Enable Midstream Partners (ENBL) 10-K 19 Feb 20 2019 FY Annual report Financial data

Cover

Cover - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Jan. 31, 2020	Jun. 28, 2019
Cover page.
Document Annual Report	true
Document Transition Report	false
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2019
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	FY
Entity Registrant Name	ENABLE MIDSTREAM PARTNERS, LP
Entity Incorporation, State or Country Code	DE
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
Entity Central Index Key	0001591763
City Area Code	405
Local Phone Number	525-7788
Trading Symbol	ENBL
Security Exchange Name	NYSE
Title of 12(b) Security	Common Units Representing Limited Partner Interests
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Current Fiscal Year End Date	--12-31
Entity Common Stock, Shares Outstanding		435,206,963
Public Float			$ 1,200
Entity Well-known Seasoned Issuer	Yes
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity File Number	1-36413
Entity Tax Identification Number	72-1252419

Consolidated Statements of Inco

Consolidated Statements of Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Revenues (including revenues from affiliates (Note 16)):
Total Revenues	$ 2,960	$ 3,431	$ 2,803
Cost and Expenses (including expenses from affiliates (Note 16)):
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)	1,279	1,819	1,381
Operation and maintenance	423	388	369
General and administrative	103	113	95
Depreciation and amortization	433	398	366
Impairment (Note 10)	86	0	0
Taxes other than income taxes	67	65	64
Total Cost and Expenses	2,391	2,783	2,275
Operating Income	569	648	528
Other Income (Expense):
Interest expense	(190)	(152)	(120)
Equity in earnings of equity method affiliate	17	26	28
Other, net	3	0	0
Total Other Expense	(170)	(126)	(92)
Income Before Income Tax
Income Before Income Tax	399	522	436
Income tax benefit	(1)	(1)	(1)
Net Income
Net Income	400	523	437
Less: Net income attributable to noncontrolling interests
Less: Net income attributable to noncontrolling interests	4	2	1
Net Income Attributable to Limited Partners
Net Income Attributable to Limited Partners	396	521	436
Less: Series A Preferred Unit distributions (Note 7)
Less: Series A Preferred Unit distributions (Note 7)	36	36	36
Net Income Attributable to Common and Subordinated Units (Note 6)
Net Income Attributable to Common and Subordinated Units (Note 6)	360	485	400
Common Units
Net Income Attributable to Common and Subordinated Units (Note 6)
Net Income Attributable to Common and Subordinated Units (Note 6)	$ 360	$ 485	$ 273
Basic and Diluted earnings (loss) per unit
Basic earnings per unit (Note 6)	$ 0.83	$ 1.12	$ 0.92
Diluted earnings per unit (Note 6)	$ 0.82	$ 1.11	$ 0.92
Subordinated Units
Net Income Attributable to Common and Subordinated Units (Note 6)
Net Income Attributable to Common and Subordinated Units (Note 6)	$ 0	$ 0	$ 127
Basic and Diluted earnings (loss) per unit
Basic earnings per unit (Note 6)	$ 0	$ 0	$ 0.93
Diluted earnings per unit (Note 6)	$ 0	$ 0	$ 0.93
Product
Revenues (including revenues from affiliates (Note 16)):
Total Revenues	$ 1,533	$ 2,106	$ 1,653
Natural Gas, Gathering, Transportation, Marketing and Processing
Revenues (including revenues from affiliates (Note 16)):
Total Revenues	$ 1,427	$ 1,325	$ 1,150

Consolidated Statement of Compr

Consolidated Statement of Comprehensive Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Statement of Comprehensive Income [Abstract]
Net income	$ 400	$ 523	$ 437
Unrealized losses on derivative instruments	(3)	0	0
Reclassification of derivative losses to net income	0	0	0
Other comprehensive loss	(3)	0	0
Comprehensive income	397	523	437
Less: Comprehensive income attributable to noncontrolling interests	4	2	1
Comprehensive income attributable to Limited Partners	$ 393	$ 521	$ 436

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Current Assets:
Cash and cash equivalents	$ 4	$ 8
Restricted cash	0	14
Accounts receivable, net of allowance for doubtful accounts (Note 1)	244	290
Accounts receivable—affiliated companies	25	19
Inventory	46	50
Gas imbalances	35	29
Other current assets	35	39
Total current assets	389	449
Property, Plant and Equipment:
Property, plant and equipment	13,161	12,899
Less accumulated depreciation and amortization	2,291	2,028
Property, plant and equipment, net	10,870	10,871
Other Assets:
Intangible assets, net	601	663
Goodwill	12	98
Investment in equity method affiliate	309	317
Other	85	46
Total other assets	1,007	1,124
Total Assets	12,266	12,444
Current Liabilities:
Accounts payable	161	288
Accounts payable—affiliated companies	1	4
Short-term debt	155	649
Current portion of long-term debt	251	500
Taxes accrued	32	31
Gas imbalances	19	22
Accrued compensation	31	26
Customer deposits	17	38
Other	113	57
Total current liabilities	780	1,615
Other Liabilities:
Accumulated deferred income taxes, net	4	5
Regulatory liabilities	24	23
Other	80	54
Total other liabilities	108	82
Long-Term Debt	3,969	3,129
Commitments and Contingencies (Note 17)
Partners’ Equity:
Series A Preferred Units (14,520,000 issued and outstanding at December 31, 2019 and December 31, 2018, respectively)	$ 362	$ 362
Common units issued	435,201,365	433,232,411
Common units (435,201,365 issued and outstanding at December 31, 2019 and 433,232,411 issued and outstanding at December 31, 2018, respectively)	$ 7,013	$ 7,218
Accumulated other comprehensive loss	(3)	0
Noncontrolling interests	37	38
Total Partners’ Equity	7,409	7,618
Total Liabilities and Partners’ Equity	$ 12,266	$ 12,444

Consolidated Balance Sheets - P

Consolidated Balance Sheets - Parenthetical - shares	Dec. 31, 2019	Dec. 31, 2018
Common units issued	435,201,365	433,232,411
Common units outstanding	435,201,365	433,232,411
Series A Preferred Units
Preferred units issued	14,520,000	14,520,000
Preferred units outstanding	14,520,000	14,520,000

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Statement of Cash Flows [Abstract]
Net income	$ 400	$ 523	$ 437
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	433	398	366
Deferred income taxes	(1)	(1)	(3)
Impairment	86	0	0
Loss on sale/retirement of assets	8	1	7
Equity in earnings of equity method affiliate	(17)	(26)	(28)
Return on investment in equity method affiliate	17	26	28
Equity-based compensation	16	16	15
Amortization of debt costs and discount (premium)	(1)	(1)	(2)
Changes in other assets and liabilities:
Accounts receivable, net	43	(10)	(23)
Accounts receivable—affiliated companies	(6)	(1)	(5)
Inventory	4	(10)	1
Gas imbalance assets	(6)	8	4
Other current assets	9	(21)	4
Other assets	11	(12)	1
Accounts payable	(75)	4	54
Accounts payable—affiliated companies	(3)	1	0
Gas imbalance liabilities	(3)	10	(23)
Other current liabilities	39	4	(4)
Other liabilities	(12)	15	5
Net cash provided by operating activities	942	924	834
Cash Flows from Investing Activities:
Capital expenditures	(432)	(728)	(416)
Acquisitions, net of cash acquired	0	(443)	(298)
Proceeds from sale of assets	1	8	1
Proceeds from insurance	1	2	2
Return of investment in equity method affiliate	8	7	5
Other, net	(8)	0	0
Net cash used in investing activities	(430)	(1,154)	(706)
Cash Flows from Financing Activities:
(Decrease) increase in short-term debt	(494)	244	405
Proceeds from long-term debt, net of issuance costs	1,544	787	691
Repayment of long-term debt	(700)	(450)	0
Proceeds from Revolving Credit Facility	0	350	1,200
Repayment of Revolving Credit Facility	(250)	(100)	(1,836)
Proceeds from issuance of common units, net of issuance costs	0	2	0
Distributions to common unitholders	(564)	(551)	(355)
Distributions to subordinated unitholders	0	0	(198)
Distributions to preferred unitholders	(36)	(36)	(36)
Distributions to non-controlling interests	(5)	(4)	(1)
Cash paid for employee equity-based compensation	(25)	(9)	(2)
Net cash (used in) provided by financing activities	(530)	233	(132)
Net (Decrease) Increase in Cash, Cash Equivalents and Restricted Cash	(18)	3	(4)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	22	19	23
Cash, Cash Equivalents and Restricted Cash at End of Period	$ 4	$ 22	$ 19

Consolidated Statements of Part

Consolidated Statements of Partners' Equity - USD ($) shares in Millions, $ in Millions	Total	Noncontrolling Interest	Series A Preferred UnitsPreferred Units	Common UnitsPartners' Capital	Subordinated UnitsPartners' Capital	Accumulated Other Comprehensive Earnings
Balance, beginning of period (in units) at Dec. 31, 2016			15	224	208
Balance, beginning of period at Dec. 31, 2016	$ 7,794	$ 12	$ 362	$ 3,737	$ 3,683	$ 0
Changes in Partners' Capital
Net income	437	1	36	$ 266	$ 134
Conversion of subordinated units (in units)				208	(208)
Conversion of subordinated units	0			$ 3,619	$ (3,619)
Distributions	(590)	(1)	$ (36)	$ (355)	$ (198)
Equity based compensation (in units)				1
Equity-based compensation, net of units for employee taxes	(13)			$ (13)
Balance, end of period (in units) at Dec. 31, 2017			15	433	0
Balance, end of period at Dec. 31, 2017	7,654	12	$ 362	$ 7,280	$ 0	0
Changes in Partners' Capital
Net income	523	2	36	485
Issuance of common units	2			2
Other comprehensive loss	28	28
Distributions	(591)	(4)	$ (36)	(551)
Equity-based compensation, net of units for employee taxes	(2)			$ (2)
Balance, end of period (in units) at Dec. 31, 2018			15	433	0
Balance, end of period at Dec. 31, 2018	7,618	38	$ 362	$ 7,218	$ 0	0
Changes in Partners' Capital
Net income	400	4	36	360
Other comprehensive loss	(3)					(3)
Distributions	(605)	(5)	$ (36)	$ (564)
Equity based compensation (in units)				2
Equity-based compensation, net of units for employee taxes	(1)			$ (1)
Balance, end of period (in units) at Dec. 31, 2019			15	435	0
Balance, end of period at Dec. 31, 2019	$ 7,409	$ 37	$ 362	$ 7,013	$ 0	$ (3)

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Summary of Significant Accounting Policies	(1) Summary of Significant Accounting Policies Organization Enable Midstream Partners, LP (Partnership) is a Delaware limited partnership formed on May 1, 2013. The Partnership’s assets and operations are organized into two reportable segments: (i) gathering and processing and (ii) transportation and storage. The gathering and processing segment primarily provides natural gas and crude oil gathering and natural gas processing services to our producer customers. The transportation and storage segment provides interstate and intrastate natural gas pipeline transportation and storage services primarily to our producer, power plant, LDC and industrial end-user customers. The Partnership’s natural gas gathering and processing assets are primarily located in Oklahoma, Texas, Arkansas and Louisiana and serve natural gas production in the Anadarko, Arkoma and Ark-La-Tex Basins. Crude oil gathering assets are located in 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. At December 31, 2019 , CenterPoint Energy held approximately 53.7% 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. See Note 7 for further information related to the Series A Preferred Units. The limited partner interests of the Partnership have limited voting rights on matters affecting the business. As such, limited partners do not have rights to elect the Partnership’s General Partner (Enable GP) on an annual or continuing basis and may not remove Enable GP without at least a 75% vote by all unitholders, including all units held by the Partnership’s limited partners, and Enable GP and its affiliates, voting together as a single class. For the years ended December 31, 2019 , 2018 and 2017 , the Partnership owned a 50% interest in SESH. See Note 11 for further discussion of SESH. For the years ended December 31, 2019 , 2018 and 2017 , the Partnership held a 50% ownership interest in Atoka and consolidated Atoka in its Consolidated Financial Statements as EOIT acted as the managing member of Atoka and had control over the operations of Atoka. In addition, for the period November 1, 2018 through December 31, 2019 , the Partnership owned a 60% interest in ESCP, which is consolidated in its 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 consolidated financial statements and related notes of the Partnership have been prepared pursuant to the rules and regulations of the SEC and GAAP. For a description of the Partnership’s reportable segments, see Note 20 . 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. Revenue Recognition The Partnership generates the majority of its revenues from midstream energy services, including natural gas gathering, processing, transportation and storage and crude oil, condensate and produced water gathering. The Partnership performs these services under various contractual arrangements, which include fee-based contract arrangements and arrangements pursuant to which it purchases and resells commodities in connection with providing the related service and earns a net margin for its fee. The Partnership reflects revenue as Product sales and Service revenues on the Consolidated Statements of Income as follows: Product sales: Product sales represent the sale of natural gas, NGLs, crude oil and condensate where the product is purchased and used in connection with providing the Partnership’s midstream services. Service revenues: Service revenues represent all other revenue generated as a result of performing the Partnership’s midstream services. The Partnership recognizes revenue from natural gas gathering, processing, transportation and storage and crude oil, condensate and water gathering services to third parties in accordance with ASU No. 2014-09 “Revenue from Contracts with Customers” (Topic 606) upon its adoption on January 1, 2018. As the Partnership adopted using the modified retrospective method, revenue for all periods prior to January 1, 2018 were recognized in accordance with “Revenue Recognition” (Topic 605). Please see Note 3 for a description of the impact of adoption. Under Topic 606, revenue is recognized at an amount that reflects the consideration to which the entity expects to be entitled in exchange for transferring goods or services. The determination of that amount and the timing of recognition is based on identifying the contracts with customers, identifying the performance obligations in the contract, determining the transaction price, allocating the transaction price to the performance obligations in the contract, and ultimately recognizing revenue when (or as) the entity satisfies the performance obligation. Service revenues for gathering, processing, transportation and storage services for the Partnership are recorded each month as services have been completed and performance obligations are met. Product revenues are recognized when control is transferred. Monthly revenues are based on the current month’s estimated volumes, contracted prices (considering current commodity prices), historical seasonal fluctuations and any known adjustments. The estimates are reversed in the following month and customers are billed on actual volumes and contracted prices. Gas sales are calculated on current-month nominations and contracted prices. Revenues associated with the production of NGLs are estimated based on current-month estimated production and contracted prices. These amounts are reversed in the following month and the customers are billed on actual production and contracted prices. Estimated revenues are reflected in Accounts receivable, net or Accounts receivable—affiliated companies, as appropriate, on the Consolidated Balance Sheets and in Total revenues on the Consolidated Statements of Income. The Partnership records deferred revenue when it receives consideration from a third party before achieving certain criteria that must be met for revenue to be recognized in accordance with GAAP. The Partnership relies on certain key natural gas producer customers for a significant portion of natural gas and NGLs supply. The Partnership relies on certain key utilities for a significant portion of transportation and storage demand. The Partnership depends on third-party facilities to transport and fractionate NGLs that it delivers to third parties at the inlet of their facilities. For the year ended December 31, 2019 , one non-affiliate customer accounted for approximately 11% , or $328 million of our consolidated revenue. These revenues were primarily included in our gathering and processing segment. There are no revenue concentrations with individual non-affiliate customers in the years ended December 31, 2018 and 2017 . See note 16 for more information on revenues from affiliates. Additionally, for the years ended December 31, 2019 , 2018 and 2017 , one third party purchased approximately 12% , 12% and 13% , respectively, of the NGLs delivered off our system, which accounted for approximately $131 million , $214 million and $140 million , or 4% , 6% and 5% , respectively, of total revenues. Additionally, in the years ended December 31, 2019 , 2018 and 2017 , another third party purchased 12% , 8% and 12% , respectively, of the NGLs delivered off our system, which accounted for $119 million , $152 million and $127 million , respectively, or 4% , 4% and 4% , respectively, of total revenues. Natural Gas and Natural Gas Liquids Purchases Cost of natural gas and natural gas liquids represents the cost of our natural gas and natural gas liquids purchased exclusive of depreciation, Operation and maintenance and General and administrative expenses and consists primarily of product and fuel costs. Estimates for gas purchases are based on estimated volumes and contracted purchase prices. Estimated gas purchases are included in Accounts Payable or Accounts Payable-affiliated companies, as appropriate, on the Consolidated Balance Sheets and in Cost of natural gas and natural gas liquids, excluding Depreciation and amortization on the Consolidated Statements of Income. Operation and Maintenance and General and Administrative Expense Operation and maintenance expense represents the cost of our service related revenues and consists primarily of labor expenses, lease costs, utility costs, insurance premiums and repairs and maintenance expenses directly related to the operations of assets. General and administrative expense represents cost incurred to manage the business. This expense includes cost of general corporate services, such as treasury, accounting, legal, information technology and human resources and all other expenses necessary or appropriate to the conduct of business. Any Operation and maintenance expense and General and administrative expense associated with product sales is immaterial. Environmental Costs The Partnership expenses or capitalizes environmental expenditures, as appropriate, depending on their future economic benefit. The Partnership expenses amounts that relate to an existing condition caused by past operations that do not have future economic benefit. The Partnership records undiscounted liabilities related to these future costs when environmental assessments and/or remediation activities are probable and the costs can be reasonably estimated. There are no material amounts accrued at December 31, 2019 or 2018 . Depreciation and Amortization Expense Depreciation is computed using the straight-line method based on economic lives or a regulatory-mandated recovery period. Amortization of intangible assets is computed using the straight-line method over the respective lives of the intangible assets. The computation of depreciation expense requires judgment regarding the estimated useful lives and salvage value of assets at the time the assets are placed in service. As circumstances warrant, useful lives are adjusted when changes in planned use, changes in estimated production lives of affiliated natural gas basins or other factors indicate that a different life would be more appropriate. Such changes could materially impact future depreciation expense. Changes in useful lives that do not result in the impairment of an asset are recognized prospectively. The computation of amortization expense on intangible assets requires judgment regarding the amortization method used. Intangible assets are amortized on a straight-line basis over their useful lives using a method of amortization that reflects the pattern in which the economic benefits of the intangible asset are consumed. Income Taxes The Partnership’s earnings are not subject to income tax ( other than Texas state margin taxes and taxes associated with the Partnership’s corporate subsidiary Enable Midstream Services) and are taxable at the individual partner level. For more information, see Note 18 . We account for deferred income taxes related to the federal and state jurisdictions using the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the future taxes attributable to the difference between financial statement carrying amounts of assets and liabilities and their respective tax basis. Deferred tax assets are also recognized for the future tax benefits attributable to the expected utilization of tax net operating loss carryforwards. In the event future utilization is determined to be unlikely, a valuation allowance is provided to reduce the tax benefits from such assets. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the period in which the temporary differences and carryforwards are expected to be recovered or settled. The effect of a change in tax rates is recognized in the period which includes the enactment date. The Partnership recognizes interest and penalties as a component of income tax expense. Cash and Cash Equivalents The Partnership considers cash equivalents to be short-term, highly liquid investments with maturities of three months or less from the date of purchase. The Consolidated Balance Sheets have $4 million and $8 million of cash and cash equivalents as of December 31, 2019 and 2018 , respectively. Restricted Cash Restricted cash consists of cash which is restricted by agreements with third parties. The Consolidated Balance Sheets have $0 and $14 million of restricted cash as of December 31, 2019 and 2018 , respectively. Accounts Receivable and Allowance for Doubtful Accounts Accounts receivable are recorded at the invoiced amount and do not typically bear interest. The determination of the allowance for doubtful accounts requires management to make estimates and judgments regarding our customers’ ability to pay. The allowance for doubtful accounts is determined based upon specific identification and estimates of future uncollectable amounts. On an ongoing basis, 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 historical bad debt write-offs, the aging of receivables and specific customer circumstances that may impact their ability to pay the amounts due. Based on this review, management determined that a $2 million allowance for doubtful accounts was required at each of the years ended December 31, 2019 and 2018 . Inventory Materials and supplies inventory is valued at cost and is subsequently recorded at the lower of cost or net realizable value. The Partnership recorded no write-downs to net realizable value related to materials and supplies inventory disposed or identified as excess or obsolete for each of the years ended December 31, 2019 and 2018 , and $1 million for the year ended December 31, 2017 . Materials and supplies are recorded to inventory when purchased and, as appropriate, subsequently charged to operation and maintenance expense on the Consolidated Statements of Income or capitalized to property, plant and equipment on the Consolidated Balance Sheets when installed. Natural gas inventory is held, through the transportation and storage reportable 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 reportable 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. During the years ended December 31, 2019 , 2018 and 2017 , the Partnership recorded write-downs to net realizable value related to natural gas and natural gas liquids inventory of $8 million , $4 million and $2 million , respectively. The cost of gas associated with sales of natural gas and natural gas liquids inventory is presented in Cost of natural gas and natural gas liquids, excluding depreciation and amortization on the Consolidated Statements of Income. December 31, 2019 2018 (In millions) Materials and supplies $ 32 $ 31 Natural gas and natural gas liquids 14 19 Total Inventory $ 46 $ 50 Gas Imbalances Gas imbalances occur when the actual amounts of natural gas delivered from or received by the Partnership’s pipeline systems differ from the amounts scheduled to be delivered or received. Imbalances are due to or due from shippers and operators and can be settled in cash or natural gas depending on contractual terms. The Partnership values all imbalances at individual, or where appropriate an average of, current market indices applicable to the Partnership’s operations, not to exceed net realizable value. Long-Lived Assets (including Intangible Assets) The Partnership records property, plant and equipment and intangible assets at historical cost. Newly constructed plant is added to plant balances at cost which includes contracted services, direct labor, materials, overhead, transportation costs and capitalized interest. Replacements of units of property are capitalized as plant. For assets that belong to a common plant account, the replaced plant is removed from plant balances and charged to Accumulated depreciation. For assets that do not belong to a common plant account, the replaced plant is removed from plant balances with the related accumulated depreciation and the remaining balance net of any salvage proceeds is recorded as a loss in the Consolidated Statements of Income as Operation and maintenance expense. The Partnership expenses repair and maintenance costs as incurred. Repair, removal and maintenance costs are included in the Consolidated Statements of Income as Operation and maintenance expense. Assessing Impairment of Long-lived Assets (including Intangible Assets) and Goodwill The Partnership periodically evaluates long-lived assets, including property, plant and equipment, and specifically identifiable intangibles other than goodwill, when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable. The determination of whether an impairment has occurred is based on an estimate of undiscounted cash flows attributable to the assets, as compared to the carrying value of the assets. For more information, see Note 14 . The Partnership assesses its goodwill for impairment annually on October 1st, or more frequently if events or changes in circumstances indicate that the carrying value of goodwill may not be recoverable. Goodwill is assessed for impairment by comparing the fair value of the reporting unit with its book value, including goodwill. The Partnership utilizes the market or income approaches to estimate the fair value of the reporting unit, also giving consideration to the alternative cost approach. Under the market approach, historical and current year forecasted cash flows are multiplied by a market multiple to determine fair value. Under the income approach, anticipated cash flows over a period of years plus a terminal value are discounted to present value using appropriate discount rates. The resulting fair value of the reporting unit is then compared to the carrying amount of the reporting unit and an impairment charge is recorded to goodwill for the difference. The Partnership performs its goodwill impairment testing at the reporting unit, which is one level below the transportation and storage and gathering and processing reportable segment level. For more information, see Note 10 . Regulatory Assets and Liabilities The Partnership applies the guidance for accounting for regulated operations to portions of the transportation and storage reportable segment. The Partnership’s rate-regulated businesses recognize removal costs as a component of depreciation expense in accordance with regulatory treatment. As of each of December 31, 2019 and 2018 , these removal costs of $24 million and $23 million , respectively, are classified as Regulatory liabilities in the Consolidated Balance Sheets. Capitalization of Interest and Allowance for Funds Used During Construction Allowance for funds used during construction (AFUDC) represents the approximate net composite interest cost of borrowed funds and a reasonable return on the equity funds used for construction. Although AFUDC increases both utility plant and earnings, it is realized in cash when the assets are included in rates for entities that apply guidance for accounting for regulated operations. Capitalized interest represents the approximate net composite interest cost of borrowed funds used for construction. Interest and AFUDC are capitalized as a component of projects under construction and will be amortized over the assets’ estimated useful lives. For the years ended December 31, 2019 , 2018 and 2017 , the Partnership capitalized interest and AFUDC of $2 million , $6 million and $1 million , respectively. Derivative Instruments The Partnership is exposed to various market risks. These risks arise from transactions entered into in the normal course of business. At times, the Partnership utilizes commodity derivative instruments such as physical forward contracts, financial futures and swaps to mitigate the impact of changes in commodity prices on its operating results and cash flows. Such derivatives are recognized in the Partnership’s Consolidated Balance Sheets at their fair value unless the Partnership elects hedge accounting or the normal purchase and sales exemption for qualified physical transactions. For commodity derivative instruments not designated as hedging instruments, the gain or loss on the derivative is recognized in Product sales in the Consolidated Statements of Income. A commodity derivative may be designated as a normal purchase or normal sale if the intent is to physically receive or deliver the product for use or sale in the normal course of business. At times, the Partnership utilizes interest rate derivative instruments such as swaps to mitigate the impact of changes in interest rates on its operating results and cash flows. Such derivatives are recognized in the Partnership’s Consolidated Balance Sheets at their fair value. For interest rate derivative instruments designated as cash flow hedging instruments, the gain or loss on the derivative is recognized in Accumulated other comprehensive loss and will be reclassified to Interest expense in the same period in which the hedged transaction is recognized in earnings. The Partnership’s policies prohibit the use of leveraged financial instruments. A leveraged financial instrument, for this purpose, is a transaction involving a derivative whose financial impact will be based on an amount other than the notional amount or volume of the instrument. Fair Value Measurements The Partnership determines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. As required, the Partnership utilizes valuation techniques that maximize the use of observable inputs (levels 1 and 2) and minimize the use of unobservable inputs (level 3) within the fair value hierarchy included in current accounting guidance. The Partnership generally applies the market approach to determine fair value. This method uses pricing and other information generated by market transactions for identical or comparable assets and liabilities. Assets and liabilities are classified within the fair value hierarchy based on the lowest level (least observable) input that is significant to the measurement in its entirety. Equity-Based Compensation The Partnership awards equity-based compensation to officers, directors and employees under the Long-Term Incentive Plan. All equity-based awards to officers, directors and employees under the Long-Term Incentive Plan, including grants of performance units, time-based phantom units (phantom units) and time-based restricted units (restricted units) are recognized in the Consolidated Statements of Income based on their fair values. The fair value of the phantom units and restricted units are based on the closing market price of the Partnership’s common unit on the grant date. The fair value of the performance units is estimated on the grant date using a lattice-based valuation model that factors in information, including the expected distribution yield, expected price volatility, risk-free interest rate and the probable outcome of the market condition, over the expected life of the performance units. Compensation expense for the phantom unit and restricted unit awards is a fixed amount determined at the grant date fair value and is recognized as services are rendered by employees over a vesting period. The vesting of the performance unit awards is also contingent upon the probable outcome of the market condition. Depending on forfeitures and actual vesting, the compensation expense recognized related to the awards could increase or decrease. Employee Benefit Plans On January 1, 2015, the Partnership adopted the 401(k) Savings Plan, covering all full-time employees. Participant contributions are discretionary, and can be up to 70% of compensation, as pre-tax, Roth, and /or after-tax contributions, subject to certain limits. We match 100% of employee contributions up to 6% of each participant’s eligible annual compensation, subject to certain limits. Matching contributions provided by the Partnership are immediately vested. The Partnership may also make discretionary profit sharing contributions. Allocations of such profit sharing contributions are based on the proportion of each participant’s eligible compensation of the plan year to the total of all participants’ eligible compensation, as defined. A participant must be employed on the last day of the Plan year in order to receive an allocation of profit sharing contributions. Profit sharing contributions must be approved by the Board of Directors annually. For the years ended December 31, 2019 , 2018 and 2017 , the Partnership contributed $20 million , $19 million and $18 million , respectively. During the years ended December 31, 2019 , 2018 and 2017 , the Partnership had certain employees who are participants under OGE Energy’s defined benefit and retiree medical plans, who will remain seconded to the Partnership, subject to certain termination rights of the Partnership and OGE Energy. For the years ended December 31, 2019 , 2018 and 2017 , the Partnership reimbursed OGE Energy $3 million , $3 million and $5 million , respectively, for these benefits. See Note 16 for further information related to our related party transactions. Fifth Amended and Restated Agreement of Limited Partnership of Enable Midstream Partners, LP On November 14, 2017, the General Partner adopted the Fifth Amended and Restated Agreement of Limited Partnership (the Partnership Agreement), to implement certain changes to the Internal Revenue Code enacted by the Bipartisan Budget Act of 2015 relating to partnership audit and adjustment procedures. The Partnership Agreement also removed references to the subordinated units (all of which previously converted into common units) and related provisions.

New Accounting Pronouncements

New Accounting Pronouncements	12 Months Ended
	Dec. 31, 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 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, although early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. The Partnership elected to adopt the guidance in ASU 2017-04 effective October 1, 2019, and as a result applied the new guidance to its annual goodwill impairment test performed as of October 1, 2019. The impairment resulting from the October 1, 2019 annual impairment test was based upon the amount by which the carrying amount exceeded the reporting unit’s fair value up to the actual amount of goodwill recorded for the Anadarko Basin reporting unit. 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 does not expect the adoption of this standard to have a material impact on our 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 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 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 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 Consolidated Financial Statements and related disclosures. Codification Improvements In April 2019, the FASB issued ASU No. 2019-04, “Codification Improvements to Topic 326, Financial Instruments-Credit Losses, Topic 815, Derivatives and Hedging, and Topic 825, Financial Instruments,” which clarifies and improves areas of guidance related to recently issued standards on credit losses, hedging and recognition and measurement. The standard is effective for interim and annual periods beginning after December 15, 2019. 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 Consolidated Financial Statements and related disclosures.

Revenues

Revenues	12 Months Ended
	Dec. 31, 2019
Revenue from Contract with Customer [Abstract]
Revenues	Revenues The Partnership adopted ASU No. 2014-09, “Revenue from Contracts with Customers” (ASC 606) on January 1, 2018 using the modified retrospective method. Upon adoption, the Partnership did not recognize a material cumulative adjustment to Partners’ Equity and there were no material changes in the timing of revenue recognition or our accounting policies. The Partnership has applied the standard only to contracts that were not expired as of January 1, 2018. The following tables disaggregate total revenues by major source from contracts with customers and the gain on derivative activity for the years ended December 31, 2019 and 2018 . Year Ended December 31, 2019 Gathering and Transportation Eliminations Total (In millions) Revenues: Product sales: Natural gas $ 368 $ 464 $ (384 ) $ 448 Natural gas liquids 943 19 (19 ) 943 Condensate 126 — — 126 Total revenues from natural gas, natural gas liquids, and condensate 1,437 483 (403 ) 1,517 Gain on derivative activity 12 4 — 16 Total Product sales $ 1,449 $ 487 $ (403 ) $ 1,533 Service revenues: Demand revenues $ 274 $ 489 $ — $ 763 Volume-dependent revenues 615 62 (13 ) 664 Total Service revenues $ 889 $ 551 $ (13 ) $ 1,427 Total Revenues $ 2,338 $ 1,038 $ (416 ) $ 2,960 Year Ended December 31, 2018 Gathering and Transportation Eliminations Total (In millions) Revenues: Product sales: Natural gas $ 480 $ 590 $ (506 ) $ 564 Natural gas liquids 1,405 30 (30 ) 1,405 Condensate 126 — — 126 Total revenues from natural gas, natural gas liquids, and condensate 2,011 620 (536 ) 2,095 Gain on derivative activity 5 5 1 11 Total Product sales $ 2,016 $ 625 $ (535 ) $ 2,106 Service revenues: Demand revenues $ 252 $ 472 $ — $ 724 Volume-dependent revenues 550 65 (14 ) 601 Total Service revenues $ 802 $ 537 $ (14 ) $ 1,325 Total Revenues $ 2,818 $ 1,162 $ (549 ) $ 3,431 Product Sales Natural Gas, NGLs or Condensate We deliver natural gas, NGLs and condensate to purchasers at contractually agreed-upon delivery points at which the purchaser takes custody, title, and risk of loss of the commodity. We recognize revenue at the point in time when control transfers to the purchaser at the delivery point based on the contractually agreed upon fixed or index-based price received. Gain (Loss) on Derivative Activity Included in Product sales are gains and losses on natural gas, natural gas liquids, and crude oil (for condensate) derivatives that are accounted for under guidance in ASC 815. See Note 13 for further discussion of our derivative and hedging activity. Service Revenues Service revenues include demand revenues and volume-dependent revenues, both of which include contracts with customers that typically contain a series of distinct services performed on discrete volumes. For these types of contracts with customers, we typically have a right to consideration from our customers in an amount that corresponds directly with the value to the customer of our performance completed to date and recognize service revenues in accordance with our election to use the right to invoice practical expedient. Demand revenues Our demand revenue arrangements are generally structured in one of the following ways: • Under a firm arrangement, a customer agrees to pay a fixed fee for a contractually agreed upon pipeline or storage capacity, which results in performance obligations for each individual period of reservation. Once the services have been completed, or the customer no longer has access to the contracted capacity, revenue is recognized. • Under a minimum volume commitment arrangement, a customer agrees to pay the contractually agreed upon gathering, compressing and treating fees for a minimum volume of natural gas or crude oil irrespective of whether or not the minimum volume of natural gas or crude oil is delivered, which results in performance obligations for each individual unit of volume. If the actual volumes exceed the minimum volume of natural gas or crude oil, the customer pays the contractually agreed upon gathering, compressing and treating fees for the excess volumes in addition to the fees paid for the minimum volume of natural gas or crude oil. Once the services have been completed, or the customer no longer has the ability to utilize the services, the performance obligation is met, and revenue is recognized. In addition, when certain minimum volume commitment fee arrangements include commitments of one year or more, significant judgment is used in interim commitment periods in which a customer’s actual volumes are deficient in relation to the minimum volume commitment. Revenue is recognized in proportion to the pattern of past performance exercised by the customer or when the likelihood of the customer meeting the minimum volume commitment becomes remote. Volume-dependent revenues Our volume-dependent revenues primarily consist of gathering, compressing, treating, processing, transportation or storage services fees on contracts that exceed their contractually committed volume or do not have firm arrangements or minimum volume commitment arrangements. These revenues are generally variable because the volumes are dependent on throughput by third-party customers for which the service provided is only specified on a daily or monthly basis. Our other fee revenue arrangements typically recognize revenue as the service is performed and have pricing terms that are generally structured in one of the following ways: (1) Contractually agreed upon monetary fee for service or (2) contractually agreed upon consideration received in the form of natural gas or natural gas liquids, which are valued at the current month index-based price, which approximates fair value. Accounts Receivable Payments for all types of revenues are typically received within 30 days of invoice. Invoices for all revenue types are sent on at least a monthly basis, except for the shortfall provisions under certain minimum volume commitment arrangements, which are typically invoiced annually. Accounts receivable includes accrued revenues associated with certain minimum volume commitments that will be invoiced at the conclusion of the measurement period specified under the respective contracts. The following table summarizes the components of accounts receivable: December 31, December 31, (In millions) Accounts Receivable: Customers $ 239 $ 297 Contract assets (1) 18 6 Non-customers 12 6 Total Accounts Receivable (2) $ 269 $ 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 $6 million of contract assets related to firm 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 the following prepayments received from customers for which the good or service has not yet been provided in connection with the prepayment: • Under certain firm arrangements, customers pay their demand fee prior to the month of contracted capacity. These fees are applied to the subsequent month’s activity and are included in other current liabilities on the Consolidated Balance Sheets. • Under certain demand and volume dependent arrangements, customers make contributions of aid in construction payments. For payments that are related to contracts under ASC 606, the payment is deferred and amortized over the life of the associated contract and the unamortized balance is included in other current or long-term liabilities on the Consolidated Balance Sheets. The table below summarizes the change in the contract liabilities for the year ended December 31, 2019 : December 31, December 31, Amounts recognized in revenues (In millions) Deferred revenues (1) $ 48 $ 48 $ 24 The table below summarizes the timing of recognition of these contract liabilities as of December 31, 2019 : 2020 2021 2022 2023 2024 and After (In millions) Deferred revenues (1) $ 25 $ 6 $ 6 $ 5 $ 6 ____________________ (1) Deferred revenues includes deferred revenue — affiliated companies. This amount is included in Other current liabilities and Other long-term liabilities. Remaining Performance Obligations We apply certain practical expedients as permitted by ASC 606, in which we are not required to disclose information regarding remaining performance obligations associated with agreements with original expected durations of one year or less, agreements in which we have elected to recognize revenue in the amount to which we have the right to invoice, and agreements where the variable consideration is allocated entirely to wholly unsatisfied performance obligations that generally do not get resolved until actual volumes are delivered and the prices are known. However, certain agreements do not qualify for practical expedients, which consist primarily of firm arrangements and minimum volume commitment arrangements. Upon completion of the performance obligations associated with these arrangements, revenue is recognized as Service revenues in the Consolidated Statements of Income. The table below summarizes the timing of recognition of the remaining performance obligations as of December 31, 2019 : 2020 2021 2022 2023 2024 and After (In millions) Transportation and Storage (1) $ 461 $ 298 $ 238 $ 225 $ 699 Gathering and Processing 137 121 123 121 313 Total remaining performance obligations $ 598 $ 419 $ 361 $ 346 $ 1,012 ____________________ (1)

Leases

Leases	12 Months Ended
	Dec. 31, 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 only to 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 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 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 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. Variable lease payments due under building rental arrangements began July 1, 2019, with amounts 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 December 31, 2019 , the weighted average remaining lease term is 6.4 years and the weighted average discount rate is 5.40% . As of December 31, 2019 , we have right-of-use assets of $37 million recorded as Other Assets, $9 million of corresponding obligations recorded as Other Current Liabilities and $31 million of corresponding obligations recorded as Other Liabilities on the Partnership’s Consolidated Balance Sheet. All lease obligations outstanding during the year ended December 31, 2019 were classified as operating leases. Therefore, all cash flows are reflected in Cash Flows from Operating Activities. Total lease costs comprised of field equipment rentals and buildings rentals were $29 million and $7 million in the Consolidated Statements of Income during the year ended December 31, 2019 , respectively. The table below summarizes lease cost for the year ended December 31, 2019 : Year Ended December 31, 2019 Gathering and Transportation Total (In millions) Lease Cost: Operating lease cost $ 11 $ — $ 11 Short-term lease cost 22 2 24 Variable lease cost 1 — 1 Total Lease Cost $ 34 $ 2 $ 36 Under ASC 842, as of December 31, 2019 , the Partnership has operating lease obligations expiring at various dates. The $4 million difference between undiscounted cash flows for operating leases and our $40 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, 2020 2021 2022 2023 2024 2025 and After Total (In millions) Noncancellable operating leases $ 11 $ 7 $ 6 $ 6 $ 4 $ 10 $ 44 Description of Lease Contracts The Partnership occupied 162,053 square feet of office space at its former principle executive offices under a lease that expired June 30, 2019 . The lease payments were $19 million over the lease term, which began April 1, 2012. These lease costs are included in General and administrative expense in the Consolidated Statements of Income. During 2017 , the Partnership entered into a lease to occupy 48,642 square feet of office space in Houston, Texas, which ends December 31, 2025. The lease payments are $4 million over the lease term, as well as a proportionate percentage of facility expenses. These lease costs are included in General and administrative expense in the Consolidated Statements of Income. On August 28, 2018, the Partnership entered into a lease to occupy 154,584 feet of office space for its principle executive offices in Oklahoma City, Oklahoma, which expires June 30, 2029 . The lease payments commenced on July 1, 2019, and total $ 25 million over the lease term, as well as a proportionate percentage of facility expenses. The Partnership relocated its headquarters to the new location during the second quarter of 2019. Minimum lease payments were $1 million in 2019 and are expected to be $2 million per year from 2020 through 2023 . The Partnership currently has 86 compression service agreements, of which 71 agreements are on a month-to-month basis and 15 agreements will expire in 2020 . The Partnership also has nine gas treating lease agreements, of which seven are on a month-to-month basis, one agreement will expire in 2021 and one agreement will expire in 2022. These lease costs are reflected in Operation and maintenance expense in the Consolidated Statements of Income. ASC 840 Lease Accounting Under ASC 840 rental expense was $35 million and $27 million during the years ended December 31, 2018 and 2017 , respectively. A s of December 31, 2018 , the Partnership had the following future minimum payments for operating lease obligations as follows : Year Ended December 31, 2019 2020-2021 2022-2023 After 2023 Total (In millions) Noncancellable operating leases $ 14 $ 6 $ 6 $ 14 $ 40

Acquisitions

Acquisitions	12 Months Ended
	Dec. 31, 2019
Business Combinations [Abstract]
Acquisitions	Acquisitions EOCS 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. 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 (in millions): Assets acquired: Cash $ 1 Current Assets 3 Property, plant and equipment 124 Intangibles 259 Goodwill 86 Liabilities assumed: Current liabilities 1 Less: Noncontrolling 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 reportable 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. The Partnership determined not to include pro forma consolidated financial statements for the periods presented as the impact would not be material. ETGP Acquisition On October 4, 2017, the Partnership acquired all of the equity interests in Align Midstream, LLC, now ETGP, a midstream service provider with natural gas gathering and processing facilities in the Cotton Valley and Haynesville plays of the Ark-La-Tex Basin, for approximately $298 million in cash. The acquisition was accounted for as a business combination and funded with borrowings under the Revolving Credit Facility. During the fourth quarter of 2017, the Partnership finalized the purchase price allocation as of October 4, 2017. The following table presents the fair value of the identified assets acquired and liabilities assumed at the acquisition date: Purchase price allocation (in millions): Assets acquired: Accounts receivable $ 5 Property, plant and equipment 111 Intangibles 176 Goodwill 12 Liabilities assumed: Current liabilities 6 Total identifiable net assets $ 298 The Partnership recognized intangible assets related to customer relationships. The acquired intangible assets will be amortized on a straight-line basis over the estimated customer contract life of approximately 10 years. Goodwill recognized from the acquisition primarily relates to greater operating leverage in the Ark-La-Tex Basin and is allocated to the gathering and processing reportable segment. The Partnership incurred approximately $2 million of acquisition costs associated with this transaction, which are included in General and administrative expense in the Consolidated Statements of Income. 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	12 Months Ended
	Dec. 31, 2019
Earnings Per Share [Abstract]
Earnings Per Limited Partner Unit	Earnings Per Limited Partner Unit Basic and diluted earnings per limited partner unit is calculated by dividing net income allocable to common and subordinated units by the weighted average number of common and subordinated units outstanding during the period. Any common units issued during the period are included on a weighted average basis for the days in which they were outstanding. The dilutive effect of the unit-based awards discussed in Note 19 was $0.01 per unit during the years ended December 31, 2019 and 2018 and less than $0.01 per unit during the year ended December 31, 2017 . The following table illustrates the Partnership’s calculation of earnings per unit for common and subordinated units: Year Ended December 31, 2019 2018 2017 (In millions, except per unit data) Net income $ 400 $ 523 $ 437 Net income attributable to noncontrolling interests 4 2 1 Series A Preferred Unit distributions 36 36 36 General partner interest in net income — — — Net income available to common and subordinated units $ 360 $ 485 $ 400 Net income allocable to common units $ 360 $ 485 $ 273 Net income allocable to subordinated units — — 127 Net income available to common and subordinated units $ 360 $ 485 $ 400 Net income allocable to common units $ 360 $ 485 $ 273 Dilutive effect of Series A Preferred Unit distribution — — — Diluted net income allocable to common units 360 485 273 Diluted net income allocable to subordinated units — — 127 Total $ 360 $ 485 $ 400 Basic weighted average number of outstanding Common units (1) 436 434 296 Subordinated units — — 137 Total 436 434 433 Basic earnings per unit Common units $ 0.83 $ 1.12 $ 0.92 Subordinated units $ — $ — $ 0.93 Basic weighted average number of outstanding common units (1) 436 434 296 Dilutive effect of Series A Preferred Units — — — Dilutive effect of performance units 1 2 1 Diluted weighted average number of outstanding common units 437 436 297 Diluted weighted average number of outstanding subordinated units — — 137 Total 437 436 434 Diluted earnings per unit Common units $ 0.82 $ 1.11 $ 0.92 Subordinated units $ — $ — $ 0.93 ____________________ (1) Basic weighted average number of outstanding common units for the years ended December 31, 2019 , 2018 , and 2017 includes approximately one million time-based phantom units. See Note 7 for discussion of the expiration of the subordination period.

Partners' Equity

Partners' Equity	12 Months Ended
	Dec. 31, 2019
Equity [Abstract]
Enable Midstream Partners, LP Partners' Equity	Partners’ Equity The Partnership Agreement requires that, within 60 days after the end of each quarter, the Partnership distribute all of its available cash (as defined in the Partnership Agreement) to unitholders of record on the applicable record date. The Partnership paid or has authorized payment of the following cash distributions to common and subordinated unitholders, as applicable, during 2019 , 2018 and 2017 (in millions, except for per unit amounts): Quarter Ended Record Date Payment Date Per Unit Distribution Total Cash Distribution 2019 December 31, 2019 (1) February 18, 2020 February 25, 2020 $ 0.3305 $ 144 September 30, 2019 November 19, 2019 November 26, 2019 $ 0.3305 $ 144 June 30, 2019 August 20, 2019 August 27, 2019 $ 0.3305 $ 144 March 31, 2019 May 21, 2019 May 29, 2019 $ 0.318 $ 138 2018 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 2017 December 31, 2017 February 20, 2018 February 27, 2018 $ 0.318 $ 138 September 30, 2017 November 14, 2017 November 21, 2017 $ 0.318 $ 138 June 30, 2017 August 22, 2017 August 29, 2017 $ 0.318 $ 138 March 31, 2017 May 23, 2017 May 30, 2017 $ 0.318 $ 137 _____________________ (1) The Board of Directors declared a $0.3305 per common unit cash distribution on February 7, 2020 , to be paid on February 25, 2020 , to common unitholders of record at the close of business on February 18, 2020 . The Partnership paid or has authorized payment of the following cash distributions to holders of the Series A Preferred Units during 2019 , 2018 , and 2017 (in millions, except for per unit amounts): Quarter Ended Record Date Payment Date Per Unit Distribution Total Cash Distribution 2019 December 31, 2019 (1) February 7, 2020 February 14, 2020 $ 0.625 $ 9 September 30, 2019 November 5, 2019 November 14, 2019 $ 0.625 $ 9 June 30, 2019 August 2, 2019 August 14, 2019 $ 0.625 $ 9 March 31, 2019 April 29, 2019 May 15, 2019 $ 0.625 $ 9 2018 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 2017 December 31, 2017 February 9, 2018 February 15, 2018 $ 0.625 $ 9 September 30, 2017 October 31, 2017 November 14, 2017 $ 0.625 $ 9 June 30, 2017 July 31, 2017 August 14, 2017 $ 0.625 $ 9 March 31, 2017 May 2, 2017 May 12, 2017 $ 0.625 $ 9 _____________________ (1) The Board of Directors declared a $0.625 per Series A Preferred Unit cash distribution on February 7, 2020 , to be paid on February 14, 2020 to Series A Preferred unitholders of record at the close of business on February 7, 2020 . General Partner Interest and Incentive Distribution Rights Enable GP owns a non-economic general partner interest in the Partnership and, except as provided below with respect to incentive distribution rights, will not be entitled to distributions that the Partnership makes prior to the liquidation of the Partnership in respect of such general partner interest. Enable GP currently holds incentive distribution rights that entitle it to receive increasing percentages, up to a maximum of 50.0% , of the cash the Partnership distributes from operating surplus (as defined in the Partnership Agreement) in excess of $0.330625 per unit per quarter. The maximum distribution of 50.0% does not include any distributions that Enable GP or its affiliates may receive on common units that they own. Expiration of Subordination Period Prior to the expiration of the subordination period, CenterPoint Energy and OGE Energy held 139,704,916 and 68,150,514 subordinated units, respectively. The financial tests required for conversion of all subordinated units were met and the 207,855,430 outstanding subordinated units converted into common units on a one -for-one basis on August 30, 2017. The conversion of the subordinated units did not change the aggregate amount of outstanding units, and the conversion of the subordinated units did not impact the amount of cash available for distribution by the Partnership. Series A Preferred Units The Partnership has 14,520,000 Series A Preferred Units, representing limited partner interests in the Partnership, which were issued at a price of $25.00 per Series A Preferred Unit. Pursuant to the Partnership Agreement , the Series A Preferred Units: • rank senior to the Partnership’s common units with respect to the payment of distributions and distribution of assets upon liquidation, dissolution and winding up; • have no stated maturity; • are not subject to any sinking fund; and • will remain outstanding indefinitely unless repurchased or redeemed by the Partnership or converted into its common units in connection with a change of control. Holders of the Series A Preferred Units receive a quarterly cash distribution on a non-cumulative basis if and when declared by the General Partner, and subject to certain adjustments, equal to an annual rate of: 10% on the stated liquidation preference of $25.00 from the date of original issue to, but not including, the five year anniversary of the original issue date; and thereafter a percentage of the stated liquidation preference equal to the sum of the three-month LIBOR plus 8.5% . At any time on or after February 18, 2021, the Partnership may redeem the Series A Preferred Units, in whole or in part, from any source of funds legally available for such purpose, by paying $25.50 per unit plus an amount equal to all accumulated and unpaid distributions thereon to the date of redemption, whether or not declared. Following changes of control or certain fundamental transactions , t he Partnership (or a third-party with its prior written consent) may redeem the Series A Preferred Units. If, upon a change of control or certain fundamental transactions, the Partnership (or a third-party with its prior written consent) does not exercise this option, then the holders of the Series A Preferred Units have the option to convert the Series A Preferred Units into a number of common units per Series A Preferred Unit as set forth in the Partnership Agreement . If under certain circumstances the Series A Preferred Units are not eligible for trading on the New York Stock Exchange, the Series A Preferred Units are required to be redeemed by the Partnership. In addition, the Partnership (or a third-party with its prior written consent) may redeem the Series A Preferred Units at any time following a reduction by any of the ratings agencies in the amount of equity content attributed to the Series A Preferred Units. On July 30, 2019, S&P announced that it was reclassifying the Series A Preferred Units from having 50% equity content to having minimal equity content. S&P’s announcement followed a revision of its criteria for evaluating the amount of equity credit attributable to hybrid securities. As a result the reduction of equity content attributed to the Series A Preferred Units by S&P, the Partnership may redeem the Series A Preferred Units at any time, upon not less than 30 days’ nor more than 60 days’ notice, at a price of $25.50 per Series A Preferred Unit plus an amount equal to all unpaid distributions thereon from the issuance date through the redemption date. Holders of Series A Preferred Units have no voting rights except for limited voting rights with respect to potential amendments to the Partnership Agreement that have a material adverse effect on the existing terms of the Series A Preferred Units, the issuance by the Partnership of certain securities, approval of certain fundamental transactions and as required by law. Upon the transfer of any Series A Preferred Unit to a non-affiliate of CenterPoint Energy, the Series A Preferred Units will automatically convert into a new series of preferred units (the Series B Preferred Units) on the later of the date of transfer and the second anniversary of the date of issue. The Series B Preferred Units will have the same terms as the Series A Preferred Units except that unpaid distributions on the Series B Preferred Units will accrue on a cumulative basis until paid. At the closing of the private placement of Series A Preferred Units, the Partnership entered into a registration rights agreement with CenterPoint Energy, pursuant to which, among other things, CenterPoint Energy has certain rights to require the Partnership to file and maintain a registration statement with respect to the resale of the Series A Preferred Units and any other series of preferred units or common units representing limited partner interests in the Partnership that are issuable upon conversion of the Series A Preferred Units. ATM Program On May 12, 2017, the Partnership entered into an ATM Equity Offering Sales Agreement in connection with an ATM Program. Pursuant to the ATM Program, the Partnership may issue and sell common units having an aggregate offering price of up to $200 million , by sales methods and at prices determined by market conditions and other factors at the time of our offerings. The Partnership has no obligation to sell any common units under the ATM Program and the Partnership may suspend sales under the ATM Program at any time. For the year ended December 31, 2019 , the Partnership did no t sell any common units under the ATM Program. For the year ended December 31, 2018 , the Partnership sold an aggregate of 140,920 common units under the ATM Program, which generated proceeds of approximately $2 million (net of approximately $25,000 of commissions). The proceeds were used for general partnership purposes. As of December 31, 2019 , approximately $197 million of common units of aggregate offering price remained available for issuance through the ATM Program.

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2019
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	Property, Plant and Equipment The Partnership completed a depreciation study for the Gathering and Processing and Transportation and Storage reportable 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. Property, plant and equipment includes the following: Weighted Average Useful Lives (Years) December 31, 2019 2018 (In millions) Property, plant and equipment, gross: Gathering and Processing 33 $ 8,252 $ 8,011 Transportation and Storage 39 4,778 4,740 Construction work-in-progress 131 148 Total $ 13,161 $ 12,899 Accumulated depreciation: Gathering and Processing 1,252 1,063 Transportation and Storage 1,039 965 Total accumulated depreciation 2,291 2,028 Property, plant and equipment, net $ 10,870 $ 10,871 The Partnership recorded depreciation expense of $371 million , $351 million and $335 million during the years ended December 31, 2019 , 2018 and 2017 , respectively.

Intangible Assets, Net

Intangible Assets, Net	12 Months Ended
	Dec. 31, 2019
Goodwill and Intangible Assets Disclosure [Abstract]
Intangible Assets, Net	Intangible Assets, Net The Partnership has intangible assets associated with customer relationships related to the acquisitions of Enogex LLC, Monarch Natural Gas, LLC, ETGP and EOCS as follows: December 31, 2019 2018 (In millions) Customer relationships: Total intangible assets (1) $ 840 $ 840 Accumulated amortization 239 177 Net intangible assets $ 601 $ 663 ____________________ (1) See Note 5 for discussion of the acquisition of EOCS and ETGP during the years ended December 31, 2018 and 2017, respectively. Intangible assets related to customer relationships have a weighted average useful life of 14 years. Intangible assets do not have any significant residual value or renewal options of existing terms. There are no intangible assets with indefinite useful lives. The Partnership recorded amortization expense of $62 million , $47 million and $31 million during the years ended December 31, 2019 , 2018 and 2017 , respectively. The following table summarizes the Partnership’s expected amortization of intangible assets for each of the next five years: 2020 2021 2022 2023 2024 (In millions) Expected amortization of intangible assets $ 62 $ 62 $ 62 $ 62 $ 62

Goodwill

Goodwill	12 Months Ended
	Dec. 31, 2019
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill	Goodwill In the fourth quarter of 2017, as a result of the acquisition of ETGP, the Partnership recorded $12 million of goodwill associated with the Ark-La-Tex Basin reporting unit, included in the gathering and processing reportable segment. In the fourth quarter of 2018, as a result of the acquisition of EOCS, the Partnership recorded $86 million of goodwill associated with the Anadarko Basin reporting unit, included in the gathering and processing reportable segment. The Partnership tests its goodwill for impairment annually on October 1st, or more frequently if events or changes in circumstances indicate that the carrying value of goodwill may not be recoverable. Goodwill is assessed for impairment by comparing the fair value of the reporting unit with its book value, including goodwill. During 2019, the crude oil and natural gas industry was impacted by current and forward commodity price declines. Amid such crude oil, natural gas and NGL price declines, producers have been cutting back spending and shifting their focus from emphasizing reserves growth, to increasing net cash flows and reducing outstanding debt, which consequently resulted in a decrease in rig count and in forecasted producer activity in the Anadarko Basin reporting unit during the fourth quarter of 2019. At the same time, unit prices and market multiples for midstream companies with gathering and processing operations have dropped to their lowest levels in the last three years. Due to the continuing decrease in forward commodity prices, the reduction in forecasted producer activities, the resulting decrease in our forecasted cash flows and the increase in the weighted average cost of capital, the Partnership determined that the fair value of the goodwill associated with our Anadarko Basin reporting unit would more likely than not be impaired. As a result, t he Partnership performed a quantitative test for our annual goodwill impairment analysis as of October 1, 2019, and determined that the carrying value of the Anadarko Basin reporting unit exceeded its fair value and that goodwill associated with the Anadarko Basin reporting unit was completely impaired in the amount of $86 million . The impairment is included in Impairments on the Consolidated Statements of Income for the year ended December 31, 2019 . While the fair value of the Ark-La-Tex Basin reporting unit exceeded its carrying value as of December 31, 2019 , a lower fair value estimate and an impairment of the Partnership’s $12 million of goodwill could result from sustained commodity price declines, throughput declines, contracted capacity declines, cost increases, regulatory or political environment changes and other changes in market conditions, such as decreased prices in market-based transactions for similar assets. The change in carrying amount of goodwill in each of our reportable segments is as follows: Gathering and Processing Transportation and Storage Total (in millions) Balance as of December 31, 2017 $ 12 $ — $ 12 EOCS Acquisition (1) 86 — 86 Balance as of December 31, 2018 $ 98 $ — $ 98 Goodwill impairment $ (86 ) $ — $ (86 ) Balance as of December 31, 2019 $ 12 $ — $ 12 _____________________ (1) See Note 5 for further discussion.

Investment in Equity Method Aff

Investment in Equity Method Affiliate	12 Months Ended
	Dec. 31, 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 for the years ended December 31, 2019 and 2018 . 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 limited partner 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. During the years ended December 31, 2019 , 2018 and 2017 , the Partnership billed SESH $17 million , $18 million and $17 million , respectively, associated with these service agreements. The Partnership includes equity in earnings of equity method affiliate under the Other Income (Expense) caption in the Consolidated Statements of Income for the years ended December 31, 2019 , 2018 and 2017 . SESH: Year Ended December 31, 2019 2018 2017 (In millions) Equity in Earnings of Equity Method Affiliate $ 17 $ 26 $ 28 Distributions from Equity Method Affiliate (1) 25 33 33 ____________________ (1) Distributions from equity method affiliate includes a $17 million , $26 million and $28 million return on investment and a $8 million , $7 million and $5 million return of investment for the years ended December 31, 2019 , 2018 and 2017 , respectively. Summarized financial information of SESH: December 31, 2019 2018 (In millions) Balance Sheets: Current assets $ 49 $ 30 Property, plant and equipment, net 1,060 1,078 Total assets $ 1,109 $ 1,108 Current liabilities $ 30 $ 13 Long-term debt 398 397 Members’ equity 681 698 Total liabilities and members’ equity $ 1,109 $ 1,108 Reconciliation: Investment in SESH $ 309 $ 317 Less: Capitalized interest on investment in SESH (1 ) (1 ) Add: Basis differential, net of amortization 33 33 The Partnership’s share of members’ equity $ 341 $ 349 Year Ended December 31, 2019 2018 2017 (In millions) Income Statements: Revenues $ 109 $ 112 $ 113 Operating income 50 67 72 Net income 33 50 54

Debt

Debt	12 Months Ended
	Dec. 31, 2019
Debt Disclosure [Abstract]
Debt	Debt The following table presents the Partnership’s outstanding debt as of December 31, 2019 and 2018 . December 31, 2019 December 31, 2018 Outstanding Principal Premium (Discount) (1) Total Debt Outstanding Principal Premium (Discount) (1) Total Debt (In millions) Commercial Paper $ 155 $ — $ 155 $ 649 $ — $ 649 Revolving Credit Facility — — — 250 — 250 2019 Term Loan Agreement 800 — 800 — — — 2019 Notes — — — 500 — 500 2024 Notes 600 — 600 600 — 600 2027 Notes 700 (2 ) 698 700 (2 ) 698 2028 Notes 800 (5 ) 795 800 (6 ) 794 2029 Notes 550 (1 ) 549 — — — 2044 Notes 550 — 550 550 — 550 EOIT Senior Notes 250 1 251 250 7 257 Total debt $ 4,405 $ (7 ) $ 4,398 $ 4,299 $ (1 ) $ 4,298 Less: Short-term debt (2) 155 649 Less: Current portion of long-term debt (3) 251 500 Less: Unamortized debt expense (4) 23 20 Total long-term debt $ 3,969 $ 3,129 ___________________ (1) Unamortized premium (discount) on long-term debt is amortized over the life of the respective debt. (2) Short-term debt includes $155 million and $649 million of commercial paper outstanding as of December 31, 2019 and 2018 , respectively. (3) As of December 31, 2019 , Current portion of long-term debt includes the $251 million outstanding balance of the EOIT Senior Notes due March 15, 2020. At December 31, 2018 , Current portion of long-term debt included the $500 million outstanding balance of the 2019 Notes due May 15, 2019. (4) As of December 31, 2019 and 2018 , there was an additional $4 million and $6 million , respectively, of unamortized debt expense related to the Revolving Credit Facility included in Other assets, not included above. Unamortized debt expense is amortized over the life of the respective debt. Maturities of outstanding debt, excluding unamortized premiums (discounts), are as follows (in millions): 2020 $ 405 2021 — 2022 800 2023 — 2024 600 Thereafter $ 2,600 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 $155 million and $649 million outstanding under our commercial paper program at December 31, 2019 and December 31, 2018 , respectively. The weighted average interest rate for the outstanding commercial paper was 2.29% as of December 31, 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 , five -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 December 31, 2019 , there were no principal advances and $3 million in letters of credit outstanding under the restated Revolving Credit Facility. The Revolving Credit Facility provides that outstanding borrowings bear interest at LIBOR and/or an alternate base rate, at the Partnership’s election, plus an applicable margin. The applicable margin is based on the Partnership’s designated credit ratings from S&P, Moody’s and Fitch Ratings. As of December 31, 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 applicable credit ratings. As of December 31, 2019 , the commitment fee under the Revolving Credit Facility was 0.20% per annum based on the Partnership’s credit ratings. The commitment fee is recorded as interest expense in the Partnership’s Consolidated Statements of Income. The Revolving Credit Facility contains a financial covenant requiring us to maintain a ratio of consolidated funded debt to consolidated EBITDA as defined under the Revolving Credit Facility as of the last day of each fiscal quarter of less than or equal to 5.00 to 1.00; provided that, for any three fiscal quarters including and following any fiscal quarter in which the aggregate value of one or more acquisitions by us or certain of our subsidiaries with a purchase price of at least $25 million in the aggregate, 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 Revolving Credit Facility also contains covenants that restrict us and certain 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 Revolving Credit Facility), restricted payments, changes in the nature of their respective businesses and entering into certain restrictive agreements. Borrowings under the Revolving Credit Facility are 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 money judgments in excess of $100 million and the occurrence of certain ERISA and bankruptcy events, subject where applicable to specified cure periods. 2019 Term Loan Agreement On January 29, 2019, the Partnership entered into an unsecured term loan agreement 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, subject to lender approval. 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 December 31, 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 December 31, 2019 , the weighted average interest rate of the 2019 Term Loan Agreement was 3.10% . Prior to the expiration of the availability period for advances on July 26, 2019, the Partnership drew $1 billion in advances under the Term Loan Agreement, which were used for general partnership purposes and repayment of the 2019 Notes. 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. On September 16, 2019, the Partnership prepaid $200 million of the advances under the Term Loan Agreement, the repayment of which was not subject to LIBOR breakage costs. As of December 31, 2019 , there was $800 million outstanding under the 2019 Term Loan Agreement. 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 On September 13, 2019, the Partnership completed the public offering of $550 million aggregate principal amount of its 4.150% Senior Notes due 2029. The Partnership received net proceeds of approximately $544 million , after deducting the underwriting discount and offering expenses. The net proceeds were used to repay $200 million of borrowings outstanding under the 2019 Term Loan Agreement, to repay amounts outstanding under the commercial paper program, and for general partnership purposes. The 2029 Notes had an unamortized discount of $1 million and unamortized debt expense of $5 million at December 31, 2019 , resulting in an effective interest rate of 4.31% from the issue date through December 31, 2019 . As of December 31, 2019 , the Partnership’s debt also included the 2024 Notes, 2027 Notes, 2028 Notes and 2044 Notes, which had $7 million of unamortized discount and $18 million of unamortized debt expense at December 31, 2019 , resulting in effective interest rates of 4.01% , 4.57% , 5.20% and 5.08% , respectively, during the year ended December 31, 2019 . In May 2019, the Partnership’s 2019 Notes matured and were paid using proceeds from the 2019 Term Loan Agreement. The indenture governing the 2024 Notes, 2027 Notes, 2028 Notes, 2029 Notes and 2044 Notes contains certain restrictions, including, among others, limitations on our ability and the ability of our principal subsidiaries to: (i) consolidate or merge and sell all or substantially all of our and our subsidiaries’ assets and properties; (ii) create, or permit to be created or to exist, any lien upon any of our or our principal subsidiaries’ principal property, or upon any shares of stock of any principal subsidiary, to secure any debt; and (iii) enter into certain sale-leaseback transactions. These covenants are subject to certain exceptions and qualifications. As of December 31, 2019 , the Partnership’s debt included EOIT’s Senior Notes. The EOIT Senior Notes had $1 million of unamortized premium at December 31, 2019 , resulting in an effective interest rate of 3.84% during the year ended December 31, 2019 . These senior notes do not contain any financial covenants other than a limitation on liens. This limitation on liens is subject to certain exceptions and qualifications. As of December 31, 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	12 Months Ended
	Dec. 31, 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 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 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 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 December 31, 2019 and 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 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 December 31, 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 the Partnership’s 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 December 31, 2019 and 2018 , the Partnership had the following derivative instruments that were not designated as hedging instruments for accounting purposes: December 31, 2019 December 31, 2018 Gross Notional Volume Purchases Sales Purchases Sales Natural gas— TBtu (1) Financial fixed futures/swaps 10 19 16 28 Financial basis futures/swaps 11 30 18 29 Financial swaptions (2) — 2 — 1 Physical purchases/sales — 6 — 11 Crude oil (for condensate)— MBbl (3) Financial futures/swaps — 990 — 945 Financial swaptions (2) — 225 — 30 Natural gas liquids— MBbl (4) Financial futures/swaps 2,490 2,415 270 2,535 ____________________ (1) As of December 31, 2019 , 86.6% of the natural gas contracts had durations of one year or less and 13.4% 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 value 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 December 31, 2019 , 72.8% of the crude oil (for condensate) contracts had durations of one year or less and 27.2% 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 December 31, 2019 , 72.2% of the natural gas liquids contracts had durations of one year or less and 27.8% had durations of more than one year and less than two years. As of December 31, 2018 , 86.1% of the natural gas liquids 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 derivative instruments designated as hedges for accounting purposes are interest rate derivative instruments priced on monthly interest rates. As of December 31, 2019 and December 31, 2018 , the Partnership had the following derivative instruments that were designated as hedging instruments for accounting purposes: December 31, 2019 December 31, 2018 Gross Notional Value (In millions) Interest rate swaps $ 300 $ — Balance Sheet Presentation Related to Derivative Instruments The fair value of the derivative instruments that are presented in the Partnership’s Consolidated Balance Sheets at December 31, 2019 and 2018 that were not designated as hedging instruments for accounting purposes are as follows: December 31, 2019 December 31, 2018 Fair Value Instrument Balance Sheet Location Assets Liabilities Assets Liabilities (In millions) Natural gas Financial futures/swaps Other Current $ 7 $ 5 $ 3 $ 5 Financial futures/swaps Other — 1 — 2 Physical purchases/sales Other Current 5 — 3 — Physical purchases/sales Other — — 4 — Crude oil (for condensate) Financial futures/swaps Other Current 1 19 9 3 Financial futures/swaps Other — 8 2 — Natural gas liquids Financial futures/swaps Other Current 25 3 10 1 Financial futures/swaps Other 11 2 2 — Total gross derivatives (1) $ 49 $ 38 $ 33 $ 11 _____________________ (1) See Note 14 for a reconciliation of the Partnership’s total derivatives fair value to the Partnership’s Consolidated Balance Sheets as of December 31, 2019 and 2018 . The fair value of the derivative instruments that are presented in the Partnership’s Consolidated Balance Sheets as of December 31, 2019 and December 31, 2018 that were designated as hedging instruments for accounting purposes are as follows: December 31, 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 December 31, 2019 . Income Statement Presentation Related to Derivative Instruments The following table presents the effect of derivative instruments on the Partnership’s Consolidated Statements of Income for the years ended December 31, 2019 , 2018 and 2017 : Amounts Recognized in Income Year Ended December 31, 2019 2018 2017 (In millions) Natural Gas Financial futures/swaps gains (losses) $ 13 $ (8 ) $ 20 Physical purchases/sales gains 2 7 9 Crude oil (for condensate) Financial futures/swaps (losses) gains (41 ) 6 (1 ) Natural gas liquids Financial futures/swaps gains (losses) 42 6 (9 ) Total $ 16 $ 11 $ 19 For derivatives not designated as hedges in the tables above, amounts recognized in income for the years ended December 31, 2019 , 2018 and 2017 are reported in Product sales. For derivatives designated as hedges, amounts recognized in income and reported in Interest expense for the year ended December 31, 2019 were approximately zero . The following table presents the components of gain (loss) on derivative activity in the Partnership’s Consolidated Statements of Income for the years ended December 31, 2019 , 2018 and 2017 : Year Ended December 31, 2019 2018 2017 (In millions) Change in fair value of derivatives $ (11 ) $ 26 $ 28 Realized gain (loss) on derivatives 27 (15 ) (9 ) Gain on derivative activity $ 16 $ 11 $ 19 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 or 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 December 31, 2019 , under these obligations, the Partnership has posted no cash collateral related to natural gas swaps and swaptions, crude oil swaps and swaptions, and NGL swaps 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	12 Months Ended
	Dec. 31, 2019
Fair Value Disclosures [Abstract]
Fair Value Measurements	Fair Value Measurements Certain assets and liabilities are recorded at fair value in the 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 December 31, 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 year ended December 31, 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 S& P’s 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 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 at December 31, 2019 and 2018 : December 31, 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) 800 800 — — 2019 Notes (Level 2) — — 500 497 2024 Notes (Level 2) 600 614 600 571 2027 Notes (Level 2) 698 698 698 642 2028 Notes (Level 2) 795 811 794 764 2029 Notes (Level 2) 549 526 — — 2044 Notes (Level 2) 550 506 550 445 EOIT Senior Notes (Level 2) 251 252 257 256 ______________________ (1) Borrowing capacity is effectively reduced by our borrowings outstanding under the commercial paper program. $155 million and $649 million of commercial paper was outstanding as of December 31, 2019 and 2018 , respectively. The fair value of the Partnership’s Revolving Credit Facility, 2019 Term Loan Agreement, 2019 Notes, 2024 Notes, 2027 Notes, 2028 Notes, 2029 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 December 31, 2019 , no material fair value adjustments or fair value measurements were required for these non-financial assets or liabilities. Based upon review of forecasted undiscounted cash flows as of December 31, 2019 , all of the asset groups were considered recoverable. Future price declines, throughput declines, contracted capacity declines, cost increases, regulatory or political environment changes and other changes in market conditions could reduce forecasted undiscounted cash flows. 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 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 December 31, 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 December 31, 2019 and December 31, 2018 : December 31, 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) $ 5 $ 31 $ — $ — Significant other observable inputs (Level 2) 44 7 14 11 Unobservable inputs (Level 3) — — — — Total fair value 49 38 14 11 Netting adjustments (37 ) (37 ) — — Total $ 12 $ 1 $ 14 $ 11 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 December 31, 2019 and 2018 . (2) Gas imbalance assets exclude fuel reserves for under retained fuel due from shippers of $21 million and $11 million at December 31, 2019 and 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 $8 million and $5 million at December 31, 2019 and 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. Changes in Level 3 Fair Value Measurements The following tables provides a reconciliation of changes in the fair value of our Level 3 commodity contracts between the periods presented. Transfers out of Level 3 represent liabilities that were previously classified as Level 3 for which the inputs became observable for classification in Level 2. Because the activity and liquidity of commodity markets vary substantially between regions and time periods, the availability of observable inputs for substantially the full term and value of the Partnership’s derivative contracts is subject to change. Commodity Contracts Natural gas liquids financial futures/swaps (In millions) Balance as of December 31, 2017 $ (5 ) Losses included in earnings (23 ) Settlements 7 Transfers out of Level 3 21 Balance as of December 31, 2018 $ — For the year ended December 31, 2019 , there were no Level 3 commodity contracts.

Supplemental Disclosure of Cash

Supplemental Disclosure of Cash Flow Information	12 Months Ended
	Dec. 31, 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: Year Ended December 31, 2019 2018 2017 (In millions) Supplemental Disclosure of Cash Flow Information: Cash Payments: Interest, net of capitalized interest $ 185 $ 148 $ 114 Income taxes, net of refunds 1 3 — Non-cash transactions: Accounts payable related to capital expenditures 10 54 39 Lease liabilities arising from the application of ASC 842 45 — — The following table reconciles cash and cash equivalents and restricted cash on the Consolidated Balance Sheets to cash, cash equivalents and restricted cash on the Consolidated Statements of Cash Flows: December 31, 2019 2018 (In millions) Cash and cash equivalents $ 4 $ 8 Restricted cash — 14 Cash, cash equivalents and restricted cash shown in the Consolidated Statement of Cash Flows $ 4 $ 22 As of December 31, 2018 , Restricted cash included $14 million of cash collateral which was provided by a third party as credit assurance. The cash collateral was released in 2019.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 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, firm no-notice transportation with storage and maximum rate firm transportation. The term of these contracts is through March 31, 2021. 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. The Partnership may agree to reimburse the costs that its customers incur to make required modifications for the repair and maintenance of pipelines that impact customer delivery points. For the years ended December 31, 2019 and 2018 , we reimbursed CenterPoint Energy’s LDCs $2 million and $1 million , respectively, in connection with receipt facility modifications that were necessitated by the repair and maintenance of our pipelines and in connection with a reimbursement associated with an unplanned pipeline outage. For the year ended December 31, 2017 , we reimbursed CenterPoint Energy’s LDCs $1 million in connection with receipt facility modifications that were necessitated by the repair and maintenance of our pipelines. Transportation and Storage Agreement with OGE Energy EOIT provides no-notice load-following transportation and storage services to four of OGE Energy’s generating facilities. Service is provided to three generating facilities under a transportation agreement with a primary term of April 1, 2019 through May 1, 2024, which 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. Service is provided to one additional generating facility in Muskogee, Oklahoma under a transportation agreement with a primary term of December 1, 2018 through December 1, 2038. EOIT has agreed to pay OGE Energy $2 million and to waive $5 million of demand fee charges as a result of damage that occurred to the Muskogee facility during commissioning as a result of the failure of certain filters on the connected transportation pipeline, which is included in the Partnership’s results of operations as of December 31, 2019. 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 6% , 5% and 5% of total revenues during the years ended December 31, 2019 , 2018 and 2017 , respectively. Amounts of total revenues from affiliated companies included in the Partnership’s Consolidated Statements of Income are summarized as follows: Year Ended December 31, 2019 2018 2017 (In millions) Gas transportation and storage service revenues — CenterPoint Energy $ 108 $ 111 $ 110 Natural gas product sales — CenterPoint Energy 8 11 6 Gas transportation and storage service revenues — OGE Energy 41 37 35 Natural gas product sales — OGE Energy 10 4 2 Total revenues — affiliated companies $ 167 $ 163 $ 153 Amounts of natural gas purchased from affiliated companies included in the Partnership’s Consolidated Statements of Income are summarized as follows: Year Ended December 31, 2019 2018 2017 (In millions) Cost of natural gas purchases — CenterPoint Energy $ — $ 3 $ 1 Cost of natural gas purchases — OGE Energy 33 23 19 Total cost of natural gas purchases — affiliated companies $ 33 $ 26 $ 20 Corporate services, operating lease expense and seconded employee 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 these 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. The Partnership leased office and data center space from an affiliate of CenterPoint Energy in Shreveport, Louisiana. The term of the lease was effective on October 1, 2016 and ended on December 31, 2019. During the years ended December 31, 2019 , 2018 and 2017 , the Partnership had certain employees who are participants under OGE Energy’s defined benefit and retiree medical plans, who will remain seconded to the Partnership, subject to certain termination rights of the Partnership and OGE Energy. The Partnership’s reimbursement of OGE Energy for 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. Amounts charged to the Partnership by affiliates for corporate services, operating lease and seconded employees, are primarily included in Operation and maintenance expenses and General and administrative expenses in the Partnership’s Consolidated Statements of Income are as follows: Year Ended December 31, 2019 2018 2017 (In millions) Corporate Services — CenterPoint Energy $ — $ 1 $ 3 Operating Lease — CenterPoint Energy 1 1 1 Seconded Employee Costs — OGE Energy 18 29 31 Corporate Services — OGE Energy — 1 3 Total corporate services, operating lease and seconded employee expense $ 19 $ 32 $ 38

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies Commercial Obligations 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, LP for 400 MMcf/d of deliveries to the Godley Plant in Johnson County, Texas. As of December 31, 2019 , the Partnership estimates the remaining associated minimum volume commitment fee to be $192 million in the aggregate. Minimum volume commitment fees are expected to be $23 million per year from 2020 through 2027 and $11 million in 2028 . 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 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 $500 million and the project is backed by a 20 -year firm transportation service. The Gulf Run Pipeline connects natural gas producing regions in the U.S., including the Haynesville, Marcellus, Utica and Barnett shales and the Mid-Continent region. The project is expected to be placed into service in 2022. On September 23, 2019, the Partnership entered into an agreement to sell its undivided 1/12th interest in the Bistineau Storage Facility in Louisiana for approximately $19 million . Until such time as the sale closes, the Partnership will continue to utilize this facility to provide storage services to its customers. On January 27, 2020, FERC approved the sale. The Partnership anticipates closing the sale on April 1, 2020. Legal, Regulatory and Other Matters The Partnership is involved in legal, environmental, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business. Some of these proceedings involve substantial amounts. The Partnership regularly analyzes current information and, as necessary, provides accruals for probable liabilities on the eventual disposition of these matters. The Partnership does not expect the disposition of these matters to have a material adverse effect on its financial condition, results of operations or cash flows.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes The Partnership’s earnings are generally not subject to income tax ( other than Texas state margin taxes and taxes associated with the Partnership’s corporate subsidiary Enable Midstream Services) and are taxable at the individual partner level. The Partnership and its non-corporate subsidiaries are pass-through entities for federal income tax purposes. For these entities, all income, expenses, gains, losses and tax credits generated flow through to their owners and, accordingly, do not result in a provision for income taxes in the consolidated financial statements. Consequently, the Consolidated Statements of Income do not include an income tax provision (other than Texas state margin taxes and taxes associated with the Partnership’s corporate subsidiary). On December 22, 2017, the act known as the “Tax Cuts and Jobs Act,” was signed into law which lowered the corporate tax rate from 35% to 21% for tax years beginning after December 31, 2017. As a result of this new law, the Partnership’s corporate subsidiaries re-valued their deferred income tax assets and liabilities as of December 31, 2017, which resulted in recording a federal deferred income tax benefit of $1 million for the year ended December 31, 2017. The items comprising income tax expense are as follows: Year Ended December 31, 2019 2018 2017 (In millions) Provision for current income taxes Federal $ — $ — $ 1 State — — 1 Total provision for current income taxes — — 2 Benefit for deferred income taxes, net Federal $ (1 ) $ (1 ) $ (2 ) State — — (1 ) Total benefit for deferred income taxes, net (1 ) (1 ) (3 ) Total income tax benefit $ (1 ) $ (1 ) $ (1 ) The components of Deferred Income Taxes as of December 31, 2019 and 2018 were as follows: December 31, 2019 2018 (In millions) Deferred tax liabilities, net: Non-current: Intercompany management fee $ 17 $ 16 Depreciation 6 5 Accrued compensation (19 ) (16 ) Total deferred tax liabilities, net $ 4 $ 5 Uncertain Income Tax Positions There were no unrecognized tax benefits as of December 31, 2019 , 2018 and 2017 . Tax Audits and Settlements The federal income tax return of the Partnership has been audited through the 2013 tax year.

Equity Based Compensation

Equity Based Compensation	12 Months Ended
	Dec. 31, 2019
Share-based Payment Arrangement [Abstract]
Equity Based Compensation	Equity-Based Compensation Enable GP has adopted the Enable Midstream Partners, LP Long Term Incentive Plan (LTIP) for officers, directors and employees of the Partnership and its affiliates, including any individual who provides services to the Partnership as a seconded employee . The LTIP provides for the following types of awards: restricted units, phantom units, appreciations rights, option rights, cash incentive awards, performance units, distribution equivalent rights, and other awards denominated in, payable in, valued in or otherwise based on or related to common units. The LTIP is administered by the Compensation Committee of the Board of Directors. With respect to any grant of equity as long-term incentive awards to our independent directors and our officers subject to reporting under Section 16 of the Exchange Act, the Compensation Committee makes recommendations to the Board of Directors and any such awards will only be effective upon the approval of the Board of Directors. The LTIP limits the number of units that may be delivered pursuant to vested awards to 13,100,000 common units, subject to proportionate adjustment in the event of unit splits and similar events. Common units cancelled, forfeited, expired or cash settled are available for delivery pursuant to other awards. The Board of Directors may terminate or amend the long-term incentive plan at any time with respect to any units for which a grant has not yet been made, including amending the long-term incentive plan to increase the number of units that may be granted subject to the requirements of the exchange upon which the common units are listed at that time. However, no change in any outstanding grant may be made that would be adverse to the participant without the consent of the participant. Performance unit, restricted unit and phantom unit awards are classified as equity on the Partnership’s Consolidated Balance Sheet. The following table summarizes the Partnership’s equity-based compensation expense for the years ended December 31, 2019 , 2018 and 2017 related to performance units, restricted units and phantom units for the Partnership’s employees and independent directors: Year Ended December 31, 2019 2018 2017 (In millions) Performance units $ 9 $ 9 $ 10 Restricted units — 1 2 Phantom units 7 6 3 Total equity-based compensation expense $ 16 $ 16 $ 15 Performance Units Awards of performance based phantom units (performance units) have been made under the LTIP in 2019 , 2018 and 2017 to certain officers and employees providing services to the Partnership. Subject to the achievement of performance goals, the performance unit awards cliff vest three years from the grant date, with distribution equivalent rights paid at vesting. The performance goals for 2019 , 2018 and 2017 awards are based on total unitholder return over a three -calendar year performance cycle. Total unitholder return is based on the relative performance of the Partnership’s common units against a peer group. The performance unit awards have a payout from zero to 200% of the target based on the level of achievement of the performance goal. Performance unit awards are paid out in common units, with distribution equivalent rights paid in cash at vesting. Any unearned performance units are cancelled. Pay out requires the confirmation of the achievement of the performance level by the Compensation Committee. Prior to vesting, performance units are subject to forfeiture if the recipient’s employment with the Partnership is terminated for any reason other than death, disability, retirement or termination other than for cause within two years of a change in control. In the event of retirement, a participant will receive a prorated payment based on the target performance or a prorated payment based on the actual performance of the performance goals during the award cycle, based on the grant year. The fair value of each performance unit award was estimated on the grant date using a lattice-based valuation model. The valuation information factored into the model includes the expected distribution yield, expected price volatility, risk-free interest rate and the probable outcome of the market condition over the expected life of the performance units. Equity-based compensation expense for each performance unit award is a fixed amount determined at the grant date fair value and is recognized over the three -year award cycle regardless of whether performance units are awarded at the end of the award cycle. Distributions are accumulated and paid at vesting and, therefore, are included in the fair value calculation of the performance unit award. The expected price volatility for the awards granted in 2019 , 2018 and 2017 is based on three years of daily stock price observations, to determine the total unitholder return ranking. The risk-free interest rate for the performance unit grants is based on the three -year U.S. Treasury yield curve in effect at the time of the grant. There are no post-vesting restrictions related to the Partnership’s performance units. The number of performance units granted based on total unitholder return and the assumptions used to calculate the grant date fair value of the performance units based on total unitholder return are shown in the following table. 2019 2018 2017 Number of units granted 638,798 551,742 468,626 Fair value of units granted $ 19.95 $ 17.70 $ 19.27 Expected price volatility 34.2 % 44.2 % 47.3 % Risk-free interest rate 2.54 % 2.36 % 1.57 % Distribution yield 8.38 % 8.56 % 9.10 % Expected life of units (in years) 3 3 3 Phantom Units Awards of phantom units have been made under the LTIP in 2019 , 2018 and 2017 to certain officers and employees providing services to the Partnership. Except for Phantom units granted to retirement eligible employees, which vest in annual tranches, phantom units cliff-vest on the first, second or third anniversary of the grant date with distribution equivalent rights paid during the vesting period. Phantom unit awards are paid out in common units, with distribution equivalent rights paid in cash. Any unearned phantom units are cancelled. Prior to vesting, phantom units are subject to forfeiture if the recipient’s employment with the Partnership is terminated for any reason other than death, disability, retirement or termination other than for cause within two years of a change in control. The fair value of the phantom units was based on the closing market price of the Partnership’s common unit on the grant date. Equity-based compensation expense for the phantom unit is a fixed amount determined at the grant date fair value and is recognized as services are rendered by employees over the vesting period. Distributions on phantom units are paid during the vesting period and, therefore, are included in the fair value calculation. The expected life of the phantom unit is based on the applicable vesting period. The number of phantom units granted and the grant date fair value are shown in the following table. 2019 2018 2017 Phantom units granted 695,486 546,708 392,338 Fair value of phantom units granted $8.95 - $15.04 $13.74 - $17.00 $15.44 - $16.93 Other Awards In 2019 , 2018 and 2017 , the Board of Directors granted common units to the independent directors of Enable GP, for their service as directors, which vested immediately. The fair value of the common units was based on the closing market price of the Partnership’s common unit on the grant date. 2019 2018 2017 Common units granted 28,221 16,335 16,653 Fair value of common units granted $ 10.43 $ 14.94 $ 15.03 Units Outstanding A summary of the activity for the Partnership’s performance units and phantom units as of December 31, 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 12/31/2018 2,109,835 $ 14.33 1,447,590 $ 12.38 Granted (1) 638,798 19.95 695,486 14.26 Vested (2)(3) (1,174,597 ) 11.09 (608,755 ) 8.71 Forfeited (180,707 ) 18.96 (141,761 ) 14.89 Units outstanding at 12/31/2019 1,393,329 19.04 1,392,560 14.65 Aggregate intrinsic value of units outstanding at December 31, 2019 $ 14 $ 14 _____________________ (1) For performance units, this 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 December 31, 2019 include 1,097,846 and 26,986 units from 2016 grants, which were approved by the Board of Directors in 2016 and paid out at 200% , or 2,195,692 units on March 1, 2019 and 53,972 units on September 6, 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. (3) Performance units outstanding as of December 31, 2019 include 378,109 units from the 2017 annual grants, which were approved by the Board of Directors in 2017 and, based on the level of achievement of a performance goal established by the Board of Directors over a performance period of January 1, 2017 through December 31, 2019, will no t vest. The decrease in outstanding units for a payout percentage of an amount other than 100% is not reflected above until the vesting date. A summary of the Partnership’s performance, restricted and phantom units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for each of the years ended December 31, 2019 , 2018 and 2017 are shown in the following tables. Year Ended December 31, 2019 Performance Units Restricted Stock Phantom Units (In millions) Aggregate intrinsic value of units vested $ 34 $ — $ 9 Fair value of units vested 13 — 5 Year Ended December 31, 2018 Performance Units Restricted Stock Phantom Units (In millions) Aggregate intrinsic value of units vested $ 11 $ 3 $ 1 Fair value of units vested 7 4 — Year Ended December 31, 2017 Performance Units Restricted Stock Phantom Units (In millions) Aggregate intrinsic value of units vested $ 5 $ 2 $ — Fair value of units vested 10 4 — Unrecognized Compensation Expense A summary of the Partnership’s unrecognized compensation expense 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. December 31, 2019 Unrecognized Compensation Cost (In millions) Weighted Average to be Recognized (In years) Performance Units $ 12 1.32 Phantom Units 9 1.24 Total $ 21 As of December 31, 2019 , there were 6,353,205 units available for issuance under the long-term incentive plan.

Reportable Segments

Reportable Segments	12 Months Ended
	Dec. 31, 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 wholesale or retail 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 described in Note 1 . 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 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. Financial data for reportable segments are as follows: Year Ended December 31, 2019 Gathering and Transportation (1) Eliminations Total (In millions) Product sales $ 1,449 $ 487 $ (403 ) $ 1,533 Service revenues 889 551 (13 ) 1,427 Total Revenues 2,338 1,038 (416 ) 2,960 Cost of natural gas and natural gas liquids, excluding depreciation and amortization shown separately 1,203 491 (415 ) 1,279 Operation and maintenance, General and administrative 320 207 (1 ) 526 Depreciation and amortization 308 125 — 433 Impairments 86 — — 86 Taxes other than income tax 41 26 — 67 Operating Income $ 380 $ 189 $ — $ 569 Total Assets $ 9,739 $ 5,886 $ (3,359 ) $ 12,266 Capital expenditures $ 314 $ 118 $ — $ 432 Year Ended December 31, 2018 Gathering and Transportation (1) Eliminations Total (In millions) Product sales $ 2,016 $ 625 $ (535 ) $ 2,106 Service revenues 802 537 (14 ) 1,325 Total Revenues 2,818 1,162 (549 ) 3,431 Cost of natural gas and natural gas liquids, excluding depreciation and amortization shown separately 1,741 628 (550 ) 1,819 Operation and maintenance, General and administrative 312 189 — 501 Depreciation and amortization 263 135 — 398 Impairments — — — — Taxes other than income tax 38 27 — 65 Operating Income $ 464 $ 183 $ 1 $ 648 Total Assets $ 9,874 $ 5,805 $ (3,235 ) $ 12,444 Capital expenditures, including acquisitions $ 981 $ 190 $ — $ 1,171 Year Ended December 31, 2017 Gathering and Processing Transportation and Storage (1) Eliminations Total (In millions) Product sales $ 1,538 $ 621 $ (506 ) $ 1,653 Service revenues 632 525 (7 ) 1,150 Total Revenues 2,170 1,146 (513 ) 2,803 Cost of natural gas and natural gas liquids, excluding depreciation and amortization shown separately 1,285 604 (508 ) 1,381 Operation and maintenance, General and administrative 289 179 (4 ) 464 Depreciation and amortization 232 134 — 366 Impairments — — — — Taxes other than income tax 37 27 — 64 Operating Income $ 327 $ 202 $ (1 ) $ 528 Total Assets $ 9,079 $ 5,616 $ (3,102 ) $ 11,593 Capital expenditures $ 601 $ 113 $ — $ 714 _____________________ (1) Equity in earnings of equity method affiliate is included in Other Income (Expense) on the Consolidated Statements of Income and is not included in the table above. See Note 11 for discussion regarding ownership interest in SESH and related equity earnings included in the transportation and storage reportable segment for the years ended December 31, 2019 , 2018 and 2017 .

Quarterly Financial Data (Unaud

Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2019
Quarterly Financial Information Disclosure [Abstract]
Quarterly Financial Data (Unaudited)	Quarterly Financial Data (Unaudited) Summarized unaudited quarterly financial data for 2019 and 2018 are as follows: Quarters Ended March 31, 2019 June 30, 2019 September 30, 2019 December 31, 2019 (in millions, except per unit data) Total Revenues $ 795 $ 735 $ 699 $ 731 Cost of natural gas and natural gas liquids 378 317 263 321 Operating income (1) 165 167 175 62 Net income 123 124 133 20 Net income attributable to limited partners 122 124 132 18 Net income attributable to common units 113 115 123 9 Basic earnings per unit Common units $ 0.26 $ 0.26 $ 0.28 $ 0.02 Diluted earnings per unit Common units $ 0.26 $ 0.26 $ 0.28 $ 0.02 Quarters Ended March 31, 2018 June 30, 2018 September 30, 2018 December 31, 2018 (in millions, except per unit data) Total Revenues $ 748 $ 805 $ 928 $ 950 Cost of natural gas and natural gas liquids 375 444 516 484 Operating income 139 126 171 212 Net income 114 95 139 175 Net income attributable to limited partners 114 95 138 174 Net income attributable to common units 105 86 129 165 Basic earnings per unit Common Units $ 0.24 $ 0.20 $ 0.30 $ 0.38 Diluted earnings per unit Common Units $ 0.24 $ 0.20 $ 0.30 $ 0.38 _____________________ (1) The Partnership recorded an impairment to goodwill of $86 million during the fourth quarter related to the Anadarko Basin reporting unit, included in the gathering and processing reportable segment. See Note 10

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization	Organization Enable Midstream Partners, LP (Partnership) is a Delaware limited partnership formed on May 1, 2013. The Partnership’s assets and operations are organized into two reportable segments: (i) gathering and processing and (ii) transportation and storage. The gathering and processing segment primarily provides natural gas and crude oil gathering and natural gas processing services to our producer customers. The transportation and storage segment provides interstate and intrastate natural gas pipeline transportation and storage services primarily to our producer, power plant, LDC and industrial end-user customers. The Partnership’s natural gas gathering and processing assets are primarily located in Oklahoma, Texas, Arkansas and Louisiana and serve natural gas production in the Anadarko, Arkoma and Ark-La-Tex Basins. Crude oil gathering assets are located in 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. At December 31, 2019 , CenterPoint Energy held approximately 53.7% 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. See Note 7 for further information related to the Series A Preferred Units. The limited partner interests of the Partnership have limited voting rights on matters affecting the business. As such, limited partners do not have rights to elect the Partnership’s General Partner (Enable GP) on an annual or continuing basis and may not remove Enable GP without at least a 75% vote by all unitholders, including all units held by the Partnership’s limited partners, and Enable GP and its affiliates, voting together as a single class. For the years ended December 31, 2019 , 2018 and 2017 , the Partnership owned a 50% interest in SESH. See Note 11 for further discussion of SESH. For the years ended December 31, 2019 , 2018 and 2017 , the Partnership held a 50% ownership interest in Atoka and consolidated Atoka in its Consolidated Financial Statements as EOIT acted as the managing member of Atoka and had control over the operations of Atoka. In addition, for the period November 1, 2018 through December 31, 2019 , the Partnership owned a 60% interest in ESCP, which is consolidated in its 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 consolidated financial statements and related notes of the Partnership have been prepared pursuant to the rules and regulations of the SEC and GAAP.
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.
Revenue Recognition	Revenue Recognition The Partnership generates the majority of its revenues from midstream energy services, including natural gas gathering, processing, transportation and storage and crude oil, condensate and produced water gathering. The Partnership performs these services under various contractual arrangements, which include fee-based contract arrangements and arrangements pursuant to which it purchases and resells commodities in connection with providing the related service and earns a net margin for its fee. The Partnership reflects revenue as Product sales and Service revenues on the Consolidated Statements of Income as follows: Product sales: Product sales represent the sale of natural gas, NGLs, crude oil and condensate where the product is purchased and used in connection with providing the Partnership’s midstream services. Service revenues: Service revenues represent all other revenue generated as a result of performing the Partnership’s midstream services. The Partnership recognizes revenue from natural gas gathering, processing, transportation and storage and crude oil, condensate and water gathering services to third parties in accordance with ASU No. 2014-09 “Revenue from Contracts with Customers” (Topic 606) upon its adoption on January 1, 2018. As the Partnership adopted using the modified retrospective method, revenue for all periods prior to January 1, 2018 were recognized in accordance with “Revenue Recognition” (Topic 605). Please see Note 3 for a description of the impact of adoption. Under Topic 606, revenue is recognized at an amount that reflects the consideration to which the entity expects to be entitled in exchange for transferring goods or services. The determination of that amount and the timing of recognition is based on identifying the contracts with customers, identifying the performance obligations in the contract, determining the transaction price, allocating the transaction price to the performance obligations in the contract, and ultimately recognizing revenue when (or as) the entity satisfies the performance obligation. Service revenues for gathering, processing, transportation and storage services for the Partnership are recorded each month as services have been completed and performance obligations are met. Product revenues are recognized when control is transferred. Monthly revenues are based on the current month’s estimated volumes, contracted prices (considering current commodity prices), historical seasonal fluctuations and any known adjustments. The estimates are reversed in the following month and customers are billed on actual volumes and contracted prices. Gas sales are calculated on current-month nominations and contracted prices. Revenues associated with the production of NGLs are estimated based on current-month estimated production and contracted prices. These amounts are reversed in the following month and the customers are billed on actual production and contracted prices. Estimated revenues are reflected in Accounts receivable, net or Accounts receivable—affiliated companies, as appropriate, on the Consolidated Balance Sheets and in Total revenues on the Consolidated Statements of Income. The Partnership records deferred revenue when it receives consideration from a third party before achieving certain criteria that must be met for revenue to be recognized in accordance with GAAP.
Natural Gas and Natural Gas Liquids Purchases	Natural Gas and Natural Gas Liquids Purchases Cost of natural gas and natural gas liquids represents the cost of our natural gas and natural gas liquids purchased exclusive of depreciation, Operation and maintenance and General and administrative expenses and consists primarily of product and fuel costs. Estimates for gas purchases are based on estimated volumes and contracted purchase prices. Estimated gas purchases are included in Accounts Payable or Accounts Payable-affiliated companies, as appropriate, on the Consolidated Balance Sheets and in Cost of natural gas and natural gas liquids, excluding Depreciation and amortization on the Consolidated Statements of Income.
Operation and Maintenance and General and Administrative Expense	Operation and Maintenance and General and Administrative Expense Operation and maintenance expense represents the cost of our service related revenues and consists primarily of labor expenses, lease costs, utility costs, insurance premiums and repairs and maintenance expenses directly related to the operations of assets. General and administrative expense represents cost incurred to manage the business. This expense includes cost of general corporate services, such as treasury, accounting, legal, information technology and human resources and all other expenses necessary or appropriate to the conduct of business. Any Operation and maintenance expense and General and administrative expense associated with product sales is immaterial.
Environmental Costs	Environmental Costs
Depreciation and Amortization	Depreciation and Amortization Expense Depreciation is computed using the straight-line method based on economic lives or a regulatory-mandated recovery period. Amortization of intangible assets is computed using the straight-line method over the respective lives of the intangible assets. The computation of depreciation expense requires judgment regarding the estimated useful lives and salvage value of assets at the time the assets are placed in service. As circumstances warrant, useful lives are adjusted when changes in planned use, changes in estimated production lives of affiliated natural gas basins or other factors indicate that a different life would be more appropriate. Such changes could materially impact future depreciation expense. Changes in useful lives that do not result in the impairment of an asset are recognized prospectively. The computation of amortization expense on intangible assets requires judgment regarding the amortization method used. Intangible assets are amortized on a straight-line basis over their useful lives using a method of amortization that reflects the pattern in which the economic benefits of the intangible asset are consumed.
Income Taxes	Income Taxes The Partnership’s earnings are not subject to income tax ( other than Texas state margin taxes and taxes associated with the Partnership’s corporate subsidiary Enable Midstream Services) and are taxable at the individual partner level. For more information, see Note 18 . We account for deferred income taxes related to the federal and state jurisdictions using the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the future taxes attributable to the difference between financial statement carrying amounts of assets and liabilities and their respective tax basis. Deferred tax assets are also recognized for the future tax benefits attributable to the expected utilization of tax net operating loss carryforwards. In the event future utilization is determined to be unlikely, a valuation allowance is provided to reduce the tax benefits from such assets. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the period in which the temporary differences and carryforwards are expected to be recovered or settled. The effect of a change in tax rates is recognized in the period which includes the enactment date. The Partnership recognizes interest and penalties as a component of income tax expense.
Cash and Cash Equivalents	Cash and Cash Equivalents The Partnership considers cash equivalents to be short-term, highly liquid investments with maturities of three
Restricted Cash	Restricted Cash
Accounts Receivable and Allowance for Doubtful Accounts	Accounts Receivable and Allowance for Doubtful Accounts
Inventory	Inventory Materials and supplies inventory is valued at cost and is subsequently recorded at the lower of cost or net realizable value. The Partnership recorded no write-downs to net realizable value related to materials and supplies inventory disposed or identified as excess or obsolete for each of the years ended December 31, 2019 and 2018 , and $1 million for the year ended December 31, 2017 . Materials and supplies are recorded to inventory when purchased and, as appropriate, subsequently charged to operation and maintenance expense on the Consolidated Statements of Income or capitalized to property, plant and equipment on the Consolidated Balance Sheets when installed. Natural gas inventory is held, through the transportation and storage reportable 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 reportable 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. During the years ended December 31, 2019 , 2018 and 2017 , the Partnership recorded write-downs to net realizable value related to natural gas and natural gas liquids inventory of $8 million , $4 million and $2 million , respectively. The cost of gas associated with sales of natural gas and natural gas liquids inventory is presented in Cost of natural gas and natural gas liquids, excluding depreciation and amortization on the Consolidated Statements of Income.
Gas Imbalances	Gas Imbalances Gas imbalances occur when the actual amounts of natural gas delivered from or received by the Partnership’s pipeline systems differ from the amounts scheduled to be delivered or received. Imbalances are due to or due from shippers and operators and can be settled in cash or natural gas depending on contractual terms. The Partnership values all imbalances at individual, or where appropriate an average of, current market indices applicable to the Partnership’s operations, not to exceed net realizable value.
Long-Lived Assets (including Intangible Assets) and Assessing Impairment of Long-lived Assets (including Intangible Assets) and Goodwill	Long-Lived Assets (including Intangible Assets) The Partnership records property, plant and equipment and intangible assets at historical cost. Newly constructed plant is added to plant balances at cost which includes contracted services, direct labor, materials, overhead, transportation costs and capitalized interest. Replacements of units of property are capitalized as plant. For assets that belong to a common plant account, the replaced plant is removed from plant balances and charged to Accumulated depreciation. For assets that do not belong to a common plant account, the replaced plant is removed from plant balances with the related accumulated depreciation and the remaining balance net of any salvage proceeds is recorded as a loss in the Consolidated Statements of Income as Operation and maintenance expense. The Partnership expenses repair and maintenance costs as incurred. Repair, removal and maintenance costs are included in the Consolidated Statements of Income as Operation and maintenance expense. Assessing Impairment of Long-lived Assets (including Intangible Assets) and Goodwill The Partnership periodically evaluates long-lived assets, including property, plant and equipment, and specifically identifiable intangibles other than goodwill, when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable. The determination of whether an impairment has occurred is based on an estimate of undiscounted cash flows attributable to the assets, as compared to the carrying value of the assets. For more information, see Note 14 . The Partnership assesses its goodwill for impairment annually on October 1st, or more frequently if events or changes in circumstances indicate that the carrying value of goodwill may not be recoverable. Goodwill is assessed for impairment by comparing the fair value of the reporting unit with its book value, including goodwill. The Partnership utilizes the market or income approaches to estimate the fair value of the reporting unit, also giving consideration to the alternative cost approach. Under the market approach, historical and current year forecasted cash flows are multiplied by a market multiple to determine fair value. Under the income approach, anticipated cash flows over a period of years plus a terminal value are discounted to present value using appropriate discount rates. The resulting fair value of the reporting unit is then compared to the carrying amount of the reporting unit and an impairment charge is recorded to goodwill for the difference. The Partnership performs its goodwill impairment testing at the reporting unit, which is one level below the transportation and storage and gathering and processing reportable segment level.
Regulatory Assets and Liabilities	Regulatory Assets and Liabilities
Capitalization of Interest and Allowance for Funds Used During Construction	Capitalization of Interest and Allowance for Funds Used During Construction
Derivative Instruments	Derivative Instruments The Partnership is exposed to various market risks. These risks arise from transactions entered into in the normal course of business. At times, the Partnership utilizes commodity derivative instruments such as physical forward contracts, financial futures and swaps to mitigate the impact of changes in commodity prices on its operating results and cash flows. Such derivatives are recognized in the Partnership’s Consolidated Balance Sheets at their fair value unless the Partnership elects hedge accounting or the normal purchase and sales exemption for qualified physical transactions. For commodity derivative instruments not designated as hedging instruments, the gain or loss on the derivative is recognized in Product sales in the Consolidated Statements of Income. A commodity derivative may be designated as a normal purchase or normal sale if the intent is to physically receive or deliver the product for use or sale in the normal course of business. At times, the Partnership utilizes interest rate derivative instruments such as swaps to mitigate the impact of changes in interest rates on its operating results and cash flows. Such derivatives are recognized in the Partnership’s Consolidated Balance Sheets at their fair value. For interest rate derivative instruments designated as cash flow hedging instruments, the gain or loss on the derivative is recognized in Accumulated other comprehensive loss and will be reclassified to Interest expense in the same period in which the hedged transaction is recognized in earnings. The Partnership’s policies prohibit the use of leveraged financial instruments. A leveraged financial instrument, for this purpose, is a transaction involving a derivative whose financial impact will be based on an amount other than the notional amount or volume of the instrument. 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 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 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 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 December 31, 2019 and 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 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 December 31, 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 the Partnership’s 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	Fair Value Measurements The Partnership determines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. As required, the Partnership utilizes valuation techniques that maximize the use of observable inputs (levels 1 and 2) and minimize the use of unobservable inputs (level 3) within the fair value hierarchy included in current accounting guidance. The Partnership generally applies the market approach to determine fair value. This method uses pricing and other information generated by market transactions for identical or comparable assets and liabilities. Assets and liabilities are classified within the fair value hierarchy based on the lowest level (least observable) input that is significant to the measurement in its entirety. Certain assets and liabilities are recorded at fair value in the 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 December 31, 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 year ended December 31, 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 S& P’s 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.
Equity Based Compensation	Equity-Based Compensation The Partnership awards equity-based compensation to officers, directors and employees under the Long-Term Incentive Plan. All equity-based awards to officers, directors and employees under the Long-Term Incentive Plan, including grants of performance units, time-based phantom units (phantom units) and time-based restricted units (restricted units) are recognized in the Consolidated Statements of Income based on their fair values. The fair value of the phantom units and restricted units are based on the closing market price of the Partnership’s common unit on the grant date. The fair value of the performance units is estimated on the grant date using a lattice-based valuation model that factors in information, including the expected distribution yield, expected price volatility, risk-free interest rate and the probable outcome of the market condition, over the expected life of the performance units. Compensation expense for the phantom unit and restricted unit awards is a fixed amount determined at the grant date fair value and is recognized as services are rendered by employees over a vesting period. The vesting of the performance unit awards is also contingent upon the probable outcome of the market condition. Depending on forfeitures and actual vesting, the compensation expense recognized related to the awards could increase or decrease.
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 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, although early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. The Partnership elected to adopt the guidance in ASU 2017-04 effective October 1, 2019, and as a result applied the new guidance to its annual goodwill impairment test performed as of October 1, 2019. The impairment resulting from the October 1, 2019 annual impairment test was based upon the amount by which the carrying amount exceeded the reporting unit’s fair value up to the actual amount of goodwill recorded for the Anadarko Basin reporting unit. 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 does not expect the adoption of this standard to have a material impact on our 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 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 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 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 Consolidated Financial Statements and related disclosures. Codification Improvements In April 2019, the FASB issued ASU No. 2019-04, “Codification Improvements to Topic 326, Financial Instruments-Credit Losses, Topic 815, Derivatives and Hedging, and Topic 825, Financial Instruments,” which clarifies and improves areas of guidance related to recently issued standards on credit losses, hedging and recognition and measurement. The standard is effective for interim and annual periods beginning after December 15, 2019. 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 Consolidated Financial Statements and related disclosures.
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 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 wholesale or retail 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 described in Note 1 . 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 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.

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Schedule of Inventory	The cost of gas associated with sales of natural gas and natural gas liquids inventory is presented in Cost of natural gas and natural gas liquids, excluding depreciation and amortization on the Consolidated Statements of Income. December 31, 2019 2018 (In millions) Materials and supplies $ 32 $ 31 Natural gas and natural gas liquids 14 19 Total Inventory $ 46 $ 50

Revenues (Tables)

Revenues (Tables)	12 Months Ended
	Dec. 31, 2019
Revenue from Contract with Customer [Abstract]
Disaggregation of Revenue	The following tables disaggregate total revenues by major source from contracts with customers and the gain on derivative activity for the years ended December 31, 2019 and 2018 . Year Ended December 31, 2019 Gathering and Transportation Eliminations Total (In millions) Revenues: Product sales: Natural gas $ 368 $ 464 $ (384 ) $ 448 Natural gas liquids 943 19 (19 ) 943 Condensate 126 — — 126 Total revenues from natural gas, natural gas liquids, and condensate 1,437 483 (403 ) 1,517 Gain on derivative activity 12 4 — 16 Total Product sales $ 1,449 $ 487 $ (403 ) $ 1,533 Service revenues: Demand revenues $ 274 $ 489 $ — $ 763 Volume-dependent revenues 615 62 (13 ) 664 Total Service revenues $ 889 $ 551 $ (13 ) $ 1,427 Total Revenues $ 2,338 $ 1,038 $ (416 ) $ 2,960 Year Ended December 31, 2018 Gathering and Transportation Eliminations Total (In millions) Revenues: Product sales: Natural gas $ 480 $ 590 $ (506 ) $ 564 Natural gas liquids 1,405 30 (30 ) 1,405 Condensate 126 — — 126 Total revenues from natural gas, natural gas liquids, and condensate 2,011 620 (536 ) 2,095 Gain on derivative activity 5 5 1 11 Total Product sales $ 2,016 $ 625 $ (535 ) $ 2,106 Service revenues: Demand revenues $ 252 $ 472 $ — $ 724 Volume-dependent revenues 550 65 (14 ) 601 Total Service revenues $ 802 $ 537 $ (14 ) $ 1,325 Total Revenues $ 2,818 $ 1,162 $ (549 ) $ 3,431
Schedule of Accounts Receivable	The following table summarizes the components of accounts receivable: December 31, December 31, (In millions) Accounts Receivable: Customers $ 239 $ 297 Contract assets (1) 18 6 Non-customers 12 6 Total Accounts Receivable (2) $ 269 $ 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 $6 million of contract assets related to firm 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 change in the contract liabilities for the year ended December 31, 2019 : December 31, December 31, Amounts recognized in revenues (In millions) Deferred revenues (1) $ 48 $ 48 $ 24 The table below summarizes the timing of recognition of these contract liabilities as of December 31, 2019 : 2020 2021 2022 2023 2024 and After (In millions) Deferred revenues (1) $ 25 $ 6 $ 6 $ 5 $ 6 ____________________ (1) Deferred revenues includes deferred revenue — affiliated companies. This amount is included in Other current liabilities and Other long-term liabilities.
Summary of Timing Recognition of Remaining Performance Obligations	The table below summarizes the timing of recognition of the remaining performance obligations as of December 31, 2019 : 2020 2021 2022 2023 2024 and After (In millions) Transportation and Storage (1) $ 461 $ 298 $ 238 $ 225 $ 699 Gathering and Processing 137 121 123 121 313 Total remaining performance obligations $ 598 $ 419 $ 361 $ 346 $ 1,012

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2019
Leases [Abstract]
Lease, Cost	The table below summarizes lease cost for the year ended December 31, 2019 : Year Ended December 31, 2019 Gathering and Transportation Total (In millions) Lease Cost: Operating lease cost $ 11 $ — $ 11 Short-term lease cost 22 2 24 Variable lease cost 1 — 1 Total Lease Cost $ 34 $ 2 $ 36
Lessee, Operating Lease, Liability, Maturity	Under ASC 842, as of December 31, 2019 , the Partnership has operating lease obligations expiring at various dates. The $4 million difference between undiscounted cash flows for operating leases and our $40 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, 2020 2021 2022 2023 2024 2025 and After Total (In millions) Noncancellable operating leases $ 11 $ 7 $ 6 $ 6 $ 4 $ 10 $ 44
Schedule of Future Minimum Rental Payments for Operating Leases	s of December 31, 2018 , the Partnership had the following future minimum payments for operating lease obligations as follows : Year Ended December 31, 2019 2020-2021 2022-2023 After 2023 Total (In millions) Noncancellable operating leases $ 14 $ 6 $ 6 $ 14 $ 40

Acquisitions (Tables)

Acquisitions (Tables)	12 Months Ended
	Dec. 31, 2019
Business Combinations [Abstract]
Schedule of Assets Acquired and Liabilities Assumed	The following table presents the fair value of the identified assets acquired and liabilities assumed at the acquisition date: Purchase price allocation (in millions): Assets acquired: Cash $ 1 Current Assets 3 Property, plant and equipment 124 Intangibles 259 Goodwill 86 Liabilities assumed: Current liabilities 1 Less: Noncontrolling interest at fair value 28 Total identifiable net assets $ 444 The following table presents the fair value of the identified assets acquired and liabilities assumed at the acquisition date: Purchase price allocation (in millions): Assets acquired: Accounts receivable $ 5 Property, plant and equipment 111 Intangibles 176 Goodwill 12 Liabilities assumed: Current liabilities 6 Total identifiable net assets $ 298

Earnings Per Limited Partner _2

Earnings Per Limited Partner Unit (Tables)	12 Months Ended
	Dec. 31, 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 and subordinated units: Year Ended December 31, 2019 2018 2017 (In millions, except per unit data) Net income $ 400 $ 523 $ 437 Net income attributable to noncontrolling interests 4 2 1 Series A Preferred Unit distributions 36 36 36 General partner interest in net income — — — Net income available to common and subordinated units $ 360 $ 485 $ 400 Net income allocable to common units $ 360 $ 485 $ 273 Net income allocable to subordinated units — — 127 Net income available to common and subordinated units $ 360 $ 485 $ 400 Net income allocable to common units $ 360 $ 485 $ 273 Dilutive effect of Series A Preferred Unit distribution — — — Diluted net income allocable to common units 360 485 273 Diluted net income allocable to subordinated units — — 127 Total $ 360 $ 485 $ 400 Basic weighted average number of outstanding Common units (1) 436 434 296 Subordinated units — — 137 Total 436 434 433 Basic earnings per unit Common units $ 0.83 $ 1.12 $ 0.92 Subordinated units $ — $ — $ 0.93 Basic weighted average number of outstanding common units (1) 436 434 296 Dilutive effect of Series A Preferred Units — — — Dilutive effect of performance units 1 2 1 Diluted weighted average number of outstanding common units 437 436 297 Diluted weighted average number of outstanding subordinated units — — 137 Total 437 436 434 Diluted earnings per unit Common units $ 0.82 $ 1.11 $ 0.92 Subordinated units $ — $ — $ 0.93 ____________________ (1) Basic weighted average number of outstanding common units for the years ended December 31, 2019 , 2018 , and 2017 includes approximately one million time-based phantom units.

Partners' Equity (Tables)

Partners' Equity (Tables)	12 Months Ended
	Dec. 31, 2019
Equity [Abstract]
Schedule Of Equity Transactions With Limited Partner	The Partnership paid or has authorized payment of the following cash distributions to common and subordinated unitholders, as applicable, during 2019 , 2018 and 2017 (in millions, except for per unit amounts): Quarter Ended Record Date Payment Date Per Unit Distribution Total Cash Distribution 2019 December 31, 2019 (1) February 18, 2020 February 25, 2020 $ 0.3305 $ 144 September 30, 2019 November 19, 2019 November 26, 2019 $ 0.3305 $ 144 June 30, 2019 August 20, 2019 August 27, 2019 $ 0.3305 $ 144 March 31, 2019 May 21, 2019 May 29, 2019 $ 0.318 $ 138 2018 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 2017 December 31, 2017 February 20, 2018 February 27, 2018 $ 0.318 $ 138 September 30, 2017 November 14, 2017 November 21, 2017 $ 0.318 $ 138 June 30, 2017 August 22, 2017 August 29, 2017 $ 0.318 $ 138 March 31, 2017 May 23, 2017 May 30, 2017 $ 0.318 $ 137 _____________________ (1) The Board of Directors declared a $0.3305 per common unit cash distribution on February 7, 2020 , to be paid on February 25, 2020 , to common unitholders of record at the close of business on February 18, 2020 .
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 2019 , 2018 , and 2017 (in millions, except for per unit amounts): Quarter Ended Record Date Payment Date Per Unit Distribution Total Cash Distribution 2019 December 31, 2019 (1) February 7, 2020 February 14, 2020 $ 0.625 $ 9 September 30, 2019 November 5, 2019 November 14, 2019 $ 0.625 $ 9 June 30, 2019 August 2, 2019 August 14, 2019 $ 0.625 $ 9 March 31, 2019 April 29, 2019 May 15, 2019 $ 0.625 $ 9 2018 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 2017 December 31, 2017 February 9, 2018 February 15, 2018 $ 0.625 $ 9 September 30, 2017 October 31, 2017 November 14, 2017 $ 0.625 $ 9 June 30, 2017 July 31, 2017 August 14, 2017 $ 0.625 $ 9 March 31, 2017 May 2, 2017 May 12, 2017 $ 0.625 $ 9 _____________________ (1) The Board of Directors declared a $0.625 per Series A Preferred Unit cash distribution on February 7, 2020 , to be paid on February 14, 2020 to Series A Preferred unitholders of record at the close of business on February 7, 2020 .

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2019
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	Property, plant and equipment includes the following: Weighted Average Useful Lives (Years) December 31, 2019 2018 (In millions) Property, plant and equipment, gross: Gathering and Processing 33 $ 8,252 $ 8,011 Transportation and Storage 39 4,778 4,740 Construction work-in-progress 131 148 Total $ 13,161 $ 12,899 Accumulated depreciation: Gathering and Processing 1,252 1,063 Transportation and Storage 1,039 965 Total accumulated depreciation 2,291 2,028 Property, plant and equipment, net $ 10,870 $ 10,871

Intangible Assets, Net (Tables)

Intangible Assets, Net (Tables)	12 Months Ended
	Dec. 31, 2019
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of Finite-Lived Intangible Assets	The Partnership has intangible assets associated with customer relationships related to the acquisitions of Enogex LLC, Monarch Natural Gas, LLC, ETGP and EOCS as follows: December 31, 2019 2018 (In millions) Customer relationships: Total intangible assets (1) $ 840 $ 840 Accumulated amortization 239 177 Net intangible assets $ 601 $ 663 ____________________ (1) See Note 5 for discussion of the acquisition of EOCS and ETGP during the years ended December 31, 2018 and 2017, respectively.
Schedule of Finite-Lived Intangible Assets, Future Amortization Expense	The following table summarizes the Partnership’s expected amortization of intangible assets for each of the next five years: 2020 2021 2022 2023 2024 (In millions) Expected amortization of intangible assets $ 62 $ 62 $ 62 $ 62 $ 62

Goodwill (Tables)

Goodwill (Tables)	12 Months Ended
	Dec. 31, 2019
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of Goodwill	The change in carrying amount of goodwill in each of our reportable segments is as follows: Gathering and Processing Transportation and Storage Total (in millions) Balance as of December 31, 2017 $ 12 $ — $ 12 EOCS Acquisition (1) 86 — 86 Balance as of December 31, 2018 $ 98 $ — $ 98 Goodwill impairment $ (86 ) $ — $ (86 ) Balance as of December 31, 2019 $ 12 $ — $ 12 _____________________ (1) See Note 5 for further discussion.

Investment in Equity Method A_2

Investment in Equity Method Affiliate (Tables)	12 Months Ended
	Dec. 31, 2019
Equity Method Investments and Joint Ventures [Abstract]
Schedule of Investments Detail	SESH: Year Ended December 31, 2019 2018 2017 (In millions) Equity in Earnings of Equity Method Affiliate $ 17 $ 26 $ 28 Distributions from Equity Method Affiliate (1) 25 33 33 ____________________ (1) Distributions from equity method affiliate includes a $17 million , $26 million and $28 million return on investment and a $8 million , $7 million and $5 million return of investment for the years ended December 31, 2019 , 2018 and 2017 , respectively. Summarized financial information of SESH: December 31, 2019 2018 (In millions) Balance Sheets: Current assets $ 49 $ 30 Property, plant and equipment, net 1,060 1,078 Total assets $ 1,109 $ 1,108 Current liabilities $ 30 $ 13 Long-term debt 398 397 Members’ equity 681 698 Total liabilities and members’ equity $ 1,109 $ 1,108 Reconciliation: Investment in SESH $ 309 $ 317 Less: Capitalized interest on investment in SESH (1 ) (1 ) Add: Basis differential, net of amortization 33 33 The Partnership’s share of members’ equity $ 341 $ 349 Year Ended December 31, 2019 2018 2017 (In millions) Income Statements: Revenues $ 109 $ 112 $ 113 Operating income 50 67 72 Net income 33 50 54

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2019
Debt Disclosure [Abstract]
Schedule of Debt	The following table presents the Partnership’s outstanding debt as of December 31, 2019 and 2018 . December 31, 2019 December 31, 2018 Outstanding Principal Premium (Discount) (1) Total Debt Outstanding Principal Premium (Discount) (1) Total Debt (In millions) Commercial Paper $ 155 $ — $ 155 $ 649 $ — $ 649 Revolving Credit Facility — — — 250 — 250 2019 Term Loan Agreement 800 — 800 — — — 2019 Notes — — — 500 — 500 2024 Notes 600 — 600 600 — 600 2027 Notes 700 (2 ) 698 700 (2 ) 698 2028 Notes 800 (5 ) 795 800 (6 ) 794 2029 Notes 550 (1 ) 549 — — — 2044 Notes 550 — 550 550 — 550 EOIT Senior Notes 250 1 251 250 7 257 Total debt $ 4,405 $ (7 ) $ 4,398 $ 4,299 $ (1 ) $ 4,298 Less: Short-term debt (2) 155 649 Less: Current portion of long-term debt (3) 251 500 Less: Unamortized debt expense (4) 23 20 Total long-term debt $ 3,969 $ 3,129 ___________________ (1) Unamortized premium (discount) on long-term debt is amortized over the life of the respective debt. (2) Short-term debt includes $155 million and $649 million of commercial paper outstanding as of December 31, 2019 and 2018 , respectively. (3) As of December 31, 2019 , Current portion of long-term debt includes the $251 million outstanding balance of the EOIT Senior Notes due March 15, 2020. At December 31, 2018 , Current portion of long-term debt included the $500 million outstanding balance of the 2019 Notes due May 15, 2019. (4) As of December 31, 2019 and 2018 , there was an additional $4 million and $6 million , respectively, of unamortized debt expense related to the Revolving Credit Facility included in Other assets, not included above. Unamortized debt expense is amortized over the life of the respective debt.
Schedule of Maturities of Long-term Debt	Maturities of outstanding debt, excluding unamortized premiums (discounts), are as follows (in millions): 2020 $ 405 2021 — 2022 800 2023 — 2024 600 Thereafter $ 2,600

Derivative Instruments and He_2

Derivative Instruments and Hedging Activities (Tables)	12 Months Ended
	Dec. 31, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Derivative Instruments	As of December 31, 2019 and December 31, 2018 , the Partnership had the following derivative instruments that were designated as hedging instruments for accounting purposes: December 31, 2019 December 31, 2018 Gross Notional Value (In millions) Interest rate swaps $ 300 $ — As of December 31, 2019 and 2018 , the Partnership had the following derivative instruments that were not designated as hedging instruments for accounting purposes: December 31, 2019 December 31, 2018 Gross Notional Volume Purchases Sales Purchases Sales Natural gas— TBtu (1) Financial fixed futures/swaps 10 19 16 28 Financial basis futures/swaps 11 30 18 29 Financial swaptions (2) — 2 — 1 Physical purchases/sales — 6 — 11 Crude oil (for condensate)— MBbl (3) Financial futures/swaps — 990 — 945 Financial swaptions (2) — 225 — 30 Natural gas liquids— MBbl (4) Financial futures/swaps 2,490 2,415 270 2,535 ____________________ (1) As of December 31, 2019 , 86.6% of the natural gas contracts had durations of one year or less and 13.4% 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 value 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 December 31, 2019 , 72.8% of the crude oil (for condensate) contracts had durations of one year or less and 27.2% 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 December 31, 2019 , 72.2% of the natural gas liquids contracts had durations of one year or less and 27.8% had durations of more than one year and less than two years. As of December 31, 2018 , 86.1% of the natural gas liquids contracts had durations of one year or less and 13.9% had durations of more than one year and less than two years.
Schedule of Derivative Assets at Fair Value	The fair value of the derivative instruments that are presented in the Partnership’s Consolidated Balance Sheets at December 31, 2019 and 2018 that were not designated as hedging instruments for accounting purposes are as follows: December 31, 2019 December 31, 2018 Fair Value Instrument Balance Sheet Location Assets Liabilities Assets Liabilities (In millions) Natural gas Financial futures/swaps Other Current $ 7 $ 5 $ 3 $ 5 Financial futures/swaps Other — 1 — 2 Physical purchases/sales Other Current 5 — 3 — Physical purchases/sales Other — — 4 — Crude oil (for condensate) Financial futures/swaps Other Current 1 19 9 3 Financial futures/swaps Other — 8 2 — Natural gas liquids Financial futures/swaps Other Current 25 3 10 1 Financial futures/swaps Other 11 2 2 — Total gross derivatives (1) $ 49 $ 38 $ 33 $ 11 _____________________ (1) See Note 14 for a reconciliation of the Partnership’s total derivatives fair value to the Partnership’s Consolidated Balance Sheets as of December 31, 2019 and 2018 . The fair value of the derivative instruments that are presented in the Partnership’s Consolidated Balance Sheets as of December 31, 2019 and December 31, 2018 that were designated as hedging instruments for accounting purposes are as follows: December 31, 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 December 31, 2019 .
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 Consolidated Statements of Income for the years ended December 31, 2019 , 2018 and 2017 : Year Ended December 31, 2019 2018 2017 (In millions) Change in fair value of derivatives $ (11 ) $ 26 $ 28 Realized gain (loss) on derivatives 27 (15 ) (9 ) Gain on derivative activity $ 16 $ 11 $ 19 The following table presents the effect of derivative instruments on the Partnership’s Consolidated Statements of Income for the years ended December 31, 2019 , 2018 and 2017 : Amounts Recognized in Income Year Ended December 31, 2019 2018 2017 (In millions) Natural Gas Financial futures/swaps gains (losses) $ 13 $ (8 ) $ 20 Physical purchases/sales gains 2 7 9 Crude oil (for condensate) Financial futures/swaps (losses) gains (41 ) 6 (1 ) Natural gas liquids Financial futures/swaps gains (losses) 42 6 (9 ) Total $ 16 $ 11 $ 19

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 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 at December 31, 2019 and 2018 : December 31, 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) 800 800 — — 2019 Notes (Level 2) — — 500 497 2024 Notes (Level 2) 600 614 600 571 2027 Notes (Level 2) 698 698 698 642 2028 Notes (Level 2) 795 811 794 764 2029 Notes (Level 2) 549 526 — — 2044 Notes (Level 2) 550 506 550 445 EOIT Senior Notes (Level 2) 251 252 257 256
Schedule of Assets and Liabilities Measured at Fair Value on a Recurring Basis	December 31, 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) $ 5 $ 31 $ — $ — Significant other observable inputs (Level 2) 44 7 14 11 Unobservable inputs (Level 3) — — — — Total fair value 49 38 14 11 Netting adjustments (37 ) (37 ) — — Total $ 12 $ 1 $ 14 $ 11 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 December 31, 2019 and 2018 . (2) Gas imbalance assets exclude fuel reserves for under retained fuel due from shippers of $21 million and $11 million at December 31, 2019 and 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 $8 million and $5 million at December 31, 2019 and 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.
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation	The following tables provides a reconciliation of changes in the fair value of our Level 3 commodity contracts between the periods presented. Transfers out of Level 3 represent liabilities that were previously classified as Level 3 for which the inputs became observable for classification in Level 2. Because the activity and liquidity of commodity markets vary substantially between regions and time periods, the availability of observable inputs for substantially the full term and value of the Partnership’s derivative contracts is subject to change. Commodity Contracts Natural gas liquids financial futures/swaps (In millions) Balance as of December 31, 2017 $ (5 ) Losses included in earnings (23 ) Settlements 7 Transfers out of Level 3 21 Balance as of December 31, 2018 $ —

Supplemental Disclosure of Ca_2

Supplemental Disclosure of Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2019
Supplemental Cash Flow Information [Abstract]
Schedule of Cash Flow, Supplemental Disclosures	The following table provides information regarding supplemental cash flow information: Year Ended December 31, 2019 2018 2017 (In millions) Supplemental Disclosure of Cash Flow Information: Cash Payments: Interest, net of capitalized interest $ 185 $ 148 $ 114 Income taxes, net of refunds 1 3 — Non-cash transactions: Accounts payable related to capital expenditures 10 54 39 Lease liabilities arising from the application of ASC 842 45 — —
Schedule of Restricted Cash and Cash Equivalents	The following table reconciles cash and cash equivalents and restricted cash on the Consolidated Balance Sheets to cash, cash equivalents and restricted cash on the Consolidated Statements of Cash Flows: December 31, 2019 2018 (In millions) Cash and cash equivalents $ 4 $ 8 Restricted cash — 14 Cash, cash equivalents and restricted cash shown in the Consolidated Statement of Cash Flows $ 4 $ 22 As of December 31, 2018 , Restricted cash included $14 million of cash collateral which was provided by a third party as credit assurance. The cash collateral was released in 2019.

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2019
Related Party Transactions [Abstract]
Schedule of Revenues from Related Parties	Amounts of total revenues from affiliated companies included in the Partnership’s Consolidated Statements of Income are summarized as follows: Year Ended December 31, 2019 2018 2017 (In millions) Gas transportation and storage service revenues — CenterPoint Energy $ 108 $ 111 $ 110 Natural gas product sales — CenterPoint Energy 8 11 6 Gas transportation and storage service revenues — OGE Energy 41 37 35 Natural gas product sales — OGE Energy 10 4 2 Total revenues — affiliated companies $ 167 $ 163 $ 153
Schedule of Natural Gas Purchased From Related Parties	Amounts of natural gas purchased from affiliated companies included in the Partnership’s Consolidated Statements of Income are summarized as follows: Year Ended December 31, 2019 2018 2017 (In millions) Cost of natural gas purchases — CenterPoint Energy $ — $ 3 $ 1 Cost of natural gas purchases — OGE Energy 33 23 19 Total cost of natural gas purchases — affiliated companies $ 33 $ 26 $ 20
Schedule of Amounts Charged to Partnership by Related Parties	Amounts charged to the Partnership by affiliates for corporate services, operating lease and seconded employees, are primarily included in Operation and maintenance expenses and General and administrative expenses in the Partnership’s Consolidated Statements of Income are as follows: Year Ended December 31, 2019 2018 2017 (In millions) Corporate Services — CenterPoint Energy $ — $ 1 $ 3 Operating Lease — CenterPoint Energy 1 1 1 Seconded Employee Costs — OGE Energy 18 29 31 Corporate Services — OGE Energy — 1 3 Total corporate services, operating lease and seconded employee expense $ 19 $ 32 $ 38

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Schedule of Components of Income Tax Expense (Benefit)	The items comprising income tax expense are as follows: Year Ended December 31, 2019 2018 2017 (In millions) Provision for current income taxes Federal $ — $ — $ 1 State — — 1 Total provision for current income taxes — — 2 Benefit for deferred income taxes, net Federal $ (1 ) $ (1 ) $ (2 ) State — — (1 ) Total benefit for deferred income taxes, net (1 ) (1 ) (3 ) Total income tax benefit $ (1 ) $ (1 ) $ (1 )
Schedule of Deferred Tax Assets and Liabilities	The components of Deferred Income Taxes as of December 31, 2019 and 2018 were as follows: December 31, 2019 2018 (In millions) Deferred tax liabilities, net: Non-current: Intercompany management fee $ 17 $ 16 Depreciation 6 5 Accrued compensation (19 ) (16 ) Total deferred tax liabilities, net $ 4 $ 5

Equity Based Compensation (Tabl

Equity Based Compensation (Tables)	12 Months Ended
	Dec. 31, 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 years ended December 31, 2019 , 2018 and 2017 related to performance units, restricted units and phantom units for the Partnership’s employees and independent directors: Year Ended December 31, 2019 2018 2017 (In millions) Performance units $ 9 $ 9 $ 10 Restricted units — 1 2 Phantom units 7 6 3 Total equity-based compensation expense $ 16 $ 16 $ 15
Schedule of Valuation Assumptions	The number of performance units granted based on total unitholder return and the assumptions used to calculate the grant date fair value of the performance units based on total unitholder return are shown in the following table. 2019 2018 2017 Number of units granted 638,798 551,742 468,626 Fair value of units granted $ 19.95 $ 17.70 $ 19.27 Expected price volatility 34.2 % 44.2 % 47.3 % Risk-free interest rate 2.54 % 2.36 % 1.57 % Distribution yield 8.38 % 8.56 % 9.10 % Expected life of units (in years) 3 3 3
Phantom Units, Grants in Period And Grant Date Fair Value	The number of phantom units granted and the grant date fair value are shown in the following table. 2019 2018 2017 Phantom units granted 695,486 546,708 392,338 Fair value of phantom units granted $8.95 - $15.04 $13.74 - $17.00 $15.44 - $16.93
Common units, Grants in Period and Grant Date Fair Value	The fair value of the common units was based on the closing market price of the Partnership’s common unit on the grant date. 2019 2018 2017 Common units granted 28,221 16,335 16,653 Fair value of common units granted $ 10.43 $ 14.94 $ 15.03
Schedule of Share-based Compensation, Activity	A summary of the activity for the Partnership’s performance units and phantom units as of December 31, 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 12/31/2018 2,109,835 $ 14.33 1,447,590 $ 12.38 Granted (1) 638,798 19.95 695,486 14.26 Vested (2)(3) (1,174,597 ) 11.09 (608,755 ) 8.71 Forfeited (180,707 ) 18.96 (141,761 ) 14.89 Units outstanding at 12/31/2019 1,393,329 19.04 1,392,560 14.65 Aggregate intrinsic value of units outstanding at December 31, 2019 $ 14 $ 14 _____________________ (1) For performance units, this 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 December 31, 2019 include 1,097,846 and 26,986 units from 2016 grants, which were approved by the Board of Directors in 2016 and paid out at 200% , or 2,195,692 units on March 1, 2019 and 53,972 units on September 6, 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. (3) Performance units outstanding as of December 31, 2019 include 378,109 units from the 2017 annual grants, which were approved by the Board of Directors in 2017 and, based on the level of achievement of a performance goal established by the Board of Directors over a performance period of January 1, 2017 through December 31, 2019, will no t vest. The decrease in outstanding units for a payout percentage of an amount other than 100% is not reflected above until the vesting date. A summary of the Partnership’s performance, restricted and phantom units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for each of the years ended December 31, 2019 , 2018 and 2017 are shown in the following tables. Year Ended December 31, 2019 Performance Units Restricted Stock Phantom Units (In millions) Aggregate intrinsic value of units vested $ 34 $ — $ 9 Fair value of units vested 13 — 5 Year Ended December 31, 2018 Performance Units Restricted Stock Phantom Units (In millions) Aggregate intrinsic value of units vested $ 11 $ 3 $ 1 Fair value of units vested 7 4 — Year Ended December 31, 2017 Performance Units Restricted Stock Phantom Units (In millions) Aggregate intrinsic value of units vested $ 5 $ 2 $ — Fair value of units vested 10 4 —
Schedule of Unrecognized Compensation Cost, Nonvested Awards	A summary of the Partnership’s unrecognized compensation expense 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. December 31, 2019 Unrecognized Compensation Cost (In millions) Weighted Average to be Recognized (In years) Performance Units $ 12 1.32 Phantom Units 9 1.24 Total $ 21

Reportable Segments (Tables)

Reportable Segments (Tables)	12 Months Ended
	Dec. 31, 2019
Segment Reporting [Abstract]
Schedule of Financial Data for Business Segments and Services	Financial data for reportable segments are as follows: Year Ended December 31, 2019 Gathering and Transportation (1) Eliminations Total (In millions) Product sales $ 1,449 $ 487 $ (403 ) $ 1,533 Service revenues 889 551 (13 ) 1,427 Total Revenues 2,338 1,038 (416 ) 2,960 Cost of natural gas and natural gas liquids, excluding depreciation and amortization shown separately 1,203 491 (415 ) 1,279 Operation and maintenance, General and administrative 320 207 (1 ) 526 Depreciation and amortization 308 125 — 433 Impairments 86 — — 86 Taxes other than income tax 41 26 — 67 Operating Income $ 380 $ 189 $ — $ 569 Total Assets $ 9,739 $ 5,886 $ (3,359 ) $ 12,266 Capital expenditures $ 314 $ 118 $ — $ 432 Year Ended December 31, 2018 Gathering and Transportation (1) Eliminations Total (In millions) Product sales $ 2,016 $ 625 $ (535 ) $ 2,106 Service revenues 802 537 (14 ) 1,325 Total Revenues 2,818 1,162 (549 ) 3,431 Cost of natural gas and natural gas liquids, excluding depreciation and amortization shown separately 1,741 628 (550 ) 1,819 Operation and maintenance, General and administrative 312 189 — 501 Depreciation and amortization 263 135 — 398 Impairments — — — — Taxes other than income tax 38 27 — 65 Operating Income $ 464 $ 183 $ 1 $ 648 Total Assets $ 9,874 $ 5,805 $ (3,235 ) $ 12,444 Capital expenditures, including acquisitions $ 981 $ 190 $ — $ 1,171 Year Ended December 31, 2017 Gathering and Processing Transportation and Storage (1) Eliminations Total (In millions) Product sales $ 1,538 $ 621 $ (506 ) $ 1,653 Service revenues 632 525 (7 ) 1,150 Total Revenues 2,170 1,146 (513 ) 2,803 Cost of natural gas and natural gas liquids, excluding depreciation and amortization shown separately 1,285 604 (508 ) 1,381 Operation and maintenance, General and administrative 289 179 (4 ) 464 Depreciation and amortization 232 134 — 366 Impairments — — — — Taxes other than income tax 37 27 — 64 Operating Income $ 327 $ 202 $ (1 ) $ 528 Total Assets $ 9,079 $ 5,616 $ (3,102 ) $ 11,593 Capital expenditures $ 601 $ 113 $ — $ 714 _____________________ (1) Equity in earnings of equity method affiliate is included in Other Income (Expense) on the Consolidated Statements of Income and is not included in the table above. See Note 11 for discussion regarding ownership interest in SESH and related equity earnings included in the transportation and storage reportable segment for the years ended December 31, 2019 , 2018 and 2017 .

Quarterly Financial Data (Una_2

Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2019
Quarterly Financial Information Disclosure [Abstract]
Schedule of Quarterly Financial Information	Summarized unaudited quarterly financial data for 2019 and 2018 are as follows: Quarters Ended March 31, 2019 June 30, 2019 September 30, 2019 December 31, 2019 (in millions, except per unit data) Total Revenues $ 795 $ 735 $ 699 $ 731 Cost of natural gas and natural gas liquids 378 317 263 321 Operating income (1) 165 167 175 62 Net income 123 124 133 20 Net income attributable to limited partners 122 124 132 18 Net income attributable to common units 113 115 123 9 Basic earnings per unit Common units $ 0.26 $ 0.26 $ 0.28 $ 0.02 Diluted earnings per unit Common units $ 0.26 $ 0.26 $ 0.28 $ 0.02 Quarters Ended March 31, 2018 June 30, 2018 September 30, 2018 December 31, 2018 (in millions, except per unit data) Total Revenues $ 748 $ 805 $ 928 $ 950 Cost of natural gas and natural gas liquids 375 444 516 484 Operating income 139 126 171 212 Net income 114 95 139 175 Net income attributable to limited partners 114 95 138 174 Net income attributable to common units 105 86 129 165 Basic earnings per unit Common Units $ 0.24 $ 0.20 $ 0.30 $ 0.38 Diluted earnings per unit Common Units $ 0.24 $ 0.20 $ 0.30 $ 0.38 _____________________ (1) The Partnership recorded an impairment to goodwill of $86 million during the fourth quarter related to the Anadarko Basin reporting unit, included in the gathering and processing reportable segment. See Note 10

Summary of Significant Accoun_4

Summary of Significant Accounting Policies - Narrative (Details)		2 Months Ended	3 Months Ended																12 Months Ended
		Dec. 31, 2018USD ($)	Dec. 31, 2019USD ($)board_membershares		Sep. 30, 2019USD ($)	[1]	Jun. 30, 2019USD ($)	[1]	Mar. 31, 2019USD ($)	[1]	Dec. 31, 2018USD ($)		Sep. 30, 2018USD ($)	[1]	Jun. 30, 2018USD ($)	[1]	Mar. 31, 2018USD ($)	[1]	Dec. 31, 2019USD ($)board_membersegmentshares	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)
Significant Accounting Policies [Line Items]
Number of reportable segments | segment																			2
Number of representatives designated by each of CenterPoint Energy and OGE Energy | board_member			2																2
Number of independent board members | board_member			3																3
Minimum percentage of vote required by all unitholders																			75.00%
Total Revenues			$ 731,000,000	[1]	$ 699,000,000		$ 735,000,000		$ 795,000,000		$ 950,000,000	[1]	$ 928,000,000		$ 805,000,000		$ 748,000,000		$ 2,960,000,000	$ 3,431,000,000	$ 2,803,000,000
Environmental exit costs		$ 0									0									0
Cash and cash equivalents		8,000,000	4,000,000								8,000,000								4,000,000	8,000,000
Restricted cash		14,000,000	0								14,000,000								0	14,000,000
Allowance for doubtful accounts receivable		2,000,000	2,000,000								2,000,000								2,000,000	2,000,000
Regulatory liabilities		$ 23,000,000	$ 24,000,000								$ 23,000,000								24,000,000	23,000,000
AFUDC, capitalized interest																			$ 2,000,000	6,000,000	1,000,000
Participant contribution percentage, maximum																			70.00%
Employer matching contribution percentage																			100.00%
Employer matching contribution percentage, percent of participant's eligible compensation																			6.00%
Partnership contributions																			$ 20,000,000	19,000,000	18,000,000
Materials and Supplies
Significant Accounting Policies [Line Items]
Write down of materials and supplies inventory																			0	0	1,000,000
Natural gas
Significant Accounting Policies [Line Items]
Write down of materials and supplies inventory																			$ 8,000,000	$ 4,000,000	$ 2,000,000
SESH
Significant Accounting Policies [Line Items]
Limited partner ownership percentage interest																				50.00%	50.00%
Ownership percentage			50.00%																50.00%
Total revenue | Customer Concentration Risk
Significant Accounting Policies [Line Items]
Concentration risk percentage																			11.00%	0.00%	0.00%
Total Revenues																			$ 328,000,000
CenterPoint | Common Units
Significant Accounting Policies [Line Items]
Units outstanding (in units) | shares			233,856,623																233,856,623
OGE Energy | Common Units
Significant Accounting Policies [Line Items]
Units outstanding (in units) | shares			110,982,805																110,982,805
Atoka
Significant Accounting Policies [Line Items]
Limited partner ownership percentage interest																			50.00%
Limited Partner | CenterPoint
Significant Accounting Policies [Line Items]
Percentage share of management rights			50.00%																50.00%
Percentage share of incentive distribution rights			40.00%																40.00%
Limited partner ownership percentage interest																			53.70%
Limited Partner | CenterPoint | Series A 10% Fixed to Floating Non Cumulative Redeemable Perpetual Preferred Units
Significant Accounting Policies [Line Items]
Preferred units issued | shares			14,520,000																14,520,000
Limited Partner | OGE Energy
Significant Accounting Policies [Line Items]
Percentage share of management rights			50.00%																50.00%
Percentage share of incentive distribution rights			60.00%																60.00%
Limited partner ownership percentage interest																			25.50%
Third Party One | Volume of natural gas liquids | Customer Concentration Risk
Significant Accounting Policies [Line Items]
Concentration risk percentage																			12.00%	12.00%	13.00%
Third Party One | Total revenue | Customer Concentration Risk
Significant Accounting Policies [Line Items]
Concentration risk percentage																			4.00%	6.00%	5.00%
Total Revenues	[1]																		$ 131,000,000	$ 214,000,000	$ 140,000,000
Third Party Two | Volume of natural gas liquids | Customer Concentration Risk
Significant Accounting Policies [Line Items]
Concentration risk percentage																			12.00%	8.00%	12.00%
Third Party Two | Total revenue | Customer Concentration Risk
Significant Accounting Policies [Line Items]
Concentration risk percentage																			4.00%	4.00%	4.00%
Total Revenues	[1]																		$ 119,000,000	$ 152,000,000	$ 127,000,000
VPP
Significant Accounting Policies [Line Items]
Limited partner ownership percentage interest		60.00%
Defined Benefit And Retiree Medical Plans | OGE Energy
Significant Accounting Policies [Line Items]
Reimbursement of benefits																			$ 3,000,000	$ 3,000,000	$ 5,000,000
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Summary of Significant Accoun_5

Summary of Significant Accounting Policies - Inventory (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Materials and supplies	$ 32	$ 31
Natural gas and natural gas liquids	14	19
Total Inventory	$ 46	$ 50

Revenues - Disaggregation of Re

Revenues - Disaggregation of Revenue (Details) - USD ($) $ in Millions	3 Months Ended																12 Months Ended
	Dec. 31, 2019	[1]	Sep. 30, 2019	[1]	Jun. 30, 2019	[1]	Mar. 31, 2019	[1]	Dec. 31, 2018	[1]	Sep. 30, 2018	[1]	Jun. 30, 2018	[1]	Mar. 31, 2018	[1]	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Disaggregation of Revenue [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate																	$ 1,517	$ 2,095
Gain (loss) on derivative activity																	16	11	$ 19
Total Revenues	$ 731		$ 699		$ 735		$ 795		$ 950		$ 928		$ 805		$ 748		2,960	3,431	2,803
Natural gas
Disaggregation of Revenue [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate																	448	564
Natural gas liquids
Disaggregation of Revenue [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate																	943	1,405
Condensate Natural Gas
Disaggregation of Revenue [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate																	126	126
Product
Disaggregation of Revenue [Line Items]
Total Revenues																	1,533	2,106	1,653
Demand Service Revenue
Disaggregation of Revenue [Line Items]
Total Revenues																	763	724
Volume Dependant Service Revenue
Disaggregation of Revenue [Line Items]
Total Revenues																	664	601
Natural Gas, Gathering, Transportation, Marketing and Processing
Disaggregation of Revenue [Line Items]
Total Revenues																	1,427	1,325	1,150
Operating Segments | Gathering and Processing
Disaggregation of Revenue [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate																	1,437	2,011
Gain (loss) on derivative activity																	12	5
Total Revenues																	2,338	2,818	2,170
Operating Segments | Gathering and Processing | Natural gas
Disaggregation of Revenue [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate																	368	480
Operating Segments | Gathering and Processing | Natural gas liquids
Disaggregation of Revenue [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate																	943	1,405
Operating Segments | Gathering and Processing | Condensate Natural Gas
Disaggregation of Revenue [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate																	126	126
Operating Segments | Gathering and Processing | Product
Disaggregation of Revenue [Line Items]
Total Revenues																	1,449	2,016	1,538
Operating Segments | Gathering and Processing | Demand Service Revenue
Disaggregation of Revenue [Line Items]
Total Revenues																	274	252
Operating Segments | Gathering and Processing | Volume Dependant Service Revenue
Disaggregation of Revenue [Line Items]
Total Revenues																	615	550
Operating Segments | Gathering and Processing | Natural Gas, Gathering, Transportation, Marketing and Processing
Disaggregation of Revenue [Line Items]
Total Revenues																	889	802	632
Operating Segments | Transportation and Storage
Disaggregation of Revenue [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate																	483	620
Gain (loss) on derivative activity																	4	5
Total Revenues																	1,038	1,162	1,146
Operating Segments | Transportation and Storage | Natural gas
Disaggregation of Revenue [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate																	464	590
Operating Segments | Transportation and Storage | Natural gas liquids
Disaggregation of Revenue [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate																	19	30
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
Operating Segments | Transportation and Storage | Product
Disaggregation of Revenue [Line Items]
Total Revenues																	487	625	621
Operating Segments | Transportation and Storage | Demand Service Revenue
Disaggregation of Revenue [Line Items]
Total Revenues																	489	472
Operating Segments | Transportation and Storage | Volume Dependant Service Revenue
Disaggregation of Revenue [Line Items]
Total Revenues																	62	65
Operating Segments | Transportation and Storage | Natural Gas, Gathering, Transportation, Marketing and Processing
Disaggregation of Revenue [Line Items]
Total Revenues																	551	537	525
Eliminations
Disaggregation of Revenue [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate																	(403)	(536)
Gain (loss) on derivative activity																	0	1
Total Revenues																	(416)	(549)	(513)
Eliminations | Natural gas
Disaggregation of Revenue [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate																	(384)	(506)
Eliminations | Natural gas liquids
Disaggregation of Revenue [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate																	(19)	(30)
Eliminations | Condensate Natural Gas
Disaggregation of Revenue [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate																	0	0
Eliminations | Product
Disaggregation of Revenue [Line Items]
Total Revenues																	(403)	(535)	(506)
Eliminations | Demand Service Revenue
Disaggregation of Revenue [Line Items]
Total Revenues																	0	0
Eliminations | Volume Dependant Service Revenue
Disaggregation of Revenue [Line Items]
Total Revenues																	(13)	(14)
Eliminations | Natural Gas, Gathering, Transportation, Marketing and Processing
Disaggregation of Revenue [Line Items]
Total Revenues																	$ (13)	$ (14)	$ (7)
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Revenues - Accounts Receivable

Revenues - Accounts Receivable (Details) - USD ($) $ in Millions		Dec. 31, 2019	Dec. 31, 2018
Disaggregation of Revenue [Line Items]
Customers		$ 239	$ 297
Contract assets	[1]	18	6
Non-customers		12	6
Total Accounts Receivable	[2]	269	$ 309
Firm Service Transportation [Member]
Disaggregation of Revenue [Line Items]
Contract assets		$ 6
[1]	(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 $6 million of contract assets related to firm transportation contracts with tiered rates, which are reflected in Other Assets.
[2]	(2) Total Accounts Receivable includes Accounts receivables, net of allowance for doubtful accounts and Accounts receivable—affiliated companies.

Revenues - Summary of Changes i

Revenues - Summary of Changes in Contract Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Deferred revenues	$ 48
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	$ 24

Revenues - Summary of Recogniti

Revenues - Summary of Recognition Contract Liabilities (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)
Revenue from Contract with Customer [Abstract]
2020	$ 25
2021	6
2022	6
2023	5
2024 and After	$ 6

Revenues - Summary of Recogni_2

Revenues - Summary of Recognition of Remaining Performance Obligations (Details) $ in Millions	Dec. 31, 2019USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total remaining performance obligations	$ 598
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01 | Transportation and Storage
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total remaining performance obligations	461
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01 | Gathering and Processing
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total remaining performance obligations	137
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total remaining performance obligations	419
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01 | Transportation and Storage
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total remaining performance obligations	298
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01 | Gathering and Processing
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total remaining performance obligations	121
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total remaining performance obligations	361
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01 | Transportation and Storage
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total remaining performance obligations	238
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01 | Gathering and Processing
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total remaining performance obligations	123
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total remaining performance obligations	346
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01 | Transportation and Storage
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total remaining performance obligations	225
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01 | Gathering and Processing
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total remaining performance obligations	121
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total remaining performance obligations	1,012
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | Transportation and Storage
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total remaining performance obligations	699
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | Gathering and Processing
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total remaining performance obligations	$ 313

Leases - Narrative (Details)

Leases - Narrative (Details) $ in Millions	12 Months Ended			87 Months Ended	96 Months Ended
	Dec. 31, 2019USD ($)ft²agreement	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Jun. 30, 2019USD ($)	Dec. 31, 2025USD ($)	Jan. 01, 2019USD ($)	Aug. 28, 2018ft²
Lessee, Lease, Description [Line Items]
Operating lease right-of-use asset	$ 40					$ 35
Weighted average remaining lease term	6 years 4 months 24 days
Weighted average discount rate	5.40%
Lease cost	$ 36
Difference between undiscounted cash flows for operation leases	4
Lease payments due	$ 40
Number of compression service agreements | agreement	86
Number of compression service agreements on month to month basis | agreement	71
Number of compression service agreements expiring next twelve months | agreement	15
Number of gas treating agreements | agreement	9
Number of gas treating lease agreements on month to month basis | agreement	7
Number of gas treating lease agreements expiring in 2021 | agreement	1
Number of gas treating lease agreements expiring in 2022 | agreement	1
Rental expense		$ 35	$ 27
Equipment
Lessee, Lease, Description [Line Items]
Lease cost	$ 29
Building
Lessee, Lease, Description [Line Items]
Renewal options (up to)	15 years
Lease cost	$ 7
Maximum | Equipment
Lessee, Lease, Description [Line Items]
Expected lease term (in years)	5 years
Lease term	3 years
Maximum | Building
Lessee, Lease, Description [Line Items]
Lease term	10 years
Minimum | Equipment
Lessee, Lease, Description [Line Items]
Expected lease term (in years)	3 years
Lease term	1 year
Minimum | Building
Lessee, Lease, Description [Line Items]
Lease term	7 years
Other Assets
Lessee, Lease, Description [Line Items]
Operating lease right-of-use asset	$ 37
Other Current Liabilities
Lessee, Lease, Description [Line Items]
Current obligations	9
Other Liabilities
Lessee, Lease, Description [Line Items]
Other obligations	$ 31
Principal executive offices
Lessee, Lease, Description [Line Items]
Lease payments				$ 19
Area of office space (in square feet) | ft²	162,053
Houston, Texas
Lessee, Lease, Description [Line Items]
Area of office space (in square feet) | ft²	48,642
Bank of Oklahoma Park Plaza
Lessee, Lease, Description [Line Items]
Area of office space (in square feet) | ft²							154,584
Lease payments due	$ 25
Minimum lease payments in next year	1
Lease payments per year thereafter	$ 2
Scenario, Forecast | Houston, Texas
Lessee, Lease, Description [Line Items]
Lease payments					$ 4

Leases - Summary of Lease Expen

Leases - Summary of Lease Expense (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)
Lessee, Lease, Description [Line Items]
Operating lease cost	$ 11
Short-term lease cost	24
Variable lease cost	1
Total Lease Cost	36
Gathering and Processing
Lessee, Lease, Description [Line Items]
Operating lease cost	11
Short-term lease cost	22
Variable lease cost	1
Total Lease Cost	34
Transportation and Storage
Lessee, Lease, Description [Line Items]
Operating lease cost	0
Short-term lease cost	2
Variable lease cost	0
Total Lease Cost	$ 2

Leases - Schedule of Operating

Leases - Schedule of Operating Lease Obligations Expiration (Details) $ in Millions	Dec. 31, 2019USD ($)
Leases [Abstract]
2020	$ 11
2021	7
2022	6
2023	6
2024	4
2025 and After	10
Total	$ 44

Leases - Operating Lease Obliga

Leases - Operating Lease Obligation under ASC 840 (Details) $ in Millions	Dec. 31, 2019USD ($)
Leases [Abstract]
2019	$ 14
2020-2021	6
2022-2023	6
After 2023	14
Total	$ 40

Acquisitions - Narrative (Detai

Acquisitions - Narrative (Details) $ in Millions	Nov. 01, 2018USD ($)mi	Oct. 04, 2017USD ($)	Dec. 31, 2019	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)
General and Administrative Expense
Business Acquisition [Line Items]
Acquisition costs associated with the transaction (less than $1 million)				$ 6
Velocity Holdings, LLC
Business Acquisition [Line Items]
Aggregate purchase price	$ 444
Percentage of Pipeline System Acquired	60.00%
Number of miles in pipeline system acquired | mi	26
Less: Noncontrolling interest at fair value	$ 28
Align Midstream, LLC
Business Acquisition [Line Items]
Aggregate purchase price		$ 298
Align Midstream, LLC | General and Administrative Expense
Business Acquisition [Line Items]
Acquisition costs associated with the transaction (less than $1 million)					$ 2
Customer Relationships
Business Acquisition [Line Items]
Weighted average useful life (in years)			14 years
Customer Relationships | Velocity Holdings, LLC
Business Acquisition [Line Items]
Weighted average useful life (in years)				15 years
Customer Relationships | Align Midstream, LLC
Business Acquisition [Line Items]
Weighted average useful life (in years)		10 years

Acquisitions - Schedule of Asse

Acquisitions - Schedule of Assets and Liabilities Assumed (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018	Nov. 01, 2018	Dec. 31, 2017	Oct. 04, 2017
Assets acquired:
Goodwill	$ 12	$ 98		$ 12
Velocity Holdings, LLC
Business Acquisition [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Cash and Equivalents			$ 1
Assets acquired:
Accounts receivable			3
Property, plant and equipment			124
Other intangible assets			259
Goodwill			86
Liabilities assumed:
Current liabilities			1
Less: Noncontrolling interest at fair value			28
Total identifiable net assets			$ 444
Align Midstream, LLC
Assets acquired:
Accounts receivable					$ 5
Property, plant and equipment					111
Other intangible assets					176
Goodwill					12
Liabilities assumed:
Current liabilities					6
Total identifiable net assets					$ 298

Earnings Per Limited Partner _3

Earnings Per Limited Partner Unit (Details) - USD ($) $ / shares in Units, shares in Millions		3 Months Ended								12 Months Ended
		Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net income		$ 20,000,000	$ 133,000,000	$ 124,000,000	$ 123,000,000	$ 175,000,000	$ 139,000,000	$ 95,000,000	$ 114,000,000	$ 400,000,000	$ 523,000,000	$ 437,000,000
Net income attributable to noncontrolling interests										4,000,000	2,000,000	1,000,000
Series A Preferred Unit distributions										36,000,000	36,000,000	36,000,000
General partner interest in net income										0	0	0
Net Income Attributable to Common and Subordinated Units (Note 6)		$ 9,000,000	$ 123,000,000	$ 115,000,000	$ 113,000,000	$ 165,000,000	$ 129,000,000	$ 86,000,000	$ 105,000,000	360,000,000	485,000,000	400,000,000
Dilutive effect of Series A Preferred Unit distribution										0	0	0
Diluted net income (loss)										$ 360,000,000	$ 485,000,000	$ 400,000,000
Basic weighted average number of outstanding
Basic weighted average number of outstanding										436	434	433
Basic earnings (loss) per unit
Diluted weighted average number of outstanding units										437	436	434
Common Units
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net Income Attributable to Common and Subordinated Units (Note 6)										$ 360,000,000	$ 485,000,000	$ 273,000,000
Diluted net income (loss)										$ 360,000,000	$ 485,000,000	$ 273,000,000
Basic weighted average number of outstanding
Basic weighted average number of outstanding	[1]									436	434	296
Basic earnings (loss) per unit
Basic earnings (loss) per unit		$ 0.02	$ 0.28	$ 0.26	$ 0.26	$ 0.38	$ 0.30	$ 0.20	$ 0.24	$ 0.83	$ 1.12	$ 0.92
Dilutive effect of Series A Preferred Units (in units)										0	0	0
Dilutive effect of performance units (in units)										1	2	1
Diluted weighted average number of outstanding units										437	436	297
Diluted earnings (loss) per unit		$ 0.02	$ 0.28	$ 0.26	$ 0.26	$ 0.38	$ 0.30	$ 0.20	$ 0.24	$ 0.82	$ 1.11	$ 0.92
Subordinated Units
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net Income Attributable to Common and Subordinated Units (Note 6)										$ 0	$ 0	$ 127,000,000
Diluted net income (loss)										$ 0	$ 0	$ 127,000,000
Basic weighted average number of outstanding
Basic weighted average number of outstanding										0	0	137
Basic earnings (loss) per unit
Basic earnings (loss) per unit										$ 0	$ 0	$ 0.93
Diluted weighted average number of outstanding units										0	0	137
Diluted earnings (loss) per unit										$ 0	$ 0	$ 0.93
Performance Units, Restricted Units, and Phantom Units
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Dilutive effect of unit-based awards (in dollars per unit) (less than $.01)										$ 0.01	$ 0.01	$ 0.01
Phantom units
Basic weighted average number of outstanding
Basic weighted average number of outstanding										1,000,000	0	0
[1]	Basic weighted average number of outstanding common units for the years ended December 31, 2019 , 2018 , and 2017 includes approximately one million time-based phantom units.

Partners' Equity - Schedule of

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

Feb. 25, 2020

Feb. 18, 2020

Feb. 14, 2020

Feb. 07, 2020

Nov. 26, 2019

Nov. 19, 2019

Nov. 14, 2019

Nov. 05, 2019

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

Feb. 27, 2018

Feb. 20, 2018

Feb. 15, 2018

Feb. 09, 2018

Nov. 21, 2017

Nov. 14, 2017

Oct. 31, 2017

Aug. 29, 2017

Aug. 22, 2017

Aug. 14, 2017

Jul. 31, 2017

May 30, 2017

May 23, 2017

May 12, 2017

May 02, 2017

Distribution Made to Limited Partner [Line Items]

Record Date

Nov. 19, 2019

Aug. 20, 2019

May 21, 2019

Feb. 19, 2019

Nov. 16, 2018

Aug. 21, 2018

May 22, 2018

Feb. 20, 2018

Nov. 14, 2017

Aug. 22, 2017

May 23, 2017

Payment Date

Nov. 26, 2019

Aug. 27, 2019

May 29, 2019

Feb. 26, 2019

Nov. 29, 2018

Aug. 28, 2018

May 29, 2018

Feb. 27, 2018

Nov. 21, 2017

Aug. 29, 2017

May 30, 2017

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

Distribution Made to Limited Partner [Line Items]

Record Date

Nov. 5, 2019

Aug. 2, 2019

Apr. 29, 2019

Feb. 8, 2019

Nov. 6, 2018

Aug. 1, 2018

May 1, 2018

Feb. 9, 2018

Oct. 31, 2017

Jul. 31, 2017

May 2, 2017

Payment Date

Nov. 14, 2019

Aug. 14, 2019

May 15, 2019

Feb. 14, 2019

Nov. 14, 2018

Aug. 14, 2018

May 15, 2018

Feb. 15, 2018

Nov. 14, 2017

Aug. 14, 2017

May 12, 2017

Cash Distribution

Distribution Made to Limited Partner [Line Items]

Per unit distribution, paid (in dollars per unit)

$ 0.3305

$ 0.3305

$ 0.318

$ 0.318

$ 0.318

$ 0.318

$ 0.318

$ 0.318

$ 0.318

$ 0.318

Total Cash Distribution

$ 144

$ 144

$ 138

$ 138

$ 138

$ 138

$ 138

$ 138

$ 138

$ 138

$ 137

Common unit cash distribution declared (in dollars per unit)

$ 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]

Per unit distribution, paid (in dollars per unit)

$ 0.625

$ 0.625

$ 0.625

$ 0.625

$ 0.625

$ 0.625

$ 0.625

$ 0.625

$ 0.625

$ 0.625

Total Cash Distribution

$ 9

$ 9

$ 9

$ 9

$ 9

$ 9

$ 9

$ 9

$ 9

$ 9

$ 9

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]

Feb. 7, 2020

Payment Date

[1]

Feb. 14, 2020

Subsequent Event | Cash Distribution

Distribution Made to Limited Partner [Line Items]

Common unit cash distribution declared (in dollars per unit)

$ 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]

Per unit distribution, paid (in dollars per unit)

[1]

$ 0.625

Total Cash Distribution

[1]

$ 9

Common unit cash distribution declared (in dollars per unit)

$ 0.625

Subsequent Event | Scenario, Forecast

Distribution Made to Limited Partner [Line Items]

Record Date

[2]

Feb. 18, 2020

Payment Date

[2]

Feb. 25, 2020

Per unit distribution, paid (in dollars per unit)

[2]

$ 0.3305

Total Cash Distribution

[2]

$ 144

[1]

The Board of Directors declared a $0.625 per Series A Preferred Unit cash distribution on February 7, 2020 , to be paid on February 14, 2020 to Series A Preferred unitholders of record at the close of business on February 7, 2020 .

[2]

The Board of Directors declared a $0.3305 per common unit cash distribution on February 7, 2020 , to be paid on February 25, 2020 , to common unitholders of record at the close of business on February 18, 2020 .

Partners' Equity - Narrative (D

Partners' Equity - Narrative (Details) - USD ($)	Aug. 30, 2017	May 12, 2017	Feb. 18, 2016	Dec. 31, 2019	Dec. 31, 2018
Distribution Made to Limited Partner [Line Items]
Limited partners' capital account, required quarterly distribution period				60 days
Conversion ratio	100.00%
Limited partners capital account, minimum quarterly distribution, annualized				150.00%
Aggregate offering price				$ 2,000,000
Number of common units in public offering				0	140,920
Common units remained available for issuance through the ATM Program				$ 197,000,000
Commissions				$ 25,000
Series A 10% Fixed to Floating Non Cumulative Redeemable Perpetual Preferred Units
Distribution Made to Limited Partner [Line Items]
Annual percentage rate			10.00%
Liquidation preference (in dollars per share)			$ 25
Duration of cash distributions			5 years
Redemption price (in dollars per share)			$ 25.50
Series A 10% Fixed to Floating Non Cumulative Redeemable Perpetual Preferred Units | LIBOR
Distribution Made to Limited Partner [Line Items]
Annual percentage rate			8.50%
Private Placement | Series A 10% Fixed to Floating Non Cumulative Redeemable Perpetual Preferred Units
Distribution Made to Limited Partner [Line Items]
Issuance of Series A Preferred Units (in units)			14,520,000
Cash purchase price (in dollars per unit)			$ 25
ATM Program
Distribution Made to Limited Partner [Line Items]
Aggregate offering price		$ 200,000,000
Subordinated Units | Limited Partner | OGE Energy
Distribution Made to Limited Partner [Line Items]
Units outstanding (in units)					68,150,514
Subordinated Units | Limited Partner | CenterPoint
Distribution Made to Limited Partner [Line Items]
Units outstanding (in units)					139,704,916
Distribution Subordination Period 1
Distribution Made to Limited Partner [Line Items]
Limited partners' capital account, minimum annualized quarterly distribution (in dollars per unit)				$ 1.15
Distribution Subordination Period 2
Distribution Made to Limited Partner [Line Items]
Limited partners' capital account, maximum annualized quarterly distribution (in dollars per unit)				$ 1.725
Maximum
Distribution Made to Limited Partner [Line Items]
Limited partners' capital account, incentive distribution rights, percentage				50.00%	50.00%
Minimum
Distribution Made to Limited Partner [Line Items]
Incentive distribution, distribution (in dollars per unit)				$ 0.330625	$ 0.330625
Subordinated Units
Distribution Made to Limited Partner [Line Items]
Units outstanding (in units)	207,855,430

Property, Plant and Equipment -

Property, Plant and Equipment - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 13,161	$ 12,899
Accumulated depreciation	2,291	2,028
Property, plant and equipment, net	10,870	10,871
Depreciation expense	$ 371	351	$ 335
Gathering and Processing
Property, Plant and Equipment [Line Items]
Weighted Average Useful Lives (Years)	33 years
Property, plant and equipment, gross	$ 8,252	8,011
Accumulated depreciation	$ 1,252	1,063
Transportation and Storage
Property, Plant and Equipment [Line Items]
Weighted Average Useful Lives (Years)	39 years
Property, plant and equipment, gross	$ 4,778	4,740
Accumulated depreciation	1,039	965
Construction work-in-progress
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 131	$ 148

Intangible Assets, Net - Narrat

Intangible Assets, Net - Narrative (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Finite-Lived Intangible Assets [Line Items]
Intangible assets with indefinite useful lives		$ 0
Amortization expense		62	$ 47	$ 31
Expected amortization of intangible assets, 2020			62
Expected amortization of intangible assets, 2021			62
Expected amortization of intangible assets, 2022			62
Expected amortization of intangible assets, 2023			62
Expected amortization of intangible assets, 2024			62
Customer Relationships
Finite-Lived Intangible Assets [Line Items]
Total intangible assets	[1]	840	840
Accumulated amortization		239	177
Net intangible assets		$ 601	$ 663
Weighted average useful life (in years)		14 years
[1]	(1) See Note 5 for discussion of the acquisition of EOCS and ETGP during the years ended December 31, 2018 and 2017, respectively.

Goodwill (Details)

Goodwill (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018
Goodwill [Roll Forward]
Goodwill		$ 98	$ 12
Goodwill impairment		(86)
Goodwill		12	98
Gathering and Processing
Goodwill [Roll Forward]
Goodwill		98	12
Goodwill impairment		(86)
Goodwill		12	98
Transportation and Storage
Goodwill [Roll Forward]
Goodwill		0	0
Goodwill impairment		0
Goodwill		$ 0	0
Velocity Holdings, LLC | Gathering and Processing
Goodwill [Roll Forward]
Goodwill acquired	[1]		86
Velocity Holdings, LLC | Transportation and Storage
Goodwill [Roll Forward]
Goodwill acquired	[1]		$ 0
[1]	(1) See Note 5 for further discussion.

Investment in Equity Method A_3

Investment in Equity Method Affiliate - Narrative (Details) - USD ($) $ in Millions

3 Months Ended

12 Months Ended

Dec. 31, 2019

Sep. 30, 2019

[1]

Jun. 30, 2019

[1]

Mar. 31, 2019

[1]

Dec. 31, 2018

Sep. 30, 2018

[1]

Jun. 30, 2018

[1]

Mar. 31, 2018

[1]

Dec. 31, 2019

Dec. 31, 2018

Dec. 31, 2017

Schedule of Equity Method Investments [Line Items]

Total Revenues

$ 731

[1]

$ 699

$ 735

$ 795

$ 950

[1]

$ 928

$ 805

$ 748

$ 2,960

$ 3,431

$ 2,803

SESH

Schedule of Equity Method Investments [Line Items]

Ownership percentage

50.00%

50.00%

SESH | Shared Operations Service Agreements | Equity Method Investee

Schedule of Equity Method Investments [Line Items]

Total Revenues

$ 17

$ 18

$ 17

SESH | Spectra Energy Partners, LP

Schedule of Equity Method Investments [Line Items]

Ownership percentage

50.00%

50.00%

Percentage distributions

50.00%

[1]

Text selection found with no content.

Investment in Equity Method A_4

Investment in Equity Method Affiliate - Schedule of Investments (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Investment in Equity Method Affiliates:
Equity in earnings of equity method affiliate		$ 17	$ 26	$ 28
Distributions from unconsolidated affiliates		17	26	28
Return of investment		(8)	(7)	(5)
SESH
Investment in Equity Method Affiliates:
Equity in earnings of equity method affiliate		17	26	28
Distributions from equity method affiliate	[1]	(25)	(33)	(33)
Distributions from unconsolidated affiliates		17	26	28
Return of investment		$ (8)	$ (7)	$ (5)
[1]	Distributions from equity method affiliate includes a $17 million , $26 million and $28 million return on investment and a $8 million , $7 million and $5 million return of investment for the years ended December 31, 2019 , 2018 and 2017 , respectively.

Investment in Equity Method A_5

Investment in Equity Method Affiliate - Financial Information of SESH (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Balance Sheets:
Investment in SESH	$ 309	$ 317
SESH
Balance Sheets:
Current assets	49	30
Property, plant and equipment, net	1,060	1,078
Total assets	1,109	1,108
Current liabilities	30	13
Long-term debt	398	397
Members’ equity	681	698
Total liabilities and members’ equity	1,109	1,108
Investment in SESH	309	317
Less: Capitalized interest on investment in SESH	(1)	(1)
Add: Basis differential, net of amortization	33	33
The Partnership’s share of members’ equity	341	349
Income Statements:
Revenues	109	112	$ 113
Equity Method Investment, Summarized Financial Information, Operating Income	50	67	72
Net income	$ 33	$ 50	$ 54

Debt - Schedule of Outstanding

Debt - Schedule of Outstanding Debt (Details) - USD ($)		Dec. 31, 2019	Sep. 13, 2019	Jan. 29, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Amount of debt outstanding		$ 4,405,000,000			$ 4,299,000,000
Debt Instrument, Unamortized Discount (Premium), Net		7,000,000			1,000,000	[1]
Long-term Debt, before Debt Issuance Costs, Net		4,398,000,000			4,298,000,000
Debt Issuance Costs, Gross	[2]	23,000,000			20,000,000
Long-term Debt, Excluding Current Maturities		3,969,000,000			3,129,000,000
2019 Term Loan Agreement [Member]
Debt Instrument [Line Items]
Face amount				$ 1,000,000,000
Loans Payable | 2019 Term Loan Agreement [Member]
Debt Instrument [Line Items]
Amount of debt outstanding		800,000,000			0
Debt Instrument, Unamortized Discount (Premium), Net		0			0	[1]
Long-term Debt, before Debt Issuance Costs, Net		800,000,000			0
Senior Notes | 2019 Notes (Level 2)
Debt Instrument [Line Items]
Amount of debt outstanding		0			500,000,000
Debt Instrument, Unamortized Discount (Premium), Net		0			0	[1]
Long-term Debt, before Debt Issuance Costs, Net		0			500,000,000
Long-term Debt, before Debt Issuance Costs, Net, Current Maturities	[3]				500,000,000
Senior Notes | 2024 Notes (Level 2)
Debt Instrument [Line Items]
Amount of debt outstanding		600,000,000			600,000,000
Debt Instrument, Unamortized Discount (Premium), Net		0			0	[1]
Long-term Debt, before Debt Issuance Costs, Net		600,000,000			600,000,000
Senior Notes | 2027 Notes (Level 2)
Debt Instrument [Line Items]
Amount of debt outstanding		700,000,000			700,000,000
Debt Instrument, Unamortized Discount (Premium), Net		(2,000,000)			(2,000,000)	[1]
Long-term Debt, before Debt Issuance Costs, Net		698,000,000			698,000,000
Senior Notes | 2028 Notes (Level 2)
Debt Instrument [Line Items]
Amount of debt outstanding		800,000,000			800,000,000
Debt Instrument, Unamortized Discount (Premium), Net		(5,000,000)			(6,000,000)	[1]
Long-term Debt, before Debt Issuance Costs, Net		795,000,000			794,000,000
Senior Notes | Senior Notes, Due in 2029 [Member]
Debt Instrument [Line Items]
Amount of debt outstanding		550,000,000			0
Debt Instrument, Unamortized Discount (Premium), Net		(1,000,000)			0	[1]
Long-term Debt, before Debt Issuance Costs, Net		549,000,000			0
Face amount			$ 550,000,000
Less: Unamortized debt expense		5,000,000
Senior Notes | 2044 Notes (Level 2)
Debt Instrument [Line Items]
Amount of debt outstanding		550,000,000			550,000,000
Debt Instrument, Unamortized Discount (Premium), Net		0			0	[1]
Long-term Debt, before Debt Issuance Costs, Net		550,000,000			550,000,000
Senior Notes | Senior Notes, Due March 2020 at 6.25%
Debt Instrument [Line Items]
Long-term Debt, before Debt Issuance Costs, Net, Current Maturities	[3]	251,000,000
Revolving Credit Facility
Debt Instrument [Line Items]
Amount of debt outstanding		0			250,000,000
Debt Instrument, Unamortized Discount (Premium), Net		0			0	[1]
Long-term Debt, before Debt Issuance Costs, Net		0			250,000,000
Debt Issuance Costs, Line of Credit Arrangements, Net		4,000,000			6,000,000
Commercial Paper
Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount (Premium), Net		0			0	[1]
Short-term debt	[4]	155,000,000			649,000,000
Subsidiary of Common Parent | Senior Notes | Senior Notes, Due March 2020 at 6.25%
Debt Instrument [Line Items]
Amount of debt outstanding		250,000,000			250,000,000
Debt Instrument, Unamortized Discount (Premium), Net		1,000,000			7,000,000	[1]
Long-term Debt, before Debt Issuance Costs, Net		251,000,000			$ 257,000,000
Premium (Discount) on long-term debt		$ 1,000,000
[1]	Unamortized premium (discount) on long-term debt is amortized over the life of the respective debt.
[2]	As of December 31, 2019 and 2018 , there was an additional $4 million and $6 million , respectively, of unamortized debt expense related to the Revolving Credit Facility included in Other assets, not included above. Unamortized debt expense is amortized over the life of the respective debt.
[3]	As of December 31, 2019 , Current portion of long-term debt includes the $251 million outstanding balance of the EOIT Senior Notes due March 15, 2020. At December 31, 2018 , Current portion of long-term debt included the $500 million
[4]	Short-term debt includes $155 million and $649 million of commercial paper outstanding as of December 31, 2019 and 2018 , respectively.

Debt - Maturities of Long Term

Debt - Maturities of Long Term Debt (Details) $ in Millions	Dec. 31, 2019USD ($)
Debt Disclosure [Abstract]
Long-term debt maturities in 2020	$ 405
Long-term debt maturities in 2021	0
Long-term debt maturities in 2022	800
Long-term debt maturities in 2023	0
Long-term debt maturities in 2024	600
Thereafter	$ 2,600

Debt - Narrative (Details)

Debt - Narrative (Details)		Sep. 16, 2019USD ($)	Sep. 13, 2019USD ($)	Apr. 06, 2018USD ($)time	Dec. 31, 2019USD ($)	Jan. 29, 2019USD ($)	Dec. 31, 2018USD ($)
Debt Instrument [Line Items]
Commercial paper, authorized							$ 1,400,000,000
Debt Instrument, Unamortized Discount (Premium), Net					$ (7,000,000)		(1,000,000)	[1]
Revolving Credit Facility
Debt Instrument [Line Items]
Debt Issuance Costs, Line of Credit Arrangements, Net					$ 4,000,000		6,000,000
Maximum borrowing capacity				$ 1,750,000,000
Letters of credit principal advances							0
Letters of credit outstanding amount							3,000,000
Unused capacity, commitment fee percentage					0.20%
Covenant, acceleration of indebtedness, threshold amount							100,000,000
Covenant, acceleration of indebtedness, nonpayment of uninsured money judgments, threshold amount							100,000,000
Term loan facility, term				5 years
Line of Credit Facility, Increase in Maximum Borrowing Capacity				$ 875,000,000
Number of times option may be exercised | time				2
Additional term of loan				1 year
Debt Instrument, Unamortized Discount (Premium), Net					$ 0		$ 0	[1]
Revolving Credit Facility | LIBOR
Debt Instrument [Line Items]
Basis spread on variable rate percentage					1.50%
Revolving Credit Facility | Minimum
Debt Instrument [Line Items]
Threshold for debt covenant ratio					$ 25,000,000
Revolving Credit Facility | Maximum
Debt Instrument [Line Items]
Consolidated debt to EBITDA ratio							5
Threshold for debt covenant ratio for acquisitions							5.50
2019 Term Loan Agreement [Member]
Debt Instrument [Line Items]
Weighted average interest rate percentage					3.10%
Threshold for debt covenant ratio for acquisitions						5.50
Covenant, acceleration of indebtedness, threshold amount						$ 100,000,000
Face amount						$ 1,000,000,000
Debt Instrument, Repaid Amount		$ 200,000,000
Debt Instrument, Principle Advance					$ 800,000,000
Debt Instrument, Covenant, Consolidated Debt to EBITDA Ratio, Maximum						5
Debt Instrument, Covenant, Acquisition Purchase Price in Rolling 12 Month Period, Minimum						$ 25,000,000
2019 Term Loan Agreement [Member] | LIBOR
Debt Instrument [Line Items]
Fixed percentage interest rate					1.25%
2019 Term Loan Agreement [Member] | Minimum | Eurodollar [Member]
Debt Instrument [Line Items]
Fixed percentage interest rate						0.75%
2019 Term Loan Agreement [Member] | Minimum | Base Rate [Member]
Debt Instrument [Line Items]
Fixed percentage interest rate						0.00%
2019 Term Loan Agreement [Member] | Maximum | Eurodollar [Member]
Debt Instrument [Line Items]
Fixed percentage interest rate						1.50%
2019 Term Loan Agreement [Member] | Maximum | Base Rate [Member]
Debt Instrument [Line Items]
Fixed percentage interest rate						0.50%
Senior Notes | Senior Notes, Due in 2029 [Member]
Debt Instrument [Line Items]
Face amount			$ 550,000,000
Fixed percentage interest rate			4.15%
Proceeds from Issuance of Senior Long-term Debt			$ 544,000,000
Unamortized debt expense					$ 5,000,000
Effective interest rate percentage					4.31%
Debt Instrument, Unamortized Discount (Premium), Net					$ 1,000,000		$ 0	[1]
Senior Notes | 2028 Notes (Level 2)
Debt Instrument [Line Items]
Effective interest rate percentage					5.20%
Debt Instrument, Unamortized Discount (Premium), Net					$ 5,000,000		6,000,000	[1]
Senior Notes | 2044 Notes (Level 2)
Debt Instrument [Line Items]
Effective interest rate percentage					5.08%
Debt Instrument, Unamortized Discount (Premium), Net					$ 0		0	[1]
Senior Notes | 2027 Notes (Level 2)
Debt Instrument [Line Items]
Effective interest rate percentage					4.57%
Debt Instrument, Unamortized Discount (Premium), Net					$ 2,000,000		2,000,000	[1]
Senior Notes | Senior Notes including 2019 Notes, 2024 Notes, and 2044 Notes
Debt Instrument [Line Items]
Unamortized discount					7,000,000
Unamortized debt expense					$ 18,000,000
Senior Notes | 2024 Notes (Level 2)
Debt Instrument [Line Items]
Effective interest rate percentage					4.01%
Debt Instrument, Unamortized Discount (Premium), Net					$ 0		$ 0	[1]
Commercial Paper
Debt Instrument [Line Items]
Weighted average interest rate percentage							2.29%
Commercial Paper	[2]				155,000,000		$ 649,000,000
Debt Instrument, Unamortized Discount (Premium), Net					$ 0		0	[1]
Subsidiary of Common Parent | Senior Notes | Senior Notes, Due March 2020 at 6.25%
Debt Instrument [Line Items]
Effective interest rate percentage					3.84%
Premium (Discount) on long-term debt					$ 1,000,000
Debt Instrument, Unamortized Discount (Premium), Net					$ (1,000,000)		$ (7,000,000)	[1]
[1]	Unamortized premium (discount) on long-term debt is amortized over the life of the respective debt.
[2]	Short-term debt includes $155 million and $649 million of commercial paper outstanding as of December 31, 2019 and 2018 , respectively.

Derivative Instruments and He_3

Derivative Instruments and Hedging Activities - Quantitative Disclosures Related to Derivative Instruments (Details) bbl in Thousands, MMBTU in Millions, $ in Millions		12 Months Ended
		Dec. 31, 2019USD ($)MMBTUbbl	Dec. 31, 2018USD ($)MMBTUbbl
Derivative [Line Items]
Fair value hedges		$ 0	$ 0
Designated as Hedging Instrument
Derivative [Line Items]
Derivative asset		0	0
Derivative liability		3	0
Designated cash flow hedges			0
Designated as Hedging Instrument | Interest rate swaps
Derivative [Line Items]
Derivative, notional amount		300	0
Not Designated as Hedging Instrument
Derivative [Line Items]
Derivative asset	[1]	49	33
Derivative liability	[1]	$ 38	$ 11
Not Designated as Hedging Instrument | Financial fixed futures/swaps | Purchases
Derivative [Line Items]
Derivative, gross notional volume (TBtu) | MMBTU	[2]	10	16
Not Designated as Hedging Instrument | Financial fixed futures/swaps | Sales
Derivative [Line Items]
Derivative, gross notional volume (TBtu) | MMBTU	[2]	19	28
Not Designated as Hedging Instrument | Financial basis futures/swaps | Purchases
Derivative [Line Items]
Derivative, gross notional volume (TBtu) | MMBTU	[2]	11	18
Not Designated as Hedging Instrument | Financial basis futures/swaps | Sales
Derivative [Line Items]
Derivative, gross notional volume (TBtu) | MMBTU	[2]	30	29
Not Designated as Hedging Instrument | Financial swaptions - natural gas | Purchases
Derivative [Line Items]
Derivative, gross notional volume (TBtu) | MMBTU	[2]	0	0
Not Designated as Hedging Instrument | Financial swaptions - natural gas | Sales
Derivative [Line Items]
Derivative, gross notional volume (TBtu) | MMBTU	[2]	2	1
Not Designated as Hedging Instrument | Physical purchases/sales | Purchases
Derivative [Line Items]
Derivative, gross notional volume (TBtu) | MMBTU	[2]	0	0
Not Designated as Hedging Instrument | Physical purchases/sales | Sales
Derivative [Line Items]
Derivative, gross notional volume (TBtu) | MMBTU	[2]	6	11
Not Designated as Hedging Instrument | Financial futures/swaps- Crude oil (for condensate) | Purchases
Derivative [Line Items]
Derivative, gross notional volume (MBbl) | bbl	[3]	0	0
Not Designated as Hedging Instrument | Financial futures/swaps- Crude oil (for condensate) | Sales
Derivative [Line Items]
Derivative, gross notional volume (MBbl) | bbl	[3]	990	945
Not Designated as Hedging Instrument | Financial swaptions - crude oil | Purchases
Derivative [Line Items]
Derivative, gross notional volume (MBbl) | bbl	[3]	0	0
Not Designated as Hedging Instrument | Financial swaptions - crude oil | Sales
Derivative [Line Items]
Derivative, gross notional volume (MBbl) | bbl	[3]	225	30
Not Designated as Hedging Instrument | Financial futures/swaps- Natural gas liquids | Purchases
Derivative [Line Items]
Derivative, gross notional volume (MBbl) | bbl	[4]	2,490	270
Not Designated as Hedging Instrument | Financial futures/swaps- Natural gas liquids | Sales
Derivative [Line Items]
Derivative, gross notional volume (MBbl) | bbl	[4]	2,415	2,535
Not Designated as Hedging Instrument | Natural gas
Derivative [Line Items]
Percent of contract with durations of one year or less		86.60%	74.00%
Percent of contracts with durations of more than one year and less than two years		13.40%	24.20%
Percent of contracts having durations of more than two years			1.80%
Not Designated as Hedging Instrument | Crude oil (for condensate)
Derivative [Line Items]
Percent of contract with durations of one year or less		72.80%	76.90%
Percent of contracts with durations of more than one year and less than two years		27.20%	23.10%
Not Designated as Hedging Instrument | Volume of natural gas liquids
Derivative [Line Items]
Percent of contract with durations of one year or less		72.20%	86.10%
Percent of contracts with durations of more than one year and less than two years		27.80%	13.90%
Other Noncurrent Assets | Designated as Hedging Instrument | Interest rate swaps
Derivative [Line Items]
Derivative asset		$ 0	$ 0
Other Noncurrent Assets | Not Designated as Hedging Instrument | Natural gas | Financial futures/swaps
Derivative [Line Items]
Derivative asset		0	0
Other Noncurrent Assets | Not Designated as Hedging Instrument | Natural gas | Physical purchases/sales
Derivative [Line Items]
Derivative asset		0	4
Other Noncurrent Assets | Not Designated as Hedging Instrument | Crude oil (for condensate) | Financial futures/swaps
Derivative [Line Items]
Derivative asset		0	2
Other Noncurrent Assets | Not Designated as Hedging Instrument | Volume of natural gas liquids | Financial futures/swaps
Derivative [Line Items]
Derivative asset		11	2
Other Noncurrent Liabilities | Designated as Hedging Instrument | Interest rate swaps
Derivative [Line Items]
Derivative liability		2	0
Other Noncurrent Liabilities | Not Designated as Hedging Instrument | Natural gas | Financial futures/swaps
Derivative [Line Items]
Derivative liability		1	2
Other Noncurrent Liabilities | Not Designated as Hedging Instrument | Natural gas | Physical purchases/sales
Derivative [Line Items]
Derivative liability		0	0
Other Noncurrent Liabilities | Not Designated as Hedging Instrument | Crude oil (for condensate) | Financial futures/swaps
Derivative [Line Items]
Derivative liability		8	0
Other Noncurrent Liabilities | Not Designated as Hedging Instrument | Volume of natural gas liquids | Financial futures/swaps
Derivative [Line Items]
Derivative liability		2	0
Other Current Assets | Designated as Hedging Instrument | Interest rate swaps
Derivative [Line Items]
Derivative asset		0	0
Other Current Assets | Not Designated as Hedging Instrument | Natural gas | Financial futures/swaps
Derivative [Line Items]
Derivative asset		7	3
Other Current Assets | Not Designated as Hedging Instrument | Natural gas | Physical purchases/sales
Derivative [Line Items]
Derivative asset		5	3
Other Current Assets | Not Designated as Hedging Instrument | Crude oil (for condensate) | Financial futures/swaps
Derivative [Line Items]
Derivative asset		1	9
Other Current Assets | Not Designated as Hedging Instrument | Volume of natural gas liquids | Financial futures/swaps
Derivative [Line Items]
Derivative asset		25	10
Other Current Liabilities | Designated as Hedging Instrument | Interest rate swaps
Derivative [Line Items]
Derivative liability		1	0
Other Current Liabilities | Not Designated as Hedging Instrument | Natural gas | Financial futures/swaps
Derivative [Line Items]
Derivative liability		5	5
Other Current Liabilities | Not Designated as Hedging Instrument | Natural gas | Physical purchases/sales
Derivative [Line Items]
Derivative liability		0	0
Other Current Liabilities | Not Designated as Hedging Instrument | Crude oil (for condensate) | Financial futures/swaps
Derivative [Line Items]
Derivative liability		19	3
Other Current Liabilities | Not Designated as Hedging Instrument | Volume of natural gas liquids | Financial futures/swaps
Derivative [Line Items]
Derivative liability		$ 3	$ 1
[1]	See Note 14 for a reconciliation of the Partnership’s total derivatives fair value to the Partnership’s Consolidated Balance Sheets as of December 31, 2019 and 2018 .
[2]	As of December 31, 2019 , 86.6% of the natural gas contracts had durations of one year or less and 13.4% 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.
[3]	As of December 31, 2019 , 72.8% of the crude oil (for condensate) contracts had durations of one year or less and 27.2% had durations of more than one year and less than two years. As of December 31, 2018 , 76.9%
[4]	As of December 31, 2019 , 72.2% of the natural gas liquids contracts had durations of one year or less and 27.8% had durations of more than one year and less than two years. As of December 31, 2018 , 86.1% of the natural gas liquids 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_4

Derivative Instruments and Hedging Activities - Balance Sheet Location (Details) - Not Designated as Hedging Instrument - USD ($) $ in Millions		Dec. 31, 2019	Dec. 31, 2018
Derivatives, Fair Value [Line Items]
Derivative asset	[1]	$ 49	$ 33
Derivative liability	[1]	38	11
Natural gas | Financial futures/swaps | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative asset		7	3
Natural gas | Financial futures/swaps | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative liability		5	5
Natural gas | Financial futures/swaps | Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative asset		0	0
Natural gas | Financial futures/swaps | Other Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative liability		1	2
Natural gas | Physical purchases/sales | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative asset		5	3
Natural gas | Physical purchases/sales | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative liability		0	0
Natural gas | Physical purchases/sales | Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative asset		0	4
Natural gas | Physical purchases/sales | Other Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative liability		0	0
Crude oil (for condensate) | Financial futures/swaps | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative asset		1	9
Crude oil (for condensate) | Financial futures/swaps | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative liability		19	3
Crude oil (for condensate) | Financial futures/swaps | Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative asset		0	2
Crude oil (for condensate) | Financial futures/swaps | Other Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative liability		8	0
Natural gas liquids financial futures/swaps | Financial futures/swaps | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative asset		25	10
Natural gas liquids financial futures/swaps | Financial futures/swaps | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative liability		3	1
Natural gas liquids financial futures/swaps | Financial futures/swaps | Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative asset		11	2
Natural gas liquids financial futures/swaps | Financial futures/swaps | Other Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative liability		$ 2	$ 0
[1]	See Note 14 for a reconciliation of the Partnership’s total derivatives fair value to the Partnership’s Consolidated Balance Sheets as of December 31, 2019 and 2018 .

Derivative Instruments and He_5

Derivative Instruments and Hedging Activities - Amounts Recognized in Income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative, net	$ 16	$ 11	$ 19
Change in fair value of derivatives	(11)	26	28
Realized gain (loss) on derivatives	27	(15)	(9)
Gain on derivative activity	16	11	19
Cash collateral already posted	0
Cash collateral posted	0
Interest rate swaps
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain on Derivative	0
Natural gas | Physical purchases/sales
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative, net	2	7	9
Natural gas | Financial futures/swaps
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative, net	13	(8)	20
Crude oil (for condensate) | Financial futures/swaps
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative, net	(41)	6	(1)
Natural gas liquids financial futures/swaps | Financial futures/swaps
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative, net	$ 42	$ 6	$ (9)

Derivative Instruments and He_6

Derivative Instruments and Hedging Activities - Derivative Instruments Designated as Hedging Instruments (Details) - Designated as Hedging Instrument - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Derivative [Line Items]
Derivative asset	$ 0	$ 0
Derivative liability	3	0
Other Current Assets | Interest rate swaps
Derivative [Line Items]
Derivative asset	0	0
Other Noncurrent Liabilities | Interest rate swaps
Derivative [Line Items]
Derivative liability	2	0
Other Current Liabilities | Interest rate swaps
Derivative [Line Items]
Derivative liability	1	0
Other Noncurrent Assets | Interest rate swaps
Derivative [Line Items]
Derivative asset	$ 0	$ 0

Fair Value Measurements - Estim

Fair Value Measurements - Estimated Fair Value of Financial Instruments and Non-Financial Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis (Details) - USD ($)		Dec. 31, 2019	Dec. 31, 2018
Commercial Paper
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commercial Paper	[1]	$ 155,000,000	$ 649,000,000
Revolving Credit Facility (Level 2) | Carrying Amount | Significant other observable inputs (Level 2) | Revolving Credit Facility (Level 2)
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Lines of Credit, Fair Value Disclosure	[2]	0	250,000,000
Revolving Credit Facility (Level 2) | Fair Value | Significant other observable inputs (Level 2) | Revolving Credit Facility (Level 2)
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Lines of Credit, Fair Value Disclosure	[2]	0	250,000,000
Loans Payable | Carrying Amount | Significant other observable inputs (Level 2) | 2019 Term Loan Agreement (Level 2)
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Loans Payable, Fair Value Disclosure		800,000,000	0
Loans Payable | Fair Value | Significant other observable inputs (Level 2) | 2019 Term Loan Agreement (Level 2)
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Loans Payable, Fair Value Disclosure		800,000,000	0
Senior Notes | Carrying Amount | 2028 Notes (Level 2)
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Notes Payable, Fair Value Disclosure		795,000,000	794,000,000
Senior Notes | Carrying Amount | Senior Notes, Due in 2029 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Notes Payable, Fair Value Disclosure		549,000,000	0
Senior Notes | Carrying Amount | Significant other observable inputs (Level 2) | 2019 Notes (Level 2)
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Notes Payable, Fair Value Disclosure		0	500,000,000
Senior Notes | Carrying Amount | Significant other observable inputs (Level 2) | 2024 Notes (Level 2)
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Notes Payable, Fair Value Disclosure		600,000,000	600,000,000
Senior Notes | Carrying Amount | Significant other observable inputs (Level 2) | 2027 Notes (Level 2)
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Notes Payable, Fair Value Disclosure		698,000,000	698,000,000
Senior Notes | Carrying Amount | Significant other observable inputs (Level 2) | 2044 Notes (Level 2)
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Notes Payable, Fair Value Disclosure		550,000,000	550,000,000
Senior Notes | Fair Value | 2028 Notes (Level 2)
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Notes Payable, Fair Value Disclosure		811,000,000	764,000,000
Senior Notes | Fair Value | Senior Notes, Due in 2029 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Notes Payable, Fair Value Disclosure		526,000,000	0
Senior Notes | Fair Value | Significant other observable inputs (Level 2) | 2019 Notes (Level 2)
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Notes Payable, Fair Value Disclosure		0	497,000,000
Senior Notes | Fair Value | Significant other observable inputs (Level 2) | 2024 Notes (Level 2)
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Notes Payable, Fair Value Disclosure		614,000,000	571,000,000
Senior Notes | Fair Value | Significant other observable inputs (Level 2) | 2027 Notes (Level 2)
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Notes Payable, Fair Value Disclosure		698,000,000	642,000,000
Senior Notes | Fair Value | Significant other observable inputs (Level 2) | 2044 Notes (Level 2)
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Notes Payable, Fair Value Disclosure		506,000,000	445,000,000
Subsidiary of Common Parent | Senior Notes | Carrying Amount | Significant other observable inputs (Level 2) | Senior Notes, Due March 2020 at 6.25%
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Notes Payable, Fair Value Disclosure		251,000,000	257,000,000
Subsidiary of Common Parent | Senior Notes | Fair Value | Significant other observable inputs (Level 2) | Senior Notes, Due March 2020 at 6.25%
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Notes Payable, Fair Value Disclosure		$ 252,000,000	$ 256,000,000
[1]	Short-term debt includes $155 million and $649 million of commercial paper outstanding as of December 31, 2019 and 2018 , respectively.
[2]	Borrowing capacity is effectively reduced by our borrowings outstanding under the commercial paper program. $155 million and $649 million of commercial paper was outstanding as of December 31, 2019 and 2018 , respectively.

Fair Value Measurements - Fair

Fair Value Measurements - Fair Value Hierarchy (Details) - USD ($)	Dec. 31, 2019	Dec. 31, 2018
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fuel reserves for under retained fuel due from shippers	$ 21,000,000	$ 11,000,000
Fuel reserves for over retained fuel due from shippers	8,000,000	5,000,000
Fair Value, Recurring | Commodity Contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset, fair value, before netting adjustments	49,000,000	33,000,000
Derivative liability, fair value, before netting adjustments	38,000,000	11,000,000
Derivative asset, netting adjustment	(37,000,000)	(9,000,000)
Derivative liability, netting adjustment	(37,000,000)	(9,000,000)
Derivative Asset	12,000,000	24,000,000
Fair Value	1,000,000	2,000,000
Fair Value, Recurring | Gas Imbalances
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset, fair value, before netting adjustments	14,000,000	18,000,000	[1],[2]
Derivative liability, fair value, before netting adjustments	11,000,000	17,000,000	[2],[3]
Derivative asset, netting adjustment	0	0	[1],[2]
Derivative liability, netting adjustment	0	0	[2],[3]
Derivative Asset	14,000,000	18,000,000	[1],[2]
Fair Value	11,000,000	17,000,000	[2],[3]
Fair Value, Recurring | Quoted market prices in active market for identical assets (Level 1) | Commodity Contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset, fair value, gross asset	5,000,000	4,000,000
Derivative asset, fair value, gross liability	31,000,000	9,000,000
Fair Value, Recurring | Quoted market prices in active market for identical assets (Level 1) | Gas Imbalances
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset, fair value, gross asset	0	0	[1],[2]
Derivative asset, fair value, gross liability	0	0	[2],[3]
Fair Value, Recurring | Significant other observable inputs (Level 2) | Commodity Contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset, fair value, gross asset	44,000,000	29,000,000
Derivative asset, fair value, gross liability	7,000,000	2,000,000
Fair Value, Recurring | Significant other observable inputs (Level 2) | Gas Imbalances
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset, fair value, gross asset	14,000,000	18,000,000	[1],[2]
Derivative asset, fair value, gross liability	11,000,000	17,000,000	[2],[3]
Fair Value, Recurring | Unobservable inputs (Level 3) | Commodity Contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset, fair value, gross asset	0	0
Derivative asset, fair value, gross liability	0	0
Fair Value, Recurring | Unobservable inputs (Level 3) | Gas Imbalances
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset, fair value, gross asset	0	0	[1],[2]
Derivative asset, fair value, gross liability	$ 0	$ 0	[2],[3]
[1]	Gas imbalance assets exclude fuel reserves for under retained fuel due from shippers of $21 million and $11 million at December 31, 2019 and 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 December 31, 2019 and 2018 .
[3]	Gas imbalance liabilities exclude fuel reserves for over retained fuel due to shippers of $8 million and $5 million at December 31, 2019 and 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.

Fair Value Measurements - Sched

Fair Value Measurements - Schedule of Changes in Fair Values of Level 3 Financial Assets (Details) - Natural gas liquids financial futures/swaps - Commodity Contracts $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Beginning Balance	$ (5)
Losses included in earnings	(23)
Settlements	(7)
Transfers out of Level 3	(21)
Ending Balance	$ 0

Supplemental Disclosure of Ca_3

Supplemental Disclosure of Cash Flow Information - Supplemental Disclosure of Cash Flow Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Supplemental Cash Flow Information [Abstract]
Interest, net of capitalized interest	$ 185	$ 148	$ 114
Income taxes, net of refunds	1	3	0
Accounts payable related to capital expenditures	10	54	39
Lease liabilities arising from the application of ASC 842	$ 45	$ 0	$ 0

Supplemental Disclosure of Ca_4

Supplemental Disclosure of Cash Flow Information - Schedule of Reconciliation of Cash and Cash Equivalents and Restricted Cash (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Supplemental Cash Flow Information [Abstract]
Cash and cash equivalents	$ 4	$ 8
Restricted cash	0	14
Cash, cash equivalents and restricted cash shown in the Consolidated Statement of Cash Flows	4	$ 22	$ 19	$ 23
Restricted cash, cash collateral	$ 14

Related Party Transactions - Na

Related Party Transactions - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Related Party Transaction [Line Items]
Partnership's revenues from affiliated companies as a percent of total revenues	6.00%	5.00%	5.00%
CenterPoint and OGE Energy | Minimum
Related Party Transaction [Line Items]
Period notice of termination for reimbursements for all employee costs	90 days
CenterPoint | Certain Services and Support Functions
Related Party Transaction [Line Items]
Expense reimbursement annual caps	$ 1
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 in 2019	5	$ 5	$ 5
OGE Energy | Certain Services and Support Functions
Related Party Transaction [Line Items]
Expense reimbursement annual caps	1
Subsidiary of Common Parent | Amount Reimbursed for Costs Incurred in Modifications of Acquired Facility | Pipelines
Related Party Transaction [Line Items]
Amount of reimbursement	$ 2	$ 1	$ 1
CenterPoint | Subsidiary of Common Parent | Three Services included in Transportation and Storage Agreements
Related Party Transaction [Line Items]
Period of written notice prior to contract termination	180 days

Related Party Transactions - Re

Related Party Transactions - Related Party Activity (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Related Party Transaction [Line Items]
Revenues from affiliated companies	$ 167	$ 163	$ 153
Cost of goods sold from affiliate	33	26	20
Total corporate services, operating lease and seconded employee expense	19	32	38
CenterPoint
Related Party Transaction [Line Items]
Cost of goods sold from affiliate	0	3	1
CenterPoint | Gas Transportation and Storage
Related Party Transaction [Line Items]
Revenues from affiliated companies	108	111	110
CenterPoint | Gas Sales
Related Party Transaction [Line Items]
Revenues from affiliated companies	8	11	6
CenterPoint | Corporate Services
Related Party Transaction [Line Items]
Total corporate services, operating lease and seconded employee expense	0	1	3
CenterPoint | Operating Lease
Related Party Transaction [Line Items]
Total corporate services, operating lease and seconded employee expense	1	1	1
OGE Energy
Related Party Transaction [Line Items]
Cost of goods sold from affiliate	33	23	19
OGE Energy | Gas Transportation and Storage
Related Party Transaction [Line Items]
Revenues from affiliated companies	41	37	35
OGE Energy | Gas Sales
Related Party Transaction [Line Items]
Revenues from affiliated companies	10	4	2
OGE Energy | Seconded Employee Costs
Related Party Transaction [Line Items]
Total corporate services, operating lease and seconded employee expense	18	29	31
OGE Energy | Corporate Services
Related Party Transaction [Line Items]
Total corporate services, operating lease and seconded employee expense	$ 0	$ 1	$ 3

Commitments and Contingencies -

Commitments and Contingencies - Narrative (Details) $ in Millions	Sep. 23, 2019USD ($)	Sep. 13, 2018	Jan. 01, 2017MMcf	Dec. 31, 2019USD ($)
Commitments and Contingencies Disclosure [Abstract]
Gathering and processing agreement term			10 years
Energy deliveries (in MMcf/d) | MMcf			400
Minimum volume commitment fee				$ 192
Minimum volume commitment fees per year from 2020 through 2027				23
Minimum volume commitment fees in 2028				11
Estimated cost to complete				$ 500
Firm transportation term		20 years
Proceeds from sale of interest in facility	$ 19

Income Taxes - Narrative (Detai

Income Taxes - Narrative (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2019	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Deferred income tax benefit	$ 1,000,000
Unrecognized tax benefits	$ 0	$ 0	$ 0

Income Taxes - Schedule of Expe

Income Taxes - Schedule of Expense (Benefit) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Provision for current income taxes
Federal	$ 0	$ 0	$ 1
State	0	0	1
Total provision for current income taxes	0	0	2
Benefit for deferred income taxes, net
Federal	(1)	(1)	(2)
State	0	0	(1)
Total benefit for deferred income taxes, net	(1)	(1)	(3)
Total income tax benefit	$ (1)	$ (1)	$ (1)

Income Taxes - Deferred Tax Ass

Income Taxes - Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Deferred tax liabilities, net:
Intercompany management fee	$ 17	$ 16
Depreciation	6	5
Accrued compensation	(19)	(16)
Total deferred tax liabilities, net	$ 4	$ 5

Equity Based Compensation - Per

Equity Based Compensation - Performance Units, Restricted Units and Phantom Units (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total equity-based compensation expense	$ 16	$ 16	$ 15
Performance units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total equity-based compensation expense	9	9	10
Restricted units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total equity-based compensation expense	0	1	2
Phantom units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total equity-based compensation expense	$ 7	$ 6	$ 3
Common Units | Long Term Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of units that may be delivered pursuant to vested awards	13,100,000

Equity Based Compensation - P_2

Equity Based Compensation - Performance Units (Details) - Performance units - $ / shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period	3 years
Award cycle	3 years
Period from change in control	2 years
Number of units granted (in units)	638,798	551,742	468,626
Fair value of units granted (in dollars per share)	$ 19.95	$ 17.70	$ 19.27
Expected price volatility percentage	34.20%	44.20%	47.30%
Risk-free interest rate percentage	2.54%	2.36%	1.57%
Distribution yield percentage	8.38%	8.56%	9.10%
Expected life of units (in years)	3 years	3 years	3 years
Awards Granted in 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Duration of daily stock price observations to determine expected price volatility		3 years
Awards Granted in 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Duration of daily stock price observations to determine expected price volatility	3 years
Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Payout percentage from target level of achievement of performance goal	0.00%
Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Payout percentage from target level of achievement of performance goal	200.00%

Equity Based Compensation - Pha

Equity Based Compensation - Phantom Units (Details) - $ / shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Phantom units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Period from change in control	2 years
Units granted (in units)	695,486	546,708	392,338
Fair value of units granted (in dollars per share)	$ 14.26
Phantom units | Certain Partnership Employees and Independent Directors of Enable GP | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value of units granted (in dollars per share)	8.95	$ 13.74	$ 15.44
Phantom units | Certain Partnership Employees and Independent Directors of Enable GP | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value of units granted (in dollars per share)	$ 15.04	$ 17	$ 16.93
Other Awards | Independent Directors Of Enable GP
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units granted (in units)	28,221	16,335	16,653
Fair value of units granted (in dollars per share)	$ 10.43	$ 14.94	$ 15.03

Equity Based Compensation - Equ

Equity Based Compensation - Equity Units Activity (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Performance units
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Units Outstanding at 12/31/2018 (in units)	2,109,835
Units granted (in units)	638,798	551,742	468,626
Vested (in units)	(1,174,597)
Forfeited (in units)	(180,707)
Units Outstanding at 12/31/2019 (in units)	1,393,329	2,109,835
Weighted Average Grant-Date Fair Value, Per Unit
Units Outstanding at 12/31/2018 (in dollars per share)	$ 14.33
Granted (in dollars per share)	19.95	$ 17.70	$ 19.27
Vested (in dollars per share)	11.09
Forfeited (in dollars per share)	18.96
Units Outstanding at 12/31/2019 (in dollars per share)	$ 19.04	$ 14.33
December 31, 2019	$ 14
Aggregate intrinsic value of units vested	34	$ 11	$ 5
Fair value of units vested	$ 13	7	10
Performance units | Minimum
Weighted Average Grant-Date Fair Value, Per Unit
Payout percentage from target level of achievement of performance goal	0.00%
Performance units | Maximum
Weighted Average Grant-Date Fair Value, Per Unit
Payout percentage from target level of achievement of performance goal	200.00%
Restricted units
Weighted Average Grant-Date Fair Value, Per Unit
Aggregate intrinsic value of units vested	$ 0	3	2
Fair value of units vested	$ 0	$ 4	$ 4
Phantom units
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Units Outstanding at 12/31/2018 (in units)	1,447,590
Units granted (in units)	695,486	546,708	392,338
Vested (in units)	(608,755)
Forfeited (in units)	(141,761)
Units Outstanding at 12/31/2019 (in units)	1,392,560	1,447,590
Weighted Average Grant-Date Fair Value, Per Unit
Units Outstanding at 12/31/2018 (in dollars per share)	$ 12.38
Granted (in dollars per share)	14.26
Vested (in dollars per share)	8.71
Forfeited (in dollars per share)	14.89
Units Outstanding at 12/31/2019 (in dollars per share)	$ 14.65	$ 12.38
December 31, 2019	$ 14
Aggregate intrinsic value of units vested	9	$ 1	$ 0
Fair value of units vested	$ 5	$ 0	$ 0
Annual Grant in 2016 | Performance units
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Units granted (in units)	1,097,846
Annual Grant in 2016 | Performance units | Maximum
Weighted Average Grant-Date Fair Value, Per Unit
Payout percentage from target level of achievement of performance goal	200.00%
Officer Annual Grant in 2016 | Performance units
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Units granted (in units)	26,986
Annual Grant in 2016 at 200% | Performance units
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)
Officer Annual Grant in 2016 at 200% | Performance units
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Vested (in units)	(53,972)
Awards Granted in 2017 | Performance units
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Units granted (in units)	378,109
Annual Grant in 2017 at 0% | Performance units | Maximum
Weighted Average Grant-Date Fair Value, Per Unit
Payout percentage from target level of achievement of performance goal	0.00%
Certain Partnership Employees and Independent Directors of Enable GP | Phantom units | Minimum
Weighted Average Grant-Date Fair Value, Per Unit
Granted (in dollars per share)	$ 8.95	$ 13.74	$ 15.44
Certain Partnership Employees and Independent Directors of Enable GP | Phantom units | Maximum
Weighted Average Grant-Date Fair Value, Per Unit
Granted (in dollars per share)	$ 15.04	$ 17	$ 16.93

Equity Based Compensation - Unr

Equity Based Compensation - Unrecognized Compensation Cost (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized Compensation Cost (In millions)		$ 21
Long Term Incentive Plan | Common Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares available for issuance		6,353,205
Performance units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized Compensation Cost (In millions)		$ 12
Weighted Average to be Recognized (In years)	1 year 3 months 25 days
Phantom units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized Compensation Cost (In millions)		$ 9
Weighted Average to be Recognized (In years)	1 year 2 months 26 days

Reportable Segments - Schedule

Reportable Segments - Schedule of Financial Data for Business Segments and Services (Details) $ in Millions	3 Months Ended																12 Months Ended
	Dec. 31, 2019USD ($)		Sep. 30, 2019USD ($)		Jun. 30, 2019USD ($)		Mar. 31, 2019USD ($)		Dec. 31, 2018USD ($)		Sep. 30, 2018USD ($)		Jun. 30, 2018USD ($)		Mar. 31, 2018USD ($)		Dec. 31, 2019USD ($)segment		Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)
Segment Reporting Information [Line Items]
Number of reportable segments | segment																	2
Total Revenues	$ 731	[1]	$ 699	[1]	$ 735	[1]	$ 795	[1]	$ 950	[1]	$ 928	[1]	$ 805	[1]	$ 748	[1]	$ 2,960		$ 3,431	$ 2,803
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)	321		263		317		378		484		516		444		375		1,279		1,819	1,381
Operation and maintenance, General and administrative																	526		501	464
Depreciation and amortization																	433		398	366
Impairments																	86		0	0
Taxes other than income taxes																	67		65	64
Operating Income	62		$ 175		$ 167		$ 165		212		$ 171		$ 126		$ 139		569		648	528
Assets	12,266								12,444								12,266		12,444	11,593
Capital expenditures																	432		1,171	714
Operating Segments | Gathering and Processing
Segment Reporting Information [Line Items]
Total Revenues																	2,338		2,818	2,170
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)																	1,203		1,741	1,285
Operation and maintenance, General and administrative																	320		312	289
Depreciation and amortization																	308		263	232
Impairments																	86		0	0
Taxes other than income taxes																	41		38	37
Operating Income																	380		464	327
Assets	9,739								9,874								9,739		9,874	9,079
Capital expenditures																	314		981	601
Operating Segments | Transportation and Storage
Segment Reporting Information [Line Items]
Total Revenues																	1,038		1,162	1,146
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)																	491		628	604
Operation and maintenance, General and administrative																	207		189	179
Depreciation and amortization																	125		135	134
Impairments																	0	[2]	0	0
Taxes other than income taxes																	26		27	27
Operating Income																	189		183	202
Assets	5,886								5,805								5,886		5,805	5,616
Capital expenditures																	118		190	113
Eliminations
Segment Reporting Information [Line Items]
Total Revenues																	(416)		(549)	(513)
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)																	(415)		(550)	(508)
Operation and maintenance, General and administrative																	(1)		0	(4)
Depreciation and amortization																	0		0	0
Impairments																	0		0	0
Taxes other than income taxes																	0		0	0
Operating Income																	0		1	(1)
Assets	$ (3,359)								$ (3,235)								(3,359)		(3,235)	(3,102)
Capital expenditures																	0		0	0
Product
Segment Reporting Information [Line Items]
Total Revenues																	1,533		2,106	1,653
Product | Operating Segments | Gathering and Processing
Segment Reporting Information [Line Items]
Total Revenues																	1,449		2,016	1,538
Product | Operating Segments | Transportation and Storage
Segment Reporting Information [Line Items]
Total Revenues																	487		625	621
Product | Eliminations
Segment Reporting Information [Line Items]
Total Revenues																	(403)		(535)	(506)
Natural Gas, Gathering, Transportation, Marketing and Processing
Segment Reporting Information [Line Items]
Total Revenues																	1,427		1,325	1,150
Natural Gas, Gathering, Transportation, Marketing and Processing | Operating Segments | Gathering and Processing
Segment Reporting Information [Line Items]
Total Revenues																	889		802	632
Natural Gas, Gathering, Transportation, Marketing and Processing | Operating Segments | Transportation and Storage
Segment Reporting Information [Line Items]
Total Revenues																	551		537	525
Natural Gas, Gathering, Transportation, Marketing and Processing | Eliminations
Segment Reporting Information [Line Items]
Total Revenues																	(13)		$ (14)	$ (7)
Total revenue | Customer Concentration Risk
Segment Reporting Information [Line Items]
Total Revenues																	$ 328
Concentration risk percentage																	11.00%		0.00%	0.00%
[1]	Text selection found with no content.
[2]	Equity in earnings of equity method affiliate is included in Other Income (Expense) on the Consolidated Statements of Income and is not included in the table above. See Note 11 for discussion regarding ownership interest in SESH and related equity earnings included in the transportation and storage reportable segment for the years ended December 31, 2019 , 2018 and 2017 .

Quarterly Financial Data (Una_3

Quarterly Financial Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended																12 Months Ended
	Dec. 31, 2019		Sep. 30, 2019		Jun. 30, 2019		Mar. 31, 2019		Dec. 31, 2018		Sep. 30, 2018		Jun. 30, 2018		Mar. 31, 2018		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Effect of Fourth Quarter Events [Line Items]
Total Revenues	$ 731	[1]	$ 699	[1]	$ 735	[1]	$ 795	[1]	$ 950	[1]	$ 928	[1]	$ 805	[1]	$ 748	[1]	$ 2,960	$ 3,431	$ 2,803
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)	321		263		317		378		484		516		444		375		1,279	1,819	1,381
Operating income (loss)	62		175		167		165		212		171		126		139		569	648	528
Net income	20		133		124		123		175		139		95		114		400	523	437
Net income attributable to limited partners	18		132		124		122		174		138		95		114		396	521	436
Net income attributable to common units	$ 9		$ 123		$ 115		$ 113		$ 165		$ 129		$ 86		$ 105		360	485	400
Goodwill impairment																	86
Common Units
Effect of Fourth Quarter Events [Line Items]
Net income attributable to common units																	$ 360	$ 485	$ 273
Basic earnings (loss) per unit	$ 0.02		$ 0.28		$ 0.26		$ 0.26		$ 0.38		$ 0.30		$ 0.20		$ 0.24		$ 0.83	$ 1.12	$ 0.92
Diluted earnings (loss) per unit	$ 0.02		$ 0.28		$ 0.26		$ 0.26		$ 0.38		$ 0.30		$ 0.20		$ 0.24		$ 0.82	$ 1.11	$ 0.92
Subordinated Units
Effect of Fourth Quarter Events [Line Items]
Net income attributable to common units																	$ 0	$ 0	$ 127
Basic earnings (loss) per unit																	$ 0	$ 0	$ 0.93
Diluted earnings (loss) per unit																	$ 0	$ 0	$ 0.93
[1]	Text selection found with no content.