Enable Midstream Partners (ENBL) 10-Q2 May 182018 Q1 Quarterly reportFinancial data

Company Profile

Document and Entity Information

Document and Entity Information - shares	3 Months Ended
Document and Entity Information - shares	Mar. 31, 2018	Apr. 13, 2018
Document and Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2018
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	Q1
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		433,074,409

Condensed Consolidated Statemen

Condensed Consolidated Statements of Income (Unaudited) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Revenues (including revenues from affiliates (Note 12)):
Product sales	$ 443	$ 386
Service revenues	305	280
Total Revenues	748	666
Cost and Expenses (including expenses from affiliates (Note 12)):
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)	375	308
Operation and maintenance	94	89
General and administrative	27	25
Depreciation and amortization	96	88
Taxes other than income tax	17	16
Total Cost and Expenses	609	526
Operating Income	139	140
Other Income (Expense):
Interest expense	(33)	(27)
Equity in earnings of equity method affiliate	6	7
Other Nonoperating Income (Expense)	2	1
Total Other Expense	(25)	(19)
Income Before Income Tax
Income Before Income Tax	114	121
Income tax expense	0	1
Net Income
Net Income	114	120
Less: Net income attributable to noncontrolling interest
Less: Net income attributable to noncontrolling interest	0	0
Net Income Attributable to Limited Partners
Net Income Attributable to Limited Partners	114	120
Less: Series A Preferred Unit distributions (Note 6)
Less: Series A Preferred Unit distributions (Note 6)	9	9
Net Income Attributable to Common and Subordinated Units (Note 5)
Net Income Attributable to Common and Subordinated Units (Note 5)	105	111
Common Units
Net Income Attributable to Common and Subordinated Units (Note 5)
Net Income Attributable to Common and Subordinated Units (Note 5)	$ 105	$ 58
Basic and Diluted earnings (loss) per unit and weighted average number of units outstanding
Basic earnings per unit (Note 5)	$ 0.24	$ 0.26
Diluted earnings per unit (Note 5)	$ 0.24	$ 0.26
Subordinated Units
Net Income Attributable to Common and Subordinated Units (Note 5)
Net Income Attributable to Common and Subordinated Units (Note 5)	$ 0	$ 53
Basic and Diluted earnings (loss) per unit and weighted average number of units outstanding
Basic earnings per unit (Note 5)	$ 0	$ 0.25
Diluted earnings per unit (Note 5)	$ 0	$ 0.25

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets (Unaudited) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Current Assets:
Cash and cash equivalents	$ 30	$ 5
Restricted cash	14	14
Accounts receivable, net of allowance for doubtful accounts	253	277
Accounts receivable—affiliated companies	19	18
Inventory	39	40
Gas imbalances	35	37
Other current assets	23	25
Total current assets	413	416
Property, Plant and Equipment:
Property, plant and equipment	12,273	12,079
Less accumulated depreciation and amortization	1,805	1,724
Property, plant and equipment, net	10,468	10,355
Other Assets:
Intangible assets, net	440	451
Goodwill	12	12
Investment in equity method affiliate	317	324
Other	37	35
Total other assets	806	822
Total Assets	11,687	11,593
Current Liabilities:
Accounts payable	209	263
Accounts payable—affiliated companies	5	3
Current portion of long-term debt	450	450
Short-term debt	595	405
Taxes accrued	26	32
Gas imbalances	8	12
Other	111	114
Total current liabilities	1,404	1,279
Other Liabilities:
Accumulated deferred income taxes, net	6	6
Regulatory liabilities	21	21
Other	43	38
Total other liabilities	70	65
Long-Term Debt	2,594	2,595
Commitments and Contingencies (Note 13)
Partners’ Equity:
Series A Preferred Units (14,520,000 issued and outstanding at March 31, 2018 and December 31, 2017)	362	362
Common units	7,246	7,280
Noncontrolling interest	11	12
Total Partners’ Equity	7,619	7,654
Total Liabilities and Partners’ Equity	$ 11,687	$ 11,593

Condensed Consolidated Balance4

Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) - shares	Mar. 31, 2018	Dec. 31, 2017
Common Units
Common and Subordinated units issued	433,072,001	432,584,080
Common units and Subordinated units outstanding	433,072,001	432,584,080
Subordinated Units
Common and Subordinated units issued	0	0
Common units and Subordinated units outstanding	0	0
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	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Cash Flows from Operating Activities:
Net income	$ 114	$ 120
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	96	88
Deferred income taxes	0	1
Loss on sale/retirement of assets	1	1
Equity in earnings of equity method affiliate	(6)	(7)
Return on investment in equity method affiliate	6	7
Equity-based compensation	5	4
Amortization of debt costs and discount (premium)	0	(1)
Changes in other assets and liabilities:
Accounts receivable, net	24	18
Accounts receivable—affiliated companies	(1)	(8)
Inventory	1	1
Gas imbalance assets	2	17
Other current assets	(4)	1
Other assets	(3)	2
Accounts payable	(62)	(55)
Accounts payable—affiliated companies	2	0
Gas imbalance liabilities	(4)	(17)
Other current liabilities	(6)	(16)
Other liabilities	1	0
Net cash provided by operating activities	166	156
Cash Flows from Investing Activities:
Capital expenditures	(190)	(61)
Proceeds from sale of assets	7	1
Return of investment in equity method affiliate	7	4
Net cash used in investing activities	(176)	(56)
Cash Flows from Financing Activities:
Proceeds from long term debt, net of issuance costs	0	691
Proceeds from revolving credit facility	0	264
Repayment of revolving credit facility	0	(900)
Increase in short-term debt	190	0
Distributions	(150)	(147)
Cash taxes paid for employee equity-based compensation	(5)	0
Net cash provided by (used in) financing activities	35	(92)
Net Increase in Cash, Cash Equivalents and Restricted Cash	25	8
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	19	23
Cash, Cash Equivalents and Restricted Cash at End of Period	$ 44	$ 31

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, 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	120	0	$ 9	$ 58	$ 53
Distributions	(147)	0	(9)	(72)	(66)
Equity-based compensation, net of units for employee taxes	4			4
Balance, end of period at Mar. 31, 2017	7,771	12	$ 362	$ 3,727	$ 3,670
Balance, end of period, units at Mar. 31, 2017			15	224	208
Balance, beginning of period at Dec. 31, 2017	7,654	12	$ 362	$ 7,280	$ 0
Balance, beginning of period, units at Dec. 31, 2017			15	433	0
Changes in Partners' Capital
Net Income	114		$ 9	$ 105	$ 0
Distributions	(149)	(1)	(9)	(139)	0
Balance, end of period at Mar. 31, 2018	$ 7,619	$ 11	$ 362	$ 7,246	$ 0
Balance, end of period, units at Mar. 31, 2018			15	433	0

Summary of Significant Accounti

Summary of Significant Accounting Policies	3 Months Ended
Summary of Significant Accounting Policies	Mar. 31, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Summary of Significant Accounting Policies	Summary of Significant Accounting Policies Organization Enable Midstream Partners, LP 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 March 31, 2018 , CenterPoint Energy held approximately 54.0% or 233,856,623 of the Partnership’s common units, and OGE Energy held approximately 25.6% or 110,982,805 of the Partnership’s common units. Additionally, CenterPoint Energy holds 14,520,000 Series A Preferred Units. See Note 6 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 on an annual or continuing basis and may not remove Enable GP, its current general partner, 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 March 31, 2018 , the Partnership owned a 50% interest in SESH. See Note 7 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. The condensed consolidated financial statements and the related notes 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 15. 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 primarily consists of cash collateral which is provided as credit assurance by third parties. The Condensed Consolidated Balance Sheets have $14 million of restricted cash at each of March 31, 2018 and December 31, 2017 . 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 $2 million allowance for doubtful accounts was required at March 31, 2018 and a $3 million allowance at December 31, 2017 . Inventory Natural gas inventory is held, through the transportation and storage segment, to provide operational support for the intrastate pipeline deliveries and to manage leased intrastate storage capacity. Natural gas liquids inventory is held, through the gathering and processing segment, due to timing differences between the production of certain natural gas liquids and ultimate sale to third parties. Natural gas and natural gas liquids inventory is valued using moving average cost and is subsequently recorded at the lower of cost or net realizable value. The Partnership recorded a $3 million and zero lower of cost or net realizable value adjustment in the three months ended March 31, 2018 and 2017 , respectively. Income Taxes The Partnership’s earnings are not subject to income tax (other than Texas state margin taxes and taxes associated with the Partnership’s corporate subsidiary, Enable Midstream Services) and are taxable at the individual partner level. We account for deferred income taxes related to the federal and state jurisdictions using the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the future taxes attributable to the difference between financial statement carrying amounts of assets and liabilities and their respective tax basis. Deferred tax assets are also recognized for the future tax benefits attributable to the expected utilization of tax net operating loss carryforwards. In the event future utilization is determined to be unlikely, a valuation allowance is provided to reduce the tax benefits from such assets. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the period in which the temporary differences and carryforwards are expected to be recovered or settled. The effect of a change in tax rates is recognized in the period which includes the enactment date. The Partnership recognizes interest and penalties as a component of income tax expense.

New Accounting Pronouncements

New Accounting Pronouncements	3 Months Ended
New Accounting Pronouncements	Mar. 31, 2018
Accounting Changes and Error Corrections [Abstract]
New Accounting Pronouncements	New Accounting Pronouncements Accounting Standards to be Adopted in Future Periods Leases In February 2016, the FASB issued ASU 2016-02, “Leases (ASC 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. In January 2018, the FASB issued ASU 2018-01, “Land Easement Practical Expedient for Transition to Topic 842.” This standard permits an entity to elect an optional transition practical expedient to not evaluate land easements that exist or expire before the Partnership's adoption of ASC 842 and that were not previously accounted for as leases under ASC 840. The Partnership intends to elect this transition provision. The Partnership continues to review contracts and easements relative to the provisions of the ASU 2016-02 lease standard and the ASU 2018-01 easement standard as well as to monitor relevant emerging industry guidance regarding the implementation of the standards. The Partnership expects to adopt these standards in the first quarter of 2019 and is currently evaluating the overall impact of the standards on our Condensed Consolidated Financial Statements and related disclosures. Financial Instruments—Credit Losses In June 2016, the FASB issued ASU No. 2016-13, “Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments.” 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.

Revenue

Revenue	3 Months Ended
Revenue	Mar. 31, 2018
Revenue from Contract with Customer [Abstract]
Revenue	Revenue The Partnership adopted ASU No. 2014-09, “Revenue from Contracts with Customers” (ASC 606) on January 1, 2018 using the modified retrospective method. Upon adoption, the Partnership did not recognize a material cumulative adjustment to Partners’ Equity and there were no material changes in the timing of revenue recognition or our accounting policies. The Partnership has applied the standard to only contracts that were not expired as of January 1, 2018. The following table disaggregates total revenues by major source from contracts with customers and the change in fair value of derivatives. Three Months Ended March 31, 2018 Gathering and Transportation Eliminations Total (In millions) Revenues: Product sales: Natural gas $ 106 $ 131 $ (109 ) $ 128 Natural gas liquids 279 7 (7 ) 279 Condensate 36 — — 36 Total revenues from natural gas, natural gas liquids, and condensate 421 138 (116 ) 443 Gain (loss) on derivative activity (3 ) 2 1 — Total Product sales $ 418 $ 140 $ (115 ) $ 443 Service revenues: Demand revenues $ 50 $ 120 $ — $ 170 Volume-dependent revenues 123 19 (7 ) 135 Total Service revenues $ 173 $ 139 $ (7 ) $ 305 Total Revenues $ 591 $ 279 $ (122 ) $ 748 Product Sales Natural Gas, NGLs or Condensate We deliver natural gas, NGLs and condensate to purchasers at contractually agreed-upon delivery points at which the purchaser takes custody, title, and risk of loss of the commodity. We recognize revenue when control transfers to the purchaser at the delivery point based on the contractually agreed upon fixed or index based price received. Gain (loss) on Derivative Activity Included in Product sales are gains and losses on natural gas, natural gas liquids, and crude oil (for condensate) derivatives that are accounted for under guidance in ASC 815. See Note 9 for further discussion of our derivative and hedging activity. Service Revenues Demand revenues Our demand revenue arrangements are generally structured in one of the following ways: • Under a firm fee arrangement, a customer agrees to pay a fixed fee for a contractually agreed upon pipeline or storage capacity. Once the services have been completed, or the customer no longer has access to the contracted capacity, revenue is recognized. • Under a minimum volume commitment fee arrangement, a customer agrees to either deliver a contractually agreed upon minimum volume of natural gas or crude oil to our system for service at a contractually agreed upon gathering fee or to pay the contractually agreed upon gathering, compressing and treating fees for the minimum volume of natural gas or crude oil irrespective of whether or not the minimum volume of natural gas or crude oil is delivered. Certain of our contracts provide our customers the option to elect to pay a higher gathering fee over the remaining term of the contract in lieu of making a contractually agreed upon shortfall payment. Once the services have been completed, or the customer no longer has the ability to utilize the services, revenue is recognized. Volume-dependent revenues Our volume-dependent revenues primarily consist of gathering, compressing, treating, processing, transportation or storage services fees on contracts that exceed their contractually committed volume or do not have firm fee arrangements or minimum volume commitments. These fees are dependent on throughput by third party customers, and revenue is recognized over time as the service is performed. Our other fee revenue arrangements have pricing terms that are generally structured in one of the following ways: (1) Contractually agreed upon monetary fee for service or (2) contractually agreed upon consideration received in the form of natural gas or natural gas liquids, which are valued at the current month index based price, which approximates fair value. Accounts Receivable Payments for all types of revenues are typically received within 30 days of invoice. Invoices for all revenue types are sent on at least a monthly basis, except for the shortfall provisions under certain minimum volume commitment contracts, which are typically invoiced annually. Accounts receivable includes accrued revenues associated with certain minimum volume commitments that will be invoiced at the conclusion of the measurement period specified under the respective contracts. March 31, December 31, (In millions) Accounts Receivable: Customers $ 233 $ 265 Accrued minimum volume commitments (contract assets) 34 27 Non-customers 5 3 Total Accounts Receivable (1) $ 272 $ 295 ____________________ (1) Total Accounts Receivable includes Accounts receivables, net of allowance for doubtful accounts and Accounts receivable—affiliated companies. Contract Liabilities Our contract liabilities primarily consist of the following prepayments received from customers: • Under certain firm fee arrangements, customers pay their demand fee prior to the month of contracted capacity. These fees are applied to the subsequent month’s activity and are included in other liabilities on the Condensed Consolidated Balance Sheets. • Under certain demand and volume dependent arrangements, customers make contributions of aid in construction payments. For payments that are related to contracts under ASC 606, the payment is deferred and amortized over the life of the associated contract and the unamortized balance is included in other current or long-term liabilities on the Condensed Consolidated Balance Sheets. The table below summarizes the change in the contract liabilities for the three months ended March 31, 2018 : March 31, December 31, Amounts recognized in revenues (In millions) Deferred revenues $ 41 $ 34 $ 15 The table below summarizes the timing of recognition of these contract liabilities as of March 31, 2018 : 2018 2019 2020 2021 2022 and After (In millions) Deferred revenues $ 19 $ 4 $ 4 $ 4 $ 10 Remaining Performance Obligations Our remaining performance obligations consist primarily of firm fee and minimum volume commitment fee arrangements. Upon completion of the performance obligations associated with these arrangements, customers are invoiced and revenue is recognized as Service revenues in the Condensed Consolidated Statements of Income. The table below summarizes the timing of recognition of the remaining performance obligations as of March 31, 2018 : 2018 2019 2020 2021 2022 and After Transportation and Storage $ 325 $ 329 $ 244 $ 123 $ 608 Gathering and Processing 175 221 118 94 328 Total remaining performance obligations $ 500 $ 550 $ 362 $ 217 $ 936 Impact of Adoption Upon adoption of ASC 606, the recognition of revenues for certain contractual arrangements was impacted as follows: • Natural gas and natural gas liquids purchase arrangements - For certain arrangements within our gathering and processing segment, the Partnership purchases and controls the entire hydrocarbon stream at the point of receipt. As of January 1, 2018, these arrangements are considered supplier contracts rather than contracts with customers. Therefore, beginning January 1, 2018, the gathering and processing fees for these arrangements that were previously recognized as Service revenues under ASC 605 are recognized as reductions to Cost of natural gas and natural gas liquids. • Percent-of-proceeds and percent-of-liquids processing arrangements - Under percent-of-proceeds and percent-of-liquids arrangements within our gathering and processing segment, the Partnership has previously recognized the value of natural gas and natural gas liquids received in our purchase cost within Cost of natural gas and natural gas liquids. As of January 1, 2018, the Partnership recognizes the value of the natural gas and NGLs received as Service revenues and as an increase to Cost of natural gas and natural gas liquids when the natural gas or NGLs are sold and Product sales are recognized. • Keep-whole arrangements - Under keep-whole arrangements within our gathering and processing segment, the Partnership has previously recognized the value of NGLs received in Product sales and the value of the thermally equivalent quantity of natural gas provided in our purchase cost within Cost of natural gas and natural gas liquids. As of January 1, 2018, the Partnership recognizes the value of the NGLs received less the value of the thermal equivalent volume of natural gas provided as Service revenues and as an increase to Cost of natural gas and natural gas liquids when the NGLs are sold and Product sales are recognized. • Fixed fuel arrangements - Under certain gathering arrangements within our gathering and processing segment as well as under certain transportation arrangements within our transportation and storage segment we receive a fixed amount of fuel regardless of actual fuel usage. Previously, revenue for fuel in excess of actual usage was recognized when such fuel was received, and additional revenue was recognized when such fuel was sold. As of January 1, 2018, fuel in excess of actual usage is treated as a byproduct obtained through the fulfillment of a contract, and the Partnership will recognize revenue at the time the excess fuel is sold. This results in a reduction of Product sales and a corresponding reduction in Cost of natural gas and natural gas liquids. • Natural gas and natural gas liquids sales arrangements - For certain arrangements within our gathering and processing segment, the Partnership sells the entire hydrocarbon stream at the point of delivery to a third-party processing facility. As of January 1, 2018, these arrangements are considered sales once control has transferred to the third-party processing facility. Therefore, beginning January 1, 2018, the transportation and fractionation fees for these arrangements that were previously recognized as a component of cost of gas and natural gas liquids, are recognized as reductions to the transaction price under ASC 606. Below is a summary of the impact of the changes on revenues as it relates to the three months ended March 31, 2018 : Three Months Ended March 31, 2018 Under ASC 606 Under ASC 605 Increase/(Decrease) (In millions) Revenues: Product sales: Natural gas $ 128 $ 139 $ (11 ) Natural gas liquids 279 283 (4 ) Condensate 36 36 — Total revenues from natural gas, natural gas liquids, and condensate 443 458 (15 ) Gain (loss) on derivative activity — — — Total Product sales $ 443 $ 458 $ (15 ) Service revenues: Demand revenues $ 170 $ 170 — Volume-dependent revenues 135 134 1 Total Service revenues $ 305 $ 304 $ 1 Total Revenues $ 748 $ 762 $ (14 ) As described above, each of the identified increases/(decreases) in revenue resulted in a corresponding change in the Cost of natural gas and natural gas liquids.

Acquisition

Acquisition	3 Months Ended
Acquisition	Mar. 31, 2018
Business Combinations [Abstract]
Acquisition	Acquisition Align Acquisition On October 4, 2017, the Partnership acquired all of the equity interests in Align Midstream, LLC, a midstream service provider with natural gas gathering and processing facilities in the Cotton Valley and Haynesville plays of the Ark-La-Tex Basin, for approximately $298 million in cash. The acquisition includes approximately 190 miles of natural gas gathering pipelines across Rusk, Panola and Shelby counties in Texas and DeSoto Parish in Louisiana and a cryogenic natural gas processing plant in Panola County, Texas, with a capacity of 100 MMcf/d. The acquisition was accounted for as a business combination and funded with borrowings under the Revolving Credit Facility. During the fourth quarter of 2017, the Partnership finalized the purchase price allocation as of October 4, 2017. The following table presents the fair value of the identified assets acquired and liabilities assumed at the acquisition date: Purchase price allocation (in millions): Assets acquired: Accounts receivable $ 5 Property, plant and equipment 111 Intangibles 176 Goodwill 12 Liabilities assumed: Current liabilities 6 Total identifiable net assets $ 298 In connection with the acquisition, the Partnership recognized intangible assets related to customer relationships. The acquired intangible assets will be amortized on a straight-line basis over the estimated customer contract life of approximately 10 years. Goodwill recognized from the acquisition primarily relates to greater operating leverage in the Ark-La-Tex Basin and is allocated to the gathering and processing segment. The Partnership incurred approximately $2 million of acquisition costs associated with this transaction, which were included in General and administrative expense in the Consolidated Statements of Income in the fourth quarter of 2017. The Partnership determined not to include pro forma consolidated financial statements for the periods presented as the impact would not be material.

Earnings Per Limited Partner Un

Earnings Per Limited Partner Unit	3 Months Ended
Earnings Per Limited Partner Unit	Mar. 31, 2018
Earnings Per Share [Abstract]
Earnings Per Limited Partner Unit	Earnings Per Limited Partner Unit The following table illustrates the Partnership’s calculation of earnings per unit for common and subordinated units: Three Months Ended March 31, 2018 2017 (In millions, except per unit data) Net income $ 114 $ 120 Net income attributable to noncontrolling interest — — Series A Preferred Unit distributions 9 9 General partner interest in net income — — Net income available to common and subordinated unitholders $ 105 $ 111 Net income allocable to common units $ 105 $ 58 Net income allocable to subordinated units — 53 Net income available to common and subordinated unitholders $ 105 $ 111 Net income allocable to common units $ 105 $ 58 Dilutive effect of Series A Preferred Unit distributions — — Diluted net income allocable to common units 105 58 Diluted net income allocable to subordinated units — 53 Total $ 105 $ 111 Basic weighted average number of outstanding Common units (1) 434 225 Subordinated units — 208 Total 434 433 Basic earnings per unit Common units $ 0.24 $ 0.26 Subordinated units $ — $ 0.25 Basic weighted average number of outstanding common units 434 225 Dilutive effect of Series A Preferred Units — — Dilutive effect of performance units 1 1 Diluted weighted average number of outstanding common units 435 226 Diluted weighted average number of outstanding subordinated units — 208 Total 435 434 Diluted earnings per unit Common units $ 0.24 $ 0.26 Subordinated units $ — $ 0.25 ____________________ (1) Basic weighted average number of outstanding common units for each of the three months ended March 31, 2018 and 2017 includes approximately one million time-based phantom units. See Note 6 for discussion of the expiration of the subordination period. The dilutive effect of the unit-based awards discussed in Note 14 was less than $0.01 per unit during each of the three months ended March 31, 2018 and 2017 .

Partners' Equity

Partners' Equity	3 Months Ended
Partners' Equity	Mar. 31, 2018
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, as applicable, during 2017 and 2018 (in millions, except for per unit amounts): Three Months Ended Record Date Payment Date Per Unit Distribution Total Cash Distribution March 31, 2018 (1) May 22, 2018 May 29, 2018 $ 0.318 $ 138 December 31, 2017 February 20, 2018 February 27, 2018 $ 0.318 $ 138 September 30, 2017 November 14, 2017 November 21, 2017 $ 0.318 $ 138 June 30, 2017 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 _____________________ (1) The board of directors of Enable GP declared this 0.318 per common unit cash distribution on May 1, 2018 , to be paid on May 29, 2018 , to common unitholders of record at the close of business on May 22, 2018 . The Partnership paid or has authorized payment of the following cash distributions to holders of the Series A Preferred Units during 2017 and 2018 (in millions, except for per unit amounts): Three Months Ended Record Date Payment Date Per Unit Distribution Total Cash Distribution March 31, 2018 (1) May 1, 2018 May 15, 2018 $ 0.625 $ 9 December 31, 2017 February 9, 2018 February 15, 2018 $ 0.625 $ 9 September 30, 2017 October 31, 2017 November 14, 2017 $ 0.625 $ 9 June 30, 2017 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 _____________________ (1) The board of directors of Enable GP declared a $0.625 per Series A Preferred Unit cash distribution on May 1, 2018 , to be paid on May 15, 2018 , to Series A Preferred unitholders of record at the close of business on May 1, 2018 . 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 that they own. Expiration of Subordination Period The financial tests required for conversion of all subordinated units were met and the 207,855,430 outstanding subordinated units were converted into common units on a one -for-one basis on August 30, 2017. The conversion of the subordinated units did not change the aggregate amount of outstanding units, and the conversion of the subordinated units did not impact the amount of cash available for distribution by the Partnership. Series A Preferred Units On February 18, 2016, the Partnership completed a 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. If and when declared by our general partner, holders of the Series A Preferred Units receive a quarterly cash distribution on a non-cumulative basis equal to subject to certain adjustments, 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, pursuant to which 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. During the three months ended March 31, 2018 , the Partnership did not issue any common units under the ATM Program.

Investment in Equity Method Aff

Investment in Equity Method Affiliate	3 Months Ended
Investment in Equity Method Affiliate	Mar. 31, 2018
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 $2 million and $5 million during the three months ended March 31, 2018 and 2017 , respectively, associated with these service agreements. The Partnership includes equity in earnings of equity method affiliate under the Other Income (Expense) caption in the Condensed Consolidated Statements of Income for the three months ended March 31, 2018 and 2017 . Equity in Earnings of Equity Method Affiliate: Three Months Ended March 31, 2018 2017 (In millions) SESH $ 6 $ 7 Distributions from Equity Method Affiliate: Three Months Ended March 31, 2018 2017 (In millions) SESH (1) $ 13 $ 11 ___________________ (1) Distributions from equity method affiliate includes a $6 million and $7 million return on investment and a $7 million and $4 million return of investment for the three months ended March 31, 2018 and 2017 , respectively. Summarized financial information of SESH: Three Months Ended March 31, 2018 2017 (In millions) Income Statements: Revenues $ 28 $ 28 Operating income $ 17 $ 17 Net income $ 12 $ 13

Debt

Debt	3 Months Ended
Debt	Mar. 31, 2018
Debt Disclosure [Abstract]
Debt	Debt The following table presents the Partnership’s outstanding debt as of March 31, 2018 and December 31, 2017 . March 31, 2018 December 31, 2017 Outstanding Principal Premium (Discount) Total Debt Outstanding Principal Premium (Discount) Total Debt (In millions) Commercial Paper $ 596 $ (1 ) $ 595 $ 405 $ — $ 405 Revolving Credit Facility — — — — — — 2015 Term Loan Agreement 450 — 450 450 — 450 2019 Notes 500 — 500 500 — 500 2024 Notes 600 — 600 600 — 600 2027 Notes 700 (3 ) 697 700 (3 ) 697 2044 Notes 550 — 550 550 — 550 EOIT Senior Notes 250 11 261 250 13 263 Total debt $ 3,646 $ 7 $ 3,653 $ 3,455 $ 10 $ 3,465 Less: Current portion of long-term debt 450 450 Less: Short-term debt (1) 595 405 Less: Unamortized debt expense (2) 14 15 Total long-term debt $ 2,594 $ 2,595 ____________________ (1) Short-term debt includes $596 million and $405 million of outstanding commercial paper as of March 31, 2018 and December 31, 2017 , respectively. (2) As of March 31, 2018 and December 31, 2017 , there was an additional $3 million 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 was scheduled to mature on June 18, 2020, subject to an extension option, which could be exercised two times to extend the term of the Revolving Credit Facility, in each case, for an additional one -year term. As of March 31, 2018 , there were no principal advances and $3 million in letters of credit outstanding under the Revolving Credit Facility. The Revolving Credit Facility provided 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 was based on the Partnership’s applicable credit ratings. As of March 31, 2018 , 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 required the Partnership to pay a fee on unused commitments. The commitment fee was based on the Partnership’s applicable credit rating from the rating agencies. As of March 31, 2018 , 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. On April 6, 2018, the Partnership amended and restated the Revolving Credit Facility. See Note 16 for a discussion of the Second Amended and Restated Revolving Credit Agreement. 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 were $596 million and $405 million outstanding under our commercial paper program at March 31, 2018 and December 31, 2017 , respectively. The weighted average interest rate for the outstanding commercial paper was 2.72% as of March 31, 2018 . 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, which is scheduled to mature on July 31, 2018. 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 March 31, 2018 , there was $450 million outstanding under the 2015 Term Loan Agreement, which is included as Current portion of long-term debt in the Partnership’s Condensed Consolidated Balance Sheets. 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 March 31, 2018 , the applicable margin for LIBOR-based borrowings under the 2015 Term Loan Agreement was 1.375% based on the Partnership’s credit ratings. For the three months ended March 31, 2018 , the weighted average interest rate of the 2015 Term Loan Agreement was 2.98% . Senior Notes On March 9, 2017, the Partnership completed the public offering of $700 million aggregate principal amount of the Partnership’s 4.400% Senior Notes due 2027. 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 $5 million at March 31, 2018 , resulting in an effective interest rate of 4.58% during the three months ended March 31, 2018 . In addition to the 2027 Notes, as of March 31, 2018 , the Partnership’s debt included the 2019 Notes, 2024 Notes and 2044 Notes, which had $9 million of unamortized debt expense at March 31, 2018 , resulting in effective interest rates of 2.57% , 4.02% and 5.08% , respectively, during the three months ended March 31, 2018 . As of March 31, 2018 , the Partnership’s debt included $250 million aggregate principal amount of EOIT’s 6.25% senior notes due 2020 . The EOIT Senior Notes had $11 million of unamortized premium at March 31, 2018 , resulting in an effective interest rate of 3.80% during the three months ended March 31, 2018 . As of March 31, 2018 , 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	3 Months Ended
Derivative Instruments and Hedging Activities	Mar. 31, 2018
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 March 31, 2018 and December 31, 2017 , 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 March 31, 2018 and December 31, 2017 , the Partnership had the following derivative instruments that were not designated as hedging instruments for accounting purposes: March 31, 2018 December 31, 2017 Gross Notional Volume Purchases Sales Purchases Sales Natural gas— TBtu (1) Financial fixed futures/swaps 19 22 17 13 Financial basis futures/swaps 27 31 17 17 Physical purchases/sales — 81 1 37 Crude oil (for condensate)— MBbl (2) Financial Futures/swaps — 874 — 564 Natural gas liquids— MBbl (3) Financial Futures/swaps — 2,195 — 1,615 ____________________ (1) As of March 31, 2018 , 82.4% of the natural gas contracts had durations of one year or less, 10.7% had durations of more than one year and less than two years and 6.9% had durations of more than two years. As of December 31, 2017 , 67.7% of the natural gas contracts had durations of one year or less, 16.1% had durations of more than one year and less than two years and 16.2% had durations of more than two years. (2) As of March 31, 2018 , 69.1% of the crude oil (for condensate) contracts had durations of one year or less and 30.9% had durations of more than one year and less than two years. As of December 31, 2017 , 100% of the crude oil (for condensate) contracts had durations of one year or less. (3) As of March 31, 2018 , 72.0% of the natural gas liquids contracts had durations of one year or less and 28.0% had durations of more than one year and less than two years. As of December 31, 2017 , 100% of the natural gas liquid contracts had durations of one year or less. Balance Sheet Presentation Related to Derivative Instruments The fair value of the derivative instruments that are presented in the Partnership’s Condensed Consolidated Balance Sheets as of March 31, 2018 and December 31, 2017 that were not designated as hedging instruments for accounting purposes are as follows: March 31, 2018 December 31, 2017 Fair Value Instrument Balance Sheet Location Assets Liabilities Assets Liabilities (In millions) Natural gas Financial futures/swaps Other Current/Other $ 3 $ 9 $ 5 $ 4 Physical purchases/sales Other Current/Other 6 1 3 — Crude oil (for condensate) Financial futures/swaps Other Current/Other — 5 — 4 Natural gas liquids Financial Futures/swaps Other Current/Other 2 2 1 5 Total gross derivatives (1) $ 11 $ 17 $ 9 $ 13 _____________________ (1) See Note 10 for a reconciliation of the Partnership’s total derivatives fair value to the Partnership’s Condensed Consolidated Balance Sheets as of March 31, 2018 and December 31, 2017 . 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 months ended March 31, 2018 and 2017 : Amounts Recognized in Income Three Months Ended March 31, 2018 2017 (In millions) Natural gas Financial futures/swaps (losses) gains $ (3 ) $ 11 Physical purchases/sales gains 2 5 Crude oil (for condensate) Financial futures/swaps (losses) gains (3 ) 3 Natural gas liquids Financial futures/swaps gains 4 2 Total $ — $ 21 For derivatives not designated as hedges in the tables above, amounts recognized in income for the periods ended March 31, 2018 and 2017 , 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 months ended March 31, 2018 and 2017 : Three Months Ended March 31, 2018 2017 (In millions) Change in fair value of derivatives $ (2 ) $ 24 Realized gain (loss) on derivatives 2 (3 ) Gain on derivative activity $ — $ 21 Credit-Risk Related Contingent Features in Derivative Instruments In the event Moody’s Investors Services or Standard & Poor’s Ratings Services were to lower the Partnership’s senior unsecured debt rating to a below investment grade rating, at March 31, 2018 , the Partnership would have been required to post $7 million of cash collateral to satisfy its obligation under its financial and physical contracts relating to derivative instruments that are in a net liability position at March 31, 2018 . In addition, the Partnership could be required to provide additional credit assurances in future dealings with third parties, which could include letters of credit or cash collateral.

Fair Value Measurements

Fair Value Measurements	3 Months Ended
Fair Value Measurements	Mar. 31, 2018
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 March 31, 2018 , 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 March 31, 2018 and December 31, 2017 . March 31, 2018 December 31, 2017 Carrying Amount Fair Value Carrying Amount Fair Value (In millions) Debt Revolving Credit Facility (Level 2) (1) $ — $ — $ — $ — 2015 Term Loan Agreement (Level 2) 450 450 450 450 2019 Notes (Level 2) 500 494 500 497 2024 Notes (Level 2) 600 588 600 602 2027 Notes (Level 2) 697 687 697 712 2044 Notes (Level 2) 550 523 550 550 EOIT Senior Notes (Level 2) 261 261 263 265 ____________________ (1) Borrowing capacity is effectively reduced by our borrowings outstanding under the commercial paper program. $596 million and $405 million of commercial paper was outstanding as of March 31, 2018 and December 31, 2017 , respectively. 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 March 31, 2018 , 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 March 31, 2018 and December 31, 2017 : March 31, 2018 Commodity Contracts Gas Imbalances (1) Assets Liabilities Assets (2) Liabilities (3) (In millions) Quoted market prices in active market for identical assets (Level 1) $ 3 $ 7 $ — $ — Significant other observable inputs (Level 2) 6 8 19 8 Unobservable inputs (Level 3) 2 2 — — Total fair value 11 17 19 8 Netting adjustments (3 ) (3 ) — — Total $ 8 $ 14 $ 19 $ 8 December 31, 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) $ 5 $ 3 $ — $ — Significant other observable inputs (Level 2) 4 5 27 12 Unobservable inputs (Level 3) — 5 — — Total fair value 9 13 27 12 Netting adjustments (5 ) (5 ) — — Total $ 4 $ 8 $ 27 $ 12 ______________________ (1) The Partnership uses the market approach to fair value its gas imbalance assets and liabilities at individual, or where appropriate an average of, current market indices applicable to the Partnership’s operations, not to exceed net realizable value. Gas imbalances held by EOIT are valued using an average of the Inside FERC Gas Market Report for Panhandle Eastern Pipe Line Co. (Texas, Oklahoma Mainline), ONEOK (Oklahoma) and ANR Pipeline (Oklahoma) indices. There were no netting adjustments as of March 31, 2018 and December 31, 2017 . (2) Gas imbalance assets exclude fuel reserves for under retained fuel due from shippers of $16 million and $10 million at March 31, 2018 and December 31, 2017 , respectively, which fuel reserves are based on the value of natural gas at the time the imbalance was created and which are not subject to revaluation at fair market value. (3) Gas imbalance liabilities exclude fuel reserves for over retained fuel due to shippers of zero at March 31, 2018 and December 31, 2017 , 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 at December 31, 2017 $ (5 ) Gains included in earnings 4 Settlements 1 Transfers out of Level 3 — Balance as of March 31, 2018 $ — Quantitative Information on Level 3 Fair Value Measurements The Partnership utilizes the market approach to measure the fair value of our commodity contracts. The significant unobservable inputs used in this approach to fair value are longer dated price quotes. Our sensitivity to these longer dated forward curve prices are presented in the table below. Significant changes in any of those inputs in isolation would result in significantly different fair value measurements, depending on our short or long position in contracts. March 31, 2018 Product Group Fair Value Forward Curve Range (In millions) (Per gallon) Natural gas liquids $ — $0.2663 - $0.8963

Supplemental Disclosure of Cash

Supplemental Disclosure of Cash Flow Information	3 Months Ended
Supplemental Disclosure of Cash Flow Information	Mar. 31, 2018
Supplemental Cash Flow Information [Abstract]
Supplemental Disclosure of Cash Flow Information	Supplemental Disclosure of Cash Flow Information The following table provides information regarding supplemental cash flow information: Three Months Ended March 31, 2018 2017 (In millions) Supplemental Disclosure of Cash Flow Information: Cash Payments: Interest, net of capitalized interest $ 29 $ 14 Income taxes, net of refunds 2 — Non-cash transactions: Accounts payable related to capital expenditures 50 20 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 Statements of Cash Flows: Three Months Ended March 31, 2018 2017 (In millions) Cash and cash equivalents $ 30 $ 17 Restricted cash 14 14 Cash, cash equivalents and restricted cash shown in the Condensed Consolidated Statements of Cash Flows $ 44 $ 31

Related Party Transactions

Related Party Transactions	3 Months Ended
Related Party Transactions	Mar. 31, 2018
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. Those services include firm transportation with seasonal contract demand, firm storage, no notice transportation with associated storage and maximum rate firm transportation. Contracts for firm transportation with seasonal contract demand, firm storage, firm no notice transportation with storage for CenterPoint’s LDCs in Arkansas, Louisiana, Oklahoma and Northeast Texas are in effect through March 21, 2021 and will remain in effect thereafter unless and until terminated by either party upon 180 days’ prior written notice. Contracts for maximum firm rate transportation for CenterPoint’s LDCs in Oklahoma and portions of Northeast Texas are also in effect through March 21, 2021. Contracts for CenterPoint’s LDCs in Arkansas, Louisiana and Texarkana, Texas terminated on March 31, 2018. MRT provides transportation and storage services to CenterPoint Energy’s LDCs in Arkansas and Louisiana. Contracts for these services are in effect through May 15, 2023 and will remain in effect thereafter unless and until terminated by either party upon 12 months’ prior written notice. 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 expand the EOIT system. 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 7% and 6% of total revenues during the three months ended March 31, 2018 and 2017 , respectively. Amounts of revenues from affiliated companies included in the Partnership’s Condensed Consolidated Statements of Income are summarized as follows: Three Months Ended March 31, 2018 2017 (In millions) Gas transportation and storage service revenue — CenterPoint Energy $ 33 $ 33 Natural gas product sales — CenterPoint Energy 6 — Gas transportation and storage service revenue — OGE Energy 9 9 Natural gas product sales — OGE Energy 1 — Total revenues — affiliated companies $ 49 $ 42 Amounts of natural gas purchased from affiliated companies included in the Partnership’s Condensed Consolidated Statements of Income are summarized as follows: Three Months Ended March 31, 2018 2017 (In millions) Cost of natural gas purchases — CenterPoint Energy $ 2 $ — Cost of natural gas purchases — OGE Energy 3 3 Total cost of natural gas purchases — affiliated companies $ 5 $ 3 Seconded employees, corporate services and operating lease expense As of March 31, 2018 , 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 seconded employee costs arising out of OGE Energy’s defined benefit and retiree medical plans is fixed at actual cost subject to a cap of $5 million in 2018 and thereafter, unless and until secondment is terminated. The Partnership receives services and support functions from each of CenterPoint Energy and OGE Energy under services agreements for an initial term that ended on April 30, 2016. The services 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 the services 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 2018 are $4 million and $1 million , respectively. The Partnership leases office and data center space from an affiliate of CenterPoint Energy in Shreveport, Louisiana. The term of the lease commenced on October 1, 2016 and extends through December 31, 2019. The Partnership expects to incur approximately $3 million in rent and maintenance expenses during the initial term of the lease. As of March 31, 2018 , CenterPoint Energy continues to provide office and data center space to the Partnership in Houston, Texas, under the services agreement. During the first quarter of 2018 the Partnership provided notice to Centerpoint Energy of its intent to terminate the provision of office space in Houston, Texas on August 31, 2018. Amounts charged to the Partnership by affiliates for seconded employees, an operating lease and corporate services, included primarily in Operation and maintenance and General and administrative expenses in the Partnership’s Condensed Consolidated Statements of Income are as follows: Three Months Ended March 31, 2018 2017 (In millions) Corporate Services — CenterPoint Energy $ 1 $ 1 Operating Lease — CenterPoint Energy — — Seconded Employee Costs — OGE Energy 8 7 Corporate Services — OGE Energy — 1 Total corporate services and seconded employees expense $ 9 $ 9 Series A Preferred Units On February 18, 2016, the Partnership completed a private placement to 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 6 for further discussion of the Series A Preferred Units.

Commitments and Contingencies

Commitments and Contingencies	3 Months Ended
Commitments and Contingencies	Mar. 31, 2018
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	3 Months Ended
Equity-Based Compensation	Mar. 31, 2018
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Equity-Based Compensation	Equity-Based Compensation The following table summarizes the Partnership’s compensation expense for the three months ended March 31, 2018 and 2017 related to performance units, restricted units, and phantom units for the Partnership’s employees and independent directors: Three Months Ended March 31, 2018 2017 (In millions) Performance units $ 3 $ 3 Restricted units 1 — Phantom units 1 1 Total compensation expense $ 5 $ 4 Units Outstanding The Partnership periodically grants performance units, restricted units and phantom units to certain employees under the Enable Midstream Partners, LP Long Term Incentive Plan. A summary of the activity for the Partnership’s performance units, restricted units, and phantom units applicable to the Partnership’s employees at March 31, 2018 and changes during 2018 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, 2017 2,040,407 $ 13.86 222,434 $ 17.87 987,380 $ 11.38 Granted (1) 529,408 17.70 — — 494,072 14.04 Vested (2) (401,772 ) 16.59 (181,068 ) 16.75 — — Forfeited (3,725 ) 13.87 (1,366 ) 16.75 (7,375 ) 11.90 Units Outstanding at March 31, 2018 2,164,318 $ 13.95 40,000 $ 22.96 1,474,077 $ 12.27 Aggregate Intrinsic Value of Units Outstanding at March 31, 2018 $ 30 $ 1 $ 20 _____________________ (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 zero percent to 200 percent of the target. (2) Performance units vested as of March 31, 2018 include 401,772 units from the annual grant, which were approved by the Board of Directors in 2015 and paid out at 200% , or 803,544 units, based on the level of achievement of a performance goal established by the Board of Directors over the performance period. The Board of Directors approved the accelerated vesting of the 2015 grant from June 1, 2018 to March 1, 2018. Unrecognized Compensation Cost A summary of the Partnership’s unrecognized compensation cost for its non-vested performance units, restricted units, and phantom units, and the weighted-average periods over which the compensation cost is expected to be recognized are shown in the following table. March 31, 2018 Unrecognized Compensation Cost (In millions) Weighted Average to be Recognized (In years) Performance Units $ 19 1.66 Restricted Units — 0.22 Phantom Units 12 1.86 Total $ 31 As of March 31, 2018 , there were 7,504,634 units available for issuance under the long-term incentive plan.

Reportable Segments

Reportable Segments	3 Months Ended
	Mar. 31, 2018
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 2017 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 March 31, 2018 Gathering and Transportation (1) Eliminations Total (In millions) Product sales $ 418 $ 140 $ (115 ) $ 443 Service revenue 173 139 (7 ) 305 Total Revenues 591 279 (122 ) 748 Cost of natural gas and natural gas liquids 358 139 (122 ) 375 Operation and maintenance, General and administrative 76 46 (1 ) 121 Depreciation and amortization 62 34 — 96 Taxes other than income tax 10 7 — 17 Operating income $ 85 $ 53 $ 1 $ 139 Capital expenditures $ 147 $ 43 $ — $ 190 Total assets $ 9,212 $ 5,652 $ (3,177 ) $ 11,687 Three Months Ended March 31, 2017 Gathering and (1) Eliminations Total (In millions) Product sales $ 351 $ 153 $ (118 ) $ 386 Service revenue 140 141 (1 ) 280 Total Revenues 491 294 (119 ) 666 Cost of natural gas and natural gas liquids 286 140 (118 ) 308 Operation and maintenance, General and administrative 70 45 (1 ) 114 Depreciation and amortization 56 32 — 88 Taxes other than income tax 9 7 — 16 Operating income $ 70 $ 70 $ — $ 140 Capital expenditures $ 51 $ 10 $ — $ 61 Total assets as of December 31, 2017 $ 9,079 $ 5,616 $ (3,102 ) $ 11,593 _____________________ (1) See Note 7 for discussion regarding ownership interests in SESH and related equity earnings included in the transportation and storage segment for the three months ended March 31, 2018 and 2017 .	[1]

[1]	See Note 7 for discussion regarding ownership interests in SESH and related equity earnings included in the transportation and storage segment for the three months ended March 31, 2018 and 2017.

Subsequent Event

Subsequent Event	3 Months Ended
Subsequent Event	Mar. 31, 2018
Subsequent Events [Abstract]
Subsequent Event	Subsequent Event On April 6, 2018, the Partnership amended and restated the Revolving Credit Facility in its entirety. The amended and restated Revolving Credit Facility is a $1.75 billion 5 -year senior unsecured revolving credit facility, which under certain circumstances may be increased from time to time up to an additional $875 million , in aggregate. The Second Amended and Restated Revolving Credit Facility contains an option, which may be exercised up to two times, to extend the Second Amended and Restated Revolving Credit Facility for an additional one -year term. The Second Amended and Restated Revolving Credit Facility provides that outstanding borrowings bear interest at the Eurodollar rate and/or an alternate base rate, at the Partnership’s election, plus an applicable margin. The applicable margin will be based on the Partnership’s designated credit ratings. The applicable margin shall equal, in the case of interest rates determined by reference to the Eurodollar rate, between 1.00% and 1.75% per annum. The Second Amended and Restated Revolving Credit Facility requires the Partnership to pay a quarterly fee on each lender’s unused commitment amount during such preceding quarter which shall equal between 0.10% and 0.30% per annum, depending on The Partnership’s designated credit rating. The Second Amended and Restated Revolving Credit Facility provides for issuance of letters of credit of up to $500 million dollars at any time outstanding. The Second and Amended Restated Revolving Credit Facility contains a financial covenant requiring the Partnership to maintain a ratio of consolidated funded debt to EBITDA as of the last day of each fiscal quarter of less than or equal to 5.00 to 1.00, although such ratio is increased to 5.50 to 1.00 for a certain period of time following an acquisition by the Partnership or certain of its subsidiaries with a purchase price that, when combined with the aggregate purchase price for all other such acquisitions in any rolling 12 -month period, is equal to or greater than $25 million . The Second Amended and Restated Revolving Credit Facility also contains covenants that restrict the Partnership and certain of its subsidiaries in respect of, among other things, mergers and consolidations, sales of all or substantially all assets, incurrence of subsidiary indebtedness, incurrence of liens, transactions with affiliates, designation of subsidiaries as excluded subsidiaries, restricted payments, changes in the nature of their respective businesses and entering into certain restrictive agreements. The Second Amended and Restated Revolving Credit Facility is subject to acceleration upon the occurrence of certain defaults, including, among others, payment defaults on such facility, breach of representations, warranties and covenants, acceleration of indebtedness (other than intercompany and non-recourse indebtedness) of $100 million or more in the aggregate, change of control, nonpayment of uninsured judgments in excess of $100 million , and the occurrence of certain ERISA and bankruptcy events, subject where applicable to specified cure periods.

Summary of Significant Accoun23

Summary of Significant Accounting Policies (Policies)	3 Months Ended
Summary of Significant Accounting Policies (Policies)	Mar. 31, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization	Organization Enable Midstream Partners, LP 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 March 31, 2018 , CenterPoint Energy held approximately 54.0% or 233,856,623 of the Partnership’s common units, and OGE Energy held approximately 25.6% or 110,982,805 of the Partnership’s common units. Additionally, CenterPoint Energy holds 14,520,000 Series A Preferred Units. See Note 6 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 on an annual or continuing basis and may not remove Enable GP, its current general partner, 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 March 31, 2018 , the Partnership owned a 50% interest in SESH. See Note 7 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. The condensed consolidated financial statements and the related notes 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 primarily consists of cash collateral which is provided as credit assurance by 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.
Inventory	Inventory Natural gas inventory is held, through the transportation and storage segment, to provide operational support for the intrastate pipeline deliveries and to manage leased intrastate storage capacity. Natural gas liquids inventory is held, through the gathering and processing segment, due to timing differences between the production of certain natural gas liquids and ultimate sale to third parties. Natural gas and natural gas liquids inventory is valued using moving average cost and is subsequently recorded at the lower of cost or net realizable value.
Income Taxes	Income Taxes The Partnership’s earnings are not subject to income tax (other than Texas state margin taxes and taxes associated with the Partnership’s corporate subsidiary, Enable Midstream Services) and are taxable at the individual partner level. We account for deferred income taxes related to the federal and state jurisdictions using the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the future taxes attributable to the difference between financial statement carrying amounts of assets and liabilities and their respective tax basis. Deferred tax assets are also recognized for the future tax benefits attributable to the expected utilization of tax net operating loss carryforwards. In the event future utilization is determined to be unlikely, a valuation allowance is provided to reduce the tax benefits from such assets. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the period in which the temporary differences and carryforwards are expected to be recovered or settled. The effect of a change in tax rates is recognized in the period which includes the enactment date. The Partnership recognizes interest and penalties as a component of income tax expense.
New Accounting Pronouncements	New Accounting Pronouncements Accounting Standards to be Adopted in Future Periods Leases In February 2016, the FASB issued ASU 2016-02, “Leases (ASC 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. In January 2018, the FASB issued ASU 2018-01, “Land Easement Practical Expedient for Transition to Topic 842.” This standard permits an entity to elect an optional transition practical expedient to not evaluate land easements that exist or expire before the Partnership's adoption of ASC 842 and that were not previously accounted for as leases under ASC 840. The Partnership intends to elect this transition provision. The Partnership continues to review contracts and easements relative to the provisions of the ASU 2016-02 lease standard and the ASU 2018-01 easement standard as well as to monitor relevant emerging industry guidance regarding the implementation of the standards. The Partnership expects to adopt these standards in the first quarter of 2019 and is currently evaluating the overall impact of the standards on our Condensed Consolidated Financial Statements and related disclosures. Financial Instruments—Credit Losses In June 2016, the FASB issued ASU No. 2016-13, “Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments.” 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.
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 March 31, 2018 and December 31, 2017 , 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 March 31, 2018 , 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 2017 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.

Revenue (Tables)

Revenue (Tables)	3 Months Ended
Revenue (Tables)	Mar. 31, 2018
Revenue from Contract with Customer [Abstract]
Disaggregation of Revenue	The following table disaggregates total revenues by major source from contracts with customers and the change in fair value of derivatives. Three Months Ended March 31, 2018 Gathering and Transportation Eliminations Total (In millions) Revenues: Product sales: Natural gas $ 106 $ 131 $ (109 ) $ 128 Natural gas liquids 279 7 (7 ) 279 Condensate 36 — — 36 Total revenues from natural gas, natural gas liquids, and condensate 421 138 (116 ) 443 Gain (loss) on derivative activity (3 ) 2 1 — Total Product sales $ 418 $ 140 $ (115 ) $ 443 Service revenues: Demand revenues $ 50 $ 120 $ — $ 170 Volume-dependent revenues 123 19 (7 ) 135 Total Service revenues $ 173 $ 139 $ (7 ) $ 305 Total Revenues $ 591 $ 279 $ (122 ) $ 748
Schedule of Accounts Receivable	March 31, December 31, (In millions) Accounts Receivable: Customers $ 233 $ 265 Accrued minimum volume commitments (contract assets) 34 27 Non-customers 5 3 Total Accounts Receivable (1) $ 272 $ 295 ____________________ (1) Total Accounts Receivable includes Accounts receivables, net of allowance for doubtful accounts and Accounts receivable—affiliated companies.
Summary of Timing Recognition of Contract Liabilities	The table below summarizes the timing of recognition of these contract liabilities as of March 31, 2018 : 2018 2019 2020 2021 2022 and After (In millions) Deferred revenues $ 19 $ 4 $ 4 $ 4 $ 10
Summary of Timing Recognition of Remaining Performance Obligations	The table below summarizes the timing of recognition of the remaining performance obligations as of March 31, 2018 : 2018 2019 2020 2021 2022 and After Transportation and Storage $ 325 $ 329 $ 244 $ 123 $ 608 Gathering and Processing 175 221 118 94 328 Total remaining performance obligations $ 500 $ 550 $ 362 $ 217 $ 936
Schedule of New Accounting Pronouncements and Changes in Accounting Principles	The table below summarizes the change in the contract liabilities for the three months ended March 31, 2018 : March 31, December 31, Amounts recognized in revenues (In millions) Deferred revenues $ 41 $ 34 $ 15 Below is a summary of the impact of the changes on revenues as it relates to the three months ended March 31, 2018 : Three Months Ended March 31, 2018 Under ASC 606 Under ASC 605 Increase/(Decrease) (In millions) Revenues: Product sales: Natural gas $ 128 $ 139 $ (11 ) Natural gas liquids 279 283 (4 ) Condensate 36 36 — Total revenues from natural gas, natural gas liquids, and condensate 443 458 (15 ) Gain (loss) on derivative activity — — — Total Product sales $ 443 $ 458 $ (15 ) Service revenues: Demand revenues $ 170 $ 170 — Volume-dependent revenues 135 134 1 Total Service revenues $ 305 $ 304 $ 1 Total Revenues $ 748 $ 762 $ (14 )

Acquisition (Tables)

Acquisition (Tables)	3 Months Ended
Acquisition (Tables)	Mar. 31, 2018
Business Combinations [Abstract]
Schedule of Business Acquisitions, by Acquisition	The following table presents the fair value of the identified assets acquired and liabilities assumed at the acquisition date: Purchase price allocation (in millions): Assets acquired: Accounts receivable $ 5 Property, plant and equipment 111 Intangibles 176 Goodwill 12 Liabilities assumed: Current liabilities 6 Total identifiable net assets $ 298

Earnings Per Limited Partner 26

Earnings Per Limited Partner Unit (Tables)	3 Months Ended
Earnings Per Limited Partner Unit (Tables)	Mar. 31, 2018
Earnings Per Share [Abstract]
Schedule Of Earnings Per Unit For Common And Subordinated Limited Partner Units	The following table illustrates the Partnership’s calculation of earnings per unit for common and subordinated units: Three Months Ended March 31, 2018 2017 (In millions, except per unit data) Net income $ 114 $ 120 Net income attributable to noncontrolling interest — — Series A Preferred Unit distributions 9 9 General partner interest in net income — — Net income available to common and subordinated unitholders $ 105 $ 111 Net income allocable to common units $ 105 $ 58 Net income allocable to subordinated units — 53 Net income available to common and subordinated unitholders $ 105 $ 111 Net income allocable to common units $ 105 $ 58 Dilutive effect of Series A Preferred Unit distributions — — Diluted net income allocable to common units 105 58 Diluted net income allocable to subordinated units — 53 Total $ 105 $ 111 Basic weighted average number of outstanding Common units (1) 434 225 Subordinated units — 208 Total 434 433 Basic earnings per unit Common units $ 0.24 $ 0.26 Subordinated units $ — $ 0.25 Basic weighted average number of outstanding common units 434 225 Dilutive effect of Series A Preferred Units — — Dilutive effect of performance units 1 1 Diluted weighted average number of outstanding common units 435 226 Diluted weighted average number of outstanding subordinated units — 208 Total 435 434 Diluted earnings per unit Common units $ 0.24 $ 0.26 Subordinated units $ — $ 0.25 ____________________ (1) Basic weighted average number of outstanding common units for each of the three months ended March 31, 2018 and 2017 includes approximately one million time-based phantom units.

Partners' Equity (Tables)

Partners' Equity (Tables)	3 Months Ended
Partners' Equity (Tables)	Mar. 31, 2018
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, as applicable, during 2017 and 2018 (in millions, except for per unit amounts): Three Months Ended Record Date Payment Date Per Unit Distribution Total Cash Distribution March 31, 2018 (1) May 22, 2018 May 29, 2018 $ 0.318 $ 138 December 31, 2017 February 20, 2018 February 27, 2018 $ 0.318 $ 138 September 30, 2017 November 14, 2017 November 21, 2017 $ 0.318 $ 138 June 30, 2017 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 _____________________ (1) The board of directors of Enable GP declared this 0.318 per common unit cash distribution on May 1, 2018 , to be paid on May 29, 2018 , to common unitholders of record at the close of business on May 22, 2018 .
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 2017 and 2018 (in millions, except for per unit amounts): Three Months Ended Record Date Payment Date Per Unit Distribution Total Cash Distribution March 31, 2018 (1) May 1, 2018 May 15, 2018 $ 0.625 $ 9 December 31, 2017 February 9, 2018 February 15, 2018 $ 0.625 $ 9 September 30, 2017 October 31, 2017 November 14, 2017 $ 0.625 $ 9 June 30, 2017 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 _____________________ (1) The board of directors of Enable GP declared a $0.625 per Series A Preferred Unit cash distribution on May 1, 2018 , to be paid on May 15, 2018 , to Series A Preferred unitholders of record at the close of business on May 1, 2018 .

Investment in Equity Method A28

Investment in Equity Method Affiliate (Tables)	3 Months Ended
Investment in Equity Method Affiliate (Tables)	Mar. 31, 2018
Equity Method Investments and Joint Ventures [Abstract]
Schedule of Investments Detail	Equity in Earnings of Equity Method Affiliate: Three Months Ended March 31, 2018 2017 (In millions) SESH $ 6 $ 7 Distributions from Equity Method Affiliate: Three Months Ended March 31, 2018 2017 (In millions) SESH (1) $ 13 $ 11 ___________________ (1) Distributions from equity method affiliate includes a $6 million and $7 million return on investment and a $7 million and $4 million return of investment for the three months ended March 31, 2018 and 2017 , respectively. Summarized financial information of SESH: Three Months Ended March 31, 2018 2017 (In millions) Income Statements: Revenues $ 28 $ 28 Operating income $ 17 $ 17 Net income $ 12 $ 13

Debt (Tables)

Debt (Tables)	3 Months Ended
Debt (Tables)	Mar. 31, 2018
Debt Disclosure [Abstract]
Schedule of Debt	The following table presents the Partnership’s outstanding debt as of March 31, 2018 and December 31, 2017 . March 31, 2018 December 31, 2017 Outstanding Principal Premium (Discount) Total Debt Outstanding Principal Premium (Discount) Total Debt (In millions) Commercial Paper $ 596 $ (1 ) $ 595 $ 405 $ — $ 405 Revolving Credit Facility — — — — — — 2015 Term Loan Agreement 450 — 450 450 — 450 2019 Notes 500 — 500 500 — 500 2024 Notes 600 — 600 600 — 600 2027 Notes 700 (3 ) 697 700 (3 ) 697 2044 Notes 550 — 550 550 — 550 EOIT Senior Notes 250 11 261 250 13 263 Total debt $ 3,646 $ 7 $ 3,653 $ 3,455 $ 10 $ 3,465 Less: Current portion of long-term debt 450 450 Less: Short-term debt (1) 595 405 Less: Unamortized debt expense (2) 14 15 Total long-term debt $ 2,594 $ 2,595 ____________________ (1) Short-term debt includes $596 million and $405 million of outstanding commercial paper as of March 31, 2018 and December 31, 2017 , respectively. (2) As of March 31, 2018 and December 31, 2017 , there was an additional $3 million of unamortized debt expense related to the Revolving Credit Facility included in Other long-term assets, not included above.

Derivative Instruments and He30

Derivative Instruments and Hedging Activities (Tables)	3 Months Ended
Derivative Instruments and Hedging Activities (Tables)	Mar. 31, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Derivative Instruments	As of March 31, 2018 and December 31, 2017 , the Partnership had the following derivative instruments that were not designated as hedging instruments for accounting purposes: March 31, 2018 December 31, 2017 Gross Notional Volume Purchases Sales Purchases Sales Natural gas— TBtu (1) Financial fixed futures/swaps 19 22 17 13 Financial basis futures/swaps 27 31 17 17 Physical purchases/sales — 81 1 37 Crude oil (for condensate)— MBbl (2) Financial Futures/swaps — 874 — 564 Natural gas liquids— MBbl (3) Financial Futures/swaps — 2,195 — 1,615 ____________________ (1) As of March 31, 2018 , 82.4% of the natural gas contracts had durations of one year or less, 10.7% had durations of more than one year and less than two years and 6.9% had durations of more than two years. As of December 31, 2017 , 67.7% of the natural gas contracts had durations of one year or less, 16.1% had durations of more than one year and less than two years and 16.2% had durations of more than two years. (2) As of March 31, 2018 , 69.1% of the crude oil (for condensate) contracts had durations of one year or less and 30.9% had durations of more than one year and less than two years. As of December 31, 2017 , 100% of the crude oil (for condensate) contracts had durations of one year or less. (3) As of March 31, 2018 , 72.0% of the natural gas liquids contracts had durations of one year or less and 28.0% had durations of more than one year and less than two years. As of December 31, 2017 , 100% of the natural gas liquid contracts had durations of one year or less.
Schedule of Derivative Assets at Fair Value	The fair value of the derivative instruments that are presented in the Partnership’s Condensed Consolidated Balance Sheets as of March 31, 2018 and December 31, 2017 that were not designated as hedging instruments for accounting purposes are as follows: March 31, 2018 December 31, 2017 Fair Value Instrument Balance Sheet Location Assets Liabilities Assets Liabilities (In millions) Natural gas Financial futures/swaps Other Current/Other $ 3 $ 9 $ 5 $ 4 Physical purchases/sales Other Current/Other 6 1 3 — Crude oil (for condensate) Financial futures/swaps Other Current/Other — 5 — 4 Natural gas liquids Financial Futures/swaps Other Current/Other 2 2 1 5 Total gross derivatives (1) $ 11 $ 17 $ 9 $ 13 _____________________ (1) See Note 10 for a reconciliation of the Partnership’s total derivatives fair value to the Partnership’s Condensed Consolidated Balance Sheets as of March 31, 2018 and December 31, 2017 .
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 months ended March 31, 2018 and 2017 : Amounts Recognized in Income Three Months Ended March 31, 2018 2017 (In millions) Natural gas Financial futures/swaps (losses) gains $ (3 ) $ 11 Physical purchases/sales gains 2 5 Crude oil (for condensate) Financial futures/swaps (losses) gains (3 ) 3 Natural gas liquids Financial futures/swaps gains 4 2 Total $ — $ 21
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 months ended March 31, 2018 and 2017 : Three Months Ended March 31, 2018 2017 (In millions) Change in fair value of derivatives $ (2 ) $ 24 Realized gain (loss) on derivatives 2 (3 ) Gain on derivative activity $ — $ 21

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	3 Months Ended
Fair Value Measurements (Tables)	Mar. 31, 2018
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 March 31, 2018 and December 31, 2017 . March 31, 2018 December 31, 2017 Carrying Amount Fair Value Carrying Amount Fair Value (In millions) Debt Revolving Credit Facility (Level 2) (1) $ — $ — $ — $ — 2015 Term Loan Agreement (Level 2) 450 450 450 450 2019 Notes (Level 2) 500 494 500 497 2024 Notes (Level 2) 600 588 600 602 2027 Notes (Level 2) 697 687 697 712 2044 Notes (Level 2) 550 523 550 550 EOIT Senior Notes (Level 2) 261 261 263 265
Schedule of Assets and Liabilities Measured at Fair Value on a Recurring Basis	The following tables summarize the Partnership’s assets and liabilities that are measured at fair value on a recurring basis as of March 31, 2018 and December 31, 2017 : March 31, 2018 Commodity Contracts Gas Imbalances (1) Assets Liabilities Assets (2) Liabilities (3) (In millions) Quoted market prices in active market for identical assets (Level 1) $ 3 $ 7 $ — $ — Significant other observable inputs (Level 2) 6 8 19 8 Unobservable inputs (Level 3) 2 2 — — Total fair value 11 17 19 8 Netting adjustments (3 ) (3 ) — — Total $ 8 $ 14 $ 19 $ 8 December 31, 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) $ 5 $ 3 $ — $ — Significant other observable inputs (Level 2) 4 5 27 12 Unobservable inputs (Level 3) — 5 — — Total fair value 9 13 27 12 Netting adjustments (5 ) (5 ) — — Total $ 4 $ 8 $ 27 $ 12 ______________________ (1) The Partnership uses the market approach to fair value its gas imbalance assets and liabilities at individual, or where appropriate an average of, current market indices applicable to the Partnership’s operations, not to exceed net realizable value. Gas imbalances held by EOIT are valued using an average of the Inside FERC Gas Market Report for Panhandle Eastern Pipe Line Co. (Texas, Oklahoma Mainline), ONEOK (Oklahoma) and ANR Pipeline (Oklahoma) indices. There were no netting adjustments as of March 31, 2018 and December 31, 2017 . (2) Gas imbalance assets exclude fuel reserves for under retained fuel due from shippers of $16 million and $10 million at March 31, 2018 and December 31, 2017 , respectively, which fuel reserves are based on the value of natural gas at the time the imbalance was created and which are not subject to revaluation at fair market value. (3) Gas imbalance liabilities exclude fuel reserves for over retained fuel due to shippers of zero at March 31, 2018 and December 31, 2017 , 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 at December 31, 2017 $ (5 ) Gains included in earnings 4 Settlements 1 Transfers out of Level 3 — Balance as of March 31, 2018 $ —
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. March 31, 2018 Product Group Fair Value Forward Curve Range (In millions) (Per gallon) Natural gas liquids $ — $0.2663 - $0.8963

Supplemental Disclosure of Ca32

Supplemental Disclosure of Cash Flow Information (Tables)	3 Months Ended
Supplemental Disclosure of Cash Flow Information (Tables)	Mar. 31, 2018
Supplemental Cash Flow Information [Abstract]
Schedule of Cash Flow, Supplemental Disclosures	The following table provides information regarding supplemental cash flow information: Three Months Ended March 31, 2018 2017 (In millions) Supplemental Disclosure of Cash Flow Information: Cash Payments: Interest, net of capitalized interest $ 29 $ 14 Income taxes, net of refunds 2 — Non-cash transactions: Accounts payable related to capital expenditures 50 20
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 Statements of Cash Flows: Three Months Ended March 31, 2018 2017 (In millions) Cash and cash equivalents $ 30 $ 17 Restricted cash 14 14 Cash, cash equivalents and restricted cash shown in the Condensed Consolidated Statements of Cash Flows $ 44 $ 31
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 Statements of Cash Flows: Three Months Ended March 31, 2018 2017 (In millions) Cash and cash equivalents $ 30 $ 17 Restricted cash 14 14 Cash, cash equivalents and restricted cash shown in the Condensed Consolidated Statements of Cash Flows $ 44 $ 31

Related Party Transactions (Tab

Related Party Transactions (Tables)	3 Months Ended
Related Party Transactions (Tables)	Mar. 31, 2018
Related Party Transactions [Abstract]
Schedule of Revenues from Related Parties	Amounts of revenues from affiliated companies included in the Partnership’s Condensed Consolidated Statements of Income are summarized as follows: Three Months Ended March 31, 2018 2017 (In millions) Gas transportation and storage service revenue — CenterPoint Energy $ 33 $ 33 Natural gas product sales — CenterPoint Energy 6 — Gas transportation and storage service revenue — OGE Energy 9 9 Natural gas product sales — OGE Energy 1 — Total revenues — affiliated companies $ 49 $ 42
Schedule of Natural Gas Purchased From Related Parties	Amounts of natural gas purchased from affiliated companies included in the Partnership’s Condensed Consolidated Statements of Income are summarized as follows: Three Months Ended March 31, 2018 2017 (In millions) Cost of natural gas purchases — CenterPoint Energy $ 2 $ — Cost of natural gas purchases — OGE Energy 3 3 Total cost of natural gas purchases — affiliated companies $ 5 $ 3
Schedule of Amounts Charged to Partnership by Related Parties	Amounts charged to the Partnership by affiliates for seconded employees, an operating lease and corporate services, included primarily in Operation and maintenance and General and administrative expenses in the Partnership’s Condensed Consolidated Statements of Income are as follows: Three Months Ended March 31, 2018 2017 (In millions) Corporate Services — CenterPoint Energy $ 1 $ 1 Operating Lease — CenterPoint Energy — — Seconded Employee Costs — OGE Energy 8 7 Corporate Services — OGE Energy — 1 Total corporate services and seconded employees expense $ 9 $ 9

Equity-Based Compensation (Tabl

Equity-Based Compensation (Tables)	3 Months Ended
Equity-Based Compensation (Tables)	Mar. 31, 2018
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Disclosure of Share-based Compensation Arrangements by Share-based Payment Award	The following table summarizes the Partnership’s compensation expense for the three months ended March 31, 2018 and 2017 related to performance units, restricted units, and phantom units for the Partnership’s employees and independent directors: Three Months Ended March 31, 2018 2017 (In millions) Performance units $ 3 $ 3 Restricted units 1 — Phantom units 1 1 Total compensation expense $ 5 $ 4
Schedule of Share-based Compensation, Activity	A summary of the activity for the Partnership’s performance units, restricted units, and phantom units applicable to the Partnership’s employees at March 31, 2018 and changes during 2018 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, 2017 2,040,407 $ 13.86 222,434 $ 17.87 987,380 $ 11.38 Granted (1) 529,408 17.70 — — 494,072 14.04 Vested (2) (401,772 ) 16.59 (181,068 ) 16.75 — — Forfeited (3,725 ) 13.87 (1,366 ) 16.75 (7,375 ) 11.90 Units Outstanding at March 31, 2018 2,164,318 $ 13.95 40,000 $ 22.96 1,474,077 $ 12.27 Aggregate Intrinsic Value of Units Outstanding at March 31, 2018 $ 30 $ 1 $ 20 _____________________ (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 zero percent to 200 percent of the target. (2) Performance units vested as of March 31, 2018 include 401,772 units from the annual grant, which were approved by the Board of Directors in 2015 and paid out at 200% , or 803,544 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. March 31, 2018 Unrecognized Compensation Cost (In millions) Weighted Average to be Recognized (In years) Performance Units $ 19 1.66 Restricted Units — 0.22 Phantom Units 12 1.86 Total $ 31

Reportable Segments (Tables)

Reportable Segments (Tables)	3 Months Ended
	Mar. 31, 2018
Segment Reporting [Abstract]
Schedule of Financial Data for Business Segments and Services	Financial data for reportable segments are as follows: Three Months Ended March 31, 2018 Gathering and Transportation (1) Eliminations Total (In millions) Product sales $ 418 $ 140 $ (115 ) $ 443 Service revenue 173 139 (7 ) 305 Total Revenues 591 279 (122 ) 748 Cost of natural gas and natural gas liquids 358 139 (122 ) 375 Operation and maintenance, General and administrative 76 46 (1 ) 121 Depreciation and amortization 62 34 — 96 Taxes other than income tax 10 7 — 17 Operating income $ 85 $ 53 $ 1 $ 139 Capital expenditures $ 147 $ 43 $ — $ 190 Total assets $ 9,212 $ 5,652 $ (3,177 ) $ 11,687 Three Months Ended March 31, 2017 Gathering and (1) Eliminations Total (In millions) Product sales $ 351 $ 153 $ (118 ) $ 386 Service revenue 140 141 (1 ) 280 Total Revenues 491 294 (119 ) 666 Cost of natural gas and natural gas liquids 286 140 (118 ) 308 Operation and maintenance, General and administrative 70 45 (1 ) 114 Depreciation and amortization 56 32 — 88 Taxes other than income tax 9 7 — 16 Operating income $ 70 $ 70 $ — $ 140 Capital expenditures $ 51 $ 10 $ — $ 61 Total assets as of December 31, 2017 $ 9,079 $ 5,616 $ (3,102 ) $ 11,593 _____________________ (1) See Note 7 for discussion regarding ownership interests in SESH and related equity earnings included in the transportation and storage segment for the three months ended March 31, 2018 and 2017 .	[1]

[1]	See Note 7 for discussion regarding ownership interests in SESH and related equity earnings included in the transportation and storage segment for the three months ended March 31, 2018 and 2017.

Summary of Significant Accoun36

Summary of Significant Accounting Policies - Narrative (Details)	3 Months Ended
	Mar. 31, 2018USD ($)board_membersegmentshares	Mar. 31, 2017USD ($)	Dec. 31, 2017USD ($)
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	$ 14,000,000	$ 14,000,000	$ 14,000,000
Allowance for doubtful accounts	2,000,000		3,000,000
Inventory adjustments	$ 3,000,000		$ 0
Impairment of long-lived assets		$ 0
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	54.00%
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 \| shares	14,520,000
Limited Partner \| CenterPoint \| Common Units
Significant Accounting Policies [Line Items]
Units outstanding \| shares	233,856,623
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	25.60%
Limited Partner \| OGE Energy \| Common Units
Significant Accounting Policies [Line Items]
Units outstanding \| shares	110,982,805

Revenue - Disaggregation of Rev

Revenue - Disaggregation of Revenue (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Disaggregation of Revenue [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate	$ 443
Gain (loss) on derivative activity	0	$ 21
Total Product sales	443	386
Service revenues	305	280
Total Revenues	748	666
Natural gas
Disaggregation of Revenue [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate	128
Natural gas liquids
Disaggregation of Revenue [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate	279
Condensate Natural Gas
Disaggregation of Revenue [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate	36
Demand Service Revenue
Disaggregation of Revenue [Line Items]
Service revenues	170
Volume Dependant Service Revenue
Disaggregation of Revenue [Line Items]
Service revenues	135
Operating Segments \| Gathering and Processing
Disaggregation of Revenue [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate	421
Gain (loss) on derivative activity	(3)
Total Product sales	418	351
Service revenues	173	140
Total Revenues	591	491
Operating Segments \| Gathering and Processing \| Natural gas
Disaggregation of Revenue [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate	106
Operating Segments \| Gathering and Processing \| Natural gas liquids
Disaggregation of Revenue [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate	279
Operating Segments \| Gathering and Processing \| Condensate Natural Gas
Disaggregation of Revenue [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate	36
Operating Segments \| Gathering and Processing \| Demand Service Revenue
Disaggregation of Revenue [Line Items]
Service revenues	50
Operating Segments \| Gathering and Processing \| Volume Dependant Service Revenue
Disaggregation of Revenue [Line Items]
Service revenues	123
Operating Segments \| Transportation and Storage
Disaggregation of Revenue [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate	138
Gain (loss) on derivative activity	2
Total Product sales	140	153
Service revenues	139	141
Total Revenues	279	294
Operating Segments \| Transportation and Storage \| Natural gas
Disaggregation of Revenue [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate	131
Operating Segments \| Transportation and Storage \| Natural gas liquids
Disaggregation of Revenue [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate	7
Operating Segments \| Transportation and Storage \| Condensate Natural Gas
Disaggregation of Revenue [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate	0
Operating Segments \| Transportation and Storage \| Demand Service Revenue
Disaggregation of Revenue [Line Items]
Service revenues	120
Operating Segments \| Transportation and Storage \| Volume Dependant Service Revenue
Disaggregation of Revenue [Line Items]
Service revenues	19
Eliminations
Disaggregation of Revenue [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate	(116)
Gain (loss) on derivative activity	1
Total Product sales	(115)	(118)
Service revenues	(7)	(1)
Total Revenues	(122)	$ (119)
Eliminations \| Natural gas
Disaggregation of Revenue [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate	(109)
Eliminations \| Natural gas liquids
Disaggregation of Revenue [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate	(7)
Eliminations \| Condensate Natural Gas
Disaggregation of Revenue [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate	0
Eliminations \| Demand Service Revenue
Disaggregation of Revenue [Line Items]
Service revenues	0
Eliminations \| Volume Dependant Service Revenue
Disaggregation of Revenue [Line Items]
Service revenues	$ (7)

Revenue - Accounts Receivable (

Revenue - Accounts Receivable (Details) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Revenue from Contract with Customer [Abstract]
Customers	$ 233	$ 265
Accrued minimum volume commitments (contract assets)	34	27
Non-customers	5	3
Total Accounts Receivable	$ 272	$ 295

Revenue - Summary of Recognitio

Revenue - Summary of Recognition Contract Liabilities (Details) $ in Millions	3 Months Ended
	Mar. 31, 2018USD ($)
Revenue from Contract with Customer [Abstract]
2,018	$ 19
2,019	4
2,020	4
2,021	4
2022 and After	$ 10

Revenue - Summary of Recognit40

Revenue - Summary of Recognition of Remaining Performance Obligations (Details) $ in Millions	Mar. 31, 2018USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2018-04-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total remaining performance obligations	$ 500
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2018-04-01 \| Transportation and Storage
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total remaining performance obligations	325
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2018-04-01 \| Gathering and Processing
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total remaining performance obligations	175
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-04-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total remaining performance obligations	550
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-04-01 \| Transportation and Storage
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total remaining performance obligations	329
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-04-01 \| Gathering and Processing
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total remaining performance obligations	221
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-04-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total remaining performance obligations	362
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-04-01 \| Transportation and Storage
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total remaining performance obligations	244
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-04-01 \| Gathering and Processing
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total remaining performance obligations	118
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-04-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total remaining performance obligations	217
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-04-01 \| Transportation and Storage
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total remaining performance obligations	123
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-04-01 \| Gathering and Processing
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total remaining performance obligations	94
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-04-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total remaining performance obligations	936
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-04-01 \| Transportation and Storage
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total remaining performance obligations	608
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-04-01 \| Gathering and Processing
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total remaining performance obligations	$ 328

Revenue - Summary of the Impact

Revenue - Summary of the Impact of the Changes on Revenues (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate	$ 443
Gain (loss) on derivative activity	0	$ 21
Product sales	443	386
Service revenues	305	280
Revenue, Net	748	$ 666
Under ASC 605
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate	458
Gain (loss) on derivative activity	0
Product sales	458
Service revenues	304
Revenue, Net	762
Increase/(Decrease)
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate	(15)
Gain (loss) on derivative activity	0
Product sales	(15)
Service revenues	1
Revenue, Net	(14)
Natural gas
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate	128
Natural gas \| Under ASC 605
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate	139
Natural gas \| Increase/(Decrease)
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate	(11)
Natural gas liquids
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate	279
Natural gas liquids \| Under ASC 605
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate	283
Natural gas liquids \| Increase/(Decrease)
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate	(4)
Condensate Natural Gas
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate	36
Condensate Natural Gas \| Under ASC 605
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate	36
Condensate Natural Gas \| Increase/(Decrease)
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate	0
Demand Service Revenue
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Service revenues	170
Demand Service Revenue \| Under ASC 605
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Service revenues	170
Demand Service Revenue \| Increase/(Decrease)
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Service revenues	0
Volume Dependant Service Revenue
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Service revenues	135
Volume Dependant Service Revenue \| Under ASC 605
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Service revenues	134
Volume Dependant Service Revenue \| Increase/(Decrease)
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Service revenues	$ 1

Revenue - Summary of Changes in

Revenue - Summary of Changes in Contract Liabilities (Details) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Deferred revenues	$ 41
Calculated under Revenue Guidance in Effect before Topic 606
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Deferred revenues		$ 34
Accounting Standards Update 2014-09 \| Difference between Revenue Guidance in Effect before and after Topic 606
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Deferred revenues	$ 15

Acquisition - Narrative (Detail

Acquisition - Narrative (Details) - Align Midstream, LLC $ in Millions	Oct. 04, 2017USD ($)mi	Dec. 31, 2017USD ($)
Business Acquisition [Line Items]
Payment to acquire Align Midstream, LLC	$ 298
General and Administrative Expense
Business Acquisition [Line Items]
Acquisition costs association with the transaction		$ 2
Pipelines
Business Acquisition [Line Items]
Length of gather pipe (miles) \| mi	190
Customer Relationships
Business Acquisition [Line Items]
Weighted average useful life (in years)	10 years

Acquisition - Schedule of Asset

Acquisition - Schedule of Assets and Liabilities Assumed (Details) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017	Oct. 04, 2017
Assets acquired:
Goodwill	$ 12	$ 12
Align Midstream, LLC
Assets acquired:
Accounts receivable			$ 5
Property, plant and equipment			111
Intangibles			176
Goodwill			12
Liabilities assumed:
Current liabilities			6
Total identifiable net assets			$ 298

Earnings Per Limited Partner 45

Earnings Per Limited Partner Unit (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions		3 Months Ended
		Mar. 31, 2018	Mar. 31, 2017
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net income		$ 114	$ 120
Net income attributable to noncontrolling interest		0	0
Series A Preferred Unit distributions		9	9
General partner interest in net income		0	0
Net Income Attributable to Common and Subordinated Units (Note 5)		105	111
Dilutive effect of Series A Preferred Unit distributions		0	0
Diluted net income		$ 105	$ 111
Basic weighted average number of outstanding
Basic weighted average number of outstanding		434	433
Basic earnings per unit
Dilutive effect of Series A Preferred Units (in units)		0	0
Dilutive effect of performance units (in units)		1	1
Diluted weighted average number of outstanding units		435	434
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
Phantom units
Basic weighted average number of outstanding
Basic weighted average number of outstanding	[1]	1	0
Common Units
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net Income Attributable to Common and Subordinated Units (Note 5)		$ 105	$ 58
Diluted net income		$ 105	$ 58
Basic weighted average number of outstanding
Basic weighted average number of outstanding	[1]	434	225
Basic earnings per unit
Basic earnings per unit		$ 0.24	$ 0.26
Diluted weighted average number of outstanding units		435	226
Diluted earnings per unit		$ 0.24	$ 0.26
Subordinated Units
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net Income Attributable to Common and Subordinated Units (Note 5)		$ 0	$ 53
Diluted net income		$ 0	$ 53
Basic weighted average number of outstanding
Basic weighted average number of outstanding		0	208
Basic earnings per unit
Basic earnings per unit		$ 0	$ 0.25
Diluted weighted average number of outstanding units		0	208
Diluted earnings per unit		$ 0	$ 0.25

[1]	Basic weighted average number of outstanding common units for each of the three months ended March 31, 2018 and 2017 includes approximately one million time-based phantom units.

Partners' Equity - Schedule of

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

May 29, 2018

May 22, 2018

May 15, 2018

May 14, 2018

May 01, 2018

Feb. 27, 2018

Feb. 20, 2018

Feb. 15, 2018

Feb. 09, 2018

Nov. 21, 2017

Nov. 14, 2017

Oct. 31, 2017

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

Distribution Made to Limited Partner [Line Items]

Record Date

Feb. 20,
2018

Nov. 14,
2017

Aug. 22,
2017

May 23,
2017

Feb. 21,
2017

Payment Date

Feb. 27,
2018

Nov. 21,
2017

Aug. 29,
2017

May 30,
2017

Feb. 28,
2017

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

Distribution Made to Limited Partner [Line Items]

Record Date

Feb. 9,
2018

Oct. 31,
2017

Jul. 31,
2017

May 2,
2017

Feb. 10,
2017

Payment Date

Feb. 15,
2018

Nov. 14,
2017

Aug. 14,
2017

May 12,
2017

Feb. 15,
2017

Cash Distribution

Distribution Made to Limited Partner [Line Items]

Cash distribution declared (in dollars per unit)

$ 0.318

Distribution made to unitholders

$ 138,000,000

$ 137,000,000

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

Distribution Made to Limited Partner [Line Items]

Cash distribution declared (in dollars per unit)

$ 0.625

Distribution made to unitholders

$ 9,000,000

Subsequent Event

Distribution Made to Limited Partner [Line Items]

Record Date

[1]

May 22,
2018

Payment Date

[1]

May 29,
2018

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]

May 1,
2018

Payment Date

[2]

May 15,
2018

Subsequent Event | Cash Distribution

Distribution Made to Limited Partner [Line Items]

Distribution Made to Limited Partner, Distributions Declared, Per Unit

[1]

$ 0.318

Cash distribution declared (in dollars per unit)

[1]

$ 0.318

Distribution made to unitholders

[1]

$ 138,000,000

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

Distribution Made to Limited Partner [Line Items]

Cash distribution declared (in dollars per unit)

0.625

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

Distribution Made to Limited Partner [Line Items]

Distribution Made to Limited Partner, Distributions Declared, Per Unit

$ 0.625

Cash distribution declared (in dollars per unit)

[2]

$ 0.625

Distribution made to unitholders

[2]

$ 9,000,000

[1]

The board of directors of Enable GP declared this 0.318 per common unit cash distribution on May 1, 2018, to be paid on May 29, 2018, to common unitholders of record at the close of business on May 22, 2018.

[2]

The board of directors of Enable GP declared a $0.625 per Series A Preferred Unit cash distribution on May 1, 2018, to be paid on May 15, 2018, to Series A Preferred unitholders of record at the close of business on May 1, 2018.

Partners' Equity - Narrative (D

Partners' Equity - Narrative (Details)	May 12, 2017USD ($)	Feb. 18, 2016USD ($)$ / sharesshares	Mar. 31, 2018$ / sharesshares	Dec. 31, 2017shares	Aug. 30, 2017shares
Distribution Made to Limited Partner [Line Items]
Limited partners' capital account, required quarterly distribution period			60 days
Subordinated Units
Distribution Made to Limited Partner [Line Items]
Units outstanding \| shares			0	0	207,855,430
Conversion basis					1
CenterPoint \| Limited Partner
Distribution Made to Limited Partner [Line Items]
Repayment of notes payable—affiliated companies \| $		$ 363,000,000
ATM Program
Distribution Made to Limited Partner [Line Items]
Aggregate offering price \| $	$ 200,000,000
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 \| $		$ 362,000,000
Expenses related to the offering \| $		$ 1,000,000
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 \| $		$ 362,000,000
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

Investment in Equity Method A48

Investment in Equity Method Affiliate - Narrative (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Schedule of Equity Method Investments [Line Items]
Equity in earnings of equity method affiliate	$ 6	$ 7
SESH
Schedule of Equity Method Investments [Line Items]
Equity in earnings of equity method affiliate	$ 6	7
Ownership percentage	50.00%
Percentage of distributions through limited partner interest	50.00%
SESH \| Equity Method Investee \| Shared Operations Service Agreements
Schedule of Equity Method Investments [Line Items]
Amount billed associated with service agreements	$ 2	$ 5

Investment in Equity Method A49

Investment in Equity Method Affiliate - Schedule of Investments (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2018	Mar. 31, 2017
Equity in Earnings of Equity Method Affiliates:
Equity in earnings of equity method affiliate		$ 6	$ 7
Distributions from Equity Method Affiliates:
Return on investment in equity method affiliate		6	7
Return of investment in equity method affiliate		7	4
SESH
Equity in Earnings of Equity Method Affiliates:
Equity in earnings of equity method affiliate		6	7
Distributions from Equity Method Affiliates:
Distributions from equity method affiliate	[1]	13	11
Return on investment in equity method affiliate		6
Return of investment in equity method affiliate		7	4
Revenues		28	28
Operating income		17	17
Net income		$ 12	$ 13

[1]	Distributions from equity method affiliate includes a $6 million and $7 million return on investment and a $7 million and $4 million return of investment for the three months ended March 31, 2018 and 2017, respectively.

Debt - Schedule of Outstanding

Debt - Schedule of Outstanding Debt (Details) - USD ($) $ in Millions		Mar. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Outstanding Principal		$ 3,646	$ 3,455
Premium (Discount)		7	10
Total Debt		3,653	3,465
Less: Unamortized debt expense	[1]	14	15
Total long-term debt		2,594	2,595
2015 Term Loan Agreement \| 2015 Term Loan Agreement
Debt Instrument [Line Items]
Outstanding Principal		450	450
Premium (Discount)		0	0
Total Debt		450	450
Less: Current portion of long-term 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	0
Total Debt		600	600
Senior Notes \| 2027 Notes
Debt Instrument [Line Items]
Outstanding Principal		700	700
Premium (Discount)		(3)	(3)
Total Debt		697	697
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)		11	13
Total Debt		261	263
Revolving Credit Facility
Debt Instrument [Line Items]
Outstanding Principal		0	0
Premium (Discount)		0	0
Total Debt		0	0
Unamortized debt expense related to Revolving Credit Facility		3
Commercial Paper
Debt Instrument [Line Items]
Short-term Debt		596	405
Premium (Discount)		(1)	0
Less: Short-term debt	[2]	$ 595	405
Commercial Paper \| Revolving Credit Facility
Debt Instrument [Line Items]
Unamortized debt expense related to Revolving Credit Facility			$ 3

[1]	As of March 31, 2018 and December 31, 2017, there was an additional $3 million of unamortized debt expense related to the Revolving Credit Facility included in Other long-term assets, not included above.
[2]	Short-term debt includes $596 million and $405 million of outstanding commercial paper as of March 31, 2018 and December 31, 2017, respectively.

Debt - Narrative (Details)

Debt - Narrative (Details)		Mar. 09, 2017USD ($)	Jul. 31, 2015USD ($)time	Jun. 18, 2015USD ($)time	Mar. 31, 2018USD ($)	Dec. 31, 2017USD ($)
Debt Instrument [Line Items]
Commercial paper, authorized					$ 1,400,000,000
Premium (Discount)					7,000,000	$ 10,000,000
Outstanding Principal					3,646,000,000	3,455,000,000
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 (in years)			1 year
Duration of term loan facility (in years)			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					2.98%
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
Premium (Discount)					$ (3,000,000)	(3,000,000)
Fixed interest rate percentage		4.40%
Net proceeds		$ 691,000,000
Unamortized debt expense					5,000,000
Outstanding Principal					$ 700,000,000	700,000,000
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					$ 9,000,000
Senior Notes \| 2019 Notes
Debt Instrument [Line Items]
Premium (Discount)					0	0
Outstanding Principal					$ 500,000,000	500,000,000
Effective interest rate percentage					2.57%
Senior Notes \| 2024 Notes
Debt Instrument [Line Items]
Premium (Discount)					$ 0	0
Outstanding Principal					$ 600,000,000	600,000,000
Effective interest rate percentage					4.02%
Senior Notes \| 2044 Notes
Debt Instrument [Line Items]
Premium (Discount)					$ 0	0
Outstanding Principal					$ 550,000,000	550,000,000
Effective interest rate percentage					5.08%
Senior Notes \| EOIT Senior Notes \| EOIT
Debt Instrument [Line Items]
Premium (Discount)					$ 11,000,000	13,000,000
Fixed interest rate percentage					6.25%
Outstanding Principal					$ 250,000,000	250,000,000
Unamortized premium					$ 11,000,000
Effective interest rate percentage					3.80%
Commercial Paper
Debt Instrument [Line Items]
Commercial paper outstanding					$ 596,000,000	405,000,000
Short-term Debt, Net of Premium (Discount)	[1]				$ 595,000,000	405,000,000
Weighted average interest rate percentage					2.72%
Premium (Discount)					$ (1,000,000)	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 (in years)				1 year
Letters of credit principal advances					0
Letters of credit outstanding amount					$ 3,000,000
Commitment fee percentage					0.20%
Premium (Discount)					$ 0	0
Outstanding Principal					$ 0	$ 0
Revolving Credit Facility \| LIBOR
Debt Instrument [Line Items]
Applicable margin percentage					1.50%

[1]	Short-term debt includes $596 million and $405 million of outstanding commercial paper as of March 31, 2018 and December 31, 2017, respectively.

Derivative Instruments and He52

Derivative Instruments and Hedging Activities (Details) - Not Designated as Hedging Instrument bbl in Thousands, MMBTU in Millions		3 Months Ended
		Mar. 31, 2018MMBTUbbl	Mar. 31, 2017MMBTUbbl	Dec. 31, 2017
Natural Gas, Financial fixed futures/swaps \| Purchases
Derivative [Line Items]
Derivative, gross notional volume (TBtu)	[1]	19	17
Natural Gas, Financial fixed futures/swaps \| Sales
Derivative [Line Items]
Derivative, gross notional volume (TBtu)	[1]	22	13
Natural gas, Financial basis futures/swaps \| Purchases
Derivative [Line Items]
Derivative, gross notional volume (TBtu)	[1]	27	17
Natural gas, Financial basis futures/swaps \| Sales
Derivative [Line Items]
Derivative, gross notional volume (TBtu)	[1]	31	17
Physical purchases/sales \| Purchases
Derivative [Line Items]
Derivative, gross notional volume (TBtu)	[1]	0	1
Physical purchases/sales \| Sales
Derivative [Line Items]
Derivative, gross notional volume (TBtu)	[1]	81	37
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]	874,000	564,000
Natural gas liquids, Financial Futures/swaps \| Purchases
Derivative [Line Items]
Derivative, gross notional volume (MMbl) \| bbl	[3]	0	0
Natural gas liquids, Financial Futures/swaps \| Sales
Derivative [Line Items]
Derivative, gross notional volume (MMbl) \| bbl	[3]	2,195,000	1,615,000
Natural gas
Derivative [Line Items]
Percent of contract with durations of one year or less		82.40%		67.70%
Percent of contracts with durations of more than one year and less than two years		10.70%		16.10%
Percent of contracts with durations of more than two years		6.90%		16.20%
Condensate
Derivative [Line Items]
Percent of contract with durations of one year or less		69.10%		100.00%
Percent of contracts with durations of more than one year and less than two years		30.90%
Natural gas liquids
Derivative [Line Items]
Percent of contract with durations of one year or less		72.00%		100.00%
Percent of contracts with durations of more than one year and less than two years		28.00%

[1]	As of March 31, 2018, 82.4% of the natural gas contracts had durations of one year or less, 10.7% had durations of more than one year and less than two years and 6.9% had durations of more than two years. As of December 31, 2017, 67.7% of the natural gas contracts had durations of one year or less, 16.1% had durations of more than one year and less than two years and 16.2% had durations of more than two years.
[2]	As of March 31, 2018, 69.1% of the crude oil (for condensate) contracts had durations of one year or less and 30.9% had durations of more than one year and less than two years. As of December 31, 2017, 100% of the crude oil (for condensate) contracts had durations of one year or less.
[3]	As of March 31, 2018, 72.0% of the natural gas liquids contracts had durations of one year or less and 28.0% had durations of more than one year and less than two years. As of December 31, 2017, 100% of the natural gas liquid contracts had durations of one year or less.

Derivative Instruments and He53

Derivative Instruments and Hedging Activities - Balance Sheet Location (Details) - USD ($)		Mar. 31, 2018	Dec. 31, 2017
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]	11,000,000	9,000,000
Liabilities	[1]	17,000,000	13,000,000
Natural gas \| Financial futures/swaps \| Not Designated as Hedging Instrument \| Other Current, Assets
Derivatives, Fair Value [Line Items]
Assets		3,000,000	5,000,000
Natural gas \| Financial futures/swaps \| Not Designated as Hedging Instrument \| Other Current Liabilities
Derivatives, Fair Value [Line Items]
Liabilities		9,000,000	4,000,000
Natural gas \| Physical purchases/sales \| Not Designated as Hedging Instrument \| Other Current, Assets
Derivatives, Fair Value [Line Items]
Assets		6,000,000	3,000,000
Natural gas \| Physical purchases/sales \| Not Designated as Hedging Instrument \| Other Current Liabilities
Derivatives, Fair Value [Line Items]
Liabilities		1,000,000	0
Crude oil (for condensate) \| Financial futures/swaps \| Not Designated as Hedging Instrument \| Other Current, Assets
Derivatives, Fair Value [Line Items]
Assets		0	0
Crude oil (for condensate) \| Financial futures/swaps \| Not Designated as Hedging Instrument \| Other Current Liabilities
Derivatives, Fair Value [Line Items]
Liabilities		5,000,000	4,000,000
Natural gas liquids \| Financial futures/swaps \| Not Designated as Hedging Instrument \| Other Current, Assets
Derivatives, Fair Value [Line Items]
Assets		2,000,000	1,000,000
Natural gas liquids \| Financial futures/swaps \| Not Designated as Hedging Instrument \| Other Current Liabilities
Derivatives, Fair Value [Line Items]
Liabilities		$ 2,000,000	$ 5,000,000

[1]	See Note 10 for a reconciliation of the Partnership’s total derivatives fair value to the Partnership’s Condensed Consolidated Balance Sheets as of March 31, 2018 and December 31, 2017.

Derivative Instruments and He54

Derivative Instruments and Hedging Activities - Amounts Recognized in Income (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivative, net	$ 0	$ 21
Change in fair value of derivatives	(2)	24
Realized gain (loss) on derivatives	2	(3)
Gain on derivative activity	0	21
Cash collateral required if ratings are lowered	7
Natural gas \| Financial futures/swaps
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivative, net	(3)	11
Natural gas \| Physical purchases/sales
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivative, net	2	5
Condensate \| Financial futures/swaps
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivative, net	(3)	3
Natural gas liquids \| Financial futures/swaps
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivative, net	$ 4	$ 2

Fair Value Measurements - Carry

Fair Value Measurements - Carrying and Fair Value Amounts (Details) - USD ($) $ in Millions		Mar. 31, 2018	Dec. 31, 2017
Carrying Amount \| Significant other observable inputs (Level 2) \| 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 \| Significant other observable inputs (Level 2) \| Senior Notes \| 2019 Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes (Level 2)		500	500
Carrying Amount \| Significant other observable inputs (Level 2) \| Senior Notes \| 2024 Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes (Level 2)		600	600
Carrying Amount \| Significant other observable inputs (Level 2) \| Senior Notes \| 2027 Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes (Level 2)		697	697
Carrying Amount \| Significant other observable inputs (Level 2) \| Senior Notes \| 2044 Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes (Level 2)		550	550
Carrying Amount \| Significant other observable inputs (Level 2) \| Senior Notes \| EOIT Senior Notes \| EOIT
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes (Level 2)		261	263
Carrying Amount \| Significant other observable inputs (Level 2) \| Revolving Credit Facility
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Revolving Credit Facility (Level 2)	[1]	0	0
Fair Value \| Significant other observable inputs (Level 2) \| 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 \| Significant other observable inputs (Level 2) \| Senior Notes \| 2019 Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes (Level 2)		494	497
Fair Value \| Significant other observable inputs (Level 2) \| Senior Notes \| 2024 Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes (Level 2)		588	602
Fair Value \| Significant other observable inputs (Level 2) \| Senior Notes \| 2027 Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes (Level 2)		687	712
Fair Value \| Significant other observable inputs (Level 2) \| Senior Notes \| 2044 Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes (Level 2)		523	550
Fair Value \| Significant other observable inputs (Level 2) \| Senior Notes \| EOIT Senior Notes \| EOIT
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes (Level 2)		261	265
Fair Value \| Significant other observable inputs (Level 2) \| Revolving Credit Facility
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Revolving Credit Facility (Level 2)	[1]	0	0
Commercial Paper
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Short-term Debt		$ 596	$ 405

[1]	Borrowing capacity is effectively reduced by our borrowings outstanding under the commercial paper program. $596 million and $405 million of commercial paper was outstanding as of March 31, 2018 and December 31, 2017, respectively.

Fair Value Measurements - Fair

Fair Value Measurements - Fair Value Hierarchy (Details) - USD ($) $ in Millions		Mar. 31, 2018	Dec. 31, 2017
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Retained fuel due from shippers		$ 16	$ 10
Over retained fuel due from shippers		0	0
Commodity Contracts \| Recurring Measurement
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, total fair value		11	9
Liabilities, total fair value		17	13
Assets		(3)	(5)
Liabilities		(3)	(5)
Assets		8	4
Liabilities		14	8
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		3	5
Liabilities		7	3
Commodity Contracts \| Recurring Measurement \| Significant other observable inputs (Level 2)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets		6	4
Liabilities		8	5
Commodity Contracts \| Recurring Measurement \| Unobservable inputs (Level 3)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets		2	0
Liabilities		2	5
Gas Imbalances \| Recurring Measurement
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, total fair value	[1],[2]	19	27
Liabilities, total fair value	[2],[3]	8	12
Assets	[1],[2]	0	0
Liabilities	[2],[3]	0	0
Assets	[1],[2]	19	27
Liabilities	[2],[3]	8	12
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]	19	27
Liabilities	[2],[3]	8	12
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 $16 million and $10 million at March 31, 2018 and December 31, 2017, respectively, which fuel reserves are based on the value of natural gas at the time the imbalance was created and which are not subject to revaluation at fair market value.
[2]	The Partnership uses the market approach to fair value its gas imbalance assets and liabilities at individual, or where appropriate an average of, current market indices applicable to the Partnership’s operations, not to exceed net realizable value. Gas imbalances held by EOIT are valued using an average of the Inside FERC Gas Market Report for Panhandle Eastern Pipe Line Co. (Texas, Oklahoma Mainline), ONEOK (Oklahoma) and ANR Pipeline (Oklahoma) indices. There were no netting adjustments as of March 31, 2018 and December 31, 2017.
[3]	Gas imbalance liabilities exclude fuel reserves for over retained fuel due to shippers of zero at March 31, 2018 and December 31, 2017, 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	3 Months Ended
	Mar. 31, 2018USD ($)
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Balance at December 31, 2017	$ (5)
Gains included in earnings	4
Settlements	1
March 31, 2018	0
Transfers out of Level 3	$ 0

Fair Value Measurements - Sch58

Fair Value Measurements - Schedule of Quantitative Information of Level 3 Inputs (Details) $ in Millions	3 Months Ended
	Mar. 31, 2018USD ($)$ / gal	Dec. 31, 2017USD ($)
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Over retained fuel due from shippers \| $	$ 0	$ 0
Commodity Contracts \| Natural gas liquids \| Market Approach Valuation Technique \| Unobservable inputs (Level 3)
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Liabilities \| $	$ 0
Commodity Contracts \| Natural gas liquids \| Minimum \| Market Approach Valuation Technique \| Unobservable inputs (Level 3)
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Forward Curve Range (in dollars per gallon) \| $ / gal	0.266
Commodity Contracts \| Natural gas liquids \| Maximum \| Market Approach Valuation Technique \| Unobservable inputs (Level 3)
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Forward Curve Range (in dollars per gallon) \| $ / gal	0.910

Supplemental Disclosure of Ca59

Supplemental Disclosure of Cash Flow Information - Supplemental Disclosure of Cash Flow Information (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Supplemental Cash Flow Information [Abstract]
Interest, net of capitalized interest	$ 29	$ 14
Income taxes, net of refunds	2	0
Accounts payable related to capital expenditures	$ 50	$ 20

Supplemental Disclosure of Ca60

Supplemental Disclosure of Cash Flow Information - Reconciliation of Cash and Cash Equivalents and Restricted Cash (Details) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017	Mar. 31, 2017	Dec. 31, 2016
Supplemental Cash Flow Elements [Abstract]
Cash and cash equivalents	$ 30	$ 5	$ 17
Restricted cash	14	14	14
Cash, cash equivalents and restricted cash shown in the Condensed Consolidated Statements of Cash Flows	$ 44	$ 19	$ 31	$ 23

Related Party Transactions - Na

Related Party Transactions - Narrative (Details) $ / shares in Units, $ in Millions	Dec. 06, 2016mi	Feb. 18, 2016USD ($)$ / sharesshares	Mar. 31, 2018USD ($)	Mar. 31, 2017
Related Party Transaction [Line Items]
Partnership's revenues from affiliated companies as a percent of total revenues			7.00%	6.00%
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, 2018 and thereafter			$ 5
OGE Energy \| Certain Services and Support Functions
Related Party Transaction [Line Items]
Expense reimbursement annual caps			1
CenterPoint \| Certain Services and Support Functions
Related Party Transaction [Line Items]
Expense reimbursement annual caps			4
Affiliated Entity \| CenterPoint \| Lease Agreement with Affiliate of CenterPoint Energy
Related Party Transaction [Line Items]
Rent and maintenance expenses			$ 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
	Mar. 31, 2018	Mar. 31, 2017
Related Party Transaction [Line Items]
Revenues from affiliated companies	$ 49	$ 42
Cost of goods sold from affiliate	5	3
Charges to the Partnership by affiliates	9	9
CenterPoint
Related Party Transaction [Line Items]
Cost of goods sold from affiliate	2	0
CenterPoint \| Gas Transportation and Storage
Related Party Transaction [Line Items]
Revenues from affiliated companies	33	33
CenterPoint \| Gas Sales
Related Party Transaction [Line Items]
Revenues from affiliated companies	6	0
CenterPoint \| Corporate Services
Related Party Transaction [Line Items]
Charges to the Partnership by affiliates	1	1
CenterPoint \| Operating Lease
Related Party Transaction [Line Items]
Charges to the Partnership by affiliates	0	0
OGE Energy
Related Party Transaction [Line Items]
Cost of goods sold from affiliate	3	3
OGE Energy \| Gas Transportation and Storage
Related Party Transaction [Line Items]
Revenues from affiliated companies	9	9
OGE Energy \| Gas Sales
Related Party Transaction [Line Items]
Revenues from affiliated companies	1	0
OGE Energy \| Corporate Services
Related Party Transaction [Line Items]
Charges to the Partnership by affiliates	0	1
OGE Energy \| Seconded Employee Costs
Related Party Transaction [Line Items]
Charges to the Partnership by affiliates	$ 8	$ 7

Equity-Based Compensation (Deta

Equity-Based Compensation (Details) - USD ($) $ in Millions	3 Months Ended
Equity-Based Compensation (Details) - USD ($) $ in Millions	Mar. 31, 2018	Mar. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	$ 5	$ 4
Performance units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	3	3
Restricted units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	1	0
Phantom units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	$ 1	$ 1

Equity-Based Compensation - Equ

Equity-Based Compensation - Equity Units Activity (Details) $ / shares in Units, $ in Millions	3 Months Ended
	Mar. 31, 2018USD ($)$ / 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)	2,040,407,000,000
Granted (in units)	529,408,000,000	[1]
Vested (in units)	(401,772,000,000)	[2]
Forfeited (in units)	(3,725,000,000)
Units Outstanding (in units)	2,164,318,000,000
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	$ 13.86
Granted (in dollars per unit) \| $ / shares	17.70	[1]
Vested (in dollars per unit) \| $ / shares	16.59	[2]
Forfeited (in dollars per unit) \| $ / shares	13.87
Units Outstanding (in dollars per unit) \| $ / shares	$ 13.95
Aggregate Intrinsic Value of Units Outstanding \| $	$ 30
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 2015
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Granted (in units)	401,772,000,000
Vested (in units)	(803,544,000,000)
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%
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)	222,434,000,000
Granted (in units)	0	[1]
Vested (in units)	(181,068,000,000)	[2]
Forfeited (in units)	(1,366,000,000)
Units Outstanding (in units)	40,000,000,000
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	$ 17.87
Granted (in dollars per unit) \| $ / shares	0	[1]
Vested (in dollars per unit) \| $ / shares	16.75	[2]
Forfeited (in dollars per unit) \| $ / shares	16.75
Units Outstanding (in dollars per unit) \| $ / shares	$ 22.96
Aggregate Intrinsic Value of Units Outstanding \| $	$ 1
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)	987,380,000,000
Granted (in units)	494,072,000,000	[1]
Vested (in units)	0	[2]
Forfeited (in units)	(7,375,000,000)
Units Outstanding (in units)	1,474,077,000,000
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	$ 11.38
Granted (in dollars per unit) \| $ / shares	14.04	[1]
Vested (in dollars per unit) \| $ / shares	0	[2]
Forfeited (in dollars per unit) \| $ / shares	11.90
Units Outstanding (in dollars per unit) \| $ / shares	$ 12.27
Aggregate Intrinsic Value of Units Outstanding \| $	$ 20

[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 zero percent to 200 percent of the target.
[2]	Performance units vested as of March 31, 2018 include 401,772 units from the annual grant, which were approved by the Board of Directors in 2015 and paid out at 200%, or 803,544 units, based on the level of achievement of a performance goal established by the Board of Directors over the performance period. The Board of Directors approved the accelerated vesting of the 2015 grant from June 1, 2018 to March 1, 2018.

Equity-Based Compensation - Unr

Equity-Based Compensation - Unrecognized Compensation Cost (Details) $ in Millions	3 Months Ended
	Mar. 31, 2018USD ($)shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized Compensation Cost (In millions)	$ 0
Performance units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized Compensation Cost (In millions)	$ 0
Weighted Average to be Recognized (In years)	1 year 7 months 28 days
Restricted units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized Compensation Cost (In millions)	$ 0
Weighted Average to be Recognized (In years)	2 months 19 days
Phantom units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized Compensation Cost (In millions)	$ 0
Weighted Average to be Recognized (In years)	1 year 10 months 10 days
Long Term Incentive Plan \| Common Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares available for issuance \| shares	7,504,634

Reportable Segments - Schedule

Reportable Segments - Schedule of Financial Data for Business Segments and Services (Details) $ in Millions	3 Months Ended
	Mar. 31, 2018USD ($)segment	Mar. 31, 2017USD ($)	Dec. 31, 2017USD ($)
Segment Reporting Information [Line Items]
Number of reportable segments \| segment	2
Product sales	$ 443	$ 386
Service revenues	305	280
Total Revenues	748	666
Cost of goods sold, excluding depreciation and amortization	375	308
Operation and maintenance, General and administrative	121	114
Depreciation and amortization	96	88
Taxes other than income tax	17	16
Operating Income	139	140
Total assets	11,687		$ 11,593
Capital expenditures	190	61
Operating Segments \| Gathering and Processing
Segment Reporting Information [Line Items]
Product sales	418	351
Service revenues	173	140
Total Revenues	591	491
Cost of goods sold, excluding depreciation and amortization	358	286
Operation and maintenance, General and administrative	76	70
Depreciation and amortization	62	56
Taxes other than income tax	10	9
Operating Income	85	70
Total assets	9,212		9,079
Capital expenditures	147	51
Operating Segments \| Transportation and Storage
Segment Reporting Information [Line Items]
Product sales	140	153
Service revenues	139	141
Total Revenues	279	294
Cost of goods sold, excluding depreciation and amortization	139	140
Operation and maintenance, General and administrative	46	45
Depreciation and amortization	34	32
Taxes other than income tax	7	7
Operating Income	53	70
Total assets	5,652		5,616
Capital expenditures	43	10
Eliminations
Segment Reporting Information [Line Items]
Product sales	(115)	(118)
Service revenues	(7)	(1)
Total Revenues	(122)	(119)
Cost of goods sold, excluding depreciation and amortization	(122)	(118)
Operation and maintenance, General and administrative	(1)	(1)
Depreciation and amortization	0	0
Taxes other than income tax	0	0
Operating Income	1	0
Total assets	(3,177)		$ (3,102)
Capital expenditures	$ 0	$ 0

Subsequent Event (Details)

Subsequent Event (Details)	Apr. 06, 2018USD ($)	Jun. 18, 2015USD ($)	Mar. 31, 2018
Revolving Credit Facility
Subsequent Event [Line Items]
Maximum borrowing capacity		$ 1,750,000,000
Extension period (in years)		1 year
Commitment fee percentage			0.20%
Second Amended and Restated Revolving Credit Facility \| Subsequent Event
Subsequent Event [Line Items]
Consolidated debt to EBITDA ratio	5
Threshold for debt covenant ratio for acquisitions	5.50
Threshold for debt covenant ratio	$ 25,000,000
Covenant, acceleration of indebtedness, threshold amount	100,000,000
Covenant, acceleration of indebtedness, nonpayment of uninsured money judgments, threshold amount	$ 100,000,000
Second Amended and Restated Revolving Credit Facility \| Minimum \| Subsequent Event
Subsequent Event [Line Items]
Commitment fee percentage	0.10%
Second Amended and Restated Revolving Credit Facility \| Maximum \| Subsequent Event
Subsequent Event [Line Items]
Commitment fee percentage	0.30%
Second Amended and Restated Revolving Credit Facility \| Eurodollar \| Minimum \| Subsequent Event
Subsequent Event [Line Items]
Fixed interest rate percentage	1.00%
Second Amended and Restated Revolving Credit Facility \| Eurodollar \| Maximum \| Subsequent Event
Subsequent Event [Line Items]
Fixed interest rate percentage	1.75%
Second Amended and Restated Revolving Credit Facility \| Revolving Credit Facility \| Line of Credit \| Subsequent Event
Subsequent Event [Line Items]
Maximum borrowing capacity	$ 1,750,000,000
Duration of term loan facility (in years)	5 years
Line of credit facility, increase limit	$ 875,000,000
Extension period (in years)	1 year
Second Amended and Restated Revolving Credit Facility \| Letter of Credit [Member] \| Line of Credit \| Subsequent Event
Subsequent Event [Line Items]
Maximum borrowing capacity	$ 500,000,000