Enable Midstream Partners (ENBL) 10-Q 6 Aug 19 2019 Q2 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2019	Jul. 15, 2019
Entity Information [Line Items]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Jun. 30, 2019
Document Transition Report	false
Entity File Number	1-36413
Entity Registrant Name	ENABLE MIDSTREAM PARTNERS, LP
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	72-1252419
Entity Address, Address Line One	499 West Sheridan Avenue,
Entity Address, Address Line Two	Suite 1500
Entity Address, City or Town	Oklahoma City,
Entity Address, State or Province	OK
Entity Address, Postal Zip Code	73102
City Area Code	405
Local Phone Number	525-7788
Title of 12(b) Security	Common Units Representing Limited Partner Interests
Trading Symbol	ENBL
Security Exchange Name	NYSE
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Shell Company	false
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Common Stock, Shares Outstanding		435,102,173
Amendment Flag	false
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	Q2
Entity Central Index Key	0001591763
Current Fiscal Year End Date	--12-31
Former Address [Member]
Entity Information [Line Items]
Entity Address, Address Line One	One Leadership Square, 211 North Robinson Avenue
Entity Address, Address Line Two	Suite 150
Entity Address, City or Town	Oklahoma City
Entity Address, State or Province	OK
Entity Address, Postal Zip Code	73102

Condensed Consolidated Statemen

Condensed Consolidated Statements of Income (Unaudited) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Revenues (including revenues from affiliates (Note 13)):
Total Revenues	$ 735	$ 805	$ 1,530	$ 1,553
Cost of Goods and Services Sold	317	444	695	819
Cost and Expenses (including expenses from affiliates (Note 13)):
Operation and maintenance	99	97	202	191
General and administrative	25	26	51	53
Depreciation and amortization	110	96	215	192
Taxes other than income tax	17	16	35	33
Total Cost and Expenses	568	679	1,198	1,288
Operating Income	167	126	332	265
Other Income (Expense):
Interest expense	(48)	(36)	(94)	(69)
Equity in earnings of equity method affiliate	4	7	7	13
Other Nonoperating Income (Expense)	1	(2)	1	0
Total Other Expense	(43)	(31)	(86)	(56)
Income Before Income Tax
Income Before Income Tax	124	95	246	209
Income tax benefit	0	0	(1)	0
Net Income
Net Income	124	95	247	209
Less: Net income attributable to noncontrolling interest
Less: Net income attributable to noncontrolling interest	0	0	1	0
Net Income Attributable to Limited Partners
Net Income Attributable to Limited Partners	124	95	246	209
Less: Series A Preferred Unit distributions (Note 7)
Less: Series A Preferred Unit distributions (Note 7)	9	9	18	18
Net Income Attributable to Common Units (Note 6)
Net Income Attributable to Common Units (Note 6)	115	86	228	191
Common Units
Net Income Attributable to Common Units (Note 6)
Net Income Attributable to Common Units (Note 6)	$ 115	$ 86	$ 228	$ 191
Basic and Diluted earnings (loss) per unit and weighted average number of units outstanding
Basic earnings per unit (Note 6)	$ 0.26	$ 0.20	$ 0.52	$ 0.44
Diluted earnings per unit (Note 6)	$ 0.26	$ 0.20	$ 0.52	$ 0.44
Product
Revenues (including revenues from affiliates (Note 13)):
Total Revenues	$ 393	$ 501	$ 836	$ 944
Natural Gas, Gathering, Transportation, Marketing and Processing
Revenues (including revenues from affiliates (Note 13)):
Total Revenues	$ 342	$ 304	$ 694	$ 609

Condensed Consolited Statement

Condensed Consolited Statement of Comprehensive Income Statement - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Net income	$ 124	$ 95	$ 247	$ 209
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), before Reclassification and Tax	(3)	0	(3)	0
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), Reclassification, after Tax	0	0	0	0
Other Comprehensive Income (Loss), Net of Tax, Portion Attributable to Parent	(3)	0	(3)	0
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	121	95	244	209
Comprehensive Income (Loss), Net of Tax, Attributable to Noncontrolling Interest	0	0	1	0
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest	$ 121	$ 95	$ 243	$ 209

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets (Unaudited) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
Current Assets:
Cash and cash equivalents	$ 9	$ 8
Restricted cash	1	14
Accounts receivable, net of allowance for doubtful accounts (Note 1)	229	290
Accounts receivable—affiliated companies	20	19
Inventory	46	50
Gas imbalances	26	29
Other current assets	45	39
Total current assets	376	449
Property, Plant and Equipment:
Property, plant and equipment	13,102	12,899
Less accumulated depreciation and amortization	2,197	2,028
Property, plant and equipment, net	10,905	10,871
Other Assets:
Intangible assets, net	632	663
Goodwill	98	98
Investment in equity method affiliate	308	317
Other	90	46
Total other assets	1,128	1,124
Total Assets	12,409	12,444
Current Liabilities:
Accounts payable	148	288
Accounts payable—affiliated companies	3	4
Current portion of long-term debt	254	500
Short-term debt	681	649
Taxes accrued	40	31
Gas imbalances	18	22
Other	126	121
Total current liabilities	1,270	1,615
Other Liabilities:
Accumulated deferred income taxes, net	4	5
Regulatory liabilities	24	23
Other	79	54
Total other liabilities	107	82
Long-Term Debt	3,473	3,129
Commitments and Contingencies (Note 14)
Partners’ Equity:
Series A Preferred Units (14,520,000 issued and outstanding at June 30, 2019 and December 31, 2018)	362	362
Common units	7,163	7,218
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax	(3)	0
Noncontrolling interest	37	38
Total Partners’ Equity	7,559	7,618
Total Liabilities and Partners’ Equity	$ 12,409	$ 12,444

Condensed Consolidated Balanc_2

Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) - shares	Jun. 30, 2019	Dec. 31, 2018
Common Units
Common and Subordinated units issued	435,073,301	432,584,080
Common units and Subordinated units outstanding	435,073,301	432,584,080
Series A Preferred Units
Preferred units issued	14,520,000	14,520,000
Preferred units outstanding	14,520,000	14,520,000

Condensed Consolidated Statem_2

Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018
Cash Flows from Operating Activities:
Net income	$ 247	$ 209
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	215	192
Deferred income taxes	(1)	0
Loss on sale/retirement of assets	2	0
Equity in earnings of equity method affiliate	(7)	(13)
Return on investment in equity method affiliate	7	13
Equity-based compensation	9	8
Amortization of Debt Discount (Premium)	0	(1)
Changes in other assets and liabilities:
Accounts receivable, net	58	(9)
Accounts receivable—affiliated companies	(1)	(3)
Inventory	4	(2)
Gas imbalance assets	3	8
Other current assets	(3)	(15)
Other assets	6	(5)
Accounts payable	(111)	(19)
Accounts payable—affiliated companies	(1)	0
Gas imbalance liabilities	(4)	4
Other current liabilities	15	22
Other liabilities	(11)	16
Net cash provided by operating activities	427	405
Cash Flows from Investing Activities:
Capital expenditures	(252)	(375)
Proceeds from sale of assets	0	8
Proceeds from Insurance Settlement, Investing Activities	0	1
Return of investment in equity method affiliate	9	8
Other, net	(9)	0
Net cash used in investing activities	(252)	(358)
Cash Flows from Financing Activities:
Increase (decrease) in short-term debt	32	(78)
Proceeds from long-term debt, net of issuance costs	850	787
Repayment of Revolving Credit Facility	(250)	0
Distributions	(296)	(295)
Cash paid for employee equity-based compensation	(23)	(9)
Net cash used in financing activities	(187)	(45)
Net (Decrease) Increase in Cash, Cash Equivalents and Restricted Cash	(12)	2
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	22	19
Cash, Cash Equivalents and Restricted Cash at End of Period	10	21
Repayments of Long-term Debt	$ 500	$ 450

Condensed Consolidated Statem_3

Condensed Consolidated Statements of Partners' Equity (Unaudited) - USD ($) shares in Millions, $ in Millions	Total	Noncontrolling Interest	Series A Preferred UnitsPreferred Units	Common UnitsPartners' Capital	AOCI Attributable to Parent
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
Changes in Partners' Capital
Net Income	114	0	$ 9	$ 105
Distributions	(149)	(1)	(9)	(139)
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
Changes in Partners' Capital
Net Income	95	0	$ 9	$ 86
Distributions	(146)	0	(9)	(137)
Equity-based compensation, net of units for employee taxes	3			$ 3
Equity-based compensation, net of units for employee taxes, units				0
Balance, end of period at Jun. 30, 2018	7,571	11	$ 362	$ 7,198	0
Balance, end of period, units at Jun. 30, 2018			15	433
Balance, beginning of period at Dec. 31, 2018	7,618	38	$ 362	$ 7,218	0
Balance, beginning of period, units at Dec. 31, 2018			15	433
Changes in Partners' Capital
Net Income	123	1	$ 9	$ 113
Distributions	(148)	(1)	(9)	(138)
Equity-based compensation, net of units for employee taxes	(10)			$ (10)
Equity-based compensation, net of units for employee taxes, units				2
Balance, end of period at Mar. 31, 2019	7,583	38	$ 362	$ 7,183
Balance, end of period, units at Mar. 31, 2019			15	435
Changes in Partners' Capital
Net Income	124	0	$ 9	$ 115
Distributions	(148)	(1)	(9)	(138)
Equity-based compensation, net of units for employee taxes	3			$ 3
Equity-based compensation, net of units for employee taxes, units				0
Balance, end of period at Jun. 30, 2019	7,559	$ 37	$ 362	$ 7,163	(3)
Balance, end of period, units at Jun. 30, 2019			15	435
Changes in Partners' Capital
Other Comprehensive Income (Loss), Net of Tax	$ (3)				$ (3)

Summary of Significant Accounti

Summary of Significant Accounting Policies	6 Months Ended
	Jun. 30, 2019
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 whose 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 Oklahoma and serve crude oil production in the SCOOP and STACK plays of the Anadarko Basin and 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, a pipeline extending from Louisiana to Alabama. CenterPoint Energy and OGE Energy each have 50% of the management interests in Enable GP. Enable GP is the general partner of the Partnership and has no other operating activities. Enable GP is governed by a board made up of two representatives designated by each of CenterPoint Energy and OGE Energy, along with the Partnership’s Chief Executive Officer and three independent board members CenterPoint Energy and OGE Energy mutually agreed to appoint. CenterPoint Energy and OGE Energy also own a 40% and 60% interest, respectively, in the incentive distribution rights held by Enable GP. As of June 30, 2019 , CenterPoint Energy held approximately 53.8% or 233,856,623 of the Partnership’s common units, and OGE Energy held approximately 25.5% or 110,982,805 of the Partnership’s common units. Additionally, CenterPoint Energy holds 14,520,000 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 June 30, 2019 , the Partnership owned a 50% interest in SESH. See Note 8 for further discussion of SESH. For the six months ended June 30, 2019 , the Partnership held a 50% ownership in Atoka and consolidated Atoka in its Condensed Consolidated Financial Statements as EOIT acted as the managing member of Atoka and had control over the operations of Atoka. In addition, beginning November 1, 2018 through June 30, 2019 , the Partnership owned a 60% interest in ESCP, which is consolidated in its Condensed Consolidated Financial Statements as EOCS acted as the managing member of ESCP and had control over the operations of ESCP. 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 16. 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. Depreciation Expense The Partnership completed a depreciation study for the Gathering and Processing and Transportation and Storage segments. Effective January 1, 2019, the new depreciation rates have been applied prospectively as a change in accounting estimate. The new depreciation rates did not result in a material change in depreciation expense or results of operations. 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, we evaluate 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 credit losses, the aging of receivables, specific customer circumstances that may impact their ability to pay the amounts due and current and forecasted economic conditions over the assets contractual lives. Based on this review, management determined that a $3 million and $2 million allowance for doubtful accounts was required at June 30, 2019 and December 31, 2018 , respectively. 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 write-downs to net realizable value related to natural gas and natural gas liquids inventory of $5 million and zero during the three months ended June 30, 2019 and 2018 , respectively, and $6 million and $3 million during the six months ended June 30, 2019 and 2018 , respectively.

New Accounting Pronouncements

New Accounting Pronouncements	6 Months Ended
	Jun. 30, 2019
Accounting Changes and Error Corrections [Abstract]
New Accounting Pronouncements	New Accounting Pronouncements Accounting Standards to be Adopted in Future Periods 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 manner. 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 expects to adopt this standard in the first quarter of 2020 and does not expect the adoption of this standard to have a material impact on our Condensed Consolidated Financial Statements and related disclosures. Intangibles—Goodwill and Other In January 2017, the FASB issued ASU No. 2017-04, “Intangibles-Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment.” This standard requires entities to test goodwill for impairment by eliminating Step 2 from the goodwill impairment test. The standard is effective for interim and annual reporting periods beginning after December 15, 2019. The Partnership does not expect the adoption of this standard to have a material impact on our Condensed Consolidated Financial Statements and related disclosures. Fair Value Measurement—Disclosure Framework-Changes to the Disclosure Requirements for Fair Value Measurement In August 2018, the FASB issued ASU No. 2018-13, “Fair Value Measurement (Topic 820): Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement” which focuses on improving the effectiveness of disclosures in the notes to the financial statements by facilitating clear communication of the information required by U.S. GAAP that is most important to users of each entity’s financial statements. The standard is effective for interim and annual reporting periods beginning after December 15, 2019, although early adoption is permitted. The Partnership expects to adopt this standard in the first quarter of 2020 and continues to evaluate the other impacts of the new standards on our Condensed Consolidated Financial Statements and related disclosures. Intangibles—Goodwill and Other—Internal-Use Software In August 2018, the FASB issued ASU No. 2018-15, “Intangibles—Goodwill and Other—Internal-Use Software: Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract,” which aims to reduce complexity in the accounting for costs of implementing a cloud computing service arrangement. ASU No. 2018-15 aligns the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. The standard is effective for interim and annual periods beginning after December 15, 2019. The Partnership does not expect the adoption of this standard to have a material impact on our Condensed Consolidated Financial Statements and related disclosures. Collaborative Arrangements In November 2018, the FASB issued ASU No. 2018-18, “Collaborative Arrangements (Topic 808): Clarifying the Interaction between Topic 808 and Topic 606.” This standard resolves the diversity in practice concerning the manner in which entities account for transactions on the basis of their view of the economics of the collaborative arrangement. The amendments (1) clarify that certain transactions between collaborative participants should be accounted for as revenue under topic 606 when the collaborative participant is a customer in the context of the unit of account; (2) add unit-of-account guidance in Topic 808 to align with the guidance in Topic 606; and (3) clarify that in a transaction that is not directly related to sales to third parties, presenting the transaction as revenue would be precluded if the collaborative participant counterparty was not a customer. The standard is effective for interim and annual periods beginning after December 15, 2019. The Partnership does not expect the adoption of this standard to have a material impact on our Condensed Consolidated Financial Statements and related disclosures. Codification Improvements

Revenue

Revenue	6 Months Ended
	Jun. 30, 2019
Revenue from Contract with Customer [Abstract]
Revenue	Revenues The following tables disaggregate total revenues by major source from contracts with customers and the gain (loss) on derivative activity for the three and six months ended June 30, 2019 and 2018 . Three Months Ended June 30, 2019 Gathering and Transportation Eliminations Total (In millions) Revenues: Product sales: Natural gas $ 94 $ 108 $ (95 ) $ 107 Natural gas liquids 237 5 (5 ) 237 Condensate 33 — — 33 Total revenues from natural gas, natural gas liquids, and condensate 364 113 (100 ) 377 Gain on derivative activity 15 1 — 16 Total Product sales $ 379 $ 114 $ (100 ) $ 393 Service revenues: Demand revenues $ 68 $ 123 $ — $ 191 Volume-dependent revenues 140 15 (4 ) 151 Total Service revenues $ 208 $ 138 $ (4 ) $ 342 Total Revenues $ 587 $ 252 $ (104 ) $ 735 Three Months Ended June 30, 2018 Gathering and Transportation Eliminations Total (In millions) Revenues: Product sales: Natural gas $ 106 $ 143 $ (107 ) $ 142 Natural gas liquids 336 6 (6 ) 336 Condensate 37 — — 37 Total revenues from natural gas, natural gas liquids, and condensate 479 149 (113 ) 515 Loss on derivative activity (14 ) — — (14 ) Total Product sales $ 465 $ 149 $ (113 ) $ 501 Service revenues: Demand revenues $ 52 $ 113 $ — $ 165 Volume-dependent revenues 124 15 — 139 Total Service revenues $ 176 $ 128 $ — $ 304 Total Revenues $ 641 $ 277 $ (113 ) $ 805 Six Months Ended June 30, 2019 Gathering and Transportation Eliminations Total (In millions) Revenues: Product sales: Natural gas $ 222 $ 270 $ (236 ) $ 256 Natural gas liquids 507 11 (11 ) 507 Condensate 67 — — 67 Total revenues from natural gas, natural gas liquids, and condensate 796 281 (247 ) 830 Gain on derivative activity 6 — — 6 Total Product sales $ 802 $ 281 $ (247 ) $ 836 Service revenues: Demand revenues $ 128 $ 254 $ — $ 382 Volume-dependent revenues 287 33 (8 ) 312 Total Service revenues $ 415 $ 287 $ (8 ) $ 694 Total Revenues $ 1,217 $ 568 $ (255 ) $ 1,530 Six Months Ended June 30, 2018 Gathering and Transportation Eliminations Total (In millions) Revenues: Product sales: Natural gas $ 212 $ 274 $ (216 ) $ 270 Natural gas liquids 615 13 (13 ) 615 Condensate 73 — — 73 Total revenues from natural gas, natural gas liquids, and condensate 900 287 (229 ) 958 Gain (loss) on derivative activity (17 ) 2 1 (14 ) Total Product sales $ 883 $ 289 $ (228 ) $ 944 Service revenues: Demand revenues $ 102 $ 233 $ — $ 335 Volume-dependent revenues 247 34 (7 ) 274 Total Service revenues $ 349 $ 267 $ (7 ) $ 609 Total Revenues $ 1,232 $ 556 $ (235 ) $ 1,553 Accounts Receivable The table below summarizes the change in accounts receivable for the six months ended June 30, 2019 . June 30, December 31, (In millions) Accounts Receivable: Customers $ 229 $ 297 Contract assets (1) 6 6 Non-customers 14 6 Total Accounts Receivable (2) $ 249 $ 309 ____________________ (1) Contract assets reflected in Total Accounts Receivable include accrued minimum volume commitments. Contract assets are primarily attributable to revenues associated with estimated shortfall volumes on certain annual minimum volume commitment arrangements. Total Accounts Receivable does not include $5 million of contracts assets related to firm service transportation contracts with tiered rates, which are reflected in Other Assets. (2) 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 prepayments received from customers for which the good or service has not yet been provided in connection with the prepayment. The table below summarizes the change in the contract liabilities for the six months ended June 30, 2019 : June 30, December 31, Amounts recognized in revenues (In millions) Deferred revenues $ 49 $ 48 $ 21 The table below summarizes the timing of recognition of these contract liabilities as of June 30, 2019 : 2019 2020 2021 2022 2023 and After (In millions) Deferred revenues $ 23 $ 6 $ 5 $ 5 $ 10 Remaining Performance Obligations Our remaining performance obligations consist primarily of firm arrangements and minimum volume commitment 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 June 30, 2019 : 2019 2020 2021 2022 2023 and After (In millions) Transportation and Storage $ 239 $ 397 $ 220 $ 166 $ 806 Gathering and Processing 125 164 136 138 460 Total remaining performance obligations $ 364 $ 561 $ 356 $ 304 $ 1,266

Leases

Leases	6 Months Ended
	Jun. 30, 2019
Leases [Abstract]
Leases	Leases On January 1, 2019, the Partnership adopted 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. The Partnership has applied the standard to only contracts that were not expired as of January 1, 2019. The Partnership elected the 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 elected the optional transition practical expedient to not reassess whether any expired or existing contracts are or contain leases, the lease classification for any expired or existing leases and initial direct costs for any existing leases. Upon adoption, we increased our asset and liability balances on the Condensed Consolidated Balance Sheets by approximately $35 million due to the required recognition of right-of-use assets and corresponding lease liabilities for all lease obligations that were classified as operating leases. The Partnership did not recognize a material cumulative adjustment to the Condensed Consolidated Statement of Partners’ Equity and we did not have any material changes in the timing of expense recognition or our accounting policies. Our lease obligations are primarily comprised of rentals of field equipment and buildings, which are recorded as Operation and maintenance and General and administrative expenses in the Partnership’s Condensed Consolidated Statements of Income. Other than the contractual terms for each lease obligation, the key inputs for our calculations of the initial right-of-use assets and corresponding lease liabilities are the expected remaining life and applicable discount rate. Field equipment has an expected lease term of three to five years , with contractual base terms of one to three years followed by month-to-month renewals. Field equipment rental arrangements do not generally contain any significant variable lease payments. While certain arrangements may include lower standby rates, field equipment is generally anticipated to be in use for all of its expected lease term. Buildings have an expected lease term of seven to ten years , which is currently the same as the contractual base term. Building rental arrangements contain market-based renewal options of up to 15 years . Variable lease payments for buildings are generally comprised of costs for utilities, maintenance and building management services. There are no variable lease payments due under building rental arrangements until July 1, 2019, after which amounts will be due monthly. The Partnership is generally not aware of the implicit rate for either field equipment or building rental arrangements, so discount rates are based upon the expected term of each arrangement and the Partnership’s uncollateralized borrowing rate associated with the expected term at the time of lease inception. As of June 30, 2019 , the weighted average remaining lease term is four years and the weighted average discount rate is 5.55% . As of June 30, 2019 , we have right-of-use assets of $38 million recorded as Other Assets, $11 million of corresponding obligations recorded as Other Current Liabilities and $30 million of corresponding obligations recorded as Other Liabilities on the Partnership’s Condensed Consolidated Balance Sheet. All lease obligations outstanding during the three and six months ended June 30, 2019 were classified as operating leases, therefore all cash flows are reflected in Cash Flows from Operating Activities. Rental costs associated with field equipment and buildings were $5 million and $2 million during the three months ended June 30, 2019 , respectively, and $12 million and $4 million during the six months ended June 30, 2019 , respectively. The table below summarizes lease expense for the three and six month periods ended June 30, 2019 : Three Months Ended June 30, 2019 Gathering and Transportation Total (In millions) Lease Expense: Lease Cost: Operating lease cost $ 3 $ — $ 3 Short-term lease cost 4 — 4 Total Lease Cost $ 7 $ — $ 7 Six Months Ended June 30, 2019 Gathering and Transportation Total (In millions) Lease Expense: Lease Cost: Operating lease cost $ 5 $ — $ 5 Short-term lease cost 10 1 11 Total Lease Cost $ 15 $ 1 $ 16 Under ASC 842, as of June 30, 2019 , the Partnership has operating lease obligations expiring at various dates. The $16 million difference between undiscounted cash flows for operating leases and our $41 million of lease obligations is due to the impact of the applicable discount rate. Undiscounted cash flows for operating lease liabilities are as follows: Year Ended December 31, 2019 2020 2021 2022 2023 2024 and After Total (In millions) Noncancellable operating leases $ 11 $ 12 $ 7 $ 6 $ 6 $ 15 $ 57 Under ASC 840, as of December 31, 2018 , the Partnership had the following operating lease obligations as well as the estimate of the period in which the obligation will be settled: Year Ended December 31, 2019 2020-2021 2022-2023 After 2023 Total (In millions) Noncancellable operating leases $ 14 $ 6 $ 6 $ 14 $ 40

Acquisition

Acquisition	6 Months Ended
	Jun. 30, 2019
Business Combinations [Abstract]
Acquisition	Acquisition Velocity Holdings, LLC Acquisition On November 1, 2018, the Partnership acquired all of the equity interests in Velocity Holdings, LLC, now EOCS, which owns and operates a crude oil and condensate gathering system in the SCOOP and STACK plays of the Anadarko Basin, for approximately $444 million in cash, subject to certain customary working capital adjustments. The acquisition was accounted for as a business combination and was funded with borrowings under the commercial paper program. During the fourth quarter of 2018, the Partnership finalized the purchase price allocation as of November 1, 2018. The following table presents the fair value of the identified assets acquired and liabilities assumed at the acquisition date: Purchase price allocation: Assets acquired: Cash $ 1 Current Assets 3 Property, plant and equipment 124 Intangibles 259 Goodwill 86 Liabilities assumed: Current liabilities 1 Less: Non-Controlling Interest at fair value 28 Total identifiable net assets $ 444 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 15 years. Goodwill recognized from the acquisition primarily relates to greater operating leverage in the Anadarko Basin and is allocated to the gathering and processing segment. Included within the acquisition was 60% of a 26 -mile pipeline system joint venture with a third party which owns and operates a refinery connected to the EOCS system. This joint venture’s financials have been consolidated within the Partnership’s financial statements resulting in $28 million in non-controlling interest. The Partnership incurred approximately $6 million of acquisition costs associated with this transaction, which were included in General and administrative expense in the Consolidated Statements of Income for the twelve months ended December 31, 2018 . 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	6 Months Ended
	Jun. 30, 2019
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 units: Three Months Ended June 30, Six Months Ended June 30, 2019 2018 2019 2018 (In millions, except per unit data) Net income $ 124 $ 95 $ 247 $ 209 Net income attributable to noncontrolling interest — — 1 — Series A Preferred Unit distributions 9 9 18 18 General partner interest in net income — — — — Net income available to common unitholders $ 115 $ 86 $ 228 $ 191 Net income allocable to common units $ 115 $ 86 $ 228 $ 191 Dilutive effect of Series A Preferred Unit distributions — — — — Diluted net income allocable to common units $ 115 $ 86 $ 228 $ 191 Basic earnings per unit Common units $ 0.26 $ 0.20 $ 0.52 $ 0.44 Basic weighted average number of common units outstanding (1) 437 435 436 434 Dilutive effect of Series A Preferred Units — — — — Dilutive effect of performance units — 1 — 1 Diluted weighted average number of common units outstanding 437 436 436 435 Diluted earnings per unit Common units $ 0.26 $ 0.20 $ 0.52 $ 0.44 ____________________ (1) Basic weighted average number of outstanding common units includes approximately one million time-based phantom units for each of the three and six months ended June 30, 2019 and 2018 , respectively.

Partners' Equity

Partners' Equity	6 Months Ended
	Jun. 30, 2019
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 unitholders, as applicable, during 2018 and 2019 (in millions, except for per unit amounts): Three Months Ended Record Date Payment Date Per Unit Distribution Total Cash Distribution June 30, 2019 (1) August 20, 2019 August 27, 2019 $ 0.3305 $ 144 March 31, 2019 May 21, 2019 May 29, 2019 0.318 138 December 31, 2018 February 19, 2019 February 26, 2019 0.318 138 September 30, 2018 November 16, 2018 November 29, 2018 0.318 138 June 30, 2018 August 21, 2018 August 28, 2018 0.318 138 March 31, 2018 May 22, 2018 May 29, 2018 0.318 138 _____________________ (1) The Board of Directors declared this $0.3305 per common unit cash distribution on August 2, 2019 , to be paid on August 27, 2019 to common unitholders of record at the close of business on August 20, 2019 . The Partnership paid or has authorized payment of the following cash distributions to holders of the Series A Preferred Units during 2018 and 2019 (in millions, except for per unit amounts): Three Months Ended Record Date Payment Date Per Unit Distribution Total Cash Distribution June 30, 2019 August 2, 2019 August 14, 2019 $ 0.625 $ 9 March 31, 2019 April 29, 2019 May 15, 2019 0.625 9 December 31, 2018 February 8, 2019 February 14, 2019 0.625 9 September 30, 2018 November 6, 2018 November 14, 2018 0.625 9 June 30, 2018 August 1, 2018 August 14, 2018 0.625 9 March 31, 2018 May 1, 2018 May 15, 2018 0.625 9 _____________________ (1) The Board of Directors declared a $0.625 per Series A Preferred Unit cash distribution on August 2, 2019 , to be paid on August 14, 2019 , to Series A Preferred unitholders of record at the close of business on August 2, 2019 . 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 six months ended June 30, 2019 and 2018 , the Partnership did not issue common units under the ATM Program. As of June 30, 2019 , $197 million of common units remained available for issuance through the ATM Program.

Investment in Equity Method Aff

Investment in Equity Method Affiliate	6 Months Ended
	Jun. 30, 2019
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 Enbridge, Inc. 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, Enbridge, Inc. 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 Enbridge, Inc. 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 $7 million and $6 million during the three months ended June 30, 2019 and 2018 , respectively, and $10 million and $8 million during the six months ended June 30, 2019 and 2018 , 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 and six months ended June 30, 2019 and 2018 . SESH: Three Months Ended June 30, Six Months Ended June 30, 2019 2018 2019 2018 (In millions) Equity in Earnings of Equity Method Affiliate $ 4 $ 7 $ 7 $ 13 Distributions from Equity Method Affiliate (1) $ 4 $ 8 $ 16 $ 21 ___________________ (1) Distributions from equity method affiliate includes a $4 million and $7 million return on investment and a zero and $1 million return of investment for the three months ended June 30, 2019 and 2018 , respectively. Distributions from equity method affiliate includes a $7 million and $13 million return on investment and a $9 million and $8 million return of investment for the six months ended June 30, 2019 and 2018 , respectively. Summarized financial information of SESH: Three Months Ended June 30, Six Months Ended June 30, 2019 2018 2019 2018 (In millions) Income Statements: Revenues $ 27 $ 28 $ 54 $ 56 Operating income $ 11 $ 16 $ 22 $ 33 Net income $ 7 $ 13 $ 14 $ 25

Debt

Debt	6 Months Ended
	Jun. 30, 2019
Debt Disclosure [Abstract]
Debt	Debt The following table presents the Partnership’s outstanding debt as of June 30, 2019 and December 31, 2018 . June 30, 2019 December 31, 2018 Outstanding Principal Premium (Discount) Total Debt Outstanding Principal Premium (Discount) Total Debt (In millions) Commercial Paper $ 681 $ — $ 681 $ 649 $ — $ 649 Revolving Credit Facility — — — 250 — 250 2019 Term Loan Agreement 850 — 850 — — — 2019 Notes — — — 500 — 500 2024 Notes 600 — 600 600 — 600 2027 Notes 700 (2 ) 698 700 (2 ) 698 2028 Notes 800 (6 ) 794 800 (6 ) 794 2044 Notes 550 — 550 550 — 550 EOIT Senior Notes 250 4 254 250 7 257 Total debt $ 4,431 $ (4 ) $ 4,427 $ 4,299 $ (1 ) $ 4,298 Less: Short-term debt (1) 681 649 Less: Current portion of long-term debt (2) 254 500 Less: Unamortized debt expense (3) 19 20 Total long-term debt $ 3,473 $ 3,129 ____________________ (1) Short-term debt includes $681 million and $649 million of outstanding commercial paper as of June 30, 2019 and December 31, 2018 , respectively. (2) As of June 30, 2019 , Current portion of long-term debt included $254 million outstanding balance of the EOIT Senior Notes due March 15, 2020. As of December 31, 2018 , Current portion of long-term debt included $500 million outstanding balance of the 2019 Notes due May 15, 2019. (3) As of June 30, 2019 and December 31, 2018 , there was an additional $5 million and $6 million , respectively, of unamortized debt expense related to the Revolving Credit Facility included in Other assets, not included above. 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 $681 million and $649 million outstanding under our commercial paper program at June 30, 2019 and December 31, 2018 , respectively. The weighted average interest rate for the outstanding commercial paper was 3.25% as of June 30, 2019 . Revolving Credit Facility On April 6, 2018, the Partnership amended and restated its Revolving Credit Facility. As amended and restated, the 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 . The Revolving Credit Facility is scheduled to mature on April 6, 2023, 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 June 30, 2019 , there were no principal advances and $3 million in letters of credit outstanding under the Revolving Credit Facility. The Revolving Credit Facility provides that outstanding borrowings bear interest at the LIBOR and/or an alternate base rate, at the Partnership’s election, plus an applicable margin. The applicable margin is based on the Partnership’s designated credit ratings from S&P, Moody’s and Fitch Ratings. As of June 30, 2019 , the applicable margin for LIBOR-based borrowings under the Revolving Credit Facility was 1.50% based on the Partnership’s credit ratings. In addition, the Revolving Credit Facility requires the Partnership to pay a fee on unused commitments. The commitment fee is based on the Partnership’s credit ratings. As of June 30, 2019 , the commitment fee under the restated 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. 2019 Term Loan Agreement On January 29, 2019, the Partnership entered into an unsecured term loan agreement, providing for up to $1 billion in advances with Bank of America, N.A., as administrative agent, and the several lenders thereto. The 2019 Term Loan Agreement has a scheduled maturity date of January 29, 2022, but contains an option, which may be exercised up to two times, to extend the maturity date for an additional one-year term. As of June 30, 2019 , there is a principal advance of $850 million outstanding under the 2019 Term Loan Agreement, and a delayed-draw feature permits the Partnership to borrow up to an additional $150 million within 180 days of the closing date, subject to the terms and conditions of the 2019 Term Loan Agreement. The 2019 Term Loan Agreement 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 is based on the Partnership’s credit ratings. The applicable margin shall equal, (1) in the case of interest rates determined by reference to the eurodollar rate, between 0.75% and 1.50% per annum and (2) in the case of interest rates determined by reference to the alternate base rate, between 0% and 0.50% per annum. As of June 30, 2019 , the applicable margin for LIBOR-based advances under the 2019 Term Loan Facility was 1.25% based on the Partnership’s credit ratings. As of June 30, 2019 , the weighted average interest rate of the 2019 Term Loan Agreement was 3.62% . The 2019 Term Loan Agreement requires the Partnership to, starting April 29, 2019 and continuing until the date on which all commitments have expired or been terminated or the amount available to be drawn is zero, pay a ticking fee on each lender’s unused commitment amount. The ticking fee shall equal a per annum rate of 0.125% on the actual daily amount of such lender’s portion of the unused commitments. Advances under the 2019 Term Loan Agreement are subject to certain conditions precedent, including the accuracy in all material respects of certain representations and warranties and the absence of any default or event of default. Advances under the 2019 Term Loan Agreement may be used to refinance indebtedness outstanding from time to time and for other general corporate purposes, including to fund acquisitions, investments and capital expenditures. Advances under the 2019 Term Loan Agreement can be prepaid, in whole or in part, at any time without premium or penalty, other than usual and customary LIBOR breakage costs, if applicable. The 2019 Term Loan Agreement contains a financial covenant requiring the Partnership to maintain a ratio of consolidated funded debt to consolidated EBITDA as of the last day of each fiscal quarter of less than or equal to 5.00 to 1.00; provided that, for a certain period 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 consolidated funded debt to consolidated EBITDA ratio as of the last day of each such fiscal quarter during such period would be permitted to be up to 5.50 to 1.00. The 2019 Term Loan Agreement 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 (as defined in the 2019 Term Loan Agreement), restricted payments, changes in the nature of their respective business and entering into certain restrictive agreements. The 2019 Term Loan Agreement 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. Senior Notes As of June 30, 2019 , the Partnership’s debt included the 2024 Notes, 2027 Notes, 2028 Notes and 2044 Notes, which had $8 million of unamortized discount and $19 million of unamortized debt expense at June 30, 2019 , resulting in effective interest rates of 4.01% , 4.57% , 5.20% and 5.08% , respectively, during the six months ended June 30, 2019 . In May 2019, the Partnership’s 2019 Notes matured and were paid using proceeds from the 2019 Term Loan Agreement. As of June 30, 2019 , the Partnership’s debt included EOIT’s Senior Notes. The EOIT Senior Notes had $4 million of unamortized premium at June 30, 2019 , resulting in an effective interest rate of 3.81% during the six months ended June 30, 2019 . As of June 30, 2019 , the Partnership and EOIT were in compliance with all of their debt agreements, including financial covenants.

Derivative Instruments and Hedg

Derivative Instruments and Hedging Activities	6 Months Ended
	Jun. 30, 2019
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 risks managed using derivative instruments are commodity price and interest rate risks. The Partnership is also exposed to credit risk in its business operations. Commodity Price Risk The Partnership uses forward physical contracts, commodity price swap contracts and commodity price option features to manage its commodity price risk exposures. Commodity derivative instruments used by the Partnership are as follows: • NGL put options, NGL futures and swaps, and WTI crude oil futures, swaps and swaptions are used to manage the Partnership’s NGL and condensate exposure associated with its processing agreements; • natural gas futures and swaps, natural gas options, natural gas swaptions and natural gas commodity purchases and sales are used to manage the Partnership’s natural gas price exposure associated with its gathering, processing, transportation and storage assets, 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 its 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 are recorded as Other Assets or Liabilities in the Condensed Consolidated Balance Sheets at fair value on a net basis with such amounts classified as current or long-term based on their anticipated settlement. As of June 30, 2019 and December 31, 2018 , the Partnership had no commodity derivative instruments that were designated as cash flow or fair value hedges for accounting purposes. Interest Rate Risk The Partnership uses interest rate swap contracts to manage its interest rate risk exposures. The Partnership recognizes its interest rate 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. The Partnership’s interest rate swap contracts are designated as cash flow hedging instruments for accounting purposes. For interest rate derivative instruments designated as cash flow hedging instruments, the gain or loss on the derivative is recognized currently in Accumulated other comprehensive loss and will be reclassified to Interest expense in the same period the hedged transaction affects earnings. As of June 30, 2019 , the Partnership had no interest rate derivative instruments that were designated as fair value hedges for accounting purposes. As of December 31, 2018 , the Partnership had no outstanding interest rate derivative instruments. Credit Risk 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 to manage its exposure to commodity price risk. 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 Not Designated as Hedging Instruments The majority of natural gas physical purchases and sales not designated as hedges for accounting purposes are priced based on a monthly or daily index, and the fair value is subject to little or no market price risk. Natural gas physical sales volumes exceed natural gas physical purchase volumes due to the marketing of natural gas volumes purchased via the Partnership’s processing contracts, which are not derivative instruments. As of June 30, 2019 and December 31, 2018 , the Partnership had the following derivative instruments that were not designated as hedging instruments for accounting purposes: June 30, 2019 December 31, 2018 Gross Notional Volume Purchases Sales Purchases Sales Natural gas— TBtu (1) Financial fixed futures/swaps 12 25 16 28 Financial basis futures/swaps 13 41 18 29 Financial swaptions (3) — 3 — 1 Physical purchases/sales — 9 — 11 Crude oil (for condensate)— MBbl (2) Financial futures/swaps — 765 — 945 Financial swaptions (3) — 30 — 30 Natural gas liquids— MBbl (4) Financial futures/swaps 1,980 2,370 270 2,535 ____________________ (1) As of June 30, 2019 , 78.3% of the natural gas contracts had durations of one year or less and 21.7% had durations of more than one year and less than two years. As of December 31, 2018 , 74.0% of the natural gas contracts had durations of one year or less, 24.2% had durations of more than one year and less than two years and 1.8% had durations of more than two years. (2) As of June 30, 2019 , 84.9% of the crude oil (for condensate) contracts had durations of one year or less and 15.1% had durations of more than one year and less than two years. As of December 31, 2018 , 76.9% of the crude oil (for condensate) contracts had durations of one year or less and 23.1% had durations of more than one year and less than two years. (3) The notional contains a combined derivative instrument consisting of a fixed price swap and a sold option, which gives the counterparties the right, but not the obligation, to increase the notional quantity hedged under the fixed price swap until the option expiration date. The notional volume represents the volume prior to option exercise. (4) As of June 30, 2019 , 93.8% of the natural gas liquids contracts had durations of one year or less and 6.2% had durations of more than one year and less than two years. As of December 31, 2018 , 86.1% of the natural gas liquid contracts had durations of one year or less and 13.9% had durations of more than one year and less than two years. Derivatives Designated as Hedging Instruments Derivative instruments designated as hedging instruments for accounting purposes are utilized in managing the Partnership’s interest rate risk exposures. Quantitative Disclosures Related to Derivative Instruments Designated as Hedging Instruments The majority of derivative instruments designated as hedges for accounting purposes are interest rate derivative instruments priced on monthly interest rates. As of June 30, 2019 and December 31, 2018 , the Partnership had the following derivative instruments that were designated as hedging instruments for accounting purposes: June 30, 2019 December 31, 2018 Gross Notional Value (In millions) Interest rate swaps $ 200 $ — Balance Sheet Presentation Related to Derivative Instruments The fair value of the derivative instruments that are presented in the Partnership’s Condensed Consolidated Balance Sheets as of June 30, 2019 and December 31, 2018 that were not designated as hedging instruments for accounting purposes are as follows: June 30, 2019 December 31, 2018 Fair Value Instrument Balance Sheet Location Assets Liabilities Assets Liabilities (In millions) Natural gas Financial futures/swaps Other Current $ 11 $ 6 $ 3 $ 5 Financial futures/swaps Other — 2 — 2 Physical purchases/sales Other Current 4 — 3 — Physical purchases/sales Other 2 — 4 — Crude oil (for condensate) Financial futures/swaps Other Current 2 9 9 3 Financial futures/swaps Other — 5 2 — Natural gas liquids Financial futures/swaps Other Current 23 5 10 1 Financial futures/swaps Other 6 — 2 — Total gross commodity derivatives (1) $ 48 $ 27 $ 33 $ 11 _____________________ (1) See Note 11 for a reconciliation of the Partnership’s commodity derivatives fair value to the Partnership’s Condensed Consolidated Balance Sheets as of June 30, 2019 and December 31, 2018 . The fair value of the derivative instruments that are presented in the Partnership’s Condensed Consolidated Balance Sheets as of June 30, 2019 and December 31, 2018 that were designated as hedging instruments for accounting purposes are as follows: June 30, 2019 December 31, 2018 Fair Value Instrument Balance Sheet Location Assets Liabilities Assets Liabilities (In millions) Interest rate swaps Other Current $ — $ 1 $ — $ — Interest rate swaps Other — 2 — — Total gross interest rate derivatives (1) $ — $ 3 $ — $ — _____________________ (1) All interest rate derivative instruments that were designated as cash flow hedges are considered Level 2 as of June 30, 2019 . Income Statement Presentation Related to Derivative Instruments The following table presents the effect of derivative instruments on the Partnership’s Condensed Consolidated Statements of Income for the three and six months ended June 30, 2019 and 2018 : Amounts Recognized in Income Three Months Ended June 30, Six Months Ended June 30, 2019 2018 2019 2018 (In millions) Natural gas Financial futures/swaps (losses) gains $ 9 $ (1 ) $ 8 $ (5 ) Physical purchases/sales gains 1 2 — 5 Crude oil (for condensate) Financial futures/swaps losses (10 ) (6 ) (21 ) (10 ) Natural gas liquids Financial futures/swaps (losses) gains 16 (9 ) 19 (4 ) Interest Rates Financial futures/swaps (losses) gains — — — — Total $ 16 $ (14 ) $ 6 $ (14 ) For derivatives not designated as hedges in the tables above, amounts recognized in income for the periods ended June 30, 2019 and 2018 , if any, are reported in Product sales. The following table presents the components of gain (loss) on derivative activity in the Partnership’s Condensed Consolidated Statements of Income for the three and six months ended June 30, 2019 and 2018 : Three Months Ended June 30, Six Months Ended June 30, 2019 2018 2019 2018 (In millions) Change in fair value of commodity derivatives $ 11 $ (10 ) $ (1 ) $ (12 ) Realized gain (loss) on commodity derivatives 5 (4 ) 7 (2 ) Gain (loss) on commodity derivative activity $ 16 $ (14 ) $ 6 $ (14 ) Credit-Risk Related Contingent Features in Derivative Instruments In the event Moody’s or S&P were to lower the Partnership’s senior unsecured debt rating to a below investment grade rating, the Partnership could be required to provide additional credit assurances to third parties, which could include letters of credit or cash collateral to satisfy its obligation under its financial and physical contracts relating to derivative instruments that are in a net liability position. As of June 30, 2019 , under these obligations, the Partnership has posted no cash collateral related to NGL swaps and crude swaps and swaptions and no additional collateral would be required to be posted by the Partnership in the event of a credit ratings downgrade to a below investment grade rating. In certain situations where the Partnership’s credit rating is lowered by Moody’s or S&P, the Partnership could be subject to an early termination event related to certain derivative instruments, which could result in a cash settlement of the instruments at market values on the date of such early termination.

Fair Value Measurements

Fair Value Measurements	6 Months Ended
	Jun. 30, 2019
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 either the NYMEX or the ICE and settled through either a NYMEX or ICE 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 generally include over-the-counter natural gas swaps, natural gas swaptions, natural gas basis swaps and natural gas purchase and sales transactions in markets such that the pricing is closely related to the NYMEX or the ICE pricing, over-the-counter WTI crude oil swaps and swaptions for condensate sales, and over-the-counter interest rate swaps traded in observable markets with less volume and transaction frequency than active markets. We consider the valuation of our interest rate derivatives as Level 2 as the primary input, the LIBOR curve, is based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements. 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, ICE or WTI published market prices, independent broker pricing data or broker/dealer valuations. The valuations of derivatives with pricing based on NYMEX or ICE published market prices may be considered Level 1 if they are settled through a NYMEX or ICE clearing broker account with daily margining. Over-the-counter derivatives with NYMEX, ICE 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. Certain derivatives with option features may be classified as Level 2 if valued using an industry standard Black-Scholes option pricing model that contain observable inputs in the marketplace throughout the term of the derivative instrument. 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. As of June 30, 2019 , there were no contracts 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 three and six months ended June 30, 2019 , there were no transfers between levels. The impact to the fair value of derivatives due to credit risk is calculated using the probability of default based on Standard & Poor’s Ratings Services and/or internally generated ratings. The fair value of derivative assets is adjusted for credit risk. The fair value of derivative liabilities is adjusted for credit risk only if the impact is deemed material. Estimated Fair Value of Financial Instruments The fair values of all accounts receivable, notes receivable, accounts payable, commercial paper and other such financial instruments on the Condensed Consolidated Balance Sheets are estimated to be approximately equivalent to their carrying amounts due to their short-term nature and have been excluded from the table below. The following table summarizes the fair value and carrying amount of the Partnership’s financial instruments as of June 30, 2019 and December 31, 2018 . June 30, 2019 December 31, 2018 Carrying Amount Fair Value Carrying Amount Fair Value (In millions) Debt Revolving Credit Facility (Level 2) (1) $ — $ — $ 250 $ 250 2019 Term Loan Agreement (Level 2) 850 850 — — 2019 Notes (Level 2) — — 500 497 2024 Notes (Level 2) 600 609 600 571 2027 Notes (Level 2) 698 703 698 642 2028 Notes (Level 2) 794 837 794 764 2044 Notes (Level 2) 550 511 550 445 EOIT Senior Notes (Level 2) 254 256 257 256 ____________________ (1) Borrowing capacity is effectively reduced by our borrowings outstanding under the commercial paper program. $681 million and $649 million of commercial paper was outstanding as of June 30, 2019 and December 31, 2018 , respectively. The fair value of the Partnership’s Revolving Credit Facility, 2019 Term Loan Agreement, 2019 Notes, 2024 Notes, 2027 Notes, 2028 Notes, 2044 Notes and EOIT Senior Notes is based on quoted market prices and estimates of current rates available for similar issues with similar maturities and is classified as Level 2 in the fair value hierarchy. Non-Financial Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis Certain assets and liabilities are measured at fair value on a nonrecurring basis; that is, the assets and liabilities are not measured at fair value on an ongoing basis but are subject to fair value adjustments in certain circumstances (e.g., when there is evidence of impairment). As of June 30, 2019 , 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. As of June 30, 2019 , the Partnership’s Level 2 interest rate derivatives are recorded as liabilities with no netting adjustments. The following tables summarize the Partnership’s other assets and liabilities that are measured at fair value on a recurring basis as of June 30, 2019 and December 31, 2018 : June 30, 2019 Commodity Contracts Gas Imbalances (1) Assets Liabilities Assets (2) Liabilities (3) (In millions) Quoted market prices in active market for identical assets (Level 1) $ 10 $ 21 $ — $ — Significant other observable inputs (Level 2) 38 6 13 7 Unobservable inputs (Level 3) — — — — Total fair value 48 27 13 7 Netting adjustments (27 ) (27 ) — — Total $ 21 $ — $ 13 $ 7 December 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) $ 4 $ 9 $ — $ — Significant other observable inputs (Level 2) 29 2 18 17 Unobservable inputs (Level 3) — — — — Total fair value 33 11 18 17 Netting adjustments (9 ) (9 ) — — Total $ 24 $ 2 $ 18 $ 17 ______________________ (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. There were no netting adjustments as of June 30, 2019 and December 31, 2018 . (2) Gas imbalance assets exclude fuel reserves for under retained fuel due from shippers of $13 million and $11 million at June 30, 2019 and December 31, 2018 , 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 $11 million and $5 million at June 30, 2019 and December 31, 2018 , 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.

Supplemental Disclosure of Cash

Supplemental Disclosure of Cash Flow Information	6 Months Ended
	Jun. 30, 2019
Supplemental Cash Flow Information [Abstract]
Supplemental Disclosure of Cash Flow Information	Supplemental Disclosure of Cash Flow Information The following table provides information regarding supplemental cash flow information: Six Months Ended June 30, 2019 2018 (In millions) Supplemental Disclosure of Cash Flow Information: Cash Payments: Interest, net of capitalized interest $ 95 $ 65 Income taxes, net of refunds 1 1 Non-cash transactions: Accounts payable related to capital expenditures 31 42 Lease liabilities arising from the application of ASC 842 42 — 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: June 30, 2019 2018 (In millions) Cash and cash equivalents $ 9 $ 7 Restricted cash 1 14 Cash, cash equivalents and restricted cash shown in the Condensed Consolidated Statements of Cash Flows $ 10 $ 21 During the six months ended June 30, 2019 , Restricted cash decreased $13 million

Related Party Transactions

Related Party Transactions	6 Months Ended
	Jun. 30, 2019
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 natural gas transportation and storage services to CenterPoint Energy’s LDCs in Arkansas, Louisiana, Oklahoma and Northeast Texas under a combination of contracts that include the following types of services: firm transportation, firm transportation with seasonal demand, firm storage, no-notice transportation with storage and maximum rate firm transportation. The contracts for firm transportation with seasonal demand will remain in effect through March 31, 2021. The contracts for firm transportation, firm storage and firm no-notice transportation with storage, as well as the contracts for maximum rate firm transportation for Oklahoma and portions of Northeast Texas, are in effect through March 31, 2021, and will remain in effect thereafter unless and until terminated by either party upon 180 days’ prior written notice. The contracts for maximum firm rate transportation for Arkansas, Louisiana and Texarkana, Texas terminated on March 31, 2018. MRT provides firm transportation and firm 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 twelve 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, for four of its generating facilities, with a primary term of May 1, 2014 through April 30, 2019. On October 24, 2018, EOIT entered into a no-notice load-following transportation agreement with OGE Energy, with a primary term of April 1, 2019 through May 1, 2024. 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 an additional firm transportation agreement with OGE Energy, for one of its generating facilities with a primary term of December 1, 2018 through December 1, 2038. Gas Sales and Purchases Transactions The Partnership sells natural gas volumes to affiliates of CenterPoint Energy and OGE Energy or purchases natural gas volumes from affiliates of CenterPoint Energy through a combination of forward, monthly and daily transactions. The Partnership enters into these physical natural gas transactions in the normal course of business based upon relevant market prices. The Partnership’s revenues from affiliated companies accounted for 5% and 4% of total revenues during the three months ended June 30, 2019 and 2018 , respectively, and 6% and 5% of total revenues during the six months ended June 30, 2019 and 2018 , respectively. Amounts of revenues from affiliated companies included in the Partnership’s Condensed Consolidated Statements of Income are summarized as follows: Three Months Ended June 30, Six Months Ended June 30, 2019 2018 2019 2018 (In millions) Gas transportation and storage service revenues — CenterPoint Energy $ 23 $ 24 $ 56 $ 57 Natural gas product sales — CenterPoint Energy 3 2 4 8 Gas transportation and storage service revenues — OGE Energy 13 9 26 18 Natural gas product sales — OGE Energy — 1 1 2 Total revenues — affiliated companies $ 39 $ 36 $ 87 $ 85 Amounts of natural gas purchased from affiliated companies included in the Partnership’s Condensed Consolidated Statements of Income are summarized as follows: Three Months Ended June 30, Six Months Ended June 30, 2019 2018 2019 2018 (In millions) Cost of natural gas purchases — CenterPoint Energy $ — $ — $ — $ 2 Cost of natural gas purchases — OGE Energy 7 5 13 8 Total cost of natural gas purchases — affiliated companies $ 7 $ 5 $ 13 $ 10 Seconded employees and corporate services As of June 30, 2019 , 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 2019 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 2019 are $1 million and $1 million , respectively. Amounts charged to the Partnership by affiliates for seconded employees and corporate services, included primarily in Operation and maintenance and General and administrative expenses in the Partnership’s Condensed Consolidated Statements of Income are as follows: Three Months Ended June 30, Six Months Ended June 30, 2019 2018 2019 2018 (In millions) Corporate Services — CenterPoint Energy $ — $ — $ — $ 1 Seconded Employee Costs — OGE Energy 5 7 11 15 Corporate Services — OGE Energy — 1 — 1 Total corporate services and seconded employee costs $ 5 $ 8 $ 11 $ 17

Commitments and Contingencies

Commitments and Contingencies	6 Months Ended
	Jun. 30, 2019
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies The Partnership is routinely 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 may from time to time 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 currently expect the disposition of these matters to have a material adverse effect on its financial condition, results of operations or cash flows. On January 1, 2017, the Partnership entered into a 10 -year gathering and processing agreement, which became effective on July 1, 2018, with an affiliate of Energy Transfer Partners, LP for 400 MMcf/d of deliveries to the Godley Plant in Johnson County, Texas. As of June 30, 2019 , the Partnership estimates the remaining associated 10 -year minimum volume commitment fee to be $204 million . On September 13, 2018, the Partnership executed a precedent agreement for the development of the Gulf Run Pipeline, an interstate natural gas transportation project. On January 30, 2019, a final investment decision was made by Golden Pass LNG, the cornerstone shipper for the LNG facility to be served by the Gulf Run Pipeline project. Subject to approval of the project by the FERC, the Partnership will be required to construct a large-diameter pipeline from northern Louisiana to Gulf Coast markets. In addition, the Partnership may transfer existing EGT transportation infrastructure to the Gulf Run Pipeline. Under the precedent agreement, the Partnership estimates the cost to complete the Gulf Run Pipeline project would be as much as $550 million and the project is backed by a 20

Equity-Based Compensation

Equity-Based Compensation	6 Months Ended
	Jun. 30, 2019
Share-based Payment Arrangement [Abstract]
Equity-Based Compensation	Equity-Based Compensation The following table summarizes the Partnership’s equity-based compensation expense for the three and six months ended June 30, 2019 and 2018 related to performance units, restricted units and phantom units for the Partnership’s employees and independent directors: Three Months Ended June 30, Six Months Ended June 30, 2019 2018 2019 2018 (In millions) Performance units $ 2 $ 2 $ 5 $ 5 Restricted units — — — 1 Phantom units 3 1 4 2 Total compensation expense $ 5 $ 3 $ 9 $ 8 The following table presents the assumptions related to the performance share units granted in 2019. 2019 Number of units granted 610,170 Fair value of units granted $ 19.95 Expected distribution yield 8.38 % Expected price volatility 34.2 % Risk-free interest rate 2.54 % Expected life of units (in years) 3 The following table presents the number of phantom units granted and the grant date fair value related to the phantom units granted in 2019. 2019 Phantom Units granted 585,733 Fair value of phantom units granted $14.04 - $15.04 Units Outstanding A summary of the activity for the Partnership’s performance units and phantom units applicable to the Partnership’s employees at June 30, 2019 and changes during 2019 are shown in the following table. Performance 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 (In millions, except unit data) Units outstanding at December 31, 2018 2,109,835 $ 14.33 1,447,590 $ 12.38 Granted (1) 610,170 19.95 585,733 15.02 Vested (2) (1,113,159 ) 10.45 (550,426 ) 8.19 Forfeited (47,433 ) 18.65 (47,463 ) 14.76 Units outstanding at June 30, 2019 1,559,413 $ 19.17 1,435,434 $ 14.98 Aggregate intrinsic value of units outstanding at June 30, 2019 $ 21 $ 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 0% to 200% of the target. (2) Performance units vested as of June 30, 2019 include 1,097,846 units from the 2016 annual grant, which were approved by the Board of Directors in 2016 and paid out at 200% , or 2,195,692 units on March 1, 2019, based on the level of achievement of a performance goal established by the Board of Directors over the performance period of January 1, 2016 through December 31, 2018 . Unrecognized Compensation Cost A summary of the Partnership’s unrecognized compensation cost for its non-vested performance units and phantom units, and the weighted-average periods over which the compensation cost is expected to be recognized are shown in the following table. June 30, 2019 Unrecognized Compensation Cost (In millions) Weighted Average Period for Recognition (In years) Performance Units $ 17 1.75 Phantom Units 13 1.77 Total $ 30 As of June 30, 2019 , there were 6,272,311 units available for issuance under the long-term incentive plan.

Reportable Segments

Reportable Segments	6 Months Ended
	Jun. 30, 2019
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 2018 consolidated financial statements included in the Annual Report. The Partnership uses operating income as the measure of profit or loss for its reportable segments. The Partnership’s assets and operations are organized into two reportable segments: (i) gathering and processing, which primarily provides natural gas and crude oil gathering and natural gas processing services to our producer customers, and (ii) transportation and storage, which provides interstate and intrastate natural gas pipeline transportation and storage service primarily to our producer, power plant, LDC and industrial end-user customers. Financial data for reportable segments are as follows: Three Months Ended June 30, 2019 Gathering and Processing Transportation (1) and Storage Eliminations Total (In millions) Product sales $ 379 $ 114 $ (100 ) $ 393 Service revenues 208 138 (4 ) 342 Total Revenues 587 252 (104 ) 735 Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately) 297 123 (103 ) 317 Operation and maintenance, General and administrative 75 50 (1 ) 124 Depreciation and amortization 78 32 — 110 Taxes other than income tax 10 7 — 17 Operating income $ 127 $ 40 $ — $ 167 Total Assets $ 9,881 $ 5,775 $ (3,247 ) $ 12,409 Capital expenditures $ 90 $ 19 $ — $ 109 Three Months Ended June 30, 2018 Gathering and Processing Transportation (1) and Storage Eliminations Total (In millions) Product sales $ 465 $ 149 $ (113 ) $ 501 Service revenues 176 128 — 304 Total Revenues 641 277 (113 ) 805 Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately) 411 147 (114 ) 444 Operation and maintenance, General and administrative 76 47 — 123 Depreciation and amortization 63 33 — 96 Taxes other than income tax 10 6 — 16 Operating income $ 81 $ 44 $ 1 $ 126 Total assets as of December 31, 2018 $ 9,874 $ 5,805 $ (3,235 ) $ 12,444 Capital expenditures $ 143 $ 42 $ — $ 185 _____________________ (1) See Note 8 for discussion regarding ownership interests in SESH and related equity earnings included in the transportation and storage segment for the three and six months ended June 30, 2019 and 2018 . Six Months Ended June 30, 2019 Gathering and Processing Transportation (1) and Storage Eliminations Total (In millions) Product sales $ 802 $ 281 $ (247 ) $ 836 Service revenues 415 287 (8 ) 694 Total Revenues 1,217 568 (255 ) 1,530 Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately) 657 292 (254 ) 695 Operation and maintenance, General and administrative 159 95 (1 ) 253 Depreciation and amortization 152 63 — 215 Taxes other than income tax 21 14 — 35 Operating income $ 228 $ 104 $ — $ 332 Total Assets $ 9,881 $ 5,775 $ (3,247 ) $ 12,409 Capital expenditures $ 197 $ 55 $ — $ 252 Six Months Ended June 30, 2018 Gathering and Processing Transportation (1) and Storage Eliminations Total (In millions) Product sales $ 883 $ 289 $ (228 ) $ 944 Service revenues 349 267 (7 ) 609 Total Revenues 1,232 556 (235 ) 1,553 Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately) 769 286 (236 ) 819 Operation and maintenance, General and administrative 152 93 (1 ) 244 Depreciation and amortization 125 67 — 192 Taxes other than income tax 20 13 — 33 Operating income $ 166 $ 97 $ 2 $ 265 Total assets as of December 31, 2018 $ 9,874 $ 5,805 $ (3,235 ) $ 12,444 Capital expenditures $ 291 $ 84 $ — $ 375 _____________________ (1) See Note 8 for discussion regarding ownership interests in SESH and related equity earnings included in the transportation and storage segment for the three and six months ended June 30, 2019 and 2018 .	[1]
[1]	See Note 8 for discussion regarding ownership interests in SESH and related equity earnings included in the transportation and storage segment for the three and six months ended June 30, 2019 and 2018 .

Subsequent Event

Subsequent Event	6 Months Ended
	Jun. 30, 2019
Subsequent Events [Abstract]
Subsequent Event	Subsequent Event On July 26, 2019, the Partnership borrowed an additional $150 million , subject to the terms and conditions of the 2019 Term Loan Agreement. For more information, please see Note 9 of the Notes to Condensed Consolidated Financial Statements.

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	6 Months Ended
	Jun. 30, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization	Organization Enable Midstream Partners, LP is a Delaware limited partnership whose 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 Oklahoma and serve crude oil production in the SCOOP and STACK plays of the Anadarko Basin and 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, a pipeline extending from Louisiana to Alabama. CenterPoint Energy and OGE Energy each have 50% of the management interests in Enable GP. Enable GP is the general partner of the Partnership and has no other operating activities. Enable GP is governed by a board made up of two representatives designated by each of CenterPoint Energy and OGE Energy, along with the Partnership’s Chief Executive Officer and three independent board members CenterPoint Energy and OGE Energy mutually agreed to appoint. CenterPoint Energy and OGE Energy also own a 40% and 60% interest, respectively, in the incentive distribution rights held by Enable GP. As of June 30, 2019 , CenterPoint Energy held approximately 53.8% or 233,856,623 of the Partnership’s common units, and OGE Energy held approximately 25.5% or 110,982,805 of the Partnership’s common units. Additionally, CenterPoint Energy holds 14,520,000 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 June 30, 2019 , the Partnership owned a 50% interest in SESH. See Note 8 for further discussion of SESH. For the six months ended June 30, 2019 , the Partnership held a 50% ownership in Atoka and consolidated Atoka in its Condensed Consolidated Financial Statements as EOIT acted as the managing member of Atoka and had control over the operations of Atoka. In addition, beginning November 1, 2018 through June 30, 2019 , the Partnership owned a 60% interest in ESCP, which is consolidated in its Condensed Consolidated Financial Statements as EOCS acted as the managing member of ESCP and had control over the operations of ESCP.
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.
Depreciation Expense	Depreciation Expense The Partnership completed a depreciation study for the Gathering and Processing and Transportation and Storage segments. Effective January 1, 2019, the new depreciation rates have been applied prospectively as a change in accounting estimate. The new depreciation rates did not result in a material change in depreciation expense or results of operations.
Accounts Receivable and Allowance for Doubtful Accounts	Accounts Receivable and Allowance for Doubtful Accounts
Inventory	Inventory
New Accounting Pronouncements	New Accounting Pronouncements Accounting Standards to be Adopted in Future Periods 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 manner. 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 expects to adopt this standard in the first quarter of 2020 and does not expect the adoption of this standard to have a material impact on our Condensed Consolidated Financial Statements and related disclosures. Intangibles—Goodwill and Other In January 2017, the FASB issued ASU No. 2017-04, “Intangibles-Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment.” This standard requires entities to test goodwill for impairment by eliminating Step 2 from the goodwill impairment test. The standard is effective for interim and annual reporting periods beginning after December 15, 2019. The Partnership does not expect the adoption of this standard to have a material impact on our Condensed Consolidated Financial Statements and related disclosures. Fair Value Measurement—Disclosure Framework-Changes to the Disclosure Requirements for Fair Value Measurement In August 2018, the FASB issued ASU No. 2018-13, “Fair Value Measurement (Topic 820): Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement” which focuses on improving the effectiveness of disclosures in the notes to the financial statements by facilitating clear communication of the information required by U.S. GAAP that is most important to users of each entity’s financial statements. The standard is effective for interim and annual reporting periods beginning after December 15, 2019, although early adoption is permitted. The Partnership expects to adopt this standard in the first quarter of 2020 and continues to evaluate the other impacts of the new standards on our Condensed Consolidated Financial Statements and related disclosures. Intangibles—Goodwill and Other—Internal-Use Software In August 2018, the FASB issued ASU No. 2018-15, “Intangibles—Goodwill and Other—Internal-Use Software: Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract,” which aims to reduce complexity in the accounting for costs of implementing a cloud computing service arrangement. ASU No. 2018-15 aligns the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. The standard is effective for interim and annual periods beginning after December 15, 2019. The Partnership does not expect the adoption of this standard to have a material impact on our Condensed Consolidated Financial Statements and related disclosures. Collaborative Arrangements In November 2018, the FASB issued ASU No. 2018-18, “Collaborative Arrangements (Topic 808): Clarifying the Interaction between Topic 808 and Topic 606.” This standard resolves the diversity in practice concerning the manner in which entities account for transactions on the basis of their view of the economics of the collaborative arrangement. The amendments (1) clarify that certain transactions between collaborative participants should be accounted for as revenue under topic 606 when the collaborative participant is a customer in the context of the unit of account; (2) add unit-of-account guidance in Topic 808 to align with the guidance in Topic 606; and (3) clarify that in a transaction that is not directly related to sales to third parties, presenting the transaction as revenue would be precluded if the collaborative participant counterparty was not a customer. The standard is effective for interim and annual periods beginning after December 15, 2019. The Partnership does not expect the adoption of this standard to have a material impact on our Condensed Consolidated Financial Statements and related disclosures. Codification Improvements
Derivatives Instruments and Hedging Activities	The Partnership is exposed to certain risks relating to its ongoing business operations. The primary risks managed using derivative instruments are commodity price and interest rate risks. The Partnership is also exposed to credit risk in its business operations. Commodity Price Risk The Partnership uses forward physical contracts, commodity price swap contracts and commodity price option features to manage its commodity price risk exposures. Commodity derivative instruments used by the Partnership are as follows: • NGL put options, NGL futures and swaps, and WTI crude oil futures, swaps and swaptions are used to manage the Partnership’s NGL and condensate exposure associated with its processing agreements; • natural gas futures and swaps, natural gas options, natural gas swaptions and natural gas commodity purchases and sales are used to manage the Partnership’s natural gas price exposure associated with its gathering, processing, transportation and storage assets, 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 its 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 are recorded as Other Assets or Liabilities in the Condensed Consolidated Balance Sheets at fair value on a net basis with such amounts classified as current or long-term based on their anticipated settlement. As of June 30, 2019 and December 31, 2018 , the Partnership had no commodity derivative instruments that were designated as cash flow or fair value hedges for accounting purposes. Interest Rate Risk The Partnership uses interest rate swap contracts to manage its interest rate risk exposures. The Partnership recognizes its interest rate 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. The Partnership’s interest rate swap contracts are designated as cash flow hedging instruments for accounting purposes. For interest rate derivative instruments designated as cash flow hedging instruments, the gain or loss on the derivative is recognized currently in Accumulated other comprehensive loss and will be reclassified to Interest expense in the same period the hedged transaction affects earnings. As of June 30, 2019 , the Partnership had no interest rate derivative instruments that were designated as fair value hedges for accounting purposes. As of December 31, 2018 , the Partnership had no outstanding interest rate derivative instruments. Credit Risk 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 to manage its exposure to commodity price risk. 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 Not Designated as Hedging 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	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 either the NYMEX or the ICE and settled through either a NYMEX or ICE 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 generally include over-the-counter natural gas swaps, natural gas swaptions, natural gas basis swaps and natural gas purchase and sales transactions in markets such that the pricing is closely related to the NYMEX or the ICE pricing, over-the-counter WTI crude oil swaps and swaptions for condensate sales, and over-the-counter interest rate swaps traded in observable markets with less volume and transaction frequency than active markets. We consider the valuation of our interest rate derivatives as Level 2 as the primary input, the LIBOR curve, is based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements. 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, ICE or WTI published market prices, independent broker pricing data or broker/dealer valuations. The valuations of derivatives with pricing based on NYMEX or ICE published market prices may be considered Level 1 if they are settled through a NYMEX or ICE clearing broker account with daily margining. Over-the-counter derivatives with NYMEX, ICE 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. Certain derivatives with option features may be classified as Level 2 if valued using an industry standard Black-Scholes option pricing model that contain observable inputs in the marketplace throughout the term of the derivative instrument. 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. As of June 30, 2019 , there were no contracts 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 three and six months ended June 30, 2019 , 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 2018 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)	6 Months Ended
	Jun. 30, 2019
Disaggregation of Revenue [Line Items]
Disaggregation of Revenue	The following tables disaggregate total revenues by major source from contracts with customers and the gain (loss) on derivative activity for the three and six months ended June 30, 2019 and 2018 . Three Months Ended June 30, 2019 Gathering and Transportation Eliminations Total (In millions) Revenues: Product sales: Natural gas $ 94 $ 108 $ (95 ) $ 107 Natural gas liquids 237 5 (5 ) 237 Condensate 33 — — 33 Total revenues from natural gas, natural gas liquids, and condensate 364 113 (100 ) 377 Gain on derivative activity 15 1 — 16 Total Product sales $ 379 $ 114 $ (100 ) $ 393 Service revenues: Demand revenues $ 68 $ 123 $ — $ 191 Volume-dependent revenues 140 15 (4 ) 151 Total Service revenues $ 208 $ 138 $ (4 ) $ 342 Total Revenues $ 587 $ 252 $ (104 ) $ 735 Three Months Ended June 30, 2018 Gathering and Transportation Eliminations Total (In millions) Revenues: Product sales: Natural gas $ 106 $ 143 $ (107 ) $ 142 Natural gas liquids 336 6 (6 ) 336 Condensate 37 — — 37 Total revenues from natural gas, natural gas liquids, and condensate 479 149 (113 ) 515 Loss on derivative activity (14 ) — — (14 ) Total Product sales $ 465 $ 149 $ (113 ) $ 501 Service revenues: Demand revenues $ 52 $ 113 $ — $ 165 Volume-dependent revenues 124 15 — 139 Total Service revenues $ 176 $ 128 $ — $ 304 Total Revenues $ 641 $ 277 $ (113 ) $ 805
Schedule of Accounts Receivable	June 30, December 31, (In millions) Accounts Receivable: Customers $ 229 $ 297 Contract assets (1) 6 6 Non-customers 14 6 Total Accounts Receivable (2) $ 249 $ 309 ____________________ (1) Contract assets reflected in Total Accounts Receivable include accrued minimum volume commitments. Contract assets are primarily attributable to revenues associated with estimated shortfall volumes on certain annual minimum volume commitment arrangements. Total Accounts Receivable does not include $5 million of contracts assets related to firm service transportation contracts with tiered rates, which are reflected in Other Assets. (2) 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 June 30, 2019 : 2019 2020 2021 2022 2023 and After (In millions) Deferred revenues $ 23 $ 6 $ 5 $ 5 $ 10
Summary of Timing Recognition of Remaining Performance Obligations	The table below summarizes the timing of recognition of the remaining performance obligations as of June 30, 2019 : 2019 2020 2021 2022 2023 and After (In millions) Transportation and Storage $ 239 $ 397 $ 220 $ 166 $ 806 Gathering and Processing 125 164 136 138 460 Total remaining performance obligations $ 364 $ 561 $ 356 $ 304 $ 1,266
Schedule of New Accounting Pronouncements and Changes in Accounting Principles	The table below summarizes the change in the contract liabilities for the six months ended June 30, 2019 : June 30, December 31, Amounts recognized in revenues (In millions) Deferred revenues $ 49 $ 48 $ 21

Leases (Tables)

Leases (Tables)	6 Months Ended
	Jun. 30, 2019
Leases [Abstract]
Summary of Lease Expense	The table below summarizes lease expense for the three and six month periods ended June 30, 2019 : Three Months Ended June 30, 2019 Gathering and Transportation Total (In millions) Lease Expense: Lease Cost: Operating lease cost $ 3 $ — $ 3 Short-term lease cost 4 — 4 Total Lease Cost $ 7 $ — $ 7
Schedule of Operating Lease Obligations Expiration	Undiscounted cash flows for operating lease liabilities are as follows: Year Ended December 31, 2019 2020 2021 2022 2023 2024 and After Total (In millions) Noncancellable operating leases $ 11 $ 12 $ 7 $ 6 $ 6 $ 15 $ 57
Operating Lease Obligation under ASC 840	Under ASC 840, as of December 31, 2018 , the Partnership had the following operating lease obligations as well as the estimate of the period in which the obligation will be settled: Year Ended December 31, 2019 2020-2021 2022-2023 After 2023 Total (In millions) Noncancellable operating leases $ 14 $ 6 $ 6 $ 14 $ 40

Acquisition (Tables)

Acquisition (Tables)	6 Months Ended
	Jun. 30, 2019
Business Combinations [Abstract]
Schedule of Business Acquisitions, by Acquisition	Purchase price allocation: Assets acquired: Cash $ 1 Current Assets 3 Property, plant and equipment 124 Intangibles 259 Goodwill 86 Liabilities assumed: Current liabilities 1 Less: Non-Controlling Interest at fair value 28 Total identifiable net assets $ 444

Earnings Per Limited Partner _2

Earnings Per Limited Partner Unit (Tables)	6 Months Ended
	Jun. 30, 2019
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 units: Three Months Ended June 30, Six Months Ended June 30, 2019 2018 2019 2018 (In millions, except per unit data) Net income $ 124 $ 95 $ 247 $ 209 Net income attributable to noncontrolling interest — — 1 — Series A Preferred Unit distributions 9 9 18 18 General partner interest in net income — — — — Net income available to common unitholders $ 115 $ 86 $ 228 $ 191 Net income allocable to common units $ 115 $ 86 $ 228 $ 191 Dilutive effect of Series A Preferred Unit distributions — — — — Diluted net income allocable to common units $ 115 $ 86 $ 228 $ 191 Basic earnings per unit Common units $ 0.26 $ 0.20 $ 0.52 $ 0.44 Basic weighted average number of common units outstanding (1) 437 435 436 434 Dilutive effect of Series A Preferred Units — — — — Dilutive effect of performance units — 1 — 1 Diluted weighted average number of common units outstanding 437 436 436 435 Diluted earnings per unit Common units $ 0.26 $ 0.20 $ 0.52 $ 0.44 ____________________ (1) Basic weighted average number of outstanding common units includes approximately one million time-based phantom units for each of the three and six months ended June 30, 2019 and 2018 , respectively.

Partners' Equity (Tables)

Partners' Equity (Tables)	6 Months Ended
	Jun. 30, 2019
Equity [Abstract]
Schedule of Equity Transactions with Limited Partner	The Partnership paid or has authorized payment of the following cash distributions to common unitholders, as applicable, during 2018 and 2019 (in millions, except for per unit amounts): Three Months Ended Record Date Payment Date Per Unit Distribution Total Cash Distribution June 30, 2019 (1) August 20, 2019 August 27, 2019 $ 0.3305 $ 144 March 31, 2019 May 21, 2019 May 29, 2019 0.318 138 December 31, 2018 February 19, 2019 February 26, 2019 0.318 138 September 30, 2018 November 16, 2018 November 29, 2018 0.318 138 June 30, 2018 August 21, 2018 August 28, 2018 0.318 138 March 31, 2018 May 22, 2018 May 29, 2018 0.318 138 _____________________ (1) The Board of Directors declared this $0.3305 per common unit cash distribution on August 2, 2019 , to be paid on August 27, 2019 to common unitholders of record at the close of business on August 20, 2019
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 2018 and 2019 (in millions, except for per unit amounts): Three Months Ended Record Date Payment Date Per Unit Distribution Total Cash Distribution June 30, 2019 August 2, 2019 August 14, 2019 $ 0.625 $ 9 March 31, 2019 April 29, 2019 May 15, 2019 0.625 9 December 31, 2018 February 8, 2019 February 14, 2019 0.625 9 September 30, 2018 November 6, 2018 November 14, 2018 0.625 9 June 30, 2018 August 1, 2018 August 14, 2018 0.625 9 March 31, 2018 May 1, 2018 May 15, 2018 0.625 9 _____________________ (1) The Board of Directors declared a $0.625 per Series A Preferred Unit cash distribution on August 2, 2019 , to be paid on August 14, 2019 , to Series A Preferred unitholders of record at the close of business on August 2, 2019 .

Investment in Equity Method A_2

Investment in Equity Method Affiliate (Tables)	6 Months Ended
	Jun. 30, 2019
Equity Method Investments and Joint Ventures [Abstract]
Schedule of Investments Detail	SESH: Three Months Ended June 30, Six Months Ended June 30, 2019 2018 2019 2018 (In millions) Equity in Earnings of Equity Method Affiliate $ 4 $ 7 $ 7 $ 13 Distributions from Equity Method Affiliate (1) $ 4 $ 8 $ 16 $ 21 ___________________ (1) Distributions from equity method affiliate includes a $4 million and $7 million return on investment and a zero and $1 million return of investment for the three months ended June 30, 2019 and 2018 , respectively. Distributions from equity method affiliate includes a $7 million and $13 million return on investment and a $9 million and $8 million return of investment for the six months ended June 30, 2019 and 2018 , respectively. Summarized financial information of SESH: Three Months Ended June 30, Six Months Ended June 30, 2019 2018 2019 2018 (In millions) Income Statements: Revenues $ 27 $ 28 $ 54 $ 56 Operating income $ 11 $ 16 $ 22 $ 33 Net income $ 7 $ 13 $ 14 $ 25

Debt (Tables)

Debt (Tables)	6 Months Ended
	Jun. 30, 2019
Debt Disclosure [Abstract]
Schedule of Debt	The following table presents the Partnership’s outstanding debt as of June 30, 2019 and December 31, 2018 . June 30, 2019 December 31, 2018 Outstanding Principal Premium (Discount) Total Debt Outstanding Principal Premium (Discount) Total Debt (In millions) Commercial Paper $ 681 $ — $ 681 $ 649 $ — $ 649 Revolving Credit Facility — — — 250 — 250 2019 Term Loan Agreement 850 — 850 — — — 2019 Notes — — — 500 — 500 2024 Notes 600 — 600 600 — 600 2027 Notes 700 (2 ) 698 700 (2 ) 698 2028 Notes 800 (6 ) 794 800 (6 ) 794 2044 Notes 550 — 550 550 — 550 EOIT Senior Notes 250 4 254 250 7 257 Total debt $ 4,431 $ (4 ) $ 4,427 $ 4,299 $ (1 ) $ 4,298 Less: Short-term debt (1) 681 649 Less: Current portion of long-term debt (2) 254 500 Less: Unamortized debt expense (3) 19 20 Total long-term debt $ 3,473 $ 3,129 ____________________ (1) Short-term debt includes $681 million and $649 million of outstanding commercial paper as of June 30, 2019 and December 31, 2018 , respectively. (2) As of June 30, 2019 , Current portion of long-term debt included $254 million outstanding balance of the EOIT Senior Notes due March 15, 2020. As of December 31, 2018 , Current portion of long-term debt included $500 million outstanding balance of the 2019 Notes due May 15, 2019. (3) As of June 30, 2019 and December 31, 2018 , there was an additional $5 million and $6 million , respectively, of unamortized debt expense related to the Revolving Credit Facility included in Other assets, not included above.

Derivative Instruments and He_2

Derivative Instruments and Hedging Activities (Tables)	6 Months Ended
	Jun. 30, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Derivative Instruments	As of June 30, 2019 and December 31, 2018 , the Partnership had the following derivative instruments that were not designated as hedging instruments for accounting purposes: June 30, 2019 December 31, 2018 Gross Notional Volume Purchases Sales Purchases Sales Natural gas— TBtu (1) Financial fixed futures/swaps 12 25 16 28 Financial basis futures/swaps 13 41 18 29 Financial swaptions (3) — 3 — 1 Physical purchases/sales — 9 — 11 Crude oil (for condensate)— MBbl (2) Financial futures/swaps — 765 — 945 Financial swaptions (3) — 30 — 30 Natural gas liquids— MBbl (4) Financial futures/swaps 1,980 2,370 270 2,535 ____________________ (1) As of June 30, 2019 , 78.3% of the natural gas contracts had durations of one year or less and 21.7% had durations of more than one year and less than two years. As of December 31, 2018 , 74.0% of the natural gas contracts had durations of one year or less, 24.2% had durations of more than one year and less than two years and 1.8% had durations of more than two years. (2) As of June 30, 2019 , 84.9% of the crude oil (for condensate) contracts had durations of one year or less and 15.1% had durations of more than one year and less than two years. As of December 31, 2018 , 76.9% of the crude oil (for condensate) contracts had durations of one year or less and 23.1% had durations of more than one year and less than two years. (3) The notional contains a combined derivative instrument consisting of a fixed price swap and a sold option, which gives the counterparties the right, but not the obligation, to increase the notional quantity hedged under the fixed price swap until the option expiration date. The notional volume represents the volume prior to option exercise. (4) As of June 30, 2019 , 93.8% of the natural gas liquids contracts had durations of one year or less and 6.2% had durations of more than one year and less than two years. As of December 31, 2018 , 86.1% of the natural gas liquid contracts had durations of one year or less and 13.9% had durations of more than one year and less than two years. The fair value of the derivative instruments that are presented in the Partnership’s Condensed Consolidated Balance Sheets as of June 30, 2019 and December 31, 2018 that were designated as hedging instruments for accounting purposes are as follows: June 30, 2019 December 31, 2018 Fair Value Instrument Balance Sheet Location Assets Liabilities Assets Liabilities (In millions) Interest rate swaps Other Current $ — $ 1 $ — $ — Interest rate swaps Other — 2 — — Total gross interest rate derivatives (1) $ — $ 3 $ — $ — _____________________ (1) All interest rate derivative instruments that were designated as cash flow hedges are considered Level 2 as of June 30, 2019 . As of June 30, 2019 and December 31, 2018 , the Partnership had the following derivative instruments that were designated as hedging instruments for accounting purposes: June 30, 2019 December 31, 2018 Gross Notional Value (In millions) Interest rate swaps $ 200 $ —
Schedule of Derivative Assets at Fair Value	The fair value of the derivative instruments that are presented in the Partnership’s Condensed Consolidated Balance Sheets as of June 30, 2019 and December 31, 2018 that were not designated as hedging instruments for accounting purposes are as follows: June 30, 2019 December 31, 2018 Fair Value Instrument Balance Sheet Location Assets Liabilities Assets Liabilities (In millions) Natural gas Financial futures/swaps Other Current $ 11 $ 6 $ 3 $ 5 Financial futures/swaps Other — 2 — 2 Physical purchases/sales Other Current 4 — 3 — Physical purchases/sales Other 2 — 4 — Crude oil (for condensate) Financial futures/swaps Other Current 2 9 9 3 Financial futures/swaps Other — 5 2 — Natural gas liquids Financial futures/swaps Other Current 23 5 10 1 Financial futures/swaps Other 6 — 2 — Total gross commodity derivatives (1) $ 48 $ 27 $ 33 $ 11 _____________________ (1) See Note 11 for a reconciliation of the Partnership’s commodity derivatives fair value to the Partnership’s Condensed Consolidated Balance Sheets as of June 30, 2019 and December 31, 2018 .
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value	The following table presents the effect of derivative instruments on the Partnership’s Condensed Consolidated Statements of Income for the three and six months ended June 30, 2019 and 2018 : Amounts Recognized in Income Three Months Ended June 30, Six Months Ended June 30, 2019 2018 2019 2018 (In millions) Natural gas Financial futures/swaps (losses) gains $ 9 $ (1 ) $ 8 $ (5 ) Physical purchases/sales gains 1 2 — 5 Crude oil (for condensate) Financial futures/swaps losses (10 ) (6 ) (21 ) (10 ) Natural gas liquids Financial futures/swaps (losses) gains 16 (9 ) 19 (4 ) Interest Rates Financial futures/swaps (losses) gains — — — — Total $ 16 $ (14 ) $ 6 $ (14 )
Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location	The following table presents the components of gain (loss) on derivative activity in the Partnership’s Condensed Consolidated Statements of Income for the three and six months ended June 30, 2019 and 2018 : Three Months Ended June 30, Six Months Ended June 30, 2019 2018 2019 2018 (In millions) Change in fair value of commodity derivatives $ 11 $ (10 ) $ (1 ) $ (12 ) Realized gain (loss) on commodity derivatives 5 (4 ) 7 (2 ) Gain (loss) on commodity derivative activity $ 16 $ (14 ) $ 6 $ (14 )

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	6 Months Ended
	Jun. 30, 2019
Fair Value Disclosures [Abstract]
Schedule of Fair Value and Carrying Amount of Financial Instruments	The following table summarizes the fair value and carrying amount of the Partnership’s financial instruments as of June 30, 2019 and December 31, 2018 . June 30, 2019 December 31, 2018 Carrying Amount Fair Value Carrying Amount Fair Value (In millions) Debt Revolving Credit Facility (Level 2) (1) $ — $ — $ 250 $ 250 2019 Term Loan Agreement (Level 2) 850 850 — — 2019 Notes (Level 2) — — 500 497 2024 Notes (Level 2) 600 609 600 571 2027 Notes (Level 2) 698 703 698 642 2028 Notes (Level 2) 794 837 794 764 2044 Notes (Level 2) 550 511 550 445 EOIT Senior Notes (Level 2) 254 256 257 256 ____________________ (1) Borrowing capacity is effectively reduced by our borrowings outstanding under the commercial paper program. $681 million and $649 million of commercial paper was outstanding as of June 30, 2019 and December 31, 2018 , respectively.
Schedule of Assets and Liabilities Measured at Fair Value on a Recurring Basis	The following tables summarize the Partnership’s other assets and liabilities that are measured at fair value on a recurring basis as of June 30, 2019 and December 31, 2018 : June 30, 2019 Commodity Contracts Gas Imbalances (1) Assets Liabilities Assets (2) Liabilities (3) (In millions) Quoted market prices in active market for identical assets (Level 1) $ 10 $ 21 $ — $ — Significant other observable inputs (Level 2) 38 6 13 7 Unobservable inputs (Level 3) — — — — Total fair value 48 27 13 7 Netting adjustments (27 ) (27 ) — — Total $ 21 $ — $ 13 $ 7 December 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) $ 4 $ 9 $ — $ — Significant other observable inputs (Level 2) 29 2 18 17 Unobservable inputs (Level 3) — — — — Total fair value 33 11 18 17 Netting adjustments (9 ) (9 ) — — Total $ 24 $ 2 $ 18 $ 17 ______________________ (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. There were no netting adjustments as of June 30, 2019 and December 31, 2018 . (2) Gas imbalance assets exclude fuel reserves for under retained fuel due from shippers of $13 million and $11 million at June 30, 2019 and December 31, 2018 , 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 $11 million and $5 million at June 30, 2019 and December 31, 2018 , 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.

Supplemental Disclosure of Ca_2

Supplemental Disclosure of Cash Flow Information (Tables)	6 Months Ended
	Jun. 30, 2019
Supplemental Cash Flow Information [Abstract]
Schedule of Cash Flow, Supplemental Disclosures	The following table provides information regarding supplemental cash flow information: Six Months Ended June 30, 2019 2018 (In millions) Supplemental Disclosure of Cash Flow Information: Cash Payments: Interest, net of capitalized interest $ 95 $ 65 Income taxes, net of refunds 1 1 Non-cash transactions: Accounts payable related to capital expenditures 31 42 Lease liabilities arising from the application of ASC 842 42 —
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: June 30, 2019 2018 (In millions) Cash and cash equivalents $ 9 $ 7 Restricted cash 1 14 Cash, cash equivalents and restricted cash shown in the Condensed Consolidated Statements of Cash Flows $ 10 $ 21 During the six months ended June 30, 2019 , Restricted cash decreased $13 million
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: June 30, 2019 2018 (In millions) Cash and cash equivalents $ 9 $ 7 Restricted cash 1 14 Cash, cash equivalents and restricted cash shown in the Condensed Consolidated Statements of Cash Flows $ 10 $ 21 During the six months ended June 30, 2019 , Restricted cash decreased $13 million

Related Party Transactions (Tab

Related Party Transactions (Tables)	6 Months Ended
	Jun. 30, 2019
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 June 30, Six Months Ended June 30, 2019 2018 2019 2018 (In millions) Gas transportation and storage service revenues — CenterPoint Energy $ 23 $ 24 $ 56 $ 57 Natural gas product sales — CenterPoint Energy 3 2 4 8 Gas transportation and storage service revenues — OGE Energy 13 9 26 18 Natural gas product sales — OGE Energy — 1 1 2 Total revenues — affiliated companies $ 39 $ 36 $ 87 $ 85
Schedule of Natural Gas Purchased From Related Parties	Amounts of natural gas purchased from affiliated companies included in the Partnership’s Condensed Consolidated Statements of Income are summarized as follows: Three Months Ended June 30, Six Months Ended June 30, 2019 2018 2019 2018 (In millions) Cost of natural gas purchases — CenterPoint Energy $ — $ — $ — $ 2 Cost of natural gas purchases — OGE Energy 7 5 13 8 Total cost of natural gas purchases — affiliated companies $ 7 $ 5 $ 13 $ 10
Schedule of Amounts Charged to Partnership by Related Parties	Amounts charged to the Partnership by affiliates for seconded employees and corporate services, included primarily in Operation and maintenance and General and administrative expenses in the Partnership’s Condensed Consolidated Statements of Income are as follows: Three Months Ended June 30, Six Months Ended June 30, 2019 2018 2019 2018 (In millions) Corporate Services — CenterPoint Energy $ — $ — $ — $ 1 Seconded Employee Costs — OGE Energy 5 7 11 15 Corporate Services — OGE Energy — 1 — 1 Total corporate services and seconded employee costs $ 5 $ 8 $ 11 $ 17

Equity-Based Compensation (Tabl

Equity-Based Compensation (Tables)	6 Months Ended
	Jun. 30, 2019
Share-based Payment Arrangement [Abstract]
Disclosure of Share-based Compensation Arrangements by Share-based Payment Award	The following table summarizes the Partnership’s equity-based compensation expense for the three and six months ended June 30, 2019 and 2018 related to performance units, restricted units and phantom units for the Partnership’s employees and independent directors: Three Months Ended June 30, Six Months Ended June 30, 2019 2018 2019 2018 (In millions) Performance units $ 2 $ 2 $ 5 $ 5 Restricted units — — — 1 Phantom units 3 1 4 2 Total compensation expense $ 5 $ 3 $ 9 $ 8 The following table presents the assumptions related to the performance share units granted in 2019. 2019 Number of units granted 610,170 Fair value of units granted $ 19.95 Expected distribution yield 8.38 % Expected price volatility 34.2 % Risk-free interest rate 2.54 % Expected life of units (in years) 3 The following table presents the number of phantom units granted and the grant date fair value related to the phantom units granted in 2019. 2019 Phantom Units granted 585,733 Fair value of phantom units granted $14.04 - $15.04
Schedule of Share-based Compensation, Activity	y of the activity for the Partnership’s performance units and phantom units applicable to the Partnership’s employees at June 30, 2019 and changes during 2019 are shown in the following table. Performance 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 (In millions, except unit data) Units outstanding at December 31, 2018 2,109,835 $ 14.33 1,447,590 $ 12.38 Granted (1) 610,170 19.95 585,733 15.02 Vested (2) (1,113,159 ) 10.45 (550,426 ) 8.19 Forfeited (47,433 ) 18.65 (47,463 ) 14.76 Units outstanding at June 30, 2019 1,559,413 $ 19.17 1,435,434 $ 14.98 Aggregate intrinsic value of units outstanding at June 30, 2019 $ 21 $ 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 0% to 200% of the target. (2) Performance units vested as of June 30, 2019 include 1,097,846 units from the 2016 annual grant, which were approved by the Board of Directors in 2016 and paid out at 200% , or 2,195,692 units on March 1, 2019, based on the level of achievement of a performance goal established by the Board of Directors over the performance period of January 1, 2016 through December 31, 2018 .
Schedule of Unrecognized Compensation Cost, Nonvested Awards	A summary of the Partnership’s unrecognized compensation cost for its non-vested performance units and phantom units, and the weighted-average periods over which the compensation cost is expected to be recognized are shown in the following table. June 30, 2019 Unrecognized Compensation Cost (In millions) Weighted Average Period for Recognition (In years) Performance Units $ 17 1.75 Phantom Units 13 1.77 Total $ 30

Reportable Segments (Tables)

Reportable Segments (Tables)	6 Months Ended
	Jun. 30, 2019
Segment Reporting [Abstract]
Schedule of Financial Data for Business Segments and Services	Financial data for reportable segments are as follows: Three Months Ended June 30, 2019 Gathering and Processing Transportation (1) and Storage Eliminations Total (In millions) Product sales $ 379 $ 114 $ (100 ) $ 393 Service revenues 208 138 (4 ) 342 Total Revenues 587 252 (104 ) 735 Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately) 297 123 (103 ) 317 Operation and maintenance, General and administrative 75 50 (1 ) 124 Depreciation and amortization 78 32 — 110 Taxes other than income tax 10 7 — 17 Operating income $ 127 $ 40 $ — $ 167 Total Assets $ 9,881 $ 5,775 $ (3,247 ) $ 12,409 Capital expenditures $ 90 $ 19 $ — $ 109 Three Months Ended June 30, 2018 Gathering and Processing Transportation (1) and Storage Eliminations Total (In millions) Product sales $ 465 $ 149 $ (113 ) $ 501 Service revenues 176 128 — 304 Total Revenues 641 277 (113 ) 805 Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately) 411 147 (114 ) 444 Operation and maintenance, General and administrative 76 47 — 123 Depreciation and amortization 63 33 — 96 Taxes other than income tax 10 6 — 16 Operating income $ 81 $ 44 $ 1 $ 126 Total assets as of December 31, 2018 $ 9,874 $ 5,805 $ (3,235 ) $ 12,444 Capital expenditures $ 143 $ 42 $ — $ 185 _____________________ (1) See Note 8 for discussion regarding ownership interests in SESH and related equity earnings included in the transportation and storage segment for the three and six months ended June 30, 2019 and 2018 . Six Months Ended June 30, 2019 Gathering and Processing Transportation (1) and Storage Eliminations Total (In millions) Product sales $ 802 $ 281 $ (247 ) $ 836 Service revenues 415 287 (8 ) 694 Total Revenues 1,217 568 (255 ) 1,530 Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately) 657 292 (254 ) 695 Operation and maintenance, General and administrative 159 95 (1 ) 253 Depreciation and amortization 152 63 — 215 Taxes other than income tax 21 14 — 35 Operating income $ 228 $ 104 $ — $ 332 Total Assets $ 9,881 $ 5,775 $ (3,247 ) $ 12,409 Capital expenditures $ 197 $ 55 $ — $ 252 Six Months Ended June 30, 2018 Gathering and Processing Transportation (1) and Storage Eliminations Total (In millions) Product sales $ 883 $ 289 $ (228 ) $ 944 Service revenues 349 267 (7 ) 609 Total Revenues 1,232 556 (235 ) 1,553 Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately) 769 286 (236 ) 819 Operation and maintenance, General and administrative 152 93 (1 ) 244 Depreciation and amortization 125 67 — 192 Taxes other than income tax 20 13 — 33 Operating income $ 166 $ 97 $ 2 $ 265 Total assets as of December 31, 2018 $ 9,874 $ 5,805 $ (3,235 ) $ 12,444 Capital expenditures $ 291 $ 84 $ — $ 375 _____________________ (1) See Note 8 for discussion regarding ownership interests in SESH and related equity earnings included in the transportation and storage segment for the three and six months ended June 30, 2019 and 2018 .	[1]
[1]	See Note 8 for discussion regarding ownership interests in SESH and related equity earnings included in the transportation and storage segment for the three and six months ended June 30, 2019 and 2018 .

Summary of Significant Accoun_3

Summary of Significant Accounting Policies - Narrative (Details) $ in Millions	5 Months Ended	6 Months Ended
	Mar. 31, 2019	Jun. 30, 2019USD ($)board_membersegmentshares	Dec. 31, 2018USD ($)
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%
Allowance for doubtful accounts | $		$ 3	$ 2
Inventory adjustments | $		$ 5	$ 0
SESH
Significant Accounting Policies [Line Items]
Ownership percentage		50.00%
CenterPoint | Common Units
Significant Accounting Policies [Line Items]
Units outstanding		233,856,623
OGE Energy | Common Units
Significant Accounting Policies [Line Items]
Units outstanding		110,982,805
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		53.80%
Limited Partner | CenterPoint | Series A 10% Fixed to Floating Non Cumulative Redeemable Perpetual Preferred Units
Significant Accounting Policies [Line Items]
Series A preferred units held by CenterPoint Energy		14,520,000
Limited Partner | 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		25.50%
Atoka
Significant Accounting Policies [Line Items]
Ownership interest (as a percentage)		50.00%
ESCP
Significant Accounting Policies [Line Items]
Ownership interest (as a percentage)	60.00%

Revenue - Disaggregation of Rev

Revenue - Disaggregation of Revenue (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Disaggregation of Revenue [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate	$ 377	$ 515	$ 830	$ 958
Gain (loss) on derivative activity	16	(14)	6	(14)
Total Revenues	735	805	1,530	1,553
Natural gas
Disaggregation of Revenue [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate	107	142	256	270
Natural gas liquids
Disaggregation of Revenue [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate	237	336	507	615
Condensate Natural Gas
Disaggregation of Revenue [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate	33	37	67	73
Product
Disaggregation of Revenue [Line Items]
Total Revenues	393	501	836	944
Demand Service Revenue
Disaggregation of Revenue [Line Items]
Total Revenues	191	165	382	335
Volume Dependant Service Revenue
Disaggregation of Revenue [Line Items]
Total Revenues	151	139	312	274
Natural Gas, Gathering, Transportation, Marketing and Processing
Disaggregation of Revenue [Line Items]
Total Revenues	342	304	694	609
Operating Segments | Gathering and Processing
Disaggregation of Revenue [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate	364	479	796	900
Gain (loss) on derivative activity	15	(14)	6	(17)
Total Revenues	587	641	1,217	1,232
Operating Segments | Gathering and Processing | Natural gas
Disaggregation of Revenue [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate	94	106	222	212
Operating Segments | Gathering and Processing | Natural gas liquids
Disaggregation of Revenue [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate	237	336	507	615
Operating Segments | Gathering and Processing | Condensate Natural Gas
Disaggregation of Revenue [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate	33	37	67	73
Operating Segments | Gathering and Processing | Product
Disaggregation of Revenue [Line Items]
Total Revenues	379	465	802	883
Operating Segments | Gathering and Processing | Demand Service Revenue
Disaggregation of Revenue [Line Items]
Total Revenues	68	52	128	102
Operating Segments | Gathering and Processing | Volume Dependant Service Revenue
Disaggregation of Revenue [Line Items]
Total Revenues	140	124	287	247
Operating Segments | Gathering and Processing | Natural Gas, Gathering, Transportation, Marketing and Processing
Disaggregation of Revenue [Line Items]
Total Revenues	208	176	415	349
Operating Segments | Transportation and Storage
Disaggregation of Revenue [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate	113	149	281	287
Gain (loss) on derivative activity	1	0	0	2
Total Revenues	252	277	568	556
Operating Segments | Transportation and Storage | Natural gas
Disaggregation of Revenue [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate	108	143	270	274
Operating Segments | Transportation and Storage | Natural gas liquids
Disaggregation of Revenue [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate	5	6	11	13
Operating Segments | Transportation and Storage | Condensate Natural Gas
Disaggregation of Revenue [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate	0	0	0	0
Operating Segments | Transportation and Storage | Product
Disaggregation of Revenue [Line Items]
Total Revenues	114	149	281	289
Operating Segments | Transportation and Storage | Demand Service Revenue
Disaggregation of Revenue [Line Items]
Total Revenues	123	113	254	233
Operating Segments | Transportation and Storage | Volume Dependant Service Revenue
Disaggregation of Revenue [Line Items]
Total Revenues	15	15	33	34
Operating Segments | Transportation and Storage | Natural Gas, Gathering, Transportation, Marketing and Processing
Disaggregation of Revenue [Line Items]
Total Revenues	138	128	287	267
Eliminations
Disaggregation of Revenue [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate	(100)	(113)	(247)	(229)
Gain (loss) on derivative activity	0	0	0	1
Total Revenues	(104)	(113)	(255)	(235)
Eliminations | Natural gas
Disaggregation of Revenue [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate	(95)	(107)	(236)	(216)
Eliminations | Natural gas liquids
Disaggregation of Revenue [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate	(5)	(6)	(11)	(13)
Eliminations | Condensate Natural Gas
Disaggregation of Revenue [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate	0	0	0	0
Eliminations | Product
Disaggregation of Revenue [Line Items]
Total Revenues	(100)	(113)	(247)	(228)
Eliminations | Demand Service Revenue
Disaggregation of Revenue [Line Items]
Total Revenues	0	0	0	0
Eliminations | Volume Dependant Service Revenue
Disaggregation of Revenue [Line Items]
Total Revenues	(4)	0	(8)	(7)
Eliminations | Natural Gas, Gathering, Transportation, Marketing and Processing
Disaggregation of Revenue [Line Items]
Total Revenues	$ (4)	$ 0	$ (8)	$ (7)

Revenue - Accounts Receivable (

Revenue - Accounts Receivable (Details) - USD ($) $ in Millions		Jun. 30, 2019	Dec. 31, 2018
Disaggregation of Revenue [Line Items]
Customers		$ 229	$ 297
Contract assets	[1]	6	6
Non-customers		14	6
Total Accounts Receivable	[2]	249	$ 309
Firm Service Transportation [Member]
Disaggregation of Revenue [Line Items]
Contract assets		$ 5
[1]	Contract assets reflected in Total Accounts Receivable include accrued minimum volume commitments. Contract assets are primarily attributable to revenues associated with estimated shortfall volumes on certain annual minimum volume commitment arrangements. Total Accounts Receivable does not include $5 million of contracts assets related to firm service transportation contracts with tiered rates, which are reflected in Other Assets.
[2]	Total Accounts Receivable includes Accounts receivables, net of allowance for doubtful accounts and Accounts receivable—affiliated companies.

Revenue - Summary of Changes in

Revenue - Summary of Changes in Contract Liabilities (Details) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Deferred revenues	$ 49
Calculated under Revenue Guidance in Effect before Topic 606
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Deferred revenues		$ 48
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	$ 21

Revenue - Summary of Recognitio

Revenue - Summary of Recognition Contract Liabilities (Details) $ in Millions	6 Months Ended
	Jun. 30, 2019USD ($)
Revenue from Contract with Customer [Abstract]
2018	$ 23
2019	6
2020	5
2021	5
2022 and After	$ 10

Revenue - Summary of Recognit_2

Revenue - Summary of Recognition of Remaining Performance Obligations (Details) $ in Millions	Jun. 30, 2019USD ($)
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	$ 364
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	239
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	125
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	561
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	397
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	164
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	356
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	220
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	136
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	304
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	166
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	138
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-04-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total remaining performance obligations	1,266
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-04-01 | Transportation and Storage
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total remaining performance obligations	806
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-04-01 | Gathering and Processing
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total remaining performance obligations	$ 460

Revenue - Summary of the Impact

Revenue - Summary of the Impact of the Changes on Revenues (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate	$ 377	$ 515	$ 830	$ 958
Gain (loss) on derivative activity	16	(14)	6	(14)
Total Revenues	735	805	1,530	1,553
Natural gas
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate	107	142	256	270
Natural gas liquids
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate	237	336	507	615
Condensate Natural Gas
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate	33	37	67	73
Product
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Total Revenues	393	501	836	944
Demand Service Revenue
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Total Revenues	191	165	382	335
Volume Dependant Service Revenue
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Total Revenues	151	139	312	274
Natural Gas, Gathering, Transportation, Marketing and Processing
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Total Revenues	$ 342	$ 304	$ 694	$ 609

Leases - Narrative (Details)

Leases - Narrative (Details) - USD ($) $ in Millions	3 Months Ended	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2019	Jan. 01, 2019
Lessee, Lease, Description [Line Items]
Right-of-use assets	$ 41	$ 41	$ 35
Difference between undiscounted cash flows for operating leases	16	16
Lease liabilities	$ 42	$ 42	$ 35
Weighted average lease term (in years)	4 years	4 years
Weighted average discount rate (as a percentage)	5.55%	5.55%
Rental costs	$ 7	$ 16
Other Assets
Lessee, Lease, Description [Line Items]
Right-of-use assets	38	38
Other Current Liabilities
Lessee, Lease, Description [Line Items]
Operating Lease, Liability, Current	11	11
Other Liabilities
Lessee, Lease, Description [Line Items]
Operating Lease, Liability, Noncurrent	30	30
Field equipment
Lessee, Lease, Description [Line Items]
Rental costs	$ 5	$ 12
Buildings
Lessee, Lease, Description [Line Items]
Renewal options (up to) (in years)	15 years	15 years
Rental costs	$ 2	$ 4
Minimum | Field equipment
Lessee, Lease, Description [Line Items]
Expected lease term (in years)		3 years
Contractual base terms (in years)	1 year	1 year
Minimum | Buildings
Lessee, Lease, Description [Line Items]
Contractual base terms (in years)	7 years	7 years
Maximum | Field equipment
Lessee, Lease, Description [Line Items]
Expected lease term (in years)		5 years
Contractual base terms (in years)	3 years	3 years
Maximum | Buildings
Lessee, Lease, Description [Line Items]
Contractual base terms (in years)	10 years	10 years

Leases - Summary of Lease Expen

Leases - Summary of Lease Expense (Details) - USD ($) $ in Millions	3 Months Ended	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2019
Lessee, Lease, Description [Line Items]
Operating lease cost	$ 3	$ 5
Short-term lease cost	4	11
Total Lease Cost	7	16
Gathering and Processing
Lessee, Lease, Description [Line Items]
Operating lease cost	3	5
Short-term lease cost	4	10
Total Lease Cost	7	15
Transportation and Storage
Lessee, Lease, Description [Line Items]
Operating lease cost	0	0
Short-term lease cost	0	1
Total Lease Cost	$ 0	$ 1

Leases - Schedule of Operating

Leases - Schedule of Operating Lease Obligations Expiration (Details) $ in Millions	Jun. 30, 2019USD ($)
Leases [Abstract]
2019	$ 11
2020	12
2021	7
2022	6
2023	6
2024 and After	15
Total	$ 57

Leases - Operating Lease Obliga

Leases - Operating Lease Obligation under ASC 840 (Details) $ in Millions	Jun. 30, 2019USD ($)
Leases [Abstract]
2019	$ 14
2020-2021	6
2022-2023	6
After 2023	14
Total	$ 40

Acquisition - Narrative (Detail

Acquisition - Narrative (Details) $ in Millions	Nov. 01, 2018USD ($)mi	Jun. 30, 2019USD ($)
General and Administrative Expense
Business Acquisition [Line Items]
Acquisition costs association with the transaction		$ 6
Velocity Holdings, LLC
Business Acquisition [Line Items]
Payment to acquire Align Midstream, LLC	$ 444
Percentage of Pipeline System Acquired	60.00%
Number of Miles in Pipeline System Acquired | mi	26
Less: Non-Controlling Interest at fair value	$ 28
Customer Relationships | Velocity Holdings, LLC
Business Acquisition [Line Items]
Weighted average useful life (in years)		15 years

Acquisition - Schedule of Asset

Acquisition - Schedule of Assets and Liabilities Assumed (Details) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018	Nov. 01, 2018
Assets acquired:
Goodwill	$ 98	$ 98
Velocity Holdings, LLC
Assets acquired:
Cash			$ 1
Accounts receivable			3
Property, plant and equipment			124
Intangibles			259
Goodwill			86
Liabilities assumed:
Current liabilities			1
Less: Non-Controlling Interest at fair value			28
Total identifiable net assets			$ 444

Earnings Per Limited Partner _3

Earnings Per Limited Partner Unit (Details) - USD ($) $ / shares in Units, shares in Millions		3 Months Ended				6 Months Ended
		Jun. 30, 2019		Jun. 30, 2018		Jun. 30, 2019	Jun. 30, 2018
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net income		$ 124,000,000		$ 95,000,000		$ 247,000,000	$ 209,000,000
Net income attributable to noncontrolling interest		0		0		1,000,000	0
Series A Preferred Unit distributions		9,000,000		9,000,000		18,000,000	18,000,000
General partner interest in net income		0		0		0	0
Net Income Attributable to Common Units (Note 6)		115,000,000		86,000,000		228,000,000	191,000,000
Dilutive effect of Series A Preferred Unit distributions		$ 0		$ 0		$ 0	$ 0
Basic earnings per unit
Dilutive effect of Series A Preferred Units (in units)		0		0
Dilutive effect of performance units (in units)		0		1
Phantom units
Basic weighted average number of outstanding
Basic weighted average number of outstanding	[1]	1		1		1,000,000	1
Common Units
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net Income Attributable to Common Units (Note 6)		$ 115,000,000		$ 86,000,000		$ 228,000,000	$ 191,000,000
Diluted net income		$ 115,000,000		$ 86,000,000		$ 228,000,000	$ 191,000,000
Basic weighted average number of outstanding
Basic weighted average number of outstanding		437	[1]	435	[1]	436	434	[1]
Basic earnings per unit
Basic earnings per unit		$ 0.26		$ 0.20		$ 0.52	$ 0.44
Dilutive effect of Series A Preferred Units (in units)						0	0
Dilutive effect of performance units (in units)						0	1
Diluted weighted average number of outstanding units		437		436		436	435
Diluted earnings per unit		$ 0.26		$ 0.20		$ 0.52	$ 0.44
[1]	Basic weighted average number of outstanding common units includes approximately one million time-based phantom units for each of the three and six months ended June 30, 2019 and 2018 , respectively.

Partners' Equity - Schedule of

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

Aug. 27, 2019

Aug. 20, 2019

Aug. 14, 2019

Aug. 02, 2019

May 29, 2019

May 21, 2019

May 15, 2019

Apr. 29, 2019

Feb. 26, 2019

Feb. 19, 2019

Feb. 14, 2019

Feb. 08, 2019

Nov. 29, 2018

Nov. 16, 2018

Nov. 14, 2018

Nov. 06, 2018

Aug. 28, 2018

Aug. 21, 2018

Aug. 14, 2018

Aug. 01, 2018

May 29, 2018

May 22, 2018

May 15, 2018

May 14, 2018

May 01, 2018

Distribution Made to Limited Partner [Line Items]

Record Date

May 21, 2019

Feb. 19, 2019

Nov. 16, 2018

Aug. 21, 2018

May 22, 2018

Payment Date

May 29, 2019

Feb. 26, 2019

Nov. 29, 2018

Aug. 28, 2018

May 29, 2018

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

Distribution Made to Limited Partner [Line Items]

Record Date

Apr. 29, 2019

Feb. 8, 2019

Nov. 6, 2018

Aug. 1, 2018

May 1, 2018

Payment Date

May 15, 2019

Feb. 14, 2019

Nov. 14, 2018

Aug. 14, 2018

May 15, 2018

Cash Distribution

Distribution Made to Limited Partner [Line Items]

Cash distribution declared (in dollars per unit)

$ 0.318

$ 0.318

$ 0.318

Distribution made to unitholders

$ 138

$ 138

$ 138

$ 138

$ 138

Cash distribution (in dollars per unit)

$ 0.318

$ 0.318

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

$ 0.625

$ 0.625

$ 0.625

Distribution made to unitholders

$ 9

$ 9

$ 9

$ 9

$ 9

Cash distribution (in dollars per unit)

$ 0.625

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

[1]

Aug. 2, 2019

Subsequent Event | Cash Distribution

Distribution Made to Limited Partner [Line Items]

Distribution made to unitholders

[2]

$ 144

Cash distribution (in dollars per unit)

[2]

$ 0.3305

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 unitholders

$ 9

Cash distribution (in dollars per unit)

$ 0.625

$ 0.625

Forecast [Member] | Subsequent Event

Distribution Made to Limited Partner [Line Items]

Record Date

[2]

Aug. 20, 2019

Payment Date

[2]

Aug. 27, 2019

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

Distribution Made to Limited Partner [Line Items]

Payment Date

[1]

Aug. 14, 2019

[1]

The Board of Directors declared a $0.625 per Series A Preferred Unit cash distribution on August 2, 2019 , to be paid on August 14, 2019 , to Series A Preferred unitholders of record at the close of business on August 2, 2019 .

[2]

The Board of Directors declared this $0.3305 per common unit cash distribution on August 2, 2019 , to be paid on August 27, 2019 to common unitholders of record at the close of business on August 20, 2019

Partners' Equity - Narrative (D

Partners' Equity - Narrative (Details) - USD ($)	May 12, 2017	Jun. 30, 2019	Dec. 31, 2018
Distribution Made to Limited Partner [Line Items]
Limited partners' capital account, required quarterly distribution period		60 days
ATM Program
Distribution Made to Limited Partner [Line Items]
Aggregate offering price	$ 200,000,000
Common units available for issuance through ATM Program			$ 197,000,000

Investment in Equity Method A_3

Investment in Equity Method Affiliate - Narrative (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Schedule of Equity Method Investments [Line Items]
Amount billed associated with service agreements	$ 735	$ 805	$ 1,530	$ 1,553
Return on investment in equity method affiliate			7	13
Return of investment in equity method affiliate			$ 9	8
SESH
Schedule of Equity Method Investments [Line Items]
Ownership percentage	50.00%		50.00%
Percentage of distributions through limited partner interest			50.00%
Return on investment in equity method affiliate	$ 4	7	$ 7	13
Return of investment in equity method affiliate	0	1	9	8
SESH | Equity Method Investee | Shared Operations Service Agreements
Schedule of Equity Method Investments [Line Items]
Amount billed associated with service agreements	$ 7	$ 6	$ 10	$ 8

Investment in Equity Method A_4

Investment in Equity Method Affiliate - Schedule of Investments (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Equity in Earnings of Equity Method Affiliates:
Equity in earnings of equity method affiliate	$ 4	$ 7	$ 7	$ 13
Distributions from Equity Method Affiliates:
Return on investment in equity method affiliate			7	13
Return of investment in equity method affiliate			9	8
SESH
Equity in Earnings of Equity Method Affiliates:
Equity in earnings of equity method affiliate	4	7	7	13
Distributions from Equity Method Affiliates:
Distributions from equity method affiliate	4	8	16	21
Return on investment in equity method affiliate	4	7	7	13
Return of investment in equity method affiliate	0	1	9	8
Revenues	27	28	54	56
Operating income	11	16	22	33
Net income	$ 7	$ 13	$ 14	$ 25

Debt - Schedule of Outstanding

Debt - Schedule of Outstanding Debt (Details) - USD ($)		Jun. 30, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Outstanding Principal		$ 4,431,000,000	$ 4,299,000,000
Premium (Discount)		(4,000,000)	(1,000,000)
Total Debt		4,427,000,000	4,298,000,000
Less: Current portion of long-term debt	[1]	254,000,000
Less: Unamortized debt expense	[2]	(19,000,000)	(20,000,000)
Total long-term debt		3,473,000,000	3,129,000,000
2019 Term Loan Agreement | 2019 Term Loan Agreement
Debt Instrument [Line Items]
Outstanding Principal		850,000,000	0
Premium (Discount)		0	0
Total Debt		850,000,000	0
Senior Notes | 2019 Notes
Debt Instrument [Line Items]
Outstanding Principal		0	500,000,000
Premium (Discount)		0	0
Total Debt		0	500,000,000
Less: Current portion of long-term debt	[1]		500,000,000
Senior Notes | 2024 Notes
Debt Instrument [Line Items]
Outstanding Principal		600,000,000	600,000,000
Premium (Discount)		0	0
Total Debt		600,000,000	600,000,000
Senior Notes | 2027 Notes
Debt Instrument [Line Items]
Outstanding Principal		700,000,000	700,000,000
Premium (Discount)		(2,000,000)	(2,000,000)
Total Debt		698,000,000	698,000,000
Senior Notes | 2028 Notes
Debt Instrument [Line Items]
Outstanding Principal		800,000,000	800,000,000
Premium (Discount)		(6,000,000)	(6,000,000)
Total Debt		794,000,000	794,000,000
Senior Notes | 2044 Notes
Debt Instrument [Line Items]
Outstanding Principal		550,000,000	550,000,000
Premium (Discount)		0	0
Total Debt		550,000,000	550,000,000
Senior Notes | EOIT Senior Notes | EOIT
Debt Instrument [Line Items]
Outstanding Principal		250,000,000	250,000,000
Premium (Discount)		4,000,000	7,000,000
Total Debt		254,000,000	257,000,000
Revolving Credit Facility
Debt Instrument [Line Items]
Outstanding Principal		0	250,000,000
Premium (Discount)		0	0
Total Debt		0	250,000,000
Unamortized debt expense related to Revolving Credit Facility		5,000,000	6,000,000
Commercial Paper
Debt Instrument [Line Items]
Premium (Discount)		0	0
Short-term Debt	[3]	$ 681,000,000	$ 649,000,000
[1]	As of June 30, 2019 , Current portion of long-term debt included $254 million outstanding balance of the EOIT Senior Notes due March 15, 2020. As of December 31, 2018 , Current portion of long-term debt included $500 million outstanding balance of the 2019 Notes due May 15, 2019.
[2]	As of June 30, 2019 and December 31, 2018 , there was an additional $5 million and $6 million , respectively, of unamortized debt expense related to the Revolving Credit Facility included in Other assets, not included above.
[3]	Short-term debt includes $681 million and $649 million of outstanding commercial paper as of June 30, 2019 and December 31, 2018 , respectively.

Debt - Narrative (Details)

Debt - Narrative (Details)		Apr. 06, 2018USD ($)time	Jun. 30, 2019USD ($)	Jul. 26, 2019USD ($)	Apr. 29, 2019	Jan. 31, 2019USD ($)	Jan. 29, 2019USD ($)	Dec. 31, 2018USD ($)
Debt Instrument [Line Items]
Commercial paper, authorized								$ 1,400,000,000
Premium (Discount)			$ (4,000,000)					(1,000,000)
Outstanding Principal			$ 4,431,000,000					4,299,000,000
2019 Term Loan Agreement
Debt Instrument [Line Items]
Amount of loan agreement							$ 1,000,000,000
Weighted average interest rate percentage			3.62%
Debt Instrument, Principle Advance						$ 850,000,000
Debt Instrument, Ticketing Fee Percentage					0.125%
Consolidated debt to EBITDA ratio							5
Debt Instrument, Covenant, Acquisition Purchase Price in Rolling 12 Month Period, Minimum							$ 25,000,000
Threshold for debt covenant ratio for acquisitions							5.50
Covenant, acceleration of indebtedness, threshold amount							$ 100,000,000
LIBOR | 2019 Term Loan Agreement
Debt Instrument [Line Items]
Fixed interest rate percentage						1.25%
Senior Notes | 2027 Notes
Debt Instrument [Line Items]
Premium (Discount)			$ (2,000,000)					(2,000,000)
Outstanding Principal			$ 700,000,000					700,000,000
Effective interest rate percentage			4.57%
Senior Notes | 2028 Notes
Debt Instrument [Line Items]
Premium (Discount)			$ (6,000,000)					(6,000,000)
Outstanding Principal			$ 800,000,000					800,000,000
Effective interest rate percentage			5.20%
Senior Notes | Senior Notes including 2019 Notes, 2024 Notes, and 2044 Notes
Debt Instrument [Line Items]
Unamortized discount			$ (8,000,000)
Unamortized debt expense			19,000,000
Senior Notes | 2019 Notes
Debt Instrument [Line Items]
Premium (Discount)			0					0
Outstanding Principal			0					500,000,000
Senior Notes | 2024 Notes
Debt Instrument [Line Items]
Premium (Discount)			0					0
Outstanding Principal			$ 600,000,000					600,000,000
Effective interest rate percentage			4.01%
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)			$ 4,000,000					7,000,000
Outstanding Principal			250,000,000					250,000,000
Unamortized premium			$ 4,000,000
Effective interest rate percentage			3.81%
Commercial Paper
Debt Instrument [Line Items]
Commercial paper outstanding	[1]		$ 681,000,000					$ 649,000,000
Weighted average interest rate percentage								3.25%
Premium (Discount)			$ 0					$ 0
Revolving Credit Facility
Debt Instrument [Line Items]
Maximum borrowing capacity		$ 1,750,000,000
Duration of term loan facility (in years)		5 years
Increase in maximum borrowing capacity		$ 875,000,000
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					$ 250,000,000
Revolving Credit Facility | LIBOR
Debt Instrument [Line Items]
Applicable margin percentage			1.50%
Minimum | Eurodollar | 2019 Term Loan Agreement
Debt Instrument [Line Items]
Fixed interest rate percentage						0.75%
Minimum | Base Rate | 2019 Term Loan Agreement
Debt Instrument [Line Items]
Fixed interest rate percentage						0.00%
Maximum | Eurodollar | 2019 Term Loan Agreement
Debt Instrument [Line Items]
Fixed interest rate percentage						1.50%
Maximum | Base Rate | 2019 Term Loan Agreement
Debt Instrument [Line Items]
Fixed interest rate percentage						0.50%
Subsequent Event | 2019 Term Loan Agreement
Debt Instrument [Line Items]
Additional borrowing amount				$ 150,000,000
[1]	Short-term debt includes $681 million and $649 million of outstanding commercial paper as of June 30, 2019 and December 31, 2018 , respectively.

Derivative Instruments and He_3

Derivative Instruments and Hedging Activities - Narrative (Details) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
Derivative [Line Items]
Cash Flow Hedges Derivative Instruments at Fair Value, Net		$ 0
Fair Value Hedges, Net	$ 0	0
Designated as Hedging Instrument
Derivative [Line Items]
Cash Flow Hedges Derivative Instruments at Fair Value, Net		$ 0

Derivative Instruments and He_4

Derivative Instruments and Hedging Activities (Details) - Not Designated as Hedging Instrument bbl in Thousands, MMBTU in Millions		6 Months Ended
		Jun. 30, 2019MMBTUbbl	Jun. 30, 2018MMBTUbbl	Dec. 31, 2018
Natural Gas, Financial fixed futures/swaps | Purchases
Derivative [Line Items]
Derivative, gross notional volume (TBtu)	[1]	12	16
Natural Gas, Financial fixed futures/swaps | Sales
Derivative [Line Items]
Derivative, gross notional volume (TBtu)	[1]	25	28
Natural gas, Financial basis futures/swaps | Purchases
Derivative [Line Items]
Derivative, gross notional volume (TBtu)	[1]	13	18
Natural gas, Financial basis futures/swaps | Sales
Derivative [Line Items]
Derivative, gross notional volume (TBtu)	[1]	41	29
Natural gas, Financial swaptions | Purchases
Derivative [Line Items]
Derivative, gross notional volume (TBtu)	[1],[2]	0	0
Natural gas, Financial swaptions | Sales
Derivative [Line Items]
Derivative, gross notional volume (TBtu)	[1],[2]	3	1
Physical purchases/sales | Purchases
Derivative [Line Items]
Derivative, gross notional volume (TBtu)	[1]	0	0
Physical purchases/sales | Sales
Derivative [Line Items]
Derivative, gross notional volume (TBtu)	[1]	9	11
Crude oil, Financial Futures/swaps | Purchases
Derivative [Line Items]
Derivative, gross notional volume (MMbl) | bbl	[3]	0	0
Crude oil, Financial Futures/swaps | Sales
Derivative [Line Items]
Derivative, gross notional volume (MMbl) | bbl	[3]	765	945
Crude oil, Financial options | Purchases
Derivative [Line Items]
Derivative, gross notional volume (MMbl) | bbl	[2],[3]	0	0
Crude oil, Financial options | Sales
Derivative [Line Items]
Derivative, gross notional volume (MMbl) | bbl	[2],[3]	30	30
Natural gas liquids, Financial Futures/swaps | Purchases
Derivative [Line Items]
Derivative, gross notional volume (MMbl) | bbl	[4]	1,980	270
Natural gas liquids, Financial Futures/swaps | Sales
Derivative [Line Items]
Derivative, gross notional volume (MMbl) | bbl	[4]	2,370	2,535
Natural gas
Derivative [Line Items]
Percent of contract with durations of one year or less		78.30%		74.00%
Percent of contracts with durations of more than one year and less than two years		21.70%		24.20%
Percent of contracts with durations of more than two years				1.80%
Condensate
Derivative [Line Items]
Percent of contract with durations of one year or less		76.90%		84.90%
Percent of contracts with durations of more than one year and less than two years		15.10%		23.10%
Natural gas liquids
Derivative [Line Items]
Percent of contract with durations of one year or less		93.80%		86.10%
Percent of contracts with durations of more than one year and less than two years		6.20%		13.90%
[1]	As of June 30, 2019 , 78.3% of the natural gas contracts had durations of one year or less and 21.7% had durations of more than one year and less than two years. As of December 31, 2018 , 74.0% of the natural gas contracts had durations of one year or less, 24.2% had durations of more than one year and less than two years and 1.8% had durations of more than two years.
[2]	The notional contains a combined derivative instrument consisting of a fixed price swap and a sold option, which gives the counterparties the right, but not the obligation, to increase the notional quantity hedged under the fixed price swap until the option expiration date. The notional volume represents the volume prior to option exercise.
[3]	As of June 30, 2019 , 84.9% of the crude oil (for condensate) contracts had durations of one year or less and 15.1% had durations of more than one year and less than two years. As of December 31, 2018 , 76.9% of the crude oil (for condensate) contracts had durations of one year or less and 23.1% had durations of more than one year and less than two years.
[4]	As of June 30, 2019 , 93.8% of the natural gas liquids contracts had durations of one year or less and 6.2% had durations of more than one year and less than two years. As of December 31, 2018 , 86.1% of the natural gas liquid contracts had durations of one year or less and 13.9% had durations of more than one year and less than two years.

Derivative Instruments and He_5

Derivative Instruments and Hedging Activities - Derivative Instruments Designated as Hedging Instruments (Details) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
Designated as Hedging Instrument | Interest Rate Swap
Derivative [Line Items]
Gross Notional Value	$ 200	$ 0

Derivative Instruments and He_6

Derivative Instruments and Hedging Activities - Balance Sheet Location (Details) - USD ($) $ in Millions		Jun. 30, 2019	Dec. 31, 2018
Designated as Hedging Instrument
Derivatives, Fair Value [Line Items]
Assets	[1]	$ 0	$ 0
Liabilities	[1]	3	0
Not Designated as Hedging Instrument
Derivatives, Fair Value [Line Items]
Assets	[2]	48	33
Liabilities	[2]	27	11
Interest rate swaps | Designated as Hedging Instrument | Other Current, Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Current		0	0
Interest rate swaps | Designated as Hedging Instrument | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Current		1	0
Interest rate swaps | Designated as Hedging Instrument | Other Noncurrent Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Noncurrent		0	0
Interest rate swaps | Designated as Hedging Instrument | Other Noncurrent Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Noncurrent		2	0
Natural gas | Financial futures/swaps | Not Designated as Hedging Instrument | Other Current, Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Current		11	3
Natural gas | Financial futures/swaps | Not Designated as Hedging Instrument | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Current		6	5
Natural gas | Financial futures/swaps | Not Designated as Hedging Instrument | Other Noncurrent Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Noncurrent		0	0
Natural gas | Financial futures/swaps | Not Designated as Hedging Instrument | Other Noncurrent Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Noncurrent		2	2
Natural gas | Physical purchases/sales | Not Designated as Hedging Instrument | Other Current, Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Current		4	3
Natural gas | Physical purchases/sales | Not Designated as Hedging Instrument | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Current		0	0
Natural gas | Physical purchases/sales | Not Designated as Hedging Instrument | Other Noncurrent Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Noncurrent		2	4
Natural gas | Physical purchases/sales | Not Designated as Hedging Instrument | Other Noncurrent Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Noncurrent		0	0
Crude oil (for condensate) | Financial futures/swaps | Not Designated as Hedging Instrument | Other Current, Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Current		2	9
Crude oil (for condensate) | Financial futures/swaps | Not Designated as Hedging Instrument | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Current		9	3
Crude oil (for condensate) | Financial futures/swaps | Not Designated as Hedging Instrument | Other Noncurrent Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Noncurrent		0	2
Crude oil (for condensate) | Financial futures/swaps | Not Designated as Hedging Instrument | Other Noncurrent Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Noncurrent		5	0
Natural gas liquids | Financial futures/swaps | Not Designated as Hedging Instrument | Other Current, Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Current		23	10
Natural gas liquids | Financial futures/swaps | Not Designated as Hedging Instrument | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Current		5	1
Natural gas liquids | Financial futures/swaps | Not Designated as Hedging Instrument | Other Noncurrent Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Noncurrent		6	2
Natural gas liquids | Financial futures/swaps | Not Designated as Hedging Instrument | Other Noncurrent Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Noncurrent		$ 0	$ 0
[1]	All interest rate derivative instruments that were designated as cash flow hedges are considered Level 2 as of June 30, 2019 .
[2]	See Note 11 for a reconciliation of the Partnership’s commodity derivatives fair value to the Partnership’s Condensed Consolidated Balance Sheets as of June 30, 2019 and December 31, 2018 .

Derivative Instruments and He_7

Derivative Instruments and Hedging Activities - Amounts Recognized in Income (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivative, net	$ 16	$ (14)	$ 6	$ (14)
Change in fair value of commodity derivatives	11	(10)	(1)	(12)
Realized gain (loss) on commodity derivatives	5	(4)	7	(2)
Gain (loss) on commodity derivative activity	16	(14)	6	(14)
Cash collateral posted	0		0
Cash collateral required if ratings are lowered	0		0
Natural gas | Financial futures/swaps
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivative, net	9	(1)	8	(5)
Natural gas | Physical purchases/sales
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivative, net	1	2	0	5
Condensate | Financial futures/swaps
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivative, net	(10)	(6)	(21)	(10)
Natural gas liquids | Financial futures/swaps
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivative, net	$ 16	$ (9)	$ 19	$ (4)

Fair Value Measurements - Carry

Fair Value Measurements - Carrying and Fair Value Amounts (Details) - USD ($)		Jun. 30, 2019	Dec. 31, 2018
Carrying Amount | Senior Notes | 2028 Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes (Level 2)		$ 794,000,000	$ 794,000,000
Carrying Amount | Significant other observable inputs (Level 2) | 2019 Term Loan Agreement | 2019 Term Loan Agreement
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
2019 Term Loan Agreement (Level 2)		850,000,000	0
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)		0	500,000,000
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)		600,000,000	600,000,000
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)		698,000,000	698,000,000
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)		550,000,000	550,000,000
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)		254,000,000	257,000,000
Carrying Amount | Significant other observable inputs (Level 2) | Revolving Credit Facility | Revolving Credit Facility
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Revolving Credit Facility (Level 2)	[1]	0	250,000,000
Fair Value | Senior Notes | 2028 Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes (Level 2)		837,000,000	764,000,000
Fair Value | Significant other observable inputs (Level 2) | 2019 Term Loan Agreement | 2019 Term Loan Agreement
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
2019 Term Loan Agreement (Level 2)		850,000,000	0
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)		0	497,000,000
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)		609,000,000	571,000,000
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)		703,000,000	642,000,000
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)		511,000,000	445,000,000
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)		256,000,000	256,000,000
Fair Value | Significant other observable inputs (Level 2) | Revolving Credit Facility | Revolving Credit Facility
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Revolving Credit Facility (Level 2)	[1]	0	250,000,000
Commercial Paper
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Short-term Debt	[2]	$ 681,000,000	$ 649,000,000
[1]	Borrowing capacity is effectively reduced by our borrowings outstanding under the commercial paper program. $681 million and $649 million of commercial paper was outstanding as of June 30, 2019 and December 31, 2018 , respectively.
[2]	Short-term debt includes $681 million and $649 million of outstanding commercial paper as of June 30, 2019 and December 31, 2018 , respectively.

Fair Value Measurements - Fair

Fair Value Measurements - Fair Value Hierarchy (Details) - USD ($)		Jun. 30, 2019	Dec. 31, 2018
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Retained fuel due from shippers		$ 13,000,000	$ 11,000,000
Over retained fuel due from shippers		11,000,000	5,000,000
Commodity Contracts | Recurring Measurement
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, total fair value		48,000,000	33,000,000
Liabilities, total fair value		27,000,000	11,000,000
Assets		(27,000,000)	(9,000,000)
Liabilities		(27,000,000)	(9,000,000)
Assets		21,000,000	24,000,000
Liabilities		0	2,000,000
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		10,000,000	4,000,000
Liabilities		21,000,000	9,000,000
Commodity Contracts | Recurring Measurement | Significant other observable inputs (Level 2)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets		38,000,000	29,000,000
Liabilities		6,000,000	2,000,000
Commodity Contracts | Recurring Measurement | Unobservable inputs (Level 3)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets		0	0
Liabilities		0	0
Gas Imbalances | Recurring Measurement
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, total fair value	[1],[2]	13,000,000	18,000,000
Liabilities, total fair value	[2],[3]	7,000,000	17,000,000
Assets	[1],[2]	0	0
Liabilities	[2],[3]	0	0
Assets	[1],[2]	13,000,000	18,000,000
Liabilities	[2],[3]	7,000,000	17,000,000
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]	13,000,000	18,000,000
Liabilities	[2],[3]	7,000,000	17,000,000
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 $13 million and $11 million at June 30, 2019 and December 31, 2018 , 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. There were no netting adjustments as of June 30, 2019 and December 31, 2018 .
[3]	Gas imbalance liabilities exclude fuel reserves for over retained fuel due to shippers of $11 million and $5 million at June 30, 2019 and December 31, 2018 , 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.

Supplemental Disclosure of Ca_3

Supplemental Disclosure of Cash Flow Information - Supplemental Disclosure of Cash Flow Information (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jan. 01, 2019
Supplemental Cash Flow Information [Abstract]
Interest, net of capitalized interest	$ 95	$ 65
Income taxes, net of refunds	1	1
Accounts payable related to capital expenditures	31	$ 42
Operating Lease, Liability	$ 42		$ 35

Supplemental Disclosure of Ca_4

Supplemental Disclosure of Cash Flow Information - Reconciliation of Cash and Cash Equivalents and Restricted Cash (Details) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018	Jun. 30, 2018	Dec. 31, 2017
Supplemental Cash Flow Information [Abstract]
Cash and cash equivalents	$ 9	$ 8	$ 7
Restricted cash	1	14	14
Cash, cash equivalents and restricted cash shown in the Condensed Consolidated Statements of Cash Flows	$ 10	$ 22	$ 21	$ 19

Supplemental Disclosure of Ca_5

Supplemental Disclosure of Cash Flow Information - Narrative (Details) $ in Millions	6 Months Ended
	Jun. 30, 2019USD ($)
Supplemental Cash Flow Information [Abstract]
Decrease in restricted cash	$ 13

Related Party Transactions - Na

Related Party Transactions - Narrative (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Related Party Transaction [Line Items]
Partnership's revenues from affiliated companies as a percent of total revenues	5.00%	4.00%	6.00%	5.00%
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 | 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			$ 1

Related Party Transactions - Re

Related Party Transactions - Related Party Activity (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Related Party Transaction [Line Items]
Revenues from affiliated companies	$ 39	$ 36	$ 87	$ 85
Cost of goods sold from affiliate	7	5	13	10
Charges to the Partnership by affiliates	5	8	11	17
CenterPoint
Related Party Transaction [Line Items]
Cost of goods sold from affiliate	0	0	0	2
CenterPoint | Gas Transportation and Storage
Related Party Transaction [Line Items]
Revenues from affiliated companies	23	24	56	57
CenterPoint | Gas Sales
Related Party Transaction [Line Items]
Revenues from affiliated companies	3	2	4	8
CenterPoint | Corporate Services
Related Party Transaction [Line Items]
Charges to the Partnership by affiliates	0	0	0	1
OGE Energy
Related Party Transaction [Line Items]
Cost of goods sold from affiliate	7	5	13	8
OGE Energy | Gas Transportation and Storage
Related Party Transaction [Line Items]
Revenues from affiliated companies	13	9	26	18
OGE Energy | Gas Sales
Related Party Transaction [Line Items]
Revenues from affiliated companies	0	1	1	2
OGE Energy | Corporate Services
Related Party Transaction [Line Items]
Charges to the Partnership by affiliates	0	1	0	1
OGE Energy | Seconded Employee Costs
Related Party Transaction [Line Items]
Charges to the Partnership by affiliates	$ 5	$ 7	$ 11	$ 15

Commitments and Contingencies (

Commitments and Contingencies (Details) $ in Millions	Sep. 13, 2018	Jan. 01, 2017MMcf	Jun. 30, 2019USD ($)
Commitments and Contingencies Disclosure [Abstract]
Gathering and processing agreement term (in years)		10 years
Energy deliveries (in MMcf/d) | MMcf		400
Minimum volume commitment fee			$ 204
Estimated Cost to Complete Pipeline Project			$ 550
Firm transportation service agreement term (in years)	20 years

Equity-Based Compensation (Deta

Equity-Based Compensation (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	$ 5	$ 3	$ 9	$ 8
Performance units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	2	2	5	5
Restricted units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	0	0	0	1
Phantom units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	$ 3	$ 1	$ 4	$ 2

Equity-Based Compensation - Sch

Equity-Based Compensation - Schedule of Assumptions Related to Performance Share Units (Details) - Performance units	6 Months Ended
	Jun. 30, 2019$ / sharesshares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of units granted | shares	610,170	[1]
Fair value of units granted | $ / shares	$ 19.95	[1]
Expected distribution yield	8.38%
Expected price volatility	34.20%
Risk-free interest rate	2.54%
Expected life of units (in years)	3 years
[1]	Performance units represents the target number of performance units granted. The actual number of performance units earned, if any, is dependent upon performance and may range from 0% to 200% of the target.

Equity-Based Compensation - Pha

Equity-Based Compensation - Phantom Units (Details) - Phantom units	6 Months Ended
	Jun. 30, 2019$ / sharesshares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Phantom Units granted | shares	585,733	[1]
Fair value of phantom units granted (in dollars per share)	$ 15.02	[1]
Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value of phantom units granted (in dollars per share)	14.04
Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value of phantom units granted (in dollars per share)	$ 15.04
[1]	Performance units represents the target number of performance units granted. The actual number of performance units earned, if any, is dependent upon performance and may range from 0% to 200% of the target.

Equity-Based Compensation - Equ

Equity-Based Compensation - Equity Units Activity (Details) - USD ($) $ / shares in Units, $ in Millions		6 Months Ended
		Jun. 30, 2019	Dec. 31, 2018
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)		2,109,835
Granted (in units)	[1]	610,170
Vested (in units)	[2]	(1,113,159)
Forfeited (in units)		(47,433)
Units Outstanding (in units)		1,559,413
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)		$ 14.33
Granted (in dollars per unit)	[1]	19.95
Vested (in dollars per unit)	[2]	10.45
Forfeited (in dollars per unit)		18.65
Units Outstanding (in dollars per unit)		$ 19.17
Aggregate Intrinsic Value of Units Outstanding		$ 21
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)		1,097,846
Performance units | Annual Grant in 2014
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Vested (in units)		(2,195,692)
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%
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)		1,447,590
Granted (in units)	[1]	585,733
Vested (in units)	[2]	(550,426)
Forfeited (in units)		(47,463)
Units Outstanding (in units)		1,435,434
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)		$ 12.38
Granted (in dollars per unit)	[1]	15.02
Vested (in dollars per unit)	[2]	8.19
Forfeited (in dollars per unit)		14.76
Units Outstanding (in dollars per unit)		14.98
Aggregate Intrinsic Value of Units Outstanding			$ 20
Phantom units | Minimum
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Granted (in dollars per unit)		14.04
Phantom units | Maximum
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Granted (in dollars per unit)		$ 15.04
[1]	Performance units represents the target number of performance units granted. The actual number of performance units earned, if any, is dependent upon performance and may range from 0% to 200% of the target.
[2]	Performance units vested as of June 30, 2019 include 1,097,846 units from the 2016 annual grant, which were approved by the Board of Directors in 2016 and paid out at 200% , or 2,195,692 units on March 1, 2019, based on the level of achievement of a performance goal established by the Board of Directors over the performance period of January 1, 2016 through December 31, 2018 .

Equity-Based Compensation - Unr

Equity-Based Compensation - Unrecognized Compensation Cost (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2019	Dec. 31, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized Compensation Cost (In millions)		$ 30
Performance units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized Compensation Cost (In millions)		17
Weighted Average Period for Recognition (In years)	1 year 9 months
Phantom units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized Compensation Cost (In millions)		$ 13
Weighted Average Period for Recognition (In years)	1 year 9 months 7 days
Long Term Incentive Plan | Common Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares available for issuance		6,272,311

Reportable Segments - Schedule

Reportable Segments - Schedule of Financial Data for Business Segments and Services (Details) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019USD ($)	Jun. 30, 2018USD ($)	Jun. 30, 2019USD ($)segment	Jun. 30, 2018USD ($)	Dec. 31, 2018USD ($)
Segment Reporting Information [Line Items]
Number of reportable segments | segment			2
Total Revenues	$ 735	$ 805	$ 1,530	$ 1,553
Cost of Goods and Services Sold	317	444	695	819
Operation and maintenance, General and administrative			253	244
Depreciation and amortization	110	96	215	192
Taxes other than income tax	17	16	35	33
Operating Income	167	126	332	265
Capital expenditures			252	375
Total assets	12,409		12,409		$ 12,444
Operating Segments | Gathering and Processing
Segment Reporting Information [Line Items]
Total Revenues	587	641	1,217	1,232
Cost of Goods and Services Sold			657	769
Operation and maintenance, General and administrative			159	152
Depreciation and amortization			152	125
Taxes other than income tax			21	20
Operating Income			228	166
Capital expenditures			197	291
Total assets	9,881		9,881		9,874
Operating Segments | Transportation and Storage
Segment Reporting Information [Line Items]
Total Revenues	252	277	568	556
Cost of Goods and Services Sold			292	286
Operation and maintenance, General and administrative			95	93
Depreciation and amortization			63	67
Taxes other than income tax			14	13
Operating Income			104	97
Capital expenditures			55	84
Total assets	5,775		5,775		5,805
Eliminations
Segment Reporting Information [Line Items]
Total Revenues	(104)	(113)	(255)	(235)
Cost of Goods and Services Sold			(254)	(236)
Operation and maintenance, General and administrative			(1)	(1)
Depreciation and amortization			0	0
Taxes other than income tax			0	0
Operating Income			0	2
Capital expenditures			0	0
Total assets	(3,247)		(3,247)		$ (3,235)
Product
Segment Reporting Information [Line Items]
Total Revenues	393	501	836	944
Product | Operating Segments | Gathering and Processing
Segment Reporting Information [Line Items]
Total Revenues	379	465	802	883
Product | Operating Segments | Transportation and Storage
Segment Reporting Information [Line Items]
Total Revenues	114	149	281	289
Product | Eliminations
Segment Reporting Information [Line Items]
Total Revenues	(100)	(113)	(247)	(228)
Natural Gas, Gathering, Transportation, Marketing and Processing
Segment Reporting Information [Line Items]
Total Revenues	342	304	694	609
Natural Gas, Gathering, Transportation, Marketing and Processing | Operating Segments | Gathering and Processing
Segment Reporting Information [Line Items]
Total Revenues	208	176	415	349
Natural Gas, Gathering, Transportation, Marketing and Processing | Operating Segments | Transportation and Storage
Segment Reporting Information [Line Items]
Total Revenues	138	128	287	267
Natural Gas, Gathering, Transportation, Marketing and Processing | Eliminations
Segment Reporting Information [Line Items]
Total Revenues	$ (4)	$ 0	$ (8)	$ (7)

Subsequent Event (Details)

Subsequent Event (Details) $ in Millions	Jul. 26, 2019USD ($)
2019 Term Loan Agreement | Subsequent Event
Subsequent Event [Line Items]
Additional borrowing amount	$ 150