of the Revolving Credit facility, in each case, for an additional one -year term. As of June 30, 2017 , there were no principal advances and $3 million in letters of credit outstanding under the Revolving Credit Facility. The Revolving Credit Facility provides that outstanding borrowings bear interest at 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, 2017 , 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, 2017 , 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 no amount outstanding under our commercial paper program at each of June 30, 2017 and December 31, 2016 . 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 paper 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, 2017 , there was $450 million outstanding under the 2015 Term Loan Agreement. The 2015 Term Loan Agreement provides that outstanding borrowings bear interest at 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, 2017 , the applicable margin for LIBOR-based borrowings under the 2015 Term Loan Agreement was 1.375% based on the Partnership’s credit ratings. As of June 30, 2017 , the weighted average interest rate of the 2015 Term Loan Agreement was 2.27% . Senior Notes On March 9, 2017, the Partnership completed the public offering of $700 million 4.400% Senior Notes due 2027 (2027 Notes). The Partnership received net proceeds of approximately $691 million. The proceeds were used for general partnership purposes, including to repay amounts outstanding under the Revolving Credit Facility. The 2027 Notes had an unamortized discount of $ 3 million and unamortized debt expense of $6 million at June 30, 2017 , resulting in an effective interest rate of 4.58% during the six months ended June 30, 2017 . In addition to the 2027 Notes, as of June 30, 2017 , the Partnership’s debt included the 2019 Notes, 2024 Notes and 2044 Notes, which had $10 million of unamortized debt expense at June 30, 2017 , resulting in effective interest rates of 2.58% , 4.02% and 5.08% , respectively, during the six months ended June 30, 2017 . As of June 30, 2017 , the Partnership’s debt included EOIT’s $250 million 6.25% senior notes due March 2020 (the EOIT Senior Notes). The EOIT Senior Notes had $15 million of unamortized premium at June 30, 2017 , resulting in an effective interest rate of 3.83% , during the six months ended June 30, 2017 . 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. As of June 30, 2017 , the Partnership and EOIT were in compliance with all of their debt agreements, including financial covenants.

Derivative Instruments and Hedg

Derivative Instruments and Hedging Activities	6 Months Ended
	Jun. 30, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments and Hedging Activities	Derivative Instruments and Hedging Activities The Partnership is exposed to certain risks relating to its ongoing business operations. The primary risk managed using derivative instruments is commodity price risk. The Partnership is also exposed to credit risk in its business operations. Commodity Price Risk The Partnership has used forward physical contracts, commodity price swap contracts and commodity price option features to manage the Partnership’s commodity price risk exposures in the past. Commodity derivative instruments used by the Partnership are as follows: • NGL put options, NGL futures and swaps, and WTI crude oil 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, 2017 and December 31, 2016 , 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 seek or 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, 2017 and December 31, 2016 , the Partnership had the following derivative instruments that were not designated as hedging instruments for accounting purposes: June 30, 2017 December 31, 2016 Gross Notional Volume Purchases Sales Purchases Sales Natural gas— TBtu (1) Financial fixed futures/swaps 17 21 2 29 Financial basis futures/swaps 17 25 2 30 Physical purchases/sales 2 50 1 25 Crude oil (for condensate)— MBbl (2) Financial Futures/swaps — 330 — 540 Natural gas liquids— MBbl (3) Financial Futures/swaps — 1,310 60 1,133 ____________________ (1) As of June 30, 2017 , 67.0% of the natural gas contracts had durations of one year or less, 14.2% had durations of more than one year and less than two years and 18.8% had durations of more than two years. As of December 31, 2016 , 100.0% of the natural gas contracts had durations of one year or less. (2) As of June 30, 2017 and December 31, 2016 , 100% of the crude oil (for condensate) contracts had durations of one year or less. (3) As of June 30, 2017 , 61.1% of the natural gas liquids contracts had durations of one year or less and 38.9% had durations of more than one year and less than two years. As of December 31, 2016 , 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, 2017 and December 31, 2016 that were not designated as hedging instruments for accounting purposes are as follows: June 30, 2017 December 31, 2016 Fair Value Instrument Balance Sheet Location Assets Liabilities Assets Liabilities (In millions) Natural gas Financial futures/swaps Other Current/Other $ 4 $ 3 $ 2 $ 22 Physical purchases/sales Other Current/Other 2 — — 1 Crude oil (for condensate) Financial futures/swaps Other Current/Other 2 — — 3 Natural gas liquids Financial Futures/swaps Other Current/Other — 2 — 8 Total gross derivatives (1) $ 8 $ 5 $ 2 $ 34 _____________________ (1) See Note 9 for a reconciliation of the Partnership’s total derivatives fair value to the Partnership’s Condensed Consolidated Balance Sheets as of June 30, 2017 and December 31, 2016 . 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, 2017 and 2016 : Amounts Recognized in Income Three Months Ended Six Months Ended 2017 2016 2017 2016 (In millions) Natural gas Financial futures/swaps gains (losses) $ 5 $ (21 ) $ 16 $ (11 ) Physical purchases/sales gains (losses) 2 (4 ) 7 (8 ) Crude oil (for condensate) Financial futures/swaps gains (losses) 2 (4 ) 5 (3 ) Natural gas liquids Financial futures/swaps gains (losses) — (5 ) 2 (9 ) Total $ 9 $ (34 ) $ 30 $ (31 ) For derivatives not designated as hedges in the tables above, amounts recognized in income for the periods ended June 30, 2017 and 2016 , 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, 2017 and 2016 : Three Months Ended Six Months Ended 2017 2016 2017 2016 (In millions) Change in fair value of derivatives $ 11 $ (39 ) $ 35 $ (47 ) Realized gain (loss) on derivatives (2 ) 5 (5 ) 16 Gain (loss) on derivative activity $ 9 $ (34 ) $ 30 $ (31 ) 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, 2017 , under these obligations, no cash collateral has been posted and no additional collateral may be required to be posted by the Partnership.

Fair Value Measurements

Fair Value Measurements	6 Months Ended
	Jun. 30, 2017
Fair Value Disclosures [Abstract]
Fair Value Measurements	Fair Value Measurements Certain assets and liabilities are recorded at fair value in the Condensed Consolidated Balance Sheets and are categorized based upon the level of judgment associated with the inputs used to measure their value. Hierarchical levels, as defined below and directly related to the amount of subjectivity associated with the inputs to fair valuations of these assets and liabilities are as follows: Level 1: Inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date. Instruments classified as Level 1 include natural gas futures, swaps and options transactions for contracts traded on the NYMEX and settled through a NYMEX clearing broker. Level 2: Inputs, other than quoted prices included in Level 1, are observable for the asset or liability, either directly or indirectly. Level 2 inputs include quoted prices for similar instruments in active markets, and inputs other than quoted prices that are observable for the asset or liability. Fair value assets and liabilities that are generally included in this category are derivatives with fair values based on inputs from actively quoted markets. Instruments classified as Level 2 include over-the-counter NYMEX natural gas swaps, natural gas basis swaps and natural gas purchase and sales transactions in markets such that the pricing is closely related to the NYMEX pricing, and over-the-counter WTI crude oil 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, 2017 , there were no transfers between levels. 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. 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 due to their short-term nature 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, 2017 and December 31, 2016 . June 30, 2017 December 31, 2016 Carrying Amount Fair Value Carrying Amount Fair Value (In millions) Long-Term Debt Revolving Credit Facility (Level 2) $ — $ — $ 636 $ 636 2015 Term Loan Agreement (Level 2) 450 450 450 450 2019 Notes (Level 2) 500 496 500 490 2024 Notes (Level 2) 600 595 599 564 2027 Notes (Level 2) 697 705 — — 2044 Notes (Level 2) 550 521 550 467 EOIT Senior Notes (Level 2) 265 264 268 260 The fair value of the Partnership’s Revolving Credit Facility, 2015 Term Loan Agreement, EOIT Senior Notes, 2019 Notes, 2024 Notes, 2027 Notes 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, 2017 , no material fair value adjustments or fair value measurements were required for these non-financial assets or liabilities. 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, 2017 and December 31, 2016 : June 30, 2017 Commodity Contracts Gas Imbalances (1) Assets Liabilities Assets (2) Liabilities (3) (In millions) Quoted market prices in active market for identical assets (Level 1) $ 4 $ 3 $ — $ — Significant other observable inputs (Level 2) 4 — 22 7 Unobservable inputs (Level 3) — 2 — — Total fair value 8 5 22 7 Netting adjustments (4 ) (4 ) — — Total $ 4 $ 1 $ 22 $ 7 December 31, 2016 Commodity Contracts Gas Imbalances (1) Assets Liabilities Assets (2) Liabilities (3) (In millions) Quoted market prices in active market for identical assets (Level 1) $ 2 $ 22 $ — $ — Significant other observable inputs (Level 2) — 4 41 30 Unobservable inputs (Level 3) — 8 — — Total fair value 2 34 41 30 Netting adjustments — — — — Total $ 2 $ 34 $ 41 $ 30 ______________________ (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, 2017 and December 31, 2016 . (2) Gas imbalance assets exclude fuel reserves for under retained fuel due from shippers of $1 million and zero at June 30, 2017 and December 31, 2016 , 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 $2 million and $5 million at June 30, 2017 and December 31, 2016 , 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, 2016 $ (8 ) Gains included in earnings 2 Settlements 4 Balance as of June 30, 2017 $ (2 ) 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, 2017 Product Group Fair Value Forward Curve Range (In millions) (Per gallon) Natural gas liquids $ (2 ) $0.264 - $0.757

Supplemental Disclosure of Cash

Supplemental Disclosure of Cash Flow Information	6 Months Ended
	Jun. 30, 2017
Supplemental Cash Flow Information [Abstract]
Supplemental Disclosure of Cash Flow Information	Supplemental Disclosure of Cash Flow Information The following table provides information regarding supplemental cash flow information: Six Months Ended 2017 2016 (In millions) Supplemental Disclosure of Cash Flow Information: Cash Payments: Interest, net of capitalized interest $ 50 $ 51 Income taxes, net of refunds — 1 Non-cash transactions: Accounts payable related to capital expenditures 24 24 The following table reconciles cash and cash equivalents and restricted cash on the Condensed Consolidated Balance Sheets to cash, cash equivalents and restricted cash on the Condensed Consolidated Statement of Cash Flows: Six Months Ended 2017 2016 (In millions) Cash and cash equivalents $ 7 $ 6 Restricted cash 14 — Cash, cash equivalents and restricted cash shown in the Condensed Consolidated Statements of Cash Flows $ 21 $ 6

Related Party Transactions

Related Party Transactions	6 Months Ended
	Jun. 30, 2017
Related Party Transactions [Abstract]
Related Party Transactions	Related Party Transactions The material related party transactions with CenterPoint Energy, OGE Energy and their respective subsidiaries are summarized below. There were no material related party transactions with other affiliates. Transportation and Storage Agreements Transportation and Storage Agreements with CenterPoint Energy EGT provides the following services to CenterPoint Energy’s LDCs in Arkansas, Louisiana, Oklahoma and Northeast Texas: (1) firm transportation with seasonal contract demand, (2) firm storage, (3) no notice transportation with associated storage and (4) maximum rate firm transportation. The first three services are in effect through March 31, 2021, and will remain in effect from year to year thereafter unless either party provides 180 days’ written notice prior to the contract termination date. The maximum rate firm transportation is in effect through March 31, 2018. MRT provides firm transportation and firm storage services to CenterPoint Energy’s LDCs under agreements that are in effect through May 15, 2018, but will continue year to year thereafter unless either party provides twelve months’ written notice prior to the contract termination date. Transportation and Storage Agreement with OGE Energy EOIT provides no-notice load-following transportation and storage services to OGE Energy. On March 17, 2014, EOIT entered into a transportation agreement with OGE Energy, with a primary term of May 1, 2014 through April 30, 2019. Following the primary term, the agreement will remain in effect from year to year thereafter unless either party provides notice of termination to the other party at least 180 days prior to the commencement of the succeeding annual period. On December 6, 2016, EOIT entered into a transportation agreement with OGE Energy, with a primary term expected to begin in late 2018 and extend for 20 years. In connection with the agreement, an approximately 80 -mile pipeline will be built to serve OGE Energy’s Muskogee Power Plant. Gas Sales and Purchases Transactions The Partnership sells natural gas volumes to affiliates of CenterPoint Energy and OGE Energy or purchases natural gas volumes from affiliates of CenterPoint Energy through a combination of forward, monthly and daily transactions. The Partnership enters into these physical natural gas transactions in the normal course of business based upon relevant market prices. The Partnership’s revenues from affiliated companies accounted for 5% and 7% of total revenues during the three months ended June 30, 2017 and 2016 , respectively, and 6% and 8% of total revenues during the six months ended June 30, 2017 and 2016 , respectively. Amounts of revenues from affiliated companies included in the Partnership’s Condensed Consolidated Statements of Income are summarized as follows: Three Months Ended Six Months Ended 2017 2016 2017 2016 (In millions) Gas transportation and storage service revenue — CenterPoint Energy $ 24 $ 24 $ 57 $ 57 Natural gas product sales — CenterPoint Energy 1 — 1 1 Gas transportation and storage service revenue — OGE Energy 9 9 18 18 Natural gas product sales — OGE Energy — 5 — 6 Total revenues — affiliated companies $ 34 $ 38 $ 76 $ 82 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 Six Months Ended 2017 2016 2017 2016 (In millions) Cost of natural gas purchases — CenterPoint Energy $ 1 $ — $ 1 $ — Cost of natural gas purchases — OGE Energy 4 3 7 5 Total cost of natural gas purchases — affiliated companies $ 5 $ 3 $ 8 $ 5 Corporate services and seconded employee expense As of June 30, 2017 , the Partnership had 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 $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. Under the terms of the MFA, 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 prior to the end of any extension. 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 2017 are $3 million and $4 million , respectively. On November 1, 2016, the Partnership entered into a new lease with an affiliate of CenterPoint Energy pursuant to which the Partnership leases office space in Shreveport, Louisiana. The term of the lease was effective on October 1, 2016 and extends through December 31, 2019. The Partnership expects to incur approximately $3 million in rent and maintenance expenses through the end of the initial term of the lease. Prior to October 1, 2016, CenterPoint Energy provided the office space in Shreveport, Louisiana, under the services agreement. As of June 30, 2017 , CenterPoint Energy continues to provide office and data center space to the Partnership in Houston, Texas, under the services agreement. 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 Six Months Ended 2017 2016 2017 2016 (In millions) Corporate Services — CenterPoint Energy $ 1 $ 3 $ 2 $ 5 Seconded Employee Costs — OGE Energy 9 8 16 17 Corporate Services — OGE Energy 1 1 2 3 Total corporate services and seconded employees expense $ 11 $ 12 $ 20 $ 25 Series A Preferred Units 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 of the Series A Preferred Units. Notes payable On February 18, 2016, in connection with the private placement of the Series A Preferred Units, the Partnership redeemed $363 million of notes payable—affiliated companies payable to a subsidiary of CenterPoint Energy. As of June 30, 2017 , the Partnership has not had any notes payable to any affiliate and has not incurred interest expense to any affiliate since February 18, 2016.

Commitments and Contingencies

Commitments and Contingencies	6 Months Ended
	Jun. 30, 2017
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

Equity-Based Compensation	6 Months Ended
	Jun. 30, 2017
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Equity-Based Compensation	Equity-Based Compensation The following table summarizes the Partnership’s compensation expense for the three and six months ended June 30, 2017 and 2016 related to performance units, restricted units, and phantom units for the Partnership’s employees and independent directors: Three Months Ended Six Months Ended 2017 2016 2017 2016 (In millions) Performance units $ 2 $ 2 $ 5 $ 3 Restricted units 1 1 1 1 Phantom units 1 — 2 1 Total compensation expense $ 4 $ 3 $ 8 $ 5 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, 2017 and changes during 2017 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, 2016 1,969,107 $ 15.27 392,995 $ 20.74 643,604 $ 8.49 Granted (1) 468,626 19.27 — — 377,979 16.26 Vested (2) (334,682 ) 29.61 (148,735 ) 25.50 (1,869 ) 8.12 Forfeited (42,150 ) 14.93 (7,038 ) 19.60 (12,420 ) 10.28 Units Outstanding at June 30, 2017 2,060,901 $ 13.86 237,222 $ 17.80 1,007,294 $ 11.38 Aggregate Intrinsic Value of Units Outstanding at June 30, 2017 $ 33 $ 4 $ 16 _____________________ (1) Performance units represents the target number of performance units granted. The actual number of performance units earned, if any, is dependent upon performance and may range from 0 percent to 200 percent of the target. (2) Performance units vested as of June 30, 2017 include 334,682 units from the annual grant, which were approved by the Board of Directors in 2014 and paid out at 91.5% , or 306,170 units, based on the level of achievement of a performance goal established by the Board of Directors over the performance period. 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, 2017 Unrecognized Compensation Cost (In millions) Weighted Average to be Recognized (In years) Performance Units $ 18 1.79 Restricted Units 1 0.93 Phantom Units 8 2.06 Total $ 27 As of June 30, 2017 , there were 8,653,478 units available for issuance under the long term incentive plan.

Reportable Segments

Reportable Segments	6 Months Ended
	Jun. 30, 2017
Segment Reporting [Abstract]
Reportable Segments	Reportable Segments The Partnership’s determination of reportable segments considers the strategic operating units under which it manages sales, allocates resources and assesses performance of various products and services to customers in differing regulatory environments. The accounting policies of the reportable segments are the same as those described in the summary of significant accounting policies excerpt in the Partnership’s audited 2016 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 and crude oil gathering and natural gas processing services to our producer customers, and (ii) transportation and storage, which provides interstate and intrastate natural gas pipeline transportation and storage service primarily to our producer, power plant, LDC and industrial end-user customers. Financial data for reportable segments are as follows: Three Months Ended June 30, 2017 Gathering and Transportation (1) Eliminations Total (In millions) Product sales $ 336 $ 134 $ (116 ) $ 354 Service revenue 144 129 (1 ) 272 Total Revenues 480 263 (117 ) 626 Cost of natural gas and natural gas liquids 269 127 (117 ) 279 Operation and maintenance, General and administrative 75 45 — 120 Depreciation and amortization 55 34 — 89 Taxes other than income tax 9 7 — 16 Operating income $ 72 $ 50 $ — $ 122 Total assets $ 8,612 $ 5,516 $ (2,997 ) $ 11,131 Capital expenditures $ 39 $ 48 $ — $ 87 Three Months Ended June 30, 2016 Gathering and (1) Eliminations Total (In millions) Product sales $ 256 $ 92 $ (82 ) $ 266 Service revenue 131 133 (1 ) 263 Total 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 as of December 31, 2016 $ 7,453 $ 4,963 $ (1,204 ) $ 11,212 Capital expenditures $ 79 $ 12 $ — $ 91 Six Months Ended June 30, 2017 Gathering and Transportation (1) Eliminations Total (In millions) Product sales $ 687 $ 287 $ (234 ) $ 740 Service revenue 284 270 (2 ) 552 Total Revenues 971 557 (236 ) 1,292 Cost of natural gas and natural gas liquids 555 267 (235 ) 587 Operation and maintenance, General and administrative 145 90 (1 ) 234 Depreciation and amortization 111 66 — 177 Taxes other than income tax 18 14 — 32 Operating income $ 142 $ 120 $ — $ 262 Total assets $ 8,612 $ 5,516 $ (2,997 ) $ 11,131 Capital expenditures $ 90 $ 58 $ — $ 148 Six Months Ended June 30, 2016 Gathering and (1) Eliminations Total (In millions) Product sales $ 464 $ 198 $ (151 ) $ 511 Service revenue 256 273 (2 ) 527 Total 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 Taxes other than income tax 16 14 — 30 Operating income $ 65 $ 95 $ — $ 160 Total assets as of December 31, 2016 $ 7,453 $ 4,963 $ (1,204 ) $ 11,212 Capital expenditures $ 200 $ 21 $ — $ 221 _____________________ (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, 2017 and 2016 .

Summary of Significant Accoun21

Summary of Significant Accounting Policies (Policies)	6 Months Ended
	Jun. 30, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization	Organization Enable Midstream Partners, LP (Partnership) is a Delaware limited partnership formed on May 1, 2013 by CenterPoint Energy, OGE Energy and ArcLight. The Partnership’s assets and operations are organized into two reportable segments: (i) gathering and processing and (ii) transportation and storage. The gathering and processing segment primarily provides natural gas and crude oil gathering and natural gas processing services to our producer customers. The transportation and storage segment provides interstate and intrastate natural gas pipeline transportation and storage services primarily to our producer, power plant, LDC and industrial end-user customers. The Partnership’s natural gas gathering and processing assets are primarily located in Oklahoma, Texas, Arkansas and Louisiana and serve natural gas production in the Anadarko, Arkoma and Ark-La-Tex Basins. Crude oil gathering assets are located in North Dakota and serve crude oil production in the Bakken Shale formation of the Williston Basin. The Partnership’s natural gas transportation and storage assets consist primarily of an interstate pipeline system extending from western Oklahoma and the Texas Panhandle to Louisiana, an interstate pipeline system extending from Louisiana to Illinois, an intrastate pipeline system in Oklahoma, and our investment in SESH, an interstate pipeline extending from Louisiana to Alabama. CenterPoint Energy and OGE Energy each have 50% of the management interests in Enable GP. Enable GP is the general partner of the Partnership and has no other operating activities. Enable GP is governed by a board made up of two representatives designated by each of CenterPoint Energy and OGE Energy, along with the Partnership’s Chief Executive Officer and three independent board members CenterPoint Energy and OGE Energy mutually agreed to appoint. 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, 2017 , CenterPoint Energy held approximately 54.1% of the Partnership’s common and subordinated units, or 94,151,707 common units and 139,704,916 subordinated units, and OGE Energy held approximately 25.7% of the Partnership’s common and subordinated units, 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. The limited partner interests of the Partnership have limited voting rights on matters affecting the business. As such, limited partners do not have rights to elect the Partnership’s General Partner (Enable GP) on an annual or continuing basis and may not remove Enable GP without at least a 75% vote by all unitholders, including all units held by the Partnership’s limited partners, and Enable GP and its affiliates, voting together as a single class. As of June 30, 2017 , 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 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.
Restricted Cash	Restricted Cash Restricted cash consists of cash which is restricted by agreements with third parties.
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 typically bear interest. The determination of the allowance for doubtful accounts requires management to make estimates and judgments regarding our customers’ ability to pay. The allowance for doubtful accounts is determined based upon specific identification and estimates of future uncollectable amounts. On an ongoing basis, management evaluates our customers’ financial strength based on aging of accounts receivable, payment history, and review of other relevant information, including ratings agency credit ratings and alerts, publicly available reports and news releases, and bank and trade references. It is the policy of management to review the outstanding accounts receivable at least quarterly, giving consideration to historical bad debt write-offs, the aging of receivables and specific customer circumstances that may impact their ability to pay the amounts due.
New Accounting Pronouncements	New Accounting Pronouncements Accounting Standards to be Adopted in Future Periods 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).” Topic 606 is based on the core principle that revenue is recognized to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Topic 606 also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers, including significant judgments and changes in judgments and assets recognized from costs incurred to obtain or fulfill a contract. Topic 606 is effective for fiscal years beginning after December 15, 2017, and interim periods within those years, with early adoption permitted in 2017. However, we do not plan to adopt the standard early. Entities will have the option to apply the standard using a full retrospective or modified retrospective adoption method. The Partnership expects to adopt this ASU using the modified retrospective method. Our evaluation of the impact on our Consolidated Financial Statements and related disclosures is ongoing and not complete. In connection with our assessment work, we formed an implementation work team, completed training on the Topic 606 revenue recognition model and are continuing our review of contracts relative to the provisions of Topic 606. Leases In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842).” This standard requires, 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 this standard by the first quarter of 2019 and is currently evaluating the impact of this standard on our Condensed Consolidated Financial Statements and related disclosures. In connection with our assessment work, we formed an implementation work team and are continuing our review of our contracts relative to the provisions of the lease standard. 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.” This standard 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 does not expect the adoption of this standard to have a material impact on our Condensed Consolidated Financial Statements and related disclosures. Income Taxes In October 2016, the FASB issued ASU No. 2016-16, “Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory.” This standard requires entities to recognize the tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. The standard is effective for interim and annual reporting periods beginning after December 15, 2017, although early adoption is permitted as of the beginning of an annual period (i.e., only in the first interim period). The guidance requires application using a modified retrospective approach. The Partnership does not expect the adoption of this standard to have a material impact on our Condensed Consolidated Financial Statements and related disclosures.
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 impairments to long-lived assets in the three and six months ended June 30, 2017 or 2016 . Based upon review of forecasted undiscounted cash flows, none of the asset groups were at risk of failing step one of the impairment test. Commodity price declines, throughput declines, cost increases, regulatory or political environment changes, and other changes in market conditions could reduce forecast undiscounted cash flows.
Derivatives 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 oil 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, 2017 and December 31, 2016 , 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 seek or 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.
Fair Value Measurements	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. 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 oil 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, 2017 , there were no transfers between levels. 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	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.
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 2016 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 and crude oil gathering and natural gas processing services to our producer customers, and (ii) transportation and storage, which provides interstate and intrastate natural gas pipeline transportation and storage service primarily to our producer, power plant, LDC and industrial end-user customers.

Earnings Per Limited Partner 22

Earnings Per Limited Partner Unit (Tables)	6 Months Ended
	Jun. 30, 2017
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 Six Months Ended 2017 2016 2017 2016 (In millions, except per unit data) Net income $ 96 $ 39 $ 216 $ 125 Net income attributable to noncontrolling interest 1 — 1 — Series A Preferred Unit distribution 9 4 18 4 General partner interest in net income — — — — Net income available to common and subordinated unitholders $ 86 $ 35 $ 197 $ 121 Net income allocable to common units $ 45 $ 18 $ 102 $ 61 Net income allocable to subordinated units 41 17 95 60 Net income available to common and subordinated unitholders $ 86 $ 35 $ 197 $ 121 Net income allocable to common units $ 45 $ 18 $ 102 $ 61 Dilutive effect of Series A Preferred Unit distributions — — — 4 Diluted net income allocable to common units 45 18 102 65 Diluted net income allocable to subordinated units 41 17 95 60 Total $ 86 $ 35 $ 197 $ 125 Basic weighted average number of outstanding Common units (1) 225 214 225 214 Subordinated units 208 208 208 208 Total 433 422 433 422 Basic earnings per unit Common units $ 0.20 $ 0.08 $ 0.45 $ 0.29 Subordinated units $ 0.20 $ 0.08 $ 0.46 $ 0.29 Basic weighted average number of outstanding common units 225 214 225 214 Dilutive effect of Series A Preferred Units — — — 20 Dilutive effect of performance units 1 1 1 — Diluted weighted average number of outstanding common units 226 215 226 234 Diluted weighted average number of outstanding subordinated units 208 208 208 208 Total 434 423 434 442 Diluted earnings per unit Common units $ 0.20 $ 0.08 $ 0.45 $ 0.28 Subordinated units $ 0.20 $ 0.08 $ 0.46 $ 0.29 ____________________ (1) Basic weighted average number of outstanding common units for the three and six months ended June 30, 2017 includes approximately one million time-based phantom units.

Partners' Equity (Tables)

Partners' Equity (Tables)	6 Months Ended
	Jun. 30, 2017
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 2016 and 2017 (in millions, except for per unit amounts): Quarter Ended Record Date Payment Date Per Unit Distribution Total Cash Distribution June 30, 2017 (1) August 22, 2017 August 29, 2017 $ 0.318 $ 138 March 31, 2017 May 23, 2017 May 30, 2017 $ 0.318 $ 137 December 31, 2016 February 21, 2017 February 28, 2017 $ 0.318 $ 137 September 30, 2016 November 14, 2016 November 22, 2016 $ 0.318 $ 134 June 30, 2016 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 _____________________ (1) The board of directors of Enable GP declared this $0.318 per common unit cash distribution on July 31, 2017 , to be paid on August 29, 2017 , to common and subordinated unitholders of record at the close of business on August 22, 2017 .
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 and 2017 (in millions, except for per unit amounts): Quarter Ended Record Date Payment Date Per Unit Distribution Total Cash Distribution June 30, 2017 (1) July 31, 2017 August 14, 2017 $ 0.625 $ 9 March 31, 2017 May 2, 2017 May 12, 2017 $ 0.625 $ 9 December 31, 2016 February 10, 2017 February 15, 2017 $ 0.625 $ 9 September 30, 2016 November 1, 2016 November 14, 2016 $ 0.625 $ 9 June 30, 2016 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 July 31, 2017 , to be paid on August 14, 2017 , to Series A Preferred unitholders of record at the close of business on July 31, 2017 . (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 Equity Method A24

Investment in Equity Method Affiliate (Tables)	6 Months Ended
	Jun. 30, 2017
Equity Method Investments and Joint Ventures [Abstract]
Schedule of Investments Detail	Equity in Earnings of Equity Method Affiliate: Three Months Ended Six Months Ended 2017 2016 2017 2016 (In millions) SESH $ 7 $ 7 $ 14 $ 14 Distributions from Equity Method Affiliate: Three Months Ended Six Months Ended 2017 2016 2017 2016 (In millions) SESH (1) $ 8 $ 7 $ 19 $ 27 ___________________ (1) Distributions from equity method affiliate includes a $7 million and $7 million return on investment and a $1 million and zero return of investment for the three months ended June 30, 2017 and 2016 , respectively. Distributions from equity method affiliate includes a $14 million and $14 million return on investment and a $5 million and $13 million return of investment for the six months ended June 30, 2017 and 2016 , respectively. Summarized financial information of SESH: Three Months Ended Six Months Ended 2017 2016 2017 2016 (In millions) Income Statements: Revenues $ 28 $ 28 $ 56 $ 57 Operating income $ 18 $ 18 $ 35 $ 37 Net income $ 13 $ 14 $ 26 $ 28

Debt (Tables)

Debt (Tables)	6 Months Ended
	Jun. 30, 2017
Debt Disclosure [Abstract]
Schedule of Debt	The following table presents the Partnership’s outstanding debt as of June 30, 2017 and December 31, 2016 . June 30, 2017 December 31, 2016 Outstanding Principal Premium (Discount) Total Debt Outstanding Principal Premium (Discount) Total Debt (In millions) Revolving Credit Facility $ — $ — $ — $ 636 $ — $ 636 2015 Term Loan Agreement 450 — 450 450 — 450 2019 Notes 500 — 500 500 — 500 2024 Notes 600 — 600 600 (1 ) 599 2027 Notes 700 (3 ) 697 — — — 2044 Notes 550 — 550 550 — 550 EOIT Senior Notes 250 15 265 250 18 268 Total debt $ 3,050 $ 12 $ 3,062 $ 2,986 $ 17 $ 3,003 Less: Unamortized debt expense (1) 16 10 Total long-term debt $ 3,046 $ 2,993 ____________________ (1) As of June 30, 2017 and December 31, 2016 , there was an additional $4 million and $5 million , respectively, of unamortized debt expense related to the Revolving Credit Facility included in Other long-term assets, not included above.

Derivative Instruments and He26

Derivative Instruments and Hedging Activities (Tables)	6 Months Ended
	Jun. 30, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Derivative Instruments	As of June 30, 2017 and December 31, 2016 , the Partnership had the following derivative instruments that were not designated as hedging instruments for accounting purposes: June 30, 2017 December 31, 2016 Gross Notional Volume Purchases Sales Purchases Sales Natural gas— TBtu (1) Financial fixed futures/swaps 17 21 2 29 Financial basis futures/swaps 17 25 2 30 Physical purchases/sales 2 50 1 25 Crude oil (for condensate)— MBbl (2) Financial Futures/swaps — 330 — 540 Natural gas liquids— MBbl (3) Financial Futures/swaps — 1,310 60 1,133 ____________________ (1) As of June 30, 2017 , 67.0% of the natural gas contracts had durations of one year or less, 14.2% had durations of more than one year and less than two years and 18.8% had durations of more than two years. As of December 31, 2016 , 100.0% of the natural gas contracts had durations of one year or less. (2) As of June 30, 2017 and December 31, 2016 , 100% of the crude oil (for condensate) contracts had durations of one year or less. (3) As of June 30, 2017 , 61.1% of the natural gas liquids contracts had durations of one year or less and 38.9% had durations of more than one year and less than two years. As of December 31, 2016 , 100% of the natural gas liquid contracts had durations of one year or less.
Schedule of Derivative Assets at Fair Value	The fair value of the derivative instruments that are presented in the Partnership’s Condensed Consolidated Balance Sheets as of June 30, 2017 and December 31, 2016 that were not designated as hedging instruments for accounting purposes are as follows: June 30, 2017 December 31, 2016 Fair Value Instrument Balance Sheet Location Assets Liabilities Assets Liabilities (In millions) Natural gas Financial futures/swaps Other Current/Other $ 4 $ 3 $ 2 $ 22 Physical purchases/sales Other Current/Other 2 — — 1 Crude oil (for condensate) Financial futures/swaps Other Current/Other 2 — — 3 Natural gas liquids Financial Futures/swaps Other Current/Other — 2 — 8 Total gross derivatives (1) $ 8 $ 5 $ 2 $ 34 _____________________ (1) See Note 9 for a reconciliation of the Partnership’s total derivatives fair value to the Partnership’s Condensed Consolidated Balance Sheets as of June 30, 2017 and December 31, 2016 .
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, 2017 and 2016 : Amounts Recognized in Income Three Months Ended Six Months Ended 2017 2016 2017 2016 (In millions) Natural gas Financial futures/swaps gains (losses) $ 5 $ (21 ) $ 16 $ (11 ) Physical purchases/sales gains (losses) 2 (4 ) 7 (8 ) Crude oil (for condensate) Financial futures/swaps gains (losses) 2 (4 ) 5 (3 ) Natural gas liquids Financial futures/swaps gains (losses) — (5 ) 2 (9 ) Total $ 9 $ (34 ) $ 30 $ (31 )
Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location	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, 2017 and 2016 : Three Months Ended Six Months Ended 2017 2016 2017 2016 (In millions) Change in fair value of derivatives $ 11 $ (39 ) $ 35 $ (47 ) Realized gain (loss) on derivatives (2 ) 5 (5 ) 16 Gain (loss) on derivative activity $ 9 $ (34 ) $ 30 $ (31 )

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	6 Months Ended
	Jun. 30, 2017
Fair Value Disclosures [Abstract]
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, 2017 and December 31, 2016 . June 30, 2017 December 31, 2016 Carrying Amount Fair Value Carrying Amount Fair Value (In millions) Long-Term Debt Revolving Credit Facility (Level 2) $ — $ — $ 636 $ 636 2015 Term Loan Agreement (Level 2) 450 450 450 450 2019 Notes (Level 2) 500 496 500 490 2024 Notes (Level 2) 600 595 599 564 2027 Notes (Level 2) 697 705 — — 2044 Notes (Level 2) 550 521 550 467 EOIT Senior Notes (Level 2) 265 264 268 260
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, 2017 and December 31, 2016 : June 30, 2017 Commodity Contracts Gas Imbalances (1) Assets Liabilities Assets (2) Liabilities (3) (In millions) Quoted market prices in active market for identical assets (Level 1) $ 4 $ 3 $ — $ — Significant other observable inputs (Level 2) 4 — 22 7 Unobservable inputs (Level 3) — 2 — — Total fair value 8 5 22 7 Netting adjustments (4 ) (4 ) — — Total $ 4 $ 1 $ 22 $ 7 December 31, 2016 Commodity Contracts Gas Imbalances (1) Assets Liabilities Assets (2) Liabilities (3) (In millions) Quoted market prices in active market for identical assets (Level 1) $ 2 $ 22 $ — $ — Significant other observable inputs (Level 2) — 4 41 30 Unobservable inputs (Level 3) — 8 — — Total fair value 2 34 41 30 Netting adjustments — — — — Total $ 2 $ 34 $ 41 $ 30 ______________________ (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, 2017 and December 31, 2016 . (2) Gas imbalance assets exclude fuel reserves for under retained fuel due from shippers of $1 million and zero at June 30, 2017 and December 31, 2016 , 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 $2 million and $5 million at June 30, 2017 and December 31, 2016 , 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, Net Derivative Asset (Liability) 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, 2016 $ (8 ) Gains included in earnings 2 Settlements 4 Balance as of June 30, 2017 $ (2 )
Fair Value Inputs, Quantitative Information	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, 2017 Product Group Fair Value Forward Curve Range (In millions) (Per gallon) Natural gas liquids $ (2 ) $0.264 - $0.757

Supplemental Disclosure of Ca28

Supplemental Disclosure of Cash Flow Information (Tables)	6 Months Ended
	Jun. 30, 2017
Supplemental Cash Flow Information [Abstract]
Schedule of Cash Flow, Supplemental Disclosures	The following table provides information regarding supplemental cash flow information: Six Months Ended 2017 2016 (In millions) Supplemental Disclosure of Cash Flow Information: Cash Payments: Interest, net of capitalized interest $ 50 $ 51 Income taxes, net of refunds — 1 Non-cash transactions: Accounts payable related to capital expenditures 24 24
Schedule of Restricted Cash and Cash Equivalents	The following table reconciles cash and cash equivalents and restricted cash on the Condensed Consolidated Balance Sheets to cash, cash equivalents and restricted cash on the Condensed Consolidated Statement of Cash Flows: Six Months Ended 2017 2016 (In millions) Cash and cash equivalents $ 7 $ 6 Restricted cash 14 — Cash, cash equivalents and restricted cash shown in the Condensed Consolidated Statements of Cash Flows $ 21 $ 6
Schedule of Cash and Cash Equivalents	The following table reconciles cash and cash equivalents and restricted cash on the Condensed Consolidated Balance Sheets to cash, cash equivalents and restricted cash on the Condensed Consolidated Statement of Cash Flows: Six Months Ended 2017 2016 (In millions) Cash and cash equivalents $ 7 $ 6 Restricted cash 14 — Cash, cash equivalents and restricted cash shown in the Condensed Consolidated Statements of Cash Flows $ 21 $ 6

Related Party Transactions (Tab

Related Party Transactions (Tables)	6 Months Ended
	Jun. 30, 2017
Related Party Transactions [Abstract]
Schedule of Revenues from Related Parties	Amounts of revenues from affiliated companies included in the Partnership’s Condensed Consolidated Statements of Income are summarized as follows: Three Months Ended Six Months Ended 2017 2016 2017 2016 (In millions) Gas transportation and storage service revenue — CenterPoint Energy $ 24 $ 24 $ 57 $ 57 Natural gas product sales — CenterPoint Energy 1 — 1 1 Gas transportation and storage service revenue — OGE Energy 9 9 18 18 Natural gas product sales — OGE Energy — 5 — 6 Total revenues — affiliated companies $ 34 $ 38 $ 76 $ 82
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 Six Months Ended 2017 2016 2017 2016 (In millions) Cost of natural gas purchases — CenterPoint Energy $ 1 $ — $ 1 $ — Cost of natural gas purchases — OGE Energy 4 3 7 5 Total cost of natural gas purchases — affiliated companies $ 5 $ 3 $ 8 $ 5
Schedule of Amounts Charged to Partnership by Related Parties	Amounts charged to the Partnership by affiliates for seconded employees and corporate services, included primarily in Operation and maintenance and General and administrative expenses in the Partnership’s Condensed Consolidated Statements of Income are as follows: Three Months Ended Six Months Ended 2017 2016 2017 2016 (In millions) Corporate Services — CenterPoint Energy $ 1 $ 3 $ 2 $ 5 Seconded Employee Costs — OGE Energy 9 8 16 17 Corporate Services — OGE Energy 1 1 2 3 Total corporate services and seconded employees expense $ 11 $ 12 $ 20 $ 25

Equity-Based Compensation (Tabl

Equity-Based Compensation (Tables)	6 Months Ended
	Jun. 30, 2017
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Disclosure of Share-based Compensation Arrangements by Share-based Payment Award	The following table summarizes the Partnership’s compensation expense for the three and six months ended June 30, 2017 and 2016 related to performance units, restricted units, and phantom units for the Partnership’s employees and independent directors: Three Months Ended Six Months Ended 2017 2016 2017 2016 (In millions) Performance units $ 2 $ 2 $ 5 $ 3 Restricted units 1 1 1 1 Phantom units 1 — 2 1 Total compensation expense $ 4 $ 3 $ 8 $ 5
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, 2017 and changes during 2017 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, 2016 1,969,107 $ 15.27 392,995 $ 20.74 643,604 $ 8.49 Granted (1) 468,626 19.27 — — 377,979 16.26 Vested (2) (334,682 ) 29.61 (148,735 ) 25.50 (1,869 ) 8.12 Forfeited (42,150 ) 14.93 (7,038 ) 19.60 (12,420 ) 10.28 Units Outstanding at June 30, 2017 2,060,901 $ 13.86 237,222 $ 17.80 1,007,294 $ 11.38 Aggregate Intrinsic Value of Units Outstanding at June 30, 2017 $ 33 $ 4 $ 16 _____________________ (1) Performance units represents the target number of performance units granted. The actual number of performance units earned, if any, is dependent upon performance and may range from 0 percent to 200 percent of the target. (2) Performance units vested as of June 30, 2017 include 334,682 units from the annual grant, which were approved by the Board of Directors in 2014 and paid out at 91.5% , or 306,170 units, based on the level of achievement of a performance goal established by the Board of Directors over the performance period.
Schedule of Unrecognized Compensation Cost, Nonvested Awards	A summary of the Partnership’s unrecognized compensation cost for its non-vested performance units, restricted units, and phantom units, and the weighted-average periods over which the compensation cost is expected to be recognized are shown in the following table. June 30, 2017 Unrecognized Compensation Cost (In millions) Weighted Average to be Recognized (In years) Performance Units $ 18 1.79 Restricted Units 1 0.93 Phantom Units 8 2.06 Total $ 27

Reportable Segments (Tables)

Reportable Segments (Tables)	6 Months Ended
	Jun. 30, 2017
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, 2017 Gathering and Transportation (1) Eliminations Total (In millions) Product sales $ 336 $ 134 $ (116 ) $ 354 Service revenue 144 129 (1 ) 272 Total Revenues 480 263 (117 ) 626 Cost of natural gas and natural gas liquids 269 127 (117 ) 279 Operation and maintenance, General and administrative 75 45 — 120 Depreciation and amortization 55 34 — 89 Taxes other than income tax 9 7 — 16 Operating income $ 72 $ 50 $ — $ 122 Total assets $ 8,612 $ 5,516 $ (2,997 ) $ 11,131 Capital expenditures $ 39 $ 48 $ — $ 87 Three Months Ended June 30, 2016 Gathering and (1) Eliminations Total (In millions) Product sales $ 256 $ 92 $ (82 ) $ 266 Service revenue 131 133 (1 ) 263 Total 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 as of December 31, 2016 $ 7,453 $ 4,963 $ (1,204 ) $ 11,212 Capital expenditures $ 79 $ 12 $ — $ 91 Six Months Ended June 30, 2017 Gathering and Transportation (1) Eliminations Total (In millions) Product sales $ 687 $ 287 $ (234 ) $ 740 Service revenue 284 270 (2 ) 552 Total Revenues 971 557 (236 ) 1,292 Cost of natural gas and natural gas liquids 555 267 (235 ) 587 Operation and maintenance, General and administrative 145 90 (1 ) 234 Depreciation and amortization 111 66 — 177 Taxes other than income tax 18 14 — 32 Operating income $ 142 $ 120 $ — $ 262 Total assets $ 8,612 $ 5,516 $ (2,997 ) $ 11,131 Capital expenditures $ 90 $ 58 $ — $ 148 Six Months Ended June 30, 2016 Gathering and (1) Eliminations Total (In millions) Product sales $ 464 $ 198 $ (151 ) $ 511 Service revenue 256 273 (2 ) 527 Total 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 Taxes other than income tax 16 14 — 30 Operating income $ 65 $ 95 $ — $ 160 Total assets as of December 31, 2016 $ 7,453 $ 4,963 $ (1,204 ) $ 11,212 Capital expenditures $ 200 $ 21 $ — $ 221 _____________________ (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, 2017 and 2016 .

Summary of Significant Accoun32

Summary of Significant Accounting Policies - Narrative (Details) $ in Millions	6 Months Ended
	Jun. 30, 2017USD ($)board_membersegmentshares	Dec. 31, 2016USD ($)	Jun. 30, 2016USD ($)
Significant Accounting Policies [Line Items]
Number of reportable segments | segment	2
Number of representatives designated by each of CenterPoint Energy and OGE Energy | board_member	2
Number of independent board members | board_member	3
Percentage vote by all unitholders (at least 75%)	75.00%
Restricted cash | $	$ 14	$ 17	$ 0
Allowance for doubtful accounts | $	$ 4	$ 3
SESH
Significant Accounting Policies [Line Items]
Ownership percentage	50.00%
Limited Partner | CenterPoint
Significant Accounting Policies [Line Items]
Percentage share of management rights	50.00%
Percentage share of incentive distribution rights	40.00%
Limited partner ownership interest percentage	54.10%
Limited Partner | CenterPoint | Series A 10% Fixed to Floating Non Cumulative Redeemable Perpetual Preferred Units
Significant Accounting Policies [Line Items]
Series A preferred units held by CenterPoint Energy	14,520,000
Limited Partner | CenterPoint | Common Units
Significant Accounting Policies [Line Items]
Units outstanding	94,151,707
Limited Partner | CenterPoint | Subordinated Units
Significant Accounting Policies [Line Items]
Units outstanding	139,704,916
Limited Partner | OGE Energy
Significant Accounting Policies [Line Items]
Percentage share of management rights	50.00%
Percentage share of incentive distribution rights	60.00%
Limited partner ownership interest percentage	25.70%
Limited Partner | OGE Energy | Common Units
Significant Accounting Policies [Line Items]
Units outstanding	42,832,291
Limited Partner | OGE Energy | Subordinated Units
Significant Accounting Policies [Line Items]
Units outstanding	68,150,514

Earnings Per Limited Partner 33

Earnings Per Limited Partner Unit (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions		3 Months Ended			6 Months Ended
		Jun. 30, 2017		Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net income		$ 96		$ 39	$ 216	$ 125
Net income attributable to noncontrolling interest		1		0	1	0
Series A Preferred Unit distribution		9		4	18	4
General partner interest in net income		0		0	0	0
Net Income Attributable to Common and Subordinated Units (Note 3)		86		35	197	121
Dilutive effect of Series A Preferred Unit distributions		0		0	0	4
Diluted net income		$ 86		$ 35	$ 197	$ 125
Basic weighted average number of outstanding
Basic weighted average number of outstanding		433		422	433	422
Basic earnings per unit
Dilutive effect of Series A Preferred Units (in units)		0		0	0	20
Dilutive effect of performance units (in units)		1		1	1	0
Diluted weighted average number of outstanding units		434		423	434	442
Performance Units, Restricted Units, and Phantom Units
Basic earnings per unit
Dilutive effect of unit-based awards (in dollars per unit) (less than $.01)		$ 0.01		$ 0.01	$ 0.01	$ 0.01
Phantom units
Basic weighted average number of outstanding
Basic weighted average number of outstanding		1	[1]		1
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)		$ 45		$ 18	$ 102	$ 61
Diluted net income		$ 45		$ 18	$ 102	$ 65
Basic weighted average number of outstanding
Basic weighted average number of outstanding	[1]	225		214	225	214
Basic earnings per unit
Basic earnings per unit		$ 0.20		$ 0.08	$ 0.45	$ 0.29
Diluted weighted average number of outstanding units		226		215	226	234
Diluted earnings per unit		$ 0.20		$ 0.08	$ 0.45	$ 0.28
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)		$ 41		$ 17	$ 95	$ 60
Diluted net income		$ 41		$ 17	$ 95	$ 60
Basic weighted average number of outstanding
Basic weighted average number of outstanding		208		208	208	208
Basic earnings per unit
Basic earnings per unit		$ 0.20		$ 0.08	$ 0.46	$ 0.29
Diluted weighted average number of outstanding units		208		208	208	208
Diluted earnings per unit		$ 0.20		$ 0.08	$ 0.46	$ 0.29
[1]	Basic weighted average number of outstanding common units for the three and six months ended June 30, 2017 includes approximately one million time-based phantom units.

Partners' Equity -Schedule of C

Partners' Equity -Schedule of Cash Distributions (Details) - USD ($)

Aug. 29, 2017

Aug. 22, 2017

Aug. 14, 2017

Jul. 31, 2017

May 30, 2017

May 23, 2017

May 12, 2017

May 02, 2017

Feb. 28, 2017

Feb. 21, 2017

Feb. 15, 2017

Feb. 10, 2017

Nov. 22, 2016

Nov. 14, 2016

Nov. 01, 2016

Aug. 23, 2016

Aug. 16, 2016

Aug. 12, 2016

Aug. 02, 2016

May 13, 2016

May 06, 2016

Feb. 12, 2016

Feb. 02, 2016

Distribution Made to Limited Partner [Line Items]

Record Date

May 23, 2017

Feb. 21, 2017

Nov. 14, 2016

Aug. 16, 2016

May 6, 2016

Feb. 2, 2016

Payment Date

May 30, 2017

Feb. 28, 2017

Nov. 22, 2016

Aug. 23, 2016

May 13, 2016

Feb. 12, 2016

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

Distribution Made to Limited Partner [Line Items]

Record Date

May 2, 2017

Feb. 10, 2017

Nov. 1, 2016

Aug. 2, 2016

May 6, 2016

[1]

Payment Date

May 12, 2017

Feb. 15, 2017

Nov. 14, 2016

Aug. 12, 2016

May 13, 2016

[1]

Cash Distribution

Distribution Made to Limited Partner [Line Items]

Per unit distribution, paid (in dollars per unit)

$ 0.318

$ 0.31800

$ 0.31800

$ 0.31800

$ 0.31800

$ 0.318

Distribution made to unitholders

$ 137,000,000

$ 137,000,000

$ 134,000,000

$ 134,000,000

$ 134,000,000

$ 134,000,000

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 (in dollars per unit)

$ 0.62500

$ 0.62500

$ 0.625

$ 0.625

$ 0.2917

[1]

Distribution made to unitholders

$ 9,000,000

$ 9,000,000

$ 9,000,000

$ 9,000,000

$ 4,000,000

[1]

Full quarter equivalent distribution declared (in dollars per unit)

$ 0.625

Annualized distribution declared (in dollars per unit)

$ 2.50

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

Distribution Made to Limited Partner [Line Items]

Record Date

[2]

Jul. 31, 2017

Subsequent Event | Cash Distribution

Distribution Made to Limited Partner [Line Items]

Cash distribution declared (in dollars per unit)

$ 0.318

Subsequent Event | Scenario, Forecast

Distribution Made to Limited Partner [Line Items]

Record Date

[3]

Aug. 22, 2017

Payment Date

[3]

Aug. 29, 2017

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]

Payment Date

[2]

Aug. 14, 2017

Subsequent Event | Scenario, Forecast | Cash Distribution

Distribution Made to Limited Partner [Line Items]

Per unit distribution, paid (in dollars per unit)

[3]

$ 0.31800

Distribution made to unitholders

[3]

$ 138,000,000

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 (in dollars per unit)

[2]

$ 0.62500

Distribution made to unitholders

[2]

$ 9,000,000

Cash distribution declared (in dollars per unit)

$ 0.625000000

[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 a $0.625 per Series A Preferred Unit cash distribution on July 31, 2017, to be paid on August 14, 2017, to Series A Preferred unitholders of record at the close of business on July 31, 2017.

[3]

The board of directors of Enable GP declared this $0.318 per common unit cash distribution on July 31, 2017, to be paid on August 29, 2017, to common and subordinated unitholders of record at the close of business on August 22, 2017.

Partners' Equity Textual (Detai

Partners' Equity Textual (Details) $ / shares in Units, $ in Thousands	May 12, 2017USD ($)	Nov. 29, 2016USD ($)$ / sharesshares	Feb. 18, 2016USD ($)$ / sharesshares	Jun. 30, 2017USD ($)shares	Jun. 30, 2017USD ($)$ / sharesshares	Jun. 30, 2016USD ($)	Aug. 30, 2017shares	Dec. 31, 2016shares
Distribution Made to Limited Partner [Line Items]
Limited partners' capital account, required quarterly distribution period					60 days
Limited partners capital account, minimum quarterly distribution, annualized					150.00%
Proceeds from issuance of Series A Preferred Units, net of issuance costs					$ 0	$ 362,000
Repayment of notes payable—affiliated companies					$ 0	$ 363,000
Number of common units sold | shares		75,719
Subordinated Units
Distribution Made to Limited Partner [Line Items]
Units outstanding | shares				207,855,430	207,855,430			207,855,430
Subsequent Event | Subordinated Units | Scenario, Forecast
Distribution Made to Limited Partner [Line Items]
Units outstanding | shares							207,855,430
Conversion basis							1
CenterPoint | Limited Partner
Distribution Made to Limited Partner [Line Items]
Repayment of notes payable—affiliated companies			$ 363,000
ATM Program
Distribution Made to Limited Partner [Line Items]
Expenses related to the offering				$ 345	$ 345
Aggregate offering price	$ 200,000
Number of common units sold | shares				18,500	18,500
Proceeds received from the offering				$ 303	$ 303
Commissions				$ 3	$ 3
Public Offering
Distribution Made to Limited Partner [Line Items]
Number of common units sold | shares		10,000,000
Price per common unit | $ / shares		$ 14
Proceeds received from the offering		$ 137,000
Over-Allotment Option
Distribution Made to Limited Partner [Line Items]
Number of common units sold | shares		1,500,000
Over-Allotment Option | Affiliate of ArcLight Capital Partners, LLC
Distribution Made to Limited Partner [Line Items]
Number of common units sold | shares		1,424,281
Series A 10% Fixed to Floating Non Cumulative Redeemable Perpetual Preferred Units
Distribution Made to Limited Partner [Line Items]
Annual distribution percentage rate			10.00%
Liquidation preference (in dollars per unit) | $ / shares			$ 25
Period after date of original issue			5 years
Redemption price (in dollars per unit) | $ / shares			$ 25.50
Series A 10% Fixed to Floating Non Cumulative Redeemable Perpetual Preferred Units | LIBOR
Distribution Made to Limited Partner [Line Items]
Annual distribution percentage 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 | shares			14,520,000
Cash purchase price (in dollars per unit) | $ / shares			$ 25
Proceeds from issuance of Series A Preferred Units, net of issuance costs			$ 362,000
Expenses related to the offering			$ 1,000
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 | shares			14,520,000
Cash purchase price (in dollars per unit) | $ / shares			$ 25
Proceeds from issuance of Series A Preferred Units, net of issuance costs			$ 362,000
Distribution Subordination Period 1
Distribution Made to Limited Partner [Line Items]
Limited partners' capital account, minimum annualized quarterly distribution (in dollars per unit) | $ / shares					$ 1.15
Distribution Subordination Period 2
Distribution Made to Limited Partner [Line Items]
Limited partners' capital account, maximum annualized quarterly distribution (in dollars per unit) | $ / shares					$ 1.725
Maximum
Distribution Made to Limited Partner [Line Items]
Limited partners' capital account, incentive distribution rights, percentage					50.00%
Minimum
Distribution Made to Limited Partner [Line Items]
Incentive distribution, distribution (in dollars per unit) | $ / shares					$ 0.330625

Assessing Impairment of Long-36

Assessing Impairment of Long-lived Assets (including Intangible Assets) - Narrative (Details) - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Goodwill and Intangible Assets Disclosure [Abstract]
Impairments to long-lived assets	$ 0	$ 0	$ 0	$ 0

Investment in Equity Method A37

Investment in Equity Method Affiliate - Narrative (Details) - SESH - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Schedule of Equity Method Investments [Line Items]
Ownership percentage	50.00%		50.00%
Percentage of distributions through limited partner interest			50.00%
Equity Method Investee | Shared Operations Service Agreements
Schedule of Equity Method Investments [Line Items]
Amount billed associated with service agreements	$ 6	$ 5	$ 11	$ 9

Investment in Equity Method A38

Investment in Equity Method Affiliate - Schedule of Investments (Details) - USD ($) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Equity in Earnings of Equity Method Affiliates:
Equity in earnings of equity method affiliate		$ 7	$ 7	$ 14	$ 14
Distributions from Equity Method Affiliates:
Return on investment in equity method affiliate				14	14
Return of investment in equity method affiliate				5	13
SESH
Equity in Earnings of Equity Method Affiliates:
Equity in earnings of equity method affiliate		7	7	14	14
Distributions from Equity Method Affiliates:
Distributions from equity method affiliate	[1]	8	7	19	27
Return on investment in equity method affiliate		7	7	14	14
Return of investment in equity method affiliate		1	0	5	13
Revenues		28	28	56	57
Operating income		18	18	35	37
Net income		$ 13	$ 14	$ 26	$ 28
[1]	Distributions from equity method affiliate includes a $14 million and $14 million return on investment and a $5 million and $13 million return of investment for the six months ended June 30, 2017 and 2016, respectively.

Debt - Schedule of Outstanding

Debt - Schedule of Outstanding Debt (Details) - USD ($) $ in Millions		Jun. 30, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Outstanding Principal		$ 3,050	$ 2,986
Premium (Discount)		12	17
Total Debt		3,062	3,003
Less: Unamortized debt expense	[1]	16	10
Total long-term debt		3,046	2,993
2015 Term Loan Agreement | 2015 Term Loan Agreement
Debt Instrument [Line Items]
Outstanding Principal		450	450
Premium (Discount)		0	0
Total Debt		450	450
Senior Notes | 2019 Notes
Debt Instrument [Line Items]
Outstanding Principal		500	500
Premium (Discount)		0	0
Total Debt		500	500
Senior Notes | 2024 Notes
Debt Instrument [Line Items]
Outstanding Principal		600	600
Premium (Discount)		0	(1)
Total Debt		600	599
Senior Notes | 2027 Notes
Debt Instrument [Line Items]
Outstanding Principal		700	0
Premium (Discount)		(3)	0
Total Debt		697	0
Less: Unamortized debt expense		6
Senior Notes | 2044 Notes
Debt Instrument [Line Items]
Outstanding Principal		550	550
Premium (Discount)		0	0
Total Debt		550	550
Senior Notes | EOIT Senior Notes | EOIT
Debt Instrument [Line Items]
Outstanding Principal		250	250
Premium (Discount)		15	18
Total Debt		265	268
Revolving Credit Facility
Debt Instrument [Line Items]
Outstanding Principal		0	636
Premium (Discount)		0	0
Total Debt		0	636
Unamortized debt expense related to Revolving Credit Facility		$ 4	$ 5
[1]	As of June 30, 2017 and December 31, 2016, there was an additional $4 million and $5 million, respectively, of unamortized debt expense related to the Revolving Credit Facility included in Other long-term assets, not included above.

Debt - Narrative (Details)

Debt - Narrative (Details)		Mar. 09, 2017USD ($)	Jul. 31, 2015USD ($)time	Jun. 18, 2015USD ($)time	Jun. 30, 2017USD ($)	Dec. 31, 2016USD ($)
Debt Instrument [Line Items]
Commercial paper, authorized					$ 1,400,000,000
Unamortized debt expense	[1]				16,000,000	$ 10,000,000
Outstanding Principal					3,050,000,000	2,986,000,000
Term loan facility | 2015 Term Loan Agreement
Debt Instrument [Line Items]
Number of times option maybe exercised to extend term of Term Loan Facility | time			2
Extension period			1 year
Duration of term loan facility			3 years
Amount of loan agreement			$ 450,000,000
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
Term loan facility					$ 450,000,000
Weighted average interest rate percentage					2.27%
Term loan facility | LIBOR | 2015 Term Loan Agreement
Debt Instrument [Line Items]
Applicable margin percentage					1.375%
Senior Notes | 2027 Notes
Debt Instrument [Line Items]
Amount of loan agreement		$ 700,000,000
Fixed interest rate percentage		4.40%
Net proceeds		$ 691,000,000
Unamortized discount					$ 3,000,000
Unamortized debt expense					6,000,000
Outstanding Principal					$ 700,000,000	0
Effective interest rate percentage					4.58%
Senior Notes | Senior Notes including 2019 Notes, 2024 Notes, and 2044 Notes
Debt Instrument [Line Items]
Unamortized debt expense					$ 10,000,000
Senior Notes | 2019 Notes
Debt Instrument [Line Items]
Outstanding Principal					$ 500,000,000	500,000,000
Effective interest rate percentage					2.58%
Senior Notes | 2024 Notes
Debt Instrument [Line Items]
Outstanding Principal					$ 600,000,000	600,000,000
Effective interest rate percentage					4.02%
Senior Notes | 2044 Notes
Debt Instrument [Line Items]
Outstanding Principal					$ 550,000,000	550,000,000
Effective interest rate percentage					5.08%
Senior Notes | EOIT Senior Notes | EOIT
Debt Instrument [Line Items]
Fixed interest rate percentage					6.25%
Outstanding Principal					$ 250,000,000	250,000,000
Unamortized premium					$ 15,000,000
Effective interest rate percentage					3.83%
Commercial Paper
Debt Instrument [Line Items]
Commercial paper outstanding					$ 0	0
Revolving Credit Facility
Debt Instrument [Line Items]
Maximum borrowing capacity				$ 1,750,000,000
Number of times option maybe exercised to extend term of Term Loan Facility | time				2
Extension period				1 year
Letters of credit principal advances					0
Letters of credit outstanding amount					$ 3,000,000
Commitment fee percentage					0.20%
Outstanding Principal					$ 0	$ 636,000,000
Revolving Credit Facility | LIBOR
Debt Instrument [Line Items]
Applicable margin percentage					1.50%
[1]	As of June 30, 2017 and December 31, 2016, there was an additional $4 million and $5 million, respectively, of unamortized debt expense related to the Revolving Credit Facility included in Other long-term assets, not included above.

Derivative Instruments and He41

Derivative Instruments and Hedging Activities (Details) - Not Designated as Hedging Instrument bbl in Thousands, MMBTU in Millions		6 Months Ended
		Jun. 30, 2017MMBTUbbl	Jun. 30, 2016MMBTUbbl	Dec. 31, 2016
Natural Gas, Financial fixed futures/swaps | Purchases
Derivative [Line Items]
Derivative, gross notional volume (TBtu)	[1]	17	2
Natural Gas, Financial fixed futures/swaps | Sales
Derivative [Line Items]
Derivative, gross notional volume (TBtu)	[1]	21	29
Natural gas, Financial basis futures/swaps | Purchases
Derivative [Line Items]
Derivative, gross notional volume (TBtu)	[1]	17	2
Natural gas, Financial basis futures/swaps | Sales
Derivative [Line Items]
Derivative, gross notional volume (TBtu)	[1]	25	30
Physical purchases/sales | Purchases
Derivative [Line Items]
Derivative, gross notional volume (TBtu)	[1]	2	1
Physical purchases/sales | Sales
Derivative [Line Items]
Derivative, gross notional volume (TBtu)	[1]	50	25
Crude oil, Financial Futures/swaps | Purchases
Derivative [Line Items]
Derivative, gross notional volume (MMbl) | bbl	[2]	0	0
Crude oil, Financial Futures/swaps | Sales
Derivative [Line Items]
Derivative, gross notional volume (MMbl) | bbl	[2]	330	540
Natural gas liquids, Financial Futures/swaps | Purchases
Derivative [Line Items]
Derivative, gross notional volume (MMbl) | bbl	[3]	0	60
Natural gas liquids, Financial Futures/swaps | Sales
Derivative [Line Items]
Derivative, gross notional volume (MMbl) | bbl	[3]	1,310	1,133
Natural gas
Derivative [Line Items]
Percent of contract with durations of one year or less		67.00%		100.00%
Percent of contracts with durations of more than one year and less than two years		14.20%
Percent of contracts with durations of more than two years		18.80%
Condensate
Derivative [Line Items]
Percent of contract with durations of one year or less		100.00%		100.00%
Natural gas liquids
Derivative [Line Items]
Percent of contract with durations of one year or less		61.10%		100.00%
Percent of contracts with durations of more than one year and less than two years		38.90%
[1]	As of June 30, 2017, 67.0% of the natural gas contracts had durations of one year or less, 14.2% had durations of more than one year and less than two years and 18.8% had durations of more than two years. As of December 31, 2016, 100.0% of the natural gas contracts had durations of one year or less.
[2]	As of June 30, 2017 and December 31, 2016, 100% of the crude oil (for condensate) contracts had durations of one year or less.
[3]	As of June 30, 2017, 61.1% of the natural gas liquids contracts had durations of one year or less and 38.9% had durations of more than one year and less than two years. As of December 31, 2016, 100% of the natural gas liquid contracts had durations of one year or less.

Derivative Instruments and He42

Derivative Instruments and Hedging Activities - Balance Sheet Location (Details) - USD ($)		Jun. 30, 2017	Dec. 31, 2016
Designated as Hedging Instrument
Derivatives, Fair Value [Line Items]
Derivative instruments designated as cash flow hedges or fair value hedges		$ 0	$ 0
Not Designated as Hedging Instrument
Derivatives, Fair Value [Line Items]
Assets	[1]	8,000,000	2,000,000
Liabilities	[1]	5,000,000	34,000,000
Natural gas | Financial futures/swaps | Not Designated as Hedging Instrument | Other Current, Assets
Derivatives, Fair Value [Line Items]
Assets		4,000,000	2,000,000
Natural gas | Financial futures/swaps | Not Designated as Hedging Instrument | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Liabilities		3,000,000	22,000,000
Natural gas | Physical purchases/sales | Not Designated as Hedging Instrument | Other Current, Assets
Derivatives, Fair Value [Line Items]
Assets		2,000,000	0
Natural gas | Physical purchases/sales | Not Designated as Hedging Instrument | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Liabilities		0	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	0
Crude oil (for condensate) | Financial futures/swaps | Not Designated as Hedging Instrument | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Liabilities		0	3,000,000
Natural gas liquids | Financial futures/swaps | Not Designated as Hedging Instrument | Other Current, Assets
Derivatives, Fair Value [Line Items]
Assets		0	0
Natural gas liquids | Financial futures/swaps | Not Designated as Hedging Instrument | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Liabilities		$ 2,000,000	$ 8,000,000
[1]	See Note 9 for a reconciliation of the Partnership’s total derivatives fair value to the Partnership’s Condensed Consolidated Balance Sheets as of June 30, 2017 and December 31, 2016.

Derivative Instruments and He43

Derivative Instruments and Hedging Activities - Amounts Recognized in Income (Details) - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivative, net	$ 9,000,000	$ (34,000,000)	$ 30,000,000	$ (31,000,000)
Change in fair value of derivatives	11,000,000	(39,000,000)	35,000,000	(47,000,000)
Realized gain (loss) on derivatives	(2,000,000)	5,000,000	(5,000,000)	16,000,000
Gain (loss) on derivative activity	9,000,000	(34,000,000)	30,000,000	(31,000,000)
Cash collateral posted	0		0
Cash collateral required if ratings are lowered	0		0
Natural gas | Financial futures/swaps
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivative, net	5,000,000	(21,000,000)	16,000,000	(11,000,000)
Natural gas | Physical purchases/sales
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivative, net	2,000,000	(4,000,000)	7,000,000	(8,000,000)
Condensate | Financial futures/swaps
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivative, net	2,000,000	(4,000,000)	5,000,000	(3,000,000)
Natural gas liquids | Financial futures/swaps
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivative, net	$ 0	$ (5,000,000)	$ 2,000,000	$ (9,000,000)

Fair Value Measurements - Carry

Fair Value Measurements - Carrying and Fair Value Amounts (Details) - Significant other observable inputs (Level 2) - USD ($) $ in Millions	Jun. 30, 2017	Dec. 31, 2016
Carrying Amount | 2015 Term Loan Agreement | 2015 Term Loan Agreement
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
2015 Term Loan Agreement (Level 2)	$ 450	$ 450
Carrying Amount | Senior Notes | 2019 Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes (Level 2)	500	500
Carrying Amount | Senior Notes | 2024 Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes (Level 2)	600	599
Carrying Amount | Senior Notes | 2027 Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes (Level 2)	697	0
Carrying Amount | Senior Notes | 2044 Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes (Level 2)	550	550
Carrying Amount | Senior Notes | EOIT Senior Notes | EOIT
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes (Level 2)	265	268
Carrying Amount | Revolving Credit Facility
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Revolving Credit Facility (Level 2)	0	636
Fair Value | 2015 Term Loan Agreement | 2015 Term Loan Agreement
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
2015 Term Loan Agreement (Level 2)	450	450
Fair Value | Senior Notes | 2019 Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes (Level 2)	496	490
Fair Value | Senior Notes | 2024 Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes (Level 2)	595	564
Fair Value | Senior Notes | 2027 Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes (Level 2)	705	0
Fair Value | Senior Notes | 2044 Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes (Level 2)	521	467
Fair Value | Senior Notes | EOIT Senior Notes | EOIT
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes (Level 2)	264	260
Fair Value | Revolving Credit Facility
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Revolving Credit Facility (Level 2)	$ 0	$ 636

Fair Value Measurements - Fair

Fair Value Measurements - Fair Value Hierarchy (Details) - USD ($) $ in Millions		Jun. 30, 2017	Dec. 31, 2016
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Retained fuel due from shippers		$ 1	$ 0
Over retained fuel due from shippers		2	5
Commodity Contracts | Recurring Measurement
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, total fair value		8	2
Liabilities, total fair value		5	34
Assets		(4)	0
Liabilities		(4)	0
Assets		4	2
Liabilities		1	34
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		4	2
Liabilities		3	22
Commodity Contracts | Recurring Measurement | Significant other observable inputs (Level 2)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets		4	0
Liabilities		0	4
Commodity Contracts | Recurring Measurement | Unobservable inputs (Level 3)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets		0	0
Liabilities		2	8
Gas Imbalances | Recurring Measurement
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, total fair value	[1],[2]	22	41
Liabilities, total fair value	[2],[3]	7	30
Assets	[1],[2]	0	0
Liabilities	[2],[3]	0	0
Assets	[1],[2]	22	41
Liabilities	[2],[3]	7	30
Gas Imbalances | Recurring Measurement | Quoted market prices in active market for identical assets (Level 1)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets	[1],[2]	0	0
Liabilities	[2],[3]	0	0
Gas Imbalances | Recurring Measurement | Significant other observable inputs (Level 2)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets	[1],[2]	22	41
Liabilities	[2],[3]	7	30
Gas Imbalances | Recurring Measurement | Unobservable inputs (Level 3)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets	[1],[2]	0	0
Liabilities	[2],[3]	$ 0	$ 0
[1]	Gas imbalance assets exclude fuel reserves for under retained fuel due from shippers of $1 million and zero at June 30, 2017 and December 31, 2016, 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, 2017 and December 31, 2016.
[3]	Gas imbalance liabilities exclude fuel reserves for over retained fuel due to shippers of $2 million and $5 million at June 30, 2017 and December 31, 2016, 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 - Sched

Fair Value Measurements - Schedule of Changes in Fair Value of Level 3 Financial Instruments (Details) - Commodity Contracts - Natural gas liquids financial futures/swaps $ in Millions	6 Months Ended
	Jun. 30, 2017USD ($)
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Balance as of December 31, 2016	$ (8)
Gains included in earnings	2
Settlements	4
Balance as of June 30, 2017	$ (2)

Fair Value Measurements - Sch47

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, 2017USD ($)$ / gal
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Liabilities | $	$ (2)
Minimum
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Forward Curve Range (in dollars per gallon)	0.264
Maximum
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Forward Curve Range (in dollars per gallon)	0.757

- Supplemental Disclosure of Ca

- Supplemental Disclosure of Cash Flow Information (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016
Supplemental Cash Flow Information [Abstract]
Interest, net of capitalized interest	$ 50	$ 51
Income taxes, net of refunds	0	1
Accounts payable related to capital expenditures	$ 24	$ 24

Supplemental Disclosure of Ca49

Supplemental Disclosure of Cash Flow Information - Reconciliation of Cash and Cash Equivalents and Restricted Cash (Details) - USD ($) $ in Millions	Jun. 30, 2017	Dec. 31, 2016	Jun. 30, 2016	Dec. 31, 2015
Supplemental Cash Flow Elements [Abstract]
Cash and cash equivalents	$ 7	$ 6	$ 6
Restricted cash	14	17	0
Cash, cash equivalents and restricted cash shown in the Condensed Consolidated Statements of Cash Flows	$ 21	$ 23	$ 6	$ 4

Related Party Transactions - Na

Related Party Transactions - Narrative (Details) $ / shares in Units, $ in Millions	Dec. 06, 2016mi	Feb. 18, 2016USD ($)$ / sharesshares	Jun. 30, 2017USD ($)	Jun. 30, 2016	Jun. 30, 2017USD ($)	Jun. 30, 2016USD ($)
Related Party Transaction [Line Items]
Partnership's revenues from affiliated companies as a percent of total revenues			5.00%	7.00%	6.00%	8.00%
Proceeds from issuance of Series A Preferred Units, net of issuance costs					$ 0	$ 362
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 | shares		14,520,000
Cash purchase price (in dollars per unit) | $ / shares		$ 25
Proceeds from issuance of Series A Preferred Units, net of issuance costs		$ 362
Subsidiary of Common Parent | OGE Energy | Transportation Agreement between OGE Energy and Enable Oklahoma Intrastate Transmission, LLC | Pipelines
Related Party Transaction [Line Items]
Term of transportation and storage agreement	20 years
Length of pipeline (in miles) | mi	80
Subsidiary of Common Parent | CenterPoint | Three Services Included in Transportation and Storage Agreements
Related Party Transaction [Line Items]
Period of written notice					180 days
CenterPoint and OGE Energy | Minimum
Related Party Transaction [Line Items]
Period notice of termination for reimbursements for all employee costs					90 days
OGE Energy
Related Party Transaction [Line Items]
Period notice of termination prior to commencement of succeeding annual period					180 days
OGE Energy | Minimum
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, 2017					$ 5
Expense reimbursement, 2018					5
Expense reimbursement, thereafter					5
OGE Energy | Certain Services and Support Functions
Related Party Transaction [Line Items]
Expense reimbursement annual caps					4
CenterPoint
Related Party Transaction [Line Items]
Notes payable affiliated companies outstanding		$ 363
CenterPoint | Certain Services and Support Functions
Related Party Transaction [Line Items]
Expense reimbursement annual caps					3
Affiliated Entity | CenterPoint | Lease Agreement with Affiliate of CenterPoint Energy
Related Party Transaction [Line Items]
Rent and maintenance expenses			$ 3		$ 3
Limited Partner | CenterPoint | 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 | shares		14,520,000
Cash purchase price (in dollars per unit) | $ / shares		$ 25
Proceeds from issuance of Series A Preferred Units, net of issuance costs		$ 362

Related Party Transactions - Re

Related Party Transactions - Related Party Activity (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Related Party Transaction [Line Items]
Revenues from affiliated companies	$ 34	$ 38	$ 76	$ 82
Cost of goods sold from affiliate	5	3	8	5
Charges to the Partnership by affiliates	11	12	20	25
CenterPoint
Related Party Transaction [Line Items]
Cost of goods sold from affiliate	1	0	1	0
CenterPoint | Gas Transportation and Storage
Related Party Transaction [Line Items]
Revenues from affiliated companies	24	24	57	57
CenterPoint | Gas Sales
Related Party Transaction [Line Items]
Revenues from affiliated companies	1	0	1	1
CenterPoint | Corporate Services
Related Party Transaction [Line Items]
Charges to the Partnership by affiliates	1	3	2	5
OGE Energy
Related Party Transaction [Line Items]
Cost of goods sold from affiliate	4	3	7	5
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	0	5	0	6
OGE Energy | Corporate Services
Related Party Transaction [Line Items]
Charges to the Partnership by affiliates	1	1	2	3
OGE Energy | Seconded Employee Costs
Related Party Transaction [Line Items]
Charges to the Partnership by affiliates	$ 9	$ 8	$ 16	$ 17

Equity-Based Compensation (Deta

Equity-Based Compensation (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	$ 4	$ 3	$ 8	$ 5
Performance units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	2	2	5	3
Restricted units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	1	1	1	1
Phantom units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	$ 1	$ 0	$ 2	$ 1

Equity-Based Compensation - Equ

Equity-Based Compensation - Equity Units Activity (Details) $ / shares in Units, $ in Millions	6 Months Ended
	Jun. 30, 2017USD ($)$ / sharesshares
Performance units
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Units Outstanding (in units)	1,969,107
Granted (in units)	468,626
Vested (in units)	(334,682)
Forfeited (in units)	(42,150)
Units Outstanding (in units)	2,060,901
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Units Outstanding (in dollars per unit) | $ / shares	$ 15.27
Granted (in dollars per unit) | $ / shares	19.27
Vested (in dollars per unit) | $ / shares	29.61
Forfeited (in dollars per unit) | $ / shares	14.93
Units Outstanding (in dollars per unit) | $ / shares	$ 13.86
Aggregate Intrinsic Value of Units Outstanding | $	$ 33
Performance units | Minimum
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Payout percentage	0.00%
Performance units | Maximum
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Payout percentage	200.00%
Performance units | Annual Grant in 2014
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Granted (in units)	334,682
Vested (in units)	(306,170)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Payout percentage	91.50%
Restricted units
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Units Outstanding (in units)	392,995
Granted (in units)	0
Vested (in units)	(148,735)
Forfeited (in units)	(7,038)
Units Outstanding (in units)	237,222
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Units Outstanding (in dollars per unit) | $ / shares	$ 20.74
Granted (in dollars per unit) | $ / shares	0
Vested (in dollars per unit) | $ / shares	25.50
Forfeited (in dollars per unit) | $ / shares	19.60
Units Outstanding (in dollars per unit) | $ / shares	$ 17.80
Aggregate Intrinsic Value of Units Outstanding | $	$ 4
Phantom units
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Units Outstanding (in units)	643,604
Granted (in units)	377,979
Vested (in units)	(1,869)
Forfeited (in units)	(12,420)
Units Outstanding (in units)	1,007,294
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Units Outstanding (in dollars per unit) | $ / shares	$ 8.49
Granted (in dollars per unit) | $ / shares	16.26
Vested (in dollars per unit) | $ / shares	8.12
Forfeited (in dollars per unit) | $ / shares	10.28
Units Outstanding (in dollars per unit) | $ / shares	$ 11.38
Aggregate Intrinsic Value of Units Outstanding | $	$ 16

Equity-Based Compensation - Unr

Equity-Based Compensation - Unrecognized Compensation Cost (Details) $ in Millions	6 Months Ended
	Jun. 30, 2017USD ($)shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized Compensation Cost (In millions)	$ 27
Performance units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized Compensation Cost (In millions)	$ 18
Weighted Average to be Recognized (In years)	1 year 9 months 15 days
Restricted units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized Compensation Cost (In millions)	$ 1
Weighted Average to be Recognized (In years)	11 months 5 days
Phantom units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized Compensation Cost (In millions)	$ 8
Weighted Average to be Recognized (In years)	2 years 22 days
Long Term Incentive Plan | Common Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares available for issuance | shares	8,653,478

Reportable Segments - Schedule

Reportable Segments - Schedule of Financial Data for Business Segments and Services (Details) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2017USD ($)	Jun. 30, 2016USD ($)	Jun. 30, 2017USD ($)segment	Jun. 30, 2016USD ($)	Dec. 31, 2016USD ($)
Segment Reporting Information [Line Items]
Number of reportable segments | segment				2
Product sales		$ 354	$ 266	$ 740	$ 511
Service revenue		272	263	552	527
Total Revenues		626	529	1,292	1,038
Cost of goods sold, excluding depreciation and amortization		279	254	587	449
Operation and maintenance, General and administrative		120	120	234	235
Depreciation and amortization		89	83	177	164
Taxes other than income tax		16	15	32	30
Operating Income		122	57	262	160
Total assets		11,131		11,131		$ 11,212
Capital expenditures		87	91	148	221
Operating Segments | Gathering and Processing
Segment Reporting Information [Line Items]
Product sales		336	256	687	464
Service revenue		144	131	284	256
Total Revenues		480	387	971	720
Cost of goods sold, excluding depreciation and amortization		269	231	555	396
Operation and maintenance, General and administrative		75	67	145	142
Depreciation and amortization		55	52	111	101
Taxes other than income tax		9	8	18	16
Operating Income		72	29	142	65
Total assets		8,612		8,612		7,453
Capital expenditures		39	79	90	200
Operating Segments | Transportation and Storage
Segment Reporting Information [Line Items]
Product sales	[1]	134	92	287	198
Service revenue	[1]	129	133	270	273
Total Revenues	[1]	263	225	557	471
Cost of goods sold, excluding depreciation and amortization	[1]	127	106	267	205
Operation and maintenance, General and administrative	[1]	45	53	90	94
Depreciation and amortization	[1]	34	31	66	63
Taxes other than income tax	[1]	7	7	14	14
Operating Income	[1]	50	28	120	95
Total assets	[1]	5,516		5,516		4,963
Capital expenditures	[1]	48	12	58	21
Eliminations
Segment Reporting Information [Line Items]
Product sales		(116)	(82)	(234)	(151)
Service revenue		(1)	(1)	(2)	(2)
Total Revenues		(117)	(83)	(236)	(153)
Cost of goods sold, excluding depreciation and amortization		(117)	(83)	(235)	(152)
Operation and maintenance, General and administrative		0	0	(1)	(1)
Depreciation and amortization		0	0	0	0
Taxes other than income tax		0	0	0	0
Operating Income		0	0	0	0
Total assets		(2,997)		(2,997)		$ (1,204)
Capital expenditures		$ 0	$ 0	$ 0	$ 0
[1]	See Note 6 for discussion regarding ownership interests in SESH and related equity earnings included in the transportation and storage segment for the three and six months ended June 30, 2017 and 2016.