0001591763-21-000005 | 10-K | XBRL Viewer | Enable Midstream Partners LP

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Cover - USD ($) $ in Millions	12 Months Ended
Cover - USD ($) $ in Millions	Dec. 31, 2020	Jan. 29, 2021	Jun. 30, 2020
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Transition Report	false
Document Period End Date	Dec. 31, 2020
Entity File Number	1-36413
Entity Registrant Name	ENABLE MIDSTREAM PARTNERS, LP
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	72-1252419
Entity Address, Address Line One	499 West Sheridan Avenue,
Entity Address, Address Line Two	Suite 1500
Entity Address, City or Town	Oklahoma City,
Entity Address, State or Province	OK
Entity Address, Postal Zip Code	73102
City Area Code	405
Local Phone Number	525-7788
Title of 12(b) Security	Common Units Representing Limited Partner Interests
Trading Symbol	ENBL
Security Exchange Name	NYSE
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
ICFR Auditor Attestation Flag	true
Entity Shell Company	false
Public Float			$ 424
Entity Common Stock, Shares Outstanding		435,565,067
Amendment Flag	false
Document Fiscal Year Focus	2020
Document Fiscal Period Focus	FY
Entity Central Index Key	0001591763
Current Fiscal Year End Date	--12-31

Consolidated Statements of Income - USD ($) $ in Millions	12 Months Ended
Consolidated Statements of Income - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Revenues (including revenues from affiliates (Note 16)):
Total Revenues	$ 2,463	$ 2,960	$ 3,431
Cost and Expenses (including expenses from affiliates (Note 16)):
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)	965	1,279	1,819
Operation and maintenance	418	423	388
General and administrative	98	103	113
Depreciation and amortization	420	433	398
Impairments of property, plant and equipment and goodwill (Notes 8 and 10)	28	86	0
Taxes other than income tax	69	67	65
Total Cost and Expenses	1,998	2,391	2,783
Operating Income	465	569	648
Other Income (Expense):
Interest expense	(178)	(190)	(152)
Equity in earnings (losses) of equity method affiliate, net	(210)	17	26
Other, net	6	3	0
Total Other Expense	(382)	(170)	(126)
Income Before Income Tax
Income Before Income Tax	83	399	522
Income tax benefit	0	(1)	(1)
Net Income
Net Income	83	400	523
Less: Net income (loss) attributable to noncontrolling interests
Less: Net income (loss) attributable to noncontrolling interests	(5)	4	2
Net Income Attributable to Limited Partners
Net Income Attributable to Limited Partners	88	396	521
Less: Series A Preferred Unit distributions (Note 7)
Less: Series A Preferred Unit distributions (Note 7)	36	36	36
Net Income Attributable to Common Units (Note 6)
Net Income Attributable to Common Units (Note 6)	52	360	485
Common Units
Net Income Attributable to Common Units (Note 6)
Net Income Attributable to Common Units (Note 6)	$ 52	$ 360	$ 485
Basic and Diluted earnings (loss) per unit
Basic earnings per unit	$ 0.12	$ 0.83	$ 1.12
Diluted earnings per unit	$ 0.12	$ 0.82	$ 1.11
Product
Revenues (including revenues from affiliates (Note 16)):
Total Revenues	$ 1,132	$ 1,533	$ 2,106
Natural Gas, Gathering, Transportation, Marketing and Processing
Revenues (including revenues from affiliates (Note 16)):
Total Revenues	$ 1,331	$ 1,427	$ 1,325

Consolidated Statement of Comprehensive Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Statement of Comprehensive Income [Abstract]
Net income	$ 83	$ 400	$ 523
Change in fair value of interest rate derivative instruments	(7)	(3)	0
Reclassification of interest rate derivative losses to net income	4	0	0
Other comprehensive loss	(3)	(3)	0
Comprehensive income	80	397	523
Less: Comprehensive income (loss) attributable to noncontrolling interests	(5)	4	2
Comprehensive income attributable to Limited Partners	$ 85	$ 393	$ 521

- Definition

Amount after tax of increase (decrease) in equity from transactions and other events and circumstances from net income (loss) and other comprehensive income (loss), attributable to noncontrolling interests. Excludes changes in equity resulting from investments by owners and distributions to owners.

+ References + Details

- Definition

Amount after tax of increase (decrease) in equity from transactions and other events and circumstances from net income and other comprehensive income. Excludes changes in equity resulting from investments by owners and distributions to owners.

+ References + Details

- Definition

The consolidated profit or loss for the period, net of income taxes, including the portion attributable to the noncontrolling interest.

+ References

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+ Details

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Current Assets:
Cash and cash equivalents	$ 3	$ 4
Accounts receivable, net of allowance for doubtful accounts (Note 1)	248	244
Accounts receivable—affiliated companies	15	25
Inventory	42	46
Gas imbalances	42	35
Other current assets	31	35
Total current assets	381	389
Property, Plant and Equipment:
Property, plant and equipment	13,220	13,161
Less accumulated depreciation and amortization	2,555	2,291
Property, plant and equipment, net	10,665	10,870
Other Assets:
Intangible assets, net	539	601
Goodwill	0	12
Investment in equity method affiliate	76	309
Other	68	85
Total other assets	683	1,007
Total Assets	11,729	12,266
Current Liabilities:
Accounts payable	149	161
Accounts payable—affiliated companies	2	1
Short-term debt	250	155
Current portion of long-term debt	0	251
Taxes accrued	34	32
Gas imbalances	19	19
Accrued compensation	43	31
Customer deposits	18	17
Other	67	113
Total current liabilities	582	780
Other Liabilities:
Accumulated deferred income tax, net	5	4
Regulatory liabilities	25	24
Other	71	80
Total other liabilities	101	108
Long-Term Debt	3,951	3,969
Commitments and Contingencies (Note 17)
Partners’ Equity:
Series A Preferred Units (14,520,000 issued and outstanding at December 31, 2020 and December 31, 2019, respectively)	362	362
Common Units (435,549,892 issued and outstanding at December 31, 2020 and 435,201,365 issued and outstanding at December 31, 2019)	6,713	7,013
Accumulated other comprehensive loss	(6)	(3)
Noncontrolling interests	26	37
Total Partners’ Equity	7,095	7,409
Total Liabilities and Partners’ Equity	$ 11,729	$ 12,266
Series A Preferred Units
Partners’ Equity:
Preferred Units, Outstanding	14,520,000	14,520,000
Preferred Units, Issued	14,520,000	14,520,000
Common Units
Partners’ Equity:
Common Units, Issued	435,549,892	435,201,365
Common Units, Outstanding	435,549,892	435,201,365

Consolidated Balance Sheets - Parenthetical - shares	Dec. 31, 2020	Dec. 31, 2019
Series A Preferred Units
Preferred Units, Issued	14,520,000	14,520,000
Preferred Units, Outstanding	14,520,000	14,520,000
Common Units
Common Units, Issued	435,549,892	435,201,365
Common Units, Outstanding	435,549,892	435,201,365

Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Statement of Cash Flows [Abstract]
Net income	$ 83	$ 400	$ 523
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	420	433	398
Deferred income tax	1	(1)	(1)
Impairments of property, plant and equipment and goodwill	28	86	0
Net loss on sale/retirement of assets	24	8	1
Gain on extinguishment of debt	(5)	0	0
Equity in (earnings) losses of equity method affiliate, net	210	(17)	(26)
Return on investment in equity method affiliate	15	17	26
Equity-based compensation	13	16	16
Amortization of debt costs and discount (premium)	4	(1)	(1)
Changes in other assets and liabilities:
Accounts receivable, net	(5)	43	(10)
Accounts receivable—affiliated companies	10	(6)	(1)
Inventory	4	4	(10)
Gas imbalance assets	(7)	(6)	8
Other current assets	3	9	(21)
Other assets	5	11	(12)
Accounts payable	(10)	(75)	4
Accounts payable—affiliated companies	1	(3)	1
Gas imbalance liabilities	0	(3)	10
Other current liabilities	(32)	39	4
Other liabilities	(5)	(12)	15
Net cash provided by operating activities	757	942	924
Cash Flows from Investing Activities:
Capital expenditures	(215)	(432)	(728)
Acquisitions, net of cash acquired	0	0	(443)
Proceeds from sale of assets	20	1	8
Proceeds from insurance	1	1	2
Return of investment in equity method affiliate	8	8	7
Other, net	4	(8)	0
Net cash used in investing activities	(182)	(430)	(1,154)
Cash Flows from Financing Activities:
Increase (decrease) increase in short-term debt	95	(494)	244
Proceeds from long-term debt, net of issuance costs	0	1,544	787
Repayment of long-term debt	(267)	(700)	(450)
Proceeds from Revolving Credit Facility	869	0	350
Repayment of Revolving Credit Facility	(869)	(250)	(100)
Proceeds from issuance of common units, net of issuance costs	0	0	2
Distributions to common unitholders	(360)	(564)	(551)
Distributions to preferred unitholders	(36)	(36)	(36)
Distributions to non-controlling interests	(6)	(5)	(4)
Cash paid for employee equity-based compensation	(2)	(25)	(9)
Net cash (used in) provided by financing activities	(576)	(530)	233
Net (Decrease) Increase in Cash and Cash Equivalents	(1)	(18)	3
Cash and Cash Equivalents at Beginning of Period	4	22	19
Cash and Cash Equivalents at End of Period	$ 3	$ 4	$ 22

Consolidated Statements of Partners' Equity - USD ($) shares in Millions, $ in Millions	Total	Cumulative Effect, Period of Adoption, Adjustment [Member]	Noncontrolling Interest	Series A Preferred Units Preferred Units	Common Units Partners' Capital	Common Units Partners' Capital Cumulative Effect, Period of Adoption, Adjustment [Member]	Accumulated Other Comprehensive Earnings
Balance, beginning of period (in units) at Dec. 31, 2017				15	433
Balance, beginning of period at Dec. 31, 2017	$ 7,654		$ 12	$ 362	$ 7,280		$ 0
Changes in Partners' Capital
Net income (loss)	523		2	36	$ 485
Issuance of common units					0
Issuance of common units	2				$ 2
Acquisition of EOCS	28		28
Distributions	(591)		(4)	$ (36)	$ (551)
Equity based compensation (in units)					0
Equity-based compensation, net of units for employee taxes	(2)				$ (2)
Balance, end of period (in units) at Dec. 31, 2018				15	433
Balance, end of period at Dec. 31, 2018	7,618		38	$ 362	$ 7,218		0
Changes in Partners' Capital
Net income (loss)	400		4	36	360
Other comprehensive loss (in units)					0
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
Balance, end of period at Dec. 31, 2019	7,409	$ (3)	37	$ 362	$ 7,013	$ (3)	(3)
Changes in Partners' Capital
Net income (loss)	83		(5)	36	52
Other comprehensive loss (in units)					0
Other comprehensive loss	(3)						(3)
Distributions	(402)		(6)	$ (36)	$ (360)
Equity based compensation (in units)					0
Equity-based compensation, net of units for employee taxes	(11)				$ (11)
Balance, end of period (in units) at Dec. 31, 2020				15	435
Balance, end of period at Dec. 31, 2020	$ 7,095		$ 26	$ 362	$ 6,713		$ (6)

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2020

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Summary of Significant Accounting Policies

Organization

Enable Midstream Partners, LP (the 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. Our gathering and processing segment primarily provides natural gas gathering and processing services to our producer customers and crude oil, condensate and produced water gathering services to our producer and refiner customers. Our 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. Our 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. Our crude oil gathering assets are located in Oklahoma and North Dakota and serve crude oil production in the Anadarko and Williston Basins. Our 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, 2020, 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 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, 2020, 2019 and 2018, the Partnership owned a 50% interest in SESH. See Note 11 for further discussion of SESH. For the years ended December 31, 2020, 2019 and 2018, the Partnership owned a 50% ownership interest in Atoka and consolidated Atoka in the accompanying 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 of November 1, 2018 through December 31, 2020, the Partnership owned a 60% interest in ESCP, which is consolidated in the accompanying 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). 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 the current month’s nominations and contracted prices. Revenues associated with the production of NGLs are estimated based on the current month’s 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, 2020, one non-affiliate customer accounted for approximately 13%, or $310 million of our consolidated revenue. 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 year ended December 31, 2018. See note 16 for more information on revenues from affiliates.

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 and amortization, Operation and maintenance and General and administrative expenses and consists primarily of product and fuel costs. Estimates for purchases are based on estimated volumes and contracted purchase prices. Estimated 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 $3 million and $0 accrued at December 31, 2020 and 2019, respectively.

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 Tax

The Partnership’s earnings are not subject to income tax (other than Texas state margin tax 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 tax 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 $3 million and $4 million of cash and cash equivalents as of December 31, 2020 and 2019, respectively.

Accounts Receivable and Allowance for Doubtful Accounts

The Partnership adopted ASU No. 2016-13, “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” on January 1, 2020. Upon adoption, the Partnership recognized a $3 million cumulative adjustment to Partners’ Equity and a corresponding adjustment to 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 primarily upon the historical loss-rate method established for various pools of accounts receivables with similar levels of credit risk. The historical loss-rates are then adjusted, as necessary, based on current conditions and forecast information that could result in 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 and other receivable balances within other assets at least quarterly, giving consideration to credit losses, the aging of receivables, specific customer circumstances that may impact their ability to pay the amounts due and current and forecast economic conditions over the assets contractual lives. The following table summarizes the required allowance for doubtful accounts.


	December 31, 2020		January 1, 2020

	(In millions)
Accounts receivable	$	1	$	2
Other assets	3		3
Total Allowance for doubtful accounts	$	4	$	5

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, 2020, 2019 and 2018. 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, 2020, 2019 and 2018, the Partnership recorded write-downs to net realizable value related to natural gas and natural gas liquids inventory of $10 million, $8 million and $4 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,
	2020		2019

	(In millions)
Materials and supplies	$	32	$	32
Natural gas and natural gas liquids	10		14
Total Inventory	$	42	$	46

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.

Impairment of Long-Lived Assets (including Intangible Assets)

The Partnership periodically evaluates long-lived assets, including property, plant and equipment, and specifically identifiable intangibles other than goodwill, when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable. The determination of whether an impairment has occurred is based on an estimate of undiscounted cash flows attributable to the assets, as compared to the carrying value of the assets. For more information, see Note 8.

Impairment of Investment in Equity Method Affiliate

The Partnership evaluates its Investment in equity method affiliate for impairment when factors indicate that an other than temporary decrease in the value of its investment has occurred and the carrying amount of its investment may not be recoverable. The Partnership utilizes the market or income approaches to estimate the fair value of the investment, 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 investment is then compared to the carrying amount of the investment and an impairment charge equal to the difference, is recorded to Equity in earnings (losses) of equity method affiliate, net. Any basis difference between our recognized Investment in equity method affiliate and the underlying financial statements of the affiliate are assigned to the applicable net assets of the affiliate. For more information, see Note 11.

Impairment of Goodwill

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, 2020 and 2019, these removal costs of $25 million and $24 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, 2020, 2019 and 2018, the Partnership capitalized interest and

AFUDC of $2 million, $2 million and $6 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 certain 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

The Partnership has 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, 2020, 2019 and 2018, the Partnership contributed $20 million, $20 million and $19 million, respectively.During the years ended December 31, 2020, 2019 and 2018, the Partnership had certain employees who are participants under OGE Energy’s defined benefit and retiree medical plans, who will remain seconded to the Partnership, subject to certain termination rights of the Partnership and OGE Energy. For the years ended December 31, 2020, 2019 and 2018, the Partnership reimbursed OGE Energy $2 million, $3 million and $3 million, respectively, for these benefits. See Note 16 for further information related to our related party transactions.

New Accounting Pronouncements	12 Months Ended
New Accounting Pronouncements	Dec. 31, 2020
Accounting Changes and Error Corrections [Abstract]
New Accounting Pronouncements	New Accounting Pronouncements Reference Rate Reform In March 2020, the FASB issued ASU No. 2020-04, “Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting.” This standard provides optional guidance, for a limited time, to ease the potential burden in accounting for or recognizing the effects of reference rate reform on financial reporting. The standard was effective upon issuance and generally can be applied through December 31, 2022. The Partnership adopted ASU 2020-04 during the year ended December 31, 2020. The implementation had no material impact on the Consolidated Financial Statements and related disclosures.

- Definition

The entire disclosure for change in accounting principle. Includes, but is not limited to, nature, reason, and method of adopting amendment to accounting standards or other change in accounting principle.

+ References

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+ Details

Revenues

12 Months Ended

Dec. 31, 2020

Revenue from Contract with Customer [Abstract]

Revenues

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, 2020, 2019 and 2018.


	Year Ended December 31, 2020
	Gathering and Processing		Transportation and Storage		Eliminations		Total

	(In millions)
Revenues:
Product sales:
Natural gas	$	249	$	328	$	(285)	$	292
Natural gas liquids	762		10		(10)		762
Condensate	68		—		—		68
Total revenues from natural gas, natural gas liquids, and condensate	1,079		338		(295)		1,122
Gain on derivative activity	8		2		—		10
Total Product sales	$	1,087	$	340	$	(295)	$	1,132
Service revenues:
Demand revenues	$	135	$	491	$	—	$	626
Volume-dependent revenues	664		50		(9)		705
Total Service revenues	$	799	$	541	$	(9)	$	1,331
Total Revenues	$	1,886	$	881	$	(304)	$	2,463


	Year Ended December 31, 2019
	Gathering and Processing		Transportation and Storage		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 Processing		Transportation and Storage		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.

MRT Rate Case Settlements

In June 2018, MRT filed a general NGA rate case (the 2018 Rate Case), and in October 2019, MRT filed a second rate case (the 2019 Rate Case). MRT began collecting the rates proposed in the 2018 Rate Case, subject to refund, on January 1, 2019. On March 26, 2020, FERC issued an order approving settlements filed in the 2018 Rate Case and the 2019 Rate Case. Upon issuance of the order and approval of the settlement of the MRT rate cases, the Partnership recognized $17 million of revenues from amounts previously held in reserve related to transportation and storage services performed in 2019. In May 2020, $21 million previously held in reserve was refunded to customers, which is inclusive of interest.

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, net of allowance for doubtful accounts.


	December 31, 2020		December 31, 2019

	(In millions)
Accounts Receivable:
Customers	$	245	$	239
Contract assets (1)	12		18
Non-customers	6		12
Total Accounts Receivable (2)	$	263	$	269

____________________

(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 contract assets related to firm transportation contracts with tiered rates of $9 million as of December 31, 2020 and $6 million as of December 31, 2019, 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, 2020:


	Year Ended December 31,
	2020		2019

	(In millions)
Deferred revenues, beginning of period (1)	$	48	$	48
Amounts recognized in revenues related to the beginning balance	(25)		(24)
Net additions	21		24
Deferred revenues, end of period (1)	$	44	$	48

The table below summarizes the timing of recognition of these contract liabilities as of December 31, 2020:


	2021		2022		2023		2024		2025 and After

	(In millions)
Deferred revenues (1)	$	23	$	7	$	6	$	6	$	2

____________________

(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, 2020.


	2021		2022		2023		2024		2025 and After

	(In millions)
Transportation and Storage	$	443	$	371	$	336	$	250	$	938
Gathering and Processing	120		123		121		101		213
Total remaining performance obligations	$	563	$	494	$	457	$	351	$	1,151

- Definition

The entire disclosure of revenue from contract with customer to transfer good or service and to transfer nonfinancial asset. Includes, but is not limited to, disaggregation of revenue, credit loss recognized from contract with customer, judgment and change in judgment related to contract with customer, and asset recognized from cost incurred to obtain or fulfill contract with customer. Excludes insurance and lease contracts.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-URI http://asc.fasb.org/topic&trid=49130388

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 10
-URI http://asc.fasb.org/extlink&oid=121604090&loc=SL49130551-203045

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 13
-Subparagraph (b)(2)
-URI http://asc.fasb.org/extlink&oid=121604090&loc=SL49130556-203045

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 12
-Subparagraph (b)
-URI http://asc.fasb.org/extlink&oid=121604090&loc=SL49130554-203045

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 9
-URI http://asc.fasb.org/extlink&oid=121604090&loc=SL49130550-203045

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 12
-Subparagraph (e)
-URI http://asc.fasb.org/extlink&oid=121604090&loc=SL49130554-203045

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 12
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=121604090&loc=SL49130554-203045

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 12
-Subparagraph (d)
-URI http://asc.fasb.org/extlink&oid=121604090&loc=SL49130554-203045

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 15
-URI http://asc.fasb.org/extlink&oid=121604090&loc=SL49130558-203045

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 12
-Subparagraph (c)
-URI http://asc.fasb.org/extlink&oid=121604090&loc=SL49130554-203045

+ Details

Leases

12 Months Ended

Dec. 31, 2020

Leases [Abstract]

Leases

(4) 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 Statements of Partners’ Equity and we did not have any material changes in the timing of expense recognition or our accounting policies.

Description of Lease Contracts

Our lease obligations are primarily comprised of rentals of field equipment and office space, 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. The Partnership is generally not aware of the implicit rate for either field equipment or office space 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, 2020, the weighted average remaining lease term is 7.0 years and the weighted average discount rate is 5.47%. A description of our lease contracts follows:

Field equipment: Field equipment has an expected lease term of 3 to 5 years, with contractual base terms of 1 to 3 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. The Partnership has compression service agreements, some of which are on a month-to-month basis and some of which expire in 2021. The Partnership also has gas treating lease agreements, of which some are on a month-to-month basis, while others will expire in 2021 and in 2022. Field equipment lease costs are reflected in Operation and maintenance expense in the Consolidated Statements of Income.

Office space: Office spaces have an expected lease term of 7 to 10 years, which is currently the same as the contractual base term. Office space rental arrangements contain market-based renewal options of up to 15 years. Variable lease payments for office spaces are generally comprised of costs for utilities, maintenance and building management services. Variable lease payments due under office space rental arrangements began July 1, 2019, with amounts due monthly. The Partnership occupies principal executive offices in Oklahoma City, Oklahoma, as well as office space in Houston, Texas. Our office leases are long-term in nature and represent $17 million of our right-of-use assets and $20 million of our lease liability as of December 31, 2020. Office space lease costs, including a proportionate percentage of facility expenses, are reflected in General and administrative expense in the Consolidated Statements of Income.

The table below summarizes the operating leases included in the Consolidated Balance Sheets.


	Balance Sheet Location	December 31, 2020		December 31, 2019

		(In millions)
Operating lease asset	Other Assets	$	25	$	37
Total right-of-use assets		$	25	$	37

Operating lease liabilities	Other Current Liabilities	$	4	$	9
Operating lease liabilities	Other Liabilities	24		31
Total lease liabilities		$	28	$	40

As of December 31, 2020, all lease obligations were classified as operating leases. Therefore, all cash flows are reflected in Cash Flows from Operating Activities.

The following table presents the Partnership’s rental costs associated with field equipment and office space.


	Year Ended December 31,
	2020		2019

	(In millions)
Rental Costs:
Field equipment	$	16	$	29
Office space	6		7

The following table presents the Partnership’s lease cost.


	Year Ended December 31,
	2020		2019

	(In millions)
Lease Cost:
Operating lease cost	$	8	$	11
Short-term lease cost	12		24
Variable lease cost	2		1
Total Lease Cost	$	22	$	36

The Partnership recorded short-term lease costs of $1 million and $2 million in the transportation and storage reportable segment during the years ended December 31, 2020 and 2019, respectively. All other lease costs were included in the gathering and processing reportable segment.

Under ASC 842, as of December 31, 2020, the Partnership has operating lease obligations expiring at various dates. Undiscounted cash flows for operating lease liabilities are as follows:


	Non-cancellable operating leases
	(In millions)
Year Ending December 31,
2021	$	6
2022	5
2023	5
2024	4
2025	3
After 2025	8
Total	31
Less: impact of the applicable discount rate	3
Total lease liabilities	$	28

ASC 840 Lease Accounting

Under ASC 840 rental expense was $35 million during the year ended December 31, 2018.

Acquisitions

12 Months Ended

Dec. 31, 2020

Business Combinations [Abstract]

Acquisitions

Acquisition

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 accompanying Consolidated Financial Statements. The Partnership incurred approximately $6 million of acquisition costs associated with this transaction during the year ended December 31, 2018, 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 year ended December 31, 2018, as the impact would not be material.

Earnings Per Limited Partner Unit

12 Months Ended

Dec. 31, 2020

Earnings Per Share [Abstract]

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 following table illustrates the Partnership’s calculation of earnings per unit for common units:


	Year Ended December 31,
	2020		2019		2018

	(In millions, except per unit data)
Net income	$	83	$	400	$	523
Net income (loss) attributable to noncontrolling interests	(5)		4		2
Series A Preferred Unit distributions	36		36		36
General partner interest in net income	—		—		—
Net income available to common units	$	52	$	360	$	485




Net income allocable to common units	$	52	$	360	$	485
Dilutive effect of Series A Preferred Unit distribution (1)	—		—		—
Diluted net income allocable to common units	$	52	$	360	485






Basic weighted average number of outstanding common units (2)	437		436		434
Dilutive effect of Series A Preferred Units (1)	—		—		—
Dilutive effect of performance units (3)	1		1		2
Diluted weighted average number of outstanding common units	438		437		436


Basic and diluted earnings per common unit
Basic	$	0.12	$	0.83	$	1.12
Diluted	$	0.12	$	0.82	$	1.11

____________________

(1)For the years ended December 31, 2020, 2019, and 2018, the issuance of “if-converted” common units attributable to the Series A Preferred Units were excluded in the calculation of diluted earnings per common unit as the impact was anti-dilutive.

(2)Basic weighted average number of outstanding common units for the years ended December 31, 2020, 2019, and 2018 includes approximately 2 million, 1 million, and 1 million time-based phantom units, respectively.

(3)The dilutive effect of the performance unit awards was less than $0.01 per unit for the years ended December 31, 2020, 2019, and 2018.

Partners' Equity

12 Months Ended

Dec. 31, 2020

Equity [Abstract]

Partners' Equity

Partners’ Equity The Partnership Agreement requires that, within 60 days after the end of each quarter, the Partnership distribute all of its available cash (as defined in the Partnership Agreement) to unitholders of record on the applicable record date.

The Partnership paid or has authorized payment of the following cash distributions to common and subordinated unitholders, as applicable, during 2020, 2019 and 2018 (in millions, except for per unit amounts):


Quarter Ended	Record Date	Payment Date	Per Unit Distribution		Total Cash Distribution
2020
December 31, 2020 (1)	February 22, 2021	March 1, 2021	$	0.16525	$	72
September 30, 2020	November 17, 2020	November 24, 2020	0.16525		72
June 30, 2020	August 18, 2020	August 25, 2020	0.16525		72
March 31, 2020	May 19, 2020	May 27, 2020	0.16525		72

2019
December 31, 2019	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

_____________________

(1)The Board of Directors declared a $0.16525 per common unit cash distribution on February 12, 2021, to be paid on March 1, 2021, to common unitholders of record at the close of business on February 22, 2021.

The Partnership paid or has authorized payment of the following cash distributions to holders of the Series A Preferred Units during 2020, 2019, and 2018 (in millions, except for per unit amounts):


Quarter Ended	Record Date	Payment Date	Per Unit Distribution		Total Cash Distribution
2020
December 31, 2020 (1)	February 12, 2021	February 12, 2021	$	0.625	$	9
September 30, 2020	November 3, 2020	November 13, 2020	0.625		9
June 30, 2020	August 4, 2020	August 14, 2020	0.625		9
March 31, 2020	May 5, 2020	May 15, 2020	0.625		9

2019
December 31, 2019	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

_____________________

(1)The Board of Directors declared a $0.625 per Series A Preferred Unit cash distribution on February 12, 2021, to be paid on February 12, 2021 to Series A Preferred unitholders of record at the close of business on February 12, 2021.

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.

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 on February 18, 2016.

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, the 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. For the year ended December 31, 2020, the Partnership did not sell any common units under the ATM Program. For the year ended December 31, 2019, 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 registration statement filed with the SEC for the ATM Program expired on May 12, 2020, and the Partnership did not file a replacement registration statement.

Property, Plant and Equipment

12 Months Ended

Dec. 31, 2020

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

Property, plant and equipment includes the following:


	Weighted Average Useful Lives (Years)	December 31,
		2020		2019

		(In millions)
Property, plant and equipment, gross:
Gathering and Processing	34.5	$	8,275	$	8,252
Transportation and Storage	40.6	4,802		4,778
Construction work-in-progress		143		131
Total		$	13,220	$	13,161
Accumulated depreciation:
Gathering and Processing		1,429		1,252
Transportation and Storage		1,126		1,039
Total accumulated depreciation		2,555		2,291
Property, plant and equipment, net		$	10,665	$	10,870

The Partnership recorded depreciation expense of $358 million, $371 million and $351 million during the years ended December 31, 2020, 2019 and 2018, respectively. Effective January 1, 2019, the Partnership completed a depreciation study for the Gathering and Processing and Transportation and Storage reportable segments and the new depreciation rates were applied prospectively as a change in accounting estimate. On March 26, 2020, FERC issued an order approving MRT’s 2018 Rate Case and 2019 Rate Case settlements. As a result of the settlements, the new depreciation rates for MRT have been applied in accordance with the order. The new depreciation rates did not result in a material change in depreciation expense or results of operations.

Intangible Assets, Net

12 Months Ended

Dec. 31, 2020

Goodwill and Intangible Assets Disclosure [Abstract]

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,
	2020		2019

	(In millions)
Customer relationships:
Total intangible assets	$	840	$	840
Accumulated amortization	301		239
Net intangible assets	$	539	$	601

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, $62 million and $47 million during the years ended December 31, 2020, 2019 and 2018, respectively. The following table summarizes the Partnership’s expected amortization of intangible assets for each of the next five years:


	2021		2022		2023		2024		2025

	(In millions)
Expected amortization of intangible assets	$	62	$	62	$	62	$	62	$	62

Goodwill

12 Months Ended

Dec. 31, 2020

Goodwill and Intangible Assets Disclosure [Abstract]

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 2020, the commodity price declines due to the existing oversupply of crude oil, NGLs and natural gas were exacerbated by the ongoing COVID-19 pandemic and the economic effects of the pandemic, in addition to the dispute over crude oil production levels between Russia and members of OPEC led by Saudi Arabia in the first quarter. Despite the subsequent agreement in April 2020 by a coalition of nations including Russia and Saudi Arabia to reduce production of crude oil, the price of NGLs and crude oil have remained significantly lower than pre-pandemic levels. Amid such crude oil, NGL and natural gas price declines, producers cut back spending and shifted 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 Ark-La-Tex Basin reporting unit during the first quarter of 2020. At the same time, unit prices and market multiples for midstream companies with gathering and processing operations 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 Ark-La-Tex Basin reporting unit was more likely than not impaired as of March 31, 2020. As a result, the Partnership performed a quantitative test for our goodwill and determined that the carrying value of the Ark-La-Tex Basin reporting unit exceeded its fair value and that goodwill associated with the Ark-La-Tex Basin was completely impaired in the amount of $12 million. The impairment is included in Impairments of property plant, and equipment and goodwill on the Consolidated Statements of Income for the year ended December 31, 2020.

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 cut back spending and shifted 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, the 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.

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, 2018	$	98	$	—	$	98
Goodwill impairment	(86)		—		(86)
Balance as of December 31, 2019	12		—		12
Goodwill impairment	(12)		—		(12)
Balance as of December 31, 2020	$	—	$	—	$	—

Investment in Equity Method Affiliate

12 Months Ended

Dec. 31, 2020

Equity Method Investments and Joint Ventures [Abstract]

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, 2020 and 2019. 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.

At September 30, 2020, the Partnership estimated the fair value of its investment in SESH was below the carrying value and concluded the decline in value was other than temporary due to the expiration of a transportation contract and then current status of renewal negotiations. As a result, the Partnership recorded a $225 million impairment on its investment in SESH,

which is included in Equity in earnings (losses) of equity method affiliate, net in the Partnership’s Consolidated Statements of Income for the year ended December 31, 2020. The impairment analysis of the Partnership’s investment in SESH compared the estimated fair value of the investment to its carrying value. The fair value of the investment was determined using multiple valuation methodologies under both the market and income approaches. Due to the significant unobservable estimates and assumptions required, the Partnership concluded that the fair value estimate should be classified as a Level 3 measurement within the fair value hierarchy. The basis difference for our investment in SESH has been assigned to its property, plant and equipment and will be amortized over its approximately 50-year remaining useful life. See Note 1 for further information concerning the method used to evaluate and measure the impairment on the Partnership’s investment in SESH.

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, 2020, 2019 and 2018, the Partnership billed SESH $15 million, $17 million and $18 million, respectively, associated with these service agreements.

The Partnership includes equity in earnings (losses) of equity method affiliate, net under the Other Income (Expense) caption in the Consolidated Statements of Income for the years ended December 31, 2020, 2019 and 2018.

SESH:


	Year Ended December 31,
	2020		2019		2018

	(In millions)
Equity in Earnings of Equity Method Affiliate	$	15	$	17	$	26
Impairment of equity method affiliate investment	(225)		—		—
Equity in earnings (losses) of equity method affiliate, net	$	(210)	$	17	$	26
Distributions from Equity Method Affiliate (1)	$	23	$	25	$	33

____________________

(1)Distributions from equity method affiliate includes a $15 million, $17 million and $26 million return on investment and a $8 million, $8 million and $7 million return of investment for the years ended December 31, 2020, 2019 and 2018, respectively.

Summarized financial information of SESH:


	December 31,
	2020		2019

	(In millions)
Balance Sheets:
Current assets	$	49	$	49
Property, plant and equipment, net	1,043		1,060

Total assets	$	1,092	$	1,109
Current liabilities	$	31	$	30
Long-term debt	398		398
Members’ equity	663		681
Total liabilities and members’ equity	$	1,092	$	1,109
Reconciliation:
Investment in SESH	$	76	$	309
Add: Capitalized interest on investment in SESH	(1)		(1)
Add: Basis difference, net of amortization (1)	256		33
The Partnership’s share of members’ equity	$	331	$	341

____________________

(1)Includes the Partnership’s impairment of investment in equity method affiliate of $225 million recorded during the year ended December 31, 2020.


	Year Ended December 31,
	2020		2019		2018

	(In millions)
Income Statements:
Revenues	$	96	$	109	$	112
Operating income	44		50		67
Net income	26		33		50

Debt

12 Months Ended

Dec. 31, 2020

Debt Disclosure [Abstract]

Debt

The following table presents the Partnership’s outstanding debt as of December 31, 2020 and 2019.


	December 31, 2020						December 31, 2019
	Outstanding Principal		Premium (Discount)(1)		Total Debt		Outstanding Principal		Premium (Discount)(1)		Total Debt

	(In millions)
Commercial Paper	$	250	$	—	$	250	$	155	$	—	$	155
Revolving Credit Facility	—		—		—		—		—		—
2019 Term Loan Agreement	800		—		800		800		—		800

2024 Notes	600		—		600		600		—		600
2027 Notes	700		(2)		698		700		(2)		698
2028 Notes	800		(5)		795		800		(5)		795
2029 Notes	547		(1)		546		550		(1)		549
2044 Notes	531		—		531		550		—		550
EOIT Senior Notes	—		—		—		250		1		251
Total debt	$	4,228	$	(8)	$	4,220	$	4,405	$	(7)	$	4,398
Less: Short-term debt (2)					250						155
Less: Current portion of long-term debt (3)					—						251
Less: Unamortized debt expense (4)					19						23
Total long-term debt					$	3,951					$	3,969

___________________

(1)Unamortized premium (discount) on long-term debt is amortized over the life of the respective debt.

(2)Short-term debt includes $250 million and $155 million of commercial paper outstanding as of December 31, 2020 and 2019, respectively.

(3)As of December 31, 2019, Current portion of long-term debt included the $251 million outstanding balance of the EOIT Senior Notes which were repaid in March 2020.

(4)As of December 31, 2020 and 2019, there was an additional $3 million and $4 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):


2021	$	250
2022	800
2023	—
2024	600
2025	—
Thereafter	$	2,578

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 $250 million and $155 million outstanding under our commercial paper program at December 31, 2020 and December 31, 2019, respectively. The weighted average interest rate for the outstanding commercial paper was 0.86% as of December 31, 2020.

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 two-year term. As of December 31, 2020, there were no principal advances and no 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, 2020, 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, 2020, 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. Additionally, for the period of time during the construction by the Partnership or certain of its subsidiaries of a qualified project with a cost greater than $15 million and before the date such qualified project is substantially complete and commercially operable, the Partnership may make Qualified Project EBITDA Adjustments (as defined in the Revolving Credit Facility and 2019 Term Loan Agreement) by determining an amount as projected consolidated EBITDA attributable to such qualified project, which may be added to the actual consolidated EBITDA for the Partnership and those certain subsidiaries; provided that such amount (i) shall be no greater than 20% of the total actual consolidated EBITDA of the Partnership and those certain subsidiaries (as determined without the projected consolidated EBITDA attributable to such qualified project) and (ii) shall be subject to approval by the administrative agent.

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. As of December 31, 2020, there was $800 million outstanding under the 2019 Term Loan Agreement. 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, 2020, 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, 2020, the weighted average interest rate of the 2019 Term Loan Agreement was 2.10%.

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. For further discussion of Qualified Project EBITDA Adjustments, see “Revolving Credit Facility” above.

The 2019 Term Loan Agreement also contains covenants that restrict the Partnership and certain of its subsidiaries in respect of, among other things, mergers and consolidations, sales of all or substantially all assets, incurrence of subsidiary indebtedness, incurrence of liens, transactions with affiliates, designation of subsidiaries as Excluded Subsidiaries (as defined in the 2019 Term Loan Agreement), restricted payments, changes in the nature of their respective business and entering into certain restrictive agreements. The 2019 Term Loan Agreement is subject to acceleration upon the occurrence of certain defaults, including, among others, payment defaults on such facility, breach of representations, warranties and covenants, acceleration of indebtedness (other than intercompany and non-recourse indebtedness) of $100 million or more in the aggregate, change of control, nonpayment of uninsured judgments in excess of $100 million, and the occurrence of certain ERISA and bankruptcy events, subject, where applicable, to specified cure periods.

Senior Notes

As of December 31, 2020, the Partnership’s debt included the 2024 Notes, 2027 Notes, 2028 Notes, 2029 Notes and 2044 Notes, which had $8 million of unamortized discount and $19 million of unamortized debt expense at December 31, 2020, resulting in effective interest rates of 4.01%, 4.56%, 5.19%, 4.29% and 4.99%, respectively, during the year ended December 31, 2020. In May 2019, the Partnership’s 2019 Notes matured and were paid using proceeds from the 2019 Term Loan Agreement. In March 2020, the EOIT Senior Notes matured and were paid using proceeds from the Revolving Credit Facility.

During the year ended December 31, 2020, the Partnership repurchased $22 million aggregate principal amount of the 2029 Notes and 2044 Notes in open market transactions for approximately $17 million plus accrued interest, which resulted in a $5 million gain on extinguishment of debt. The gain is included in Other, net in the Consolidated Statements of Income.

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, 2020, the Partnership was in compliance with all of their debt agreements, including financial covenants.

Derivative Instruments and Hedging Activities

12 Months Ended

Dec. 31, 2020

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments and Hedging Activities

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 options, futures, swaps and swaptions, and WTI crude oil options, futures, swaps and swaptions are used to manage the Partnership’s NGL and condensate exposure associated with its processing agreements;

•natural gas options, futures, swaps and 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, 2020 and 2019, 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, 2020 and 2019, the Partnership had no interest rate derivative instruments that were designated as fair value hedges for accounting purposes.

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, 2020 and 2019, the Partnership had the following derivative instruments that were not designated as hedging instruments for accounting purposes:


	December 31, 2020		December 31, 2019
	Gross Notional Volume
	Purchases	Sales	Purchases	Sales
Natural gas— TBtu (1)
Financial fixed futures/swaps	—	18	10	19
Financial basis futures/swaps	—	27	11	30
Financial swaptions (2)	—	7	—	2
Physical purchases/sales	—	—	—	6
Crude oil (for condensate)— MBbl (3)
Financial futures/swaps	—	465	—	990
Financial swaptions (2)	—	90	—	225
Natural gas liquids— MBbl (4)
Financial futures/swaps	855	1,210	2,490	2,415
Financial swaptions (2)	—	45	—	—

____________________

(1)As of December 31, 2020, 95.7% of the natural gas contracts had durations of one year or less and 4.3% had durations of more than one year and less than two years. 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.

(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, 2020, 100.0% of the crude oil (for condensate) contracts had durations of one year or less. 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.

(4)As of December 31, 2020, 100.0% of the natural gas liquids contracts had durations of one year or less. 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.

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, 2020 and 2019, the Partnership had the following derivative instruments that were designated as hedging instruments for accounting purposes:


	December 31, 2020		December 31, 2019
	Gross Notional Value
	(In millions)
Interest rate swaps	$	300	$	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, 2020 and 2019 that were not designated as hedging instruments for accounting purposes are as follows:


		December 31, 2020				December 31, 2019
		Fair Value
Instrument	Balance Sheet Location	Assets		Liabilities		Assets		Liabilities

		(In millions)
Natural gas
Financial futures/swaps	Other Current	$	2	$	2	$	7	$	5
Financial swaptions	Other Current	1		2		—		—
Physical purchases/sales	Other Current	—		—		5		—
Financial futures/swaps	Other	—		—		—		1

Crude oil (for condensate)
Financial futures/swaps	Other Current	1		13		1		19
Financial futures/swaps	Other	—		—		—		8

Natural gas liquids
Financial futures/swaps	Other Current	15		3		25		3
Financial swaptions	Other Current	—		1		—		—
Financial futures/swaps	Other	—		—		11		2
Total gross derivatives (1)		$	19	$	21	$	49	$	38

_____________________

(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, 2020 and 2019.

The fair value of the derivative instruments that are presented in the Partnership’s Consolidated Balance Sheets as of December 31, 2020 and December 31, 2019 that were designated as hedging instruments for accounting purposes are as follows:


		December 31, 2020				December 31, 2019
		Fair Value
Instrument	Balance Sheet Location	Assets		Liabilities		Assets		Liabilities

		(In millions)
Interest rate swaps	Other Current	$	—	$	6	$	—	$	1
Interest rate swaps	Other	—		—		—		2
Total gross interest rate derivatives (1)		$	—	$	6	$	—	$	3

_____________________

(1)All interest rate derivative instruments that were designated as cash flow hedges are considered Level 2 as of December 31, 2020.

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, 2020, 2019 and 2018:


	Amounts Recognized in Income
	Year Ended December 31,
	2020		2019		2018

	(In millions)
Natural Gas
Financial futures/swaps gains (losses)	$	4	$	13	$	(8)
Financial swaptions gains (losses)	(2)		—		—
Physical purchases/sales gains	—		2		7
Crude oil (for condensate)
Financial futures/swaps gains (losses)	10		(41)		6

Natural gas liquids
Financial futures/swaps gains (losses)	(2)		42		6
Total	$	10	$	16	$	11

For derivatives not designated as hedges in the tables above, amounts recognized in income for the years ended December 31, 2020, 2019 and 2018 are reported in Product sales. For derivatives designated as hedges, amounts recognized in income and reported in Interest expense for the years ended December 31, 2020 and 2019 were approximately $4 million and zero, respectively.

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, 2020, 2019 and 2018:


	Year Ended December 31,
	2020		2019		2018

	(In millions)
Change in fair value of derivatives	$	(13)	$	(11)	$	26
Realized gain (loss) on derivatives	23		27		(15)
Gain on derivative activity	$	10	$	16	$	11

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, 2020, 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 less than $1 million of 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

12 Months Ended

Dec. 31, 2020

Fair Value Disclosures [Abstract]

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, 2020, 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, 2020, 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, 2020 and 2019:


	December 31, 2020				December 31, 2019
	Carrying Amount		Fair Value		Carrying Amount		Fair Value

	(In millions)
Debt
Revolving Credit Facility (Level 2) (1)	$	—	$	—	$	—	$	—
2019 Term Loan Agreement (Level 2)	800		800		800		800

2024 Notes (Level 2)	600		612		600		614
2027 Notes (Level 2)	698		709		698		698
2028 Notes (Level 2)	795		817		795		811
2029 Notes (Level 2)	546		544		549		526
2044 Notes (Level 2)	531		499		550		506
EOIT Senior Notes (Level 2)	—		—		251		252

______________________

(1) Borrowing capacity is effectively reduced by our borrowings outstanding under the commercial paper program. $250 million and $155 million of commercial paper was outstanding as of December 31, 2020 and 2019, respectively.

The fair value of the Partnership’s Revolving Credit Facility, 2019 Term Loan Agreement, 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, 2020, 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, 2020, all of the asset groups were considered recoverable. Based upon review for other than temporary declines in fair value, the investment in equity method affiliate was considered recoverable. Future price declines, throughput declines, contracted capacity declines, cost increases, regulatory or political environment changes and other changes in market conditions including the oversupply of crude oil, NGLs and natural gas as well as the ongoing COVID-19 pandemic and the economic effects of the pandemic, could reduce forecast undiscounted cash flows for the asset groups and result in other than temporary declines in the fair value of the investment in equity method affiliate.

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, 2020 and 2019, the Partnership’s Level 2 interest rate derivatives are recorded as liabilities with no netting adjustments. As of December 31, 2020 and 2019, there were no Level 3 commodity contracts. 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, 2020 and 2019:


December 31, 2020	Commodity Contracts				Gas Imbalances (1)
	Assets		Liabilities		Assets (2)		Liabilities (3)

	(In millions)
Quoted market prices in active market for identical assets (Level 1)	$	2	$	14	$	—	$	—
Significant other observable inputs (Level 2)	17		7		23		16

Total fair value	19		21		23		16
Netting adjustments	(19)		(19)		—		—
Total	$	—	$	2	$	23	$	16


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

Total fair value	49		38		14		11
Netting adjustments	(37)		(37)		—		—
Total	$	12	$	1	$	14	$	11

______________________

(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, 2020 and 2019.

(2)Gas imbalance assets exclude fuel reserves for under retained fuel due from shippers of $19 million and $21 million at December 31, 2020 and 2019, 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 $3 million and $8 million at December 31, 2020 and 2019, 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.

- Definition

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

+ References + Details

Supplemental Disclosure of Cash Flow Information

12 Months Ended

Dec. 31, 2020

Supplemental Cash Flow Information [Abstract]

Supplemental Disclosure of Cash Flow Information

The following table provides information regarding supplemental cash flow information:


	Year Ended December 31,
	2020		2019		2018

	(In millions)
Supplemental Disclosure of Cash Flow Information:
Cash Payments:
Interest, net of capitalized interest	$	180	$	185	$	148
Income tax, net of refunds	1		1		3
Non-cash transactions:
Accounts payable related to capital expenditures	9		10		54
Lease liabilities related to (derecognition) recognition of right-of-use assets	(5)		45		—
Impact of adoption of financial instruments-credit losses accounting standard (Note 1)	(3)		—		—

Related Party Transactions

12 Months Ended

Dec. 31, 2020

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

MRT provides firm transportation and firm storage services to CenterPoint Energy’s LDCs in Arkansas and Louisiana. As part of the MRT rate case settlements, contracts for these services were extended and are in effect through July 31, 2028 and will remain in effect thereafter unless and until terminated by either party upon twelve months’ prior written notice.

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 firm transportation, firm transportation with seasonal demand, firm storage and no-notice transportation with storage contracts were extended and have terms running through March 31, 2030. The maximum rate firm transportation contracts were also extended and have terms running through March 31, 2024.

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. We reimbursed CenterPoint Energy’s LDCs less than $1 million for the year ended December 31, 2020, and $2 million for the year ended December 31, 2019, in connection with receipt facility modifications that were necessitated by the repair and maintenance of our pipelines. For the year ended December 31, 2018, we reimbursed CenterPoint Energy’s LDCs $1 million in connection with a reimbursement associated with an unplanned pipeline outage.

Transportation and Storage Agreements 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 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 through December 1, 2038. EOIT paid OGE Energy $2 million and waived $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%, 6% and 5% of total revenues during the years ended December 31, 2020, 2019 and 2018, 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,
	2020		2019		2018

	(In millions)
Gas transportation and storage service revenues — CenterPoint Energy	$	100	$	108	$	111
Natural gas product sales — CenterPoint Energy	1		8		11
Gas transportation and storage service revenues — OGE Energy	38		41		37
Natural gas product sales — OGE Energy	10		10		4
Total revenues — affiliated companies	$	149	$	167	$	163

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,
	2020		2019		2018

	(In millions)
Cost of natural gas purchases — CenterPoint Energy	$	1	$	—	$	3
Cost of natural gas purchases — OGE Energy	24		33		23
Total cost of natural gas purchases — affiliated companies	$	25	$	33	$	26

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 2020 are less than $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, 2020, 2019 and 2018, the Partnership had certain employees who are participants under OGE Energy’s defined benefit and retiree medical plans, who will remain seconded to the Partnership, subject to certain termination rights of the Partnership and OGE Energy. The Partnership’s reimbursement of OGE Energy for seconded employee costs arising out of OGE Energy’s defined benefit and retiree medical plans is fixed at actual cost subject to a cap of $5 million in 2020 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,
	2020		2019		2018

	(In millions)
Corporate Services — CenterPoint Energy	$	—	$	—	$	1
Operating Lease — CenterPoint Energy	—		1		1
Seconded Employee Costs — OGE Energy	17		18		29
Corporate Services — OGE Energy	—		—		1
Total corporate services, operating lease and seconded employee expense	$	17	$	19	$	32

Commitments and Contingencies	12 Months Ended
Commitments and Contingencies	Dec. 31, 2020
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies 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. 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, 2020, the Partnership estimates the remaining associated minimum volume commitment fee to be $172 million in the aggregate. Minimum volume commitment fees are expected to be $23 million per year from 2021 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 requested approval to transfer existing EGT transportation infrastructure to the Gulf Run Pipeline. The Partnership filed applications with FERC to obtain authorization to construct and operate the pipeline on February 28, 2020. FERC issued the environmental assessment on October 29, 2020. Under the precedent agreement, the Partnership estimates the cost to complete the Gulf Run Pipeline project would be as much as $500 million. The project is backed by a 20-year firm transportation service agreement. 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 late 2022.

Income Taxes

12 Months Ended

Dec. 31, 2020

Income Tax Disclosure [Abstract]

Income Taxes

Income Tax

The Partnership’s earnings are generally not subject to income tax (other than Texas state margin tax 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 tax 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).

The items comprising income tax expense are as follows:


	Year Ended December 31,
	2020		2019		2018

	(In millions)
Provision for current income tax
Federal	$	(2)	$	—	$	—
State	1		—		—
Total provision for current income tax	(1)		—		—
Benefit for deferred income tax, net
Federal	$	1	$	(1)	$	(1)
State	—		—		—
Total benefit for deferred income tax, net	1		(1)		(1)
Total income tax benefit	$	—	$	(1)	$	(1)

The components of Deferred Income Tax as of December 31, 2020 and 2019 were as follows:


	December 31,
	2020		2019

	(In millions)
Deferred tax liabilities, net:
Non-current:
Intercompany management fee	$	16	$	17
Depreciation	5		6
Net operating loss	(1)		(2)
Accrued compensation	(15)		(17)
Total deferred tax liabilities, net	$	5	$	4

Uncertain Income Tax Positions

There were no unrecognized tax benefits as of December 31, 2020, 2019 and 2018.

Tax Audits and Settlements

The federal income tax return of the Partnership has been audited through the 2013 tax year.

Net Operating Losses

The Partnership’s corporate subsidiary, Enable Midstream Services, has federal and state net operating losses (NOL) the tax benefits of which are recorded as deferred tax assets. As of December 31, 2020, the Partnership had approximately $4 million of Federal NOLs, which can be carried forward indefinitely and approximately $8 million of various State NOLs, of which approximately $2 million will expire between 2023 and 2039. Additionally, as of December 31, 2020, the Partnership had a deferred tax asset related to Federal and State NOLs of $1 million and zero, respectively.

- Definition

The entire disclosure for income taxes. Disclosures may include net deferred tax liability or asset recognized in an enterprise's statement of financial position, net change during the year in the total valuation allowance, approximate tax effect of each type of temporary difference and carryforward that gives rise to a significant portion of deferred tax liabilities and deferred tax assets, utilization of a tax carryback, and tax uncertainties information.

+ References + Details

Equity Based Compensation

12 Months Ended

Dec. 31, 2020

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 Sheets. The following table summarizes the Partnership’s equity-based compensation expense for the years ended December 31, 2020, 2019 and 2018 related to performance units, restricted units and phantom units for the Partnership’s employees and independent directors:


	Year Ended December 31,
	2020		2019		2018

	(In millions)
Performance units	$	7	$	9	$	9
Restricted units	—		—		1
Phantom units	6		7		6
Total equity-based compensation expense	$	13	$	16	$	16

Performance Units

Awards of performance based phantom units (performance units) have been made under the LTIP in 2020, 2019 and 2018 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 2020, 2019 and 2018 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 2020, 2019 and 2018 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.


	2020			2019			2018
Number of units granted	933,738			638,798			551,742
Fair value of units granted	$	7.00		$	19.95		$	17.70
Expected price volatility	27.7		%	34.2		%	44.2		%
Risk-free interest rate	0.85		%	2.54		%	2.36		%
Distribution yield	12.27		%	8.38		%	8.56		%
Expected life of units (in years)	3			3			3

Phantom Units

Awards of phantom units have been made under the LTIP in 2020, 2019 and 2018 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.


	2020	2019	2018
Phantom units granted	1,002,345	695,486	546,708
Fair value of phantom units granted	$2.67 - $10.13	$8.95 - $15.04	$13.74 - $17.00

Other Awards

In 2020, 2019 and 2018, 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.


	2020		2019		2018
Common units granted	63,963		28,221		16,335
Fair value of common units granted	$	4.23	$	10.43	$	14.94

Units Outstanding

A summary of the activity for the Partnership’s performance units and phantom units as of December 31, 2020 and changes during 2020 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 12/31/2019	1,393,329		$	19.04	1,392,560		$	14.65
Granted (1)	933,738		7.00		1,002,345		6.44
Vested (2)(3)	(390,079)		19.21		(399,406)		15.76
Forfeited	(171,480)		14.25		(204,654)		10.46
Units outstanding at 12/31/2020	1,765,508		13.10		1,790,845		$	10.29
Aggregate intrinsic value of units outstanding at December 31, 2020	$	9			$	9

_____________________

(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, 2020 include 376,292 from the 2017 annual grant, 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 the performance period of January 1, 2017 through December 31, 2019, no performance units vested.

(3)Performance units outstanding as of December 31, 2020 include 389,817 units from the 2018 annual grants, which were approved by the Board of Directors in 2018 and, based on the level of achievement of a performance goal established by the Board of Directors over a performance period of January 1, 2018 through December 31, 2020, will vest at 0%. 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, 2020, 2019 and 2018 are shown in the following tables.


	Year Ended December 31, 2020
	Performance Units		Restricted Stock		Phantom Units

	(In millions)
Aggregate intrinsic value of units vested	$	—	$	—	$	3
Fair value of units vested	7		—		6


	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		—

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, 2020
	Unrecognized Compensation Cost (In millions)		Weighted Average Period for Recognition (In years)
Performance Units	$	9	1.43

Phantom Units	6		1.30
Total	$	15

As of December 31, 2020, there were 5,234,214 units available for issuance under the long-term incentive plan.

Reportable Segments

12 Months Ended

Dec. 31, 2020

Segment Reporting [Abstract]

Reportable Segments

The Partnership’s determination of reportable segments considers the strategic operating units under which it manages sales, allocates resources and assesses performance of various products and services to 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. Our gathering and processing segment primarily provides natural gas gathering and processing services to our producer customers and crude oil, condensate and produced water gathering services to our producer and refiner customers. Our 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, 2020	Gathering and Processing		Transportation and Storage (1)		Eliminations		Total

	(In millions)
Product sales	$	1,087	$	340	$	(295)	$	1,132
Service revenues	799		541		(9)		1,331
Total Revenues	1,886		881		(304)		2,463
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)	936		332		(303)		965
Operation and maintenance, General and administrative	334		183		(1)		516
Depreciation and amortization	299		121		—		420
Impairments of property, plant and equipment and goodwill	28		—		—		28
Taxes other than income tax	42		27		—		69
Operating Income	$	247	$	218	$	—	$	465
Total Assets	$	10,830	$	5,729	$	(4,830)	$	11,729
Capital expenditures	$	107	$	108	$	—	$	215


Year Ended December 31, 2019	Gathering and Processing		Transportation and Storage (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 of property, plant and equipment and goodwill	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 Processing		Transportation and Storage (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

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

_____________________

(1)See Note 11 for discussion regarding ownership interests in SESH and related equity earnings (losses) included in the transportation and storage reportable segment for the years ended December 31, 2020, 2019 and 2018.

- Definition

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

+ References

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+ Details

Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2020

Quarterly Financial Information Disclosure [Abstract]

Quarterly Financial Data (Unaudited)

Summarized unaudited quarterly financial data for 2020 and 2019 are as follows:


	Quarters Ended
	March 31, 2020		June 30, 2020		September 30, 2020		December 31, 2020

	(in millions, except per unit data)
Total Revenues	$	648	$	515	$	596	$	704
Cost of natural gas and natural gas liquids	226		177		250		312
Operating income	146		80		100		139
Net income (loss) (1)	105		44		(163)		97
Net income (loss) attributable to limited partners	112		44		(164)		96
Net income (loss) attributable to common units	103		35		(173)		87

Basic and diluted earnings per unit
Basic	$	0.24	$	0.08	$	(0.40)	$	0.20
Diluted	$	0.19	$	0.08	$	(0.40)	$	0.19


	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 (2)	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 and diluted earnings per unit
Basic	$	0.26	$	0.26	$	0.28	$	0.02
Diluted	$	0.26	$	0.26	$	0.28	$	0.02

_____________________

(1)The Partnership recorded an impairment of $225 million in Equity in earnings (losses) of equity method affiliate, net during the third quarter related to its investment in SESH. See Note 11 for further information.

(2)The Partnership recorded impairments to goodwill of $12 million and $86 million during the first quarter 2020 related to the Ark-La-Tex Basin reporting unit and the fourth quarter of 2019 related to the Anadarko Basin reporting unit, respectively, included in the gathering and processing reportable segment. See Note 10 for further information.

Subsequent Event	12 Months Ended
Subsequent Event	Dec. 31, 2020
Subsequent Events [Abstract]
Subsequent Event	Subsequent Event On February 17, 2021, the Partnership and Energy Transfer announced their entry into a definitive merger agreement pursuant to which Energy Transfer, through wholly owned subsidiaries, will acquire the Partnership. Under the terms of the merger agreement, the Partnership’s common unitholders will receive 0.8595 of one common unit representing limited partner interests in Energy Transfer in exchange for each Partnership common unit. In addition, each issued and outstanding Series A preferred unit of the Partnership will be exchanged for 0.0265 of an Energy Transfer Series G preferred unit, and Energy Transfer will make a $10 million cash payment for the limited liability company interests in the Partnership’s general partner. The transaction has been approved by the Conflicts Committee and the Board of Directors of Enable GP. CenterPoint Energy and OGE Energy, who collectively own approximately 79.2% of Partnership common units, have entered into support agreements pursuant to which they have agreed to vote their common units in favor of the merger. The transaction is subject to the satisfaction of customary closing conditions.

Summary of Significant Accounting Policies (Policies)	12 Months Ended
Summary of Significant Accounting Policies (Policies)	Dec. 31, 2020
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization	Organization Enable Midstream Partners, LP (the 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. Our gathering and processing segment primarily provides natural gas gathering and processing services to our producer customers and crude oil, condensate and produced water gathering services to our producer and refiner customers. Our 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. Our 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. Our crude oil gathering assets are located in Oklahoma and North Dakota and serve crude oil production in the Anadarko and Williston Basins. Our 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, 2020, 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 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, 2020, 2019 and 2018, the Partnership owned a 50% interest in SESH. See Note 11 for further discussion of SESH. For the years ended December 31, 2020, 2019 and 2018, the Partnership owned a 50% ownership interest in Atoka and consolidated Atoka in the accompanying 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 of November 1, 2018 through December 31, 2020, the Partnership owned a 60% interest in ESCP, which is consolidated in the accompanying 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 PresentationThe 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). 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 the current month’s nominations and contracted prices. Revenues associated with the production of NGLs are estimated based on the current month’s 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.
Natural Gas and Natural Gas Liquids Purchases	Natural Gas and Natural Gas Liquids PurchasesCost of natural gas and natural gas liquids represents the cost of our natural gas and natural gas liquids purchased exclusive of depreciation and amortization, Operation and maintenance and General and administrative expenses and consists primarily of product and fuel costs. Estimates for purchases are based on estimated volumes and contracted purchase prices. Estimated 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 CostsThe 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.
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 Tax The Partnership’s earnings are not subject to income tax (other than Texas state margin tax 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 tax 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 EquivalentsThe Partnership considers cash equivalents to be short-term, highly liquid investments with maturities of three months or less from the date of purchase.
Accounts Receivable and Allowance for Doubtful Accounts	Accounts Receivable and Allowance for Doubtful Accounts The Partnership adopted ASU No. 2016-13, “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” on January 1, 2020. Upon adoption, the Partnership recognized a $3 million cumulative adjustment to Partners’ Equity and a corresponding adjustment to 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 primarily upon the historical loss-rate method established for various pools of accounts receivables with similar levels of credit risk. The historical loss-rates are then adjusted, as necessary, based on current conditions and forecast information that could result in 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 and other receivable balances within other assets at least quarterly, giving consideration to credit losses, the aging of receivables, specific customer circumstances that may impact their ability to pay the amounts due and current and forecast economic conditions over the assets contractual lives
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, 2020, 2019 and 2018. 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, 2020, 2019 and 2018, the Partnership recorded write-downs to net realizable value related to natural gas and natural gas liquids inventory of $10 million, $8 million and $4 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), Impairment of Long-lived Assets (including Intangible Assets), Impairment of Investment in Equity Method Affiliate and Impairment of 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. Impairment of Long-Lived Assets (including Intangible Assets) The Partnership periodically evaluates long-lived assets, including property, plant and equipment, and specifically identifiable intangibles other than goodwill, when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable. The determination of whether an impairment has occurred is based on an estimate of undiscounted cash flows attributable to the assets, as compared to the carrying value of the assets. Impairment of Investment in Equity Method Affiliate The Partnership evaluates its Investment in equity method affiliate for impairment when factors indicate that an other than temporary decrease in the value of its investment has occurred and the carrying amount of its investment may not be recoverable. The Partnership utilizes the market or income approaches to estimate the fair value of the investment, 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 investment is then compared to the carrying amount of the investment and an impairment charge equal to the difference, is recorded to Equity in earnings (losses) of equity method affiliate, net. Any basis difference between our recognized Investment in equity method affiliate and the underlying financial statements of the affiliate are assigned to the applicable net assets of the affiliate.Impairment of GoodwillThe 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 LiabilitiesThe 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.
Capitalization of Interest and Allowance for Funds Used During Construction	Capitalization of Interest and Allowance for Funds Used During ConstructionAllowance 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.
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 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 options, futures, swaps and swaptions, and WTI crude oil options, futures, swaps and swaptions are used to manage the Partnership’s NGL and condensate exposure associated with its processing agreements; •natural gas options, futures, swaps and 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, 2020 and 2019, 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, 2020 and 2019, the Partnership had no interest rate derivative instruments that were designated as fair value hedges for accounting purposes. 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, 2020, 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, 2020, 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 certain 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	Employee Benefit Plans The Partnership has 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.
New Accounting Pronouncements	New Accounting Pronouncements Reference Rate Reform In March 2020, the FASB issued ASU No. 2020-04, “Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting.” This standard provides optional guidance, for a limited time, to ease the potential burden in accounting for or recognizing the effects of reference rate reform on financial reporting. The standard was effective upon issuance and generally can be applied through December 31, 2022. The Partnership adopted ASU 2020-04 during the year ended December 31, 2020. The implementation had no material impact on the Consolidated Financial Statements and related disclosures.
Contracts with Master Netting Arrangements	Contracts with Master Netting ArrangementsFair 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. Our gathering and processing segment primarily provides natural gas gathering and processing services to our producer customers and crude oil, condensate and produced water gathering services to our producer and refiner customers. Our 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 Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2020

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Accounts Receivable, Allowance for Credit Loss

The following table summarizes the required allowance for doubtful accounts.


	December 31, 2020		January 1, 2020

	(In millions)
Accounts receivable	$	1	$	2
Other assets	3		3
Total Allowance for doubtful accounts	$	4	$	5

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,
	2020		2019

	(In millions)
Materials and supplies	$	32	$	32
Natural gas and natural gas liquids	10		14
Total Inventory	$	42	$	46

Revenues (Tables)

12 Months Ended

Dec. 31, 2020

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, 2020, 2019 and 2018.


	Year Ended December 31, 2020
	Gathering and Processing		Transportation and Storage		Eliminations		Total

	(In millions)
Revenues:
Product sales:
Natural gas	$	249	$	328	$	(285)	$	292
Natural gas liquids	762		10		(10)		762
Condensate	68		—		—		68
Total revenues from natural gas, natural gas liquids, and condensate	1,079		338		(295)		1,122
Gain on derivative activity	8		2		—		10
Total Product sales	$	1,087	$	340	$	(295)	$	1,132
Service revenues:
Demand revenues	$	135	$	491	$	—	$	626
Volume-dependent revenues	664		50		(9)		705
Total Service revenues	$	799	$	541	$	(9)	$	1,331
Total Revenues	$	1,886	$	881	$	(304)	$	2,463


	Year Ended December 31, 2019
	Gathering and Processing		Transportation and Storage		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 Processing		Transportation and Storage		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, net of allowance for doubtful accounts.


	December 31, 2020		December 31, 2019

	(In millions)
Accounts Receivable:
Customers	$	245	$	239
Contract assets (1)	12		18
Non-customers	6		12
Total Accounts Receivable (2)	$	263	$	269

____________________

(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, 2020:


	Year Ended December 31,
	2020		2019

	(In millions)
Deferred revenues, beginning of period (1)	$	48	$	48
Amounts recognized in revenues related to the beginning balance	(25)		(24)
Net additions	21		24
Deferred revenues, end of period (1)	$	44	$	48

The table below summarizes the timing of recognition of these contract liabilities as of December 31, 2020:


	2021		2022		2023		2024		2025 and After

	(In millions)
Deferred revenues (1)	$	23	$	7	$	6	$	6	$	2

____________________

(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, 2020.


	2021		2022		2023		2024		2025 and After

	(In millions)
Transportation and Storage	$	443	$	371	$	336	$	250	$	938
Gathering and Processing	120		123		121		101		213
Total remaining performance obligations	$	563	$	494	$	457	$	351	$	1,151

Leases (Tables)

12 Months Ended

Dec. 31, 2020

Leases [Abstract]

Schedule of Leasing Assets and Liabilities Table Text Block

The table below summarizes the operating leases included in the Consolidated Balance Sheets.


	Balance Sheet Location	December 31, 2020		December 31, 2019

		(In millions)
Operating lease asset	Other Assets	$	25	$	37
Total right-of-use assets		$	25	$	37

Operating lease liabilities	Other Current Liabilities	$	4	$	9
Operating lease liabilities	Other Liabilities	24		31
Total lease liabilities		$	28	$	40

Summary of Lease Expenses

The following table presents the Partnership’s rental costs associated with field equipment and office space.


	Year Ended December 31,
	2020		2019

	(In millions)
Rental Costs:
Field equipment	$	16	$	29
Office space	6		7

The following table presents the Partnership’s lease cost.


	Year Ended December 31,
	2020		2019

	(In millions)
Lease Cost:
Operating lease cost	$	8	$	11
Short-term lease cost	12		24
Variable lease cost	2		1
Total Lease Cost	$	22	$	36

Schedule of Operating Lease Obligations Expiration

Under ASC 842, as of December 31, 2020, the Partnership has operating lease obligations expiring at various dates. Undiscounted cash flows for operating lease liabilities are as follows:


	Non-cancellable operating leases
	(In millions)
Year Ending December 31,
2021	$	6
2022	5
2023	5
2024	4
2025	3
After 2025	8
Total	31
Less: impact of the applicable discount rate	3
Total lease liabilities	$	28

Acquisitions (Tables)

12 Months Ended

Dec. 31, 2020

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

Earnings Per Limited Partner Unit (Tables)

12 Months Ended

Dec. 31, 2020

Earnings Per Share [Abstract]

Schedule Of Earnings Per Unit For Common Units

The following table illustrates the Partnership’s calculation of earnings per unit for common units:


	Year Ended December 31,
	2020		2019		2018

	(In millions, except per unit data)
Net income	$	83	$	400	$	523
Net income (loss) attributable to noncontrolling interests	(5)		4		2
Series A Preferred Unit distributions	36		36		36
General partner interest in net income	—		—		—
Net income available to common units	$	52	$	360	$	485




Net income allocable to common units	$	52	$	360	$	485
Dilutive effect of Series A Preferred Unit distribution (1)	—		—		—
Diluted net income allocable to common units	$	52	$	360	485






Basic weighted average number of outstanding common units (2)	437		436		434
Dilutive effect of Series A Preferred Units (1)	—		—		—
Dilutive effect of performance units (3)	1		1		2
Diluted weighted average number of outstanding common units	438		437		436


Basic and diluted earnings per common unit
Basic	$	0.12	$	0.83	$	1.12
Diluted	$	0.12	$	0.82	$	1.11

____________________

(3)The dilutive effect of the performance unit awards was less than $0.01 per unit for the years ended December 31, 2020, 2019, and 2018.

Partners' Equity (Tables)

12 Months Ended

Dec. 31, 2020

Equity [Abstract]

Schedule Of Equity Transactions With Limited Partner


Quarter Ended	Record Date	Payment Date	Per Unit Distribution		Total Cash Distribution
2020
December 31, 2020 (1)	February 22, 2021	March 1, 2021	$	0.16525	$	72
September 30, 2020	November 17, 2020	November 24, 2020	0.16525		72
June 30, 2020	August 18, 2020	August 25, 2020	0.16525		72
March 31, 2020	May 19, 2020	May 27, 2020	0.16525		72

2019
December 31, 2019	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

_____________________

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 2020, 2019, and 2018 (in millions, except for per unit amounts):


Quarter Ended	Record Date	Payment Date	Per Unit Distribution		Total Cash Distribution
2020
December 31, 2020 (1)	February 12, 2021	February 12, 2021	$	0.625	$	9
September 30, 2020	November 3, 2020	November 13, 2020	0.625		9
June 30, 2020	August 4, 2020	August 14, 2020	0.625		9
March 31, 2020	May 5, 2020	May 15, 2020	0.625		9

2019
December 31, 2019	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

_____________________

Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2020

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

Property, plant and equipment includes the following:


	Weighted Average Useful Lives (Years)	December 31,
		2020		2019

		(In millions)
Property, plant and equipment, gross:
Gathering and Processing	34.5	$	8,275	$	8,252
Transportation and Storage	40.6	4,802		4,778
Construction work-in-progress		143		131
Total		$	13,220	$	13,161
Accumulated depreciation:
Gathering and Processing		1,429		1,252
Transportation and Storage		1,126		1,039
Total accumulated depreciation		2,555		2,291
Property, plant and equipment, net		$	10,665	$	10,870

Intangible Assets, Net (Tables)

12 Months Ended

Dec. 31, 2020

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,
	2020		2019

	(In millions)
Customer relationships:
Total intangible assets	$	840	$	840
Accumulated amortization	301		239
Net intangible assets	$	539	$	601

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:


	2021		2022		2023		2024		2025

	(In millions)
Expected amortization of intangible assets	$	62	$	62	$	62	$	62	$	62

Goodwill (Tables)

12 Months Ended

Dec. 31, 2020

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, 2018	$	98	$	—	$	98
Goodwill impairment	(86)		—		(86)
Balance as of December 31, 2019	12		—		12
Goodwill impairment	(12)		—		(12)
Balance as of December 31, 2020	$	—	$	—	$	—

Investment in Equity Method Affiliate (Tables)

12 Months Ended

Dec. 31, 2020

Equity Method Investments and Joint Ventures [Abstract]

Schedule of Investments Detail

SESH:


	Year Ended December 31,
	2020		2019		2018

	(In millions)
Equity in Earnings of Equity Method Affiliate	$	15	$	17	$	26
Impairment of equity method affiliate investment	(225)		—		—
Equity in earnings (losses) of equity method affiliate, net	$	(210)	$	17	$	26
Distributions from Equity Method Affiliate (1)	$	23	$	25	$	33

____________________

Summarized financial information of SESH:


	December 31,
	2020		2019

	(In millions)
Balance Sheets:
Current assets	$	49	$	49
Property, plant and equipment, net	1,043		1,060

Total assets	$	1,092	$	1,109
Current liabilities	$	31	$	30
Long-term debt	398		398
Members’ equity	663		681
Total liabilities and members’ equity	$	1,092	$	1,109
Reconciliation:
Investment in SESH	$	76	$	309
Add: Capitalized interest on investment in SESH	(1)		(1)
Add: Basis difference, net of amortization (1)	256		33
The Partnership’s share of members’ equity	$	331	$	341

____________________

(1)Includes the Partnership’s impairment of investment in equity method affiliate of $225 million recorded during the year ended December 31, 2020.


	Year Ended December 31,
	2020		2019		2018

	(In millions)
Income Statements:
Revenues	$	96	$	109	$	112
Operating income	44		50		67
Net income	26		33		50

Debt (Tables)

12 Months Ended

Dec. 31, 2020

Debt Disclosure [Abstract]

Schedule of Debt

The following table presents the Partnership’s outstanding debt as of December 31, 2020 and 2019.


	December 31, 2020						December 31, 2019
	Outstanding Principal		Premium (Discount)(1)		Total Debt		Outstanding Principal		Premium (Discount)(1)		Total Debt

	(In millions)
Commercial Paper	$	250	$	—	$	250	$	155	$	—	$	155
Revolving Credit Facility	—		—		—		—		—		—
2019 Term Loan Agreement	800		—		800		800		—		800

2024 Notes	600		—		600		600		—		600
2027 Notes	700		(2)		698		700		(2)		698
2028 Notes	800		(5)		795		800		(5)		795
2029 Notes	547		(1)		546		550		(1)		549
2044 Notes	531		—		531		550		—		550
EOIT Senior Notes	—		—		—		250		1		251
Total debt	$	4,228	$	(8)	$	4,220	$	4,405	$	(7)	$	4,398
Less: Short-term debt (2)					250						155
Less: Current portion of long-term debt (3)					—						251
Less: Unamortized debt expense (4)					19						23
Total long-term debt					$	3,951					$	3,969

___________________

(1)Unamortized premium (discount) on long-term debt is amortized over the life of the respective debt.

(2)Short-term debt includes $250 million and $155 million of commercial paper outstanding as of December 31, 2020 and 2019, respectively.

(3)As of December 31, 2019, Current portion of long-term debt included the $251 million outstanding balance of the EOIT Senior Notes which were repaid in March 2020.

Schedule of Maturities of Long-term Debt

Maturities of outstanding debt, excluding unamortized premiums (discounts), are as follows (in millions):


2021	$	250
2022	800
2023	—
2024	600
2025	—
Thereafter	$	2,578

Derivative Instruments and Hedging Activities (Tables)

12 Months Ended

Dec. 31, 2020

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Derivative Instruments

As of December 31, 2020 and 2019, the Partnership had the following derivative instruments that were not designated as hedging instruments for accounting purposes:


	December 31, 2020		December 31, 2019
	Gross Notional Volume
	Purchases	Sales	Purchases	Sales
Natural gas— TBtu (1)
Financial fixed futures/swaps	—	18	10	19
Financial basis futures/swaps	—	27	11	30
Financial swaptions (2)	—	7	—	2
Physical purchases/sales	—	—	—	6
Crude oil (for condensate)— MBbl (3)
Financial futures/swaps	—	465	—	990
Financial swaptions (2)	—	90	—	225
Natural gas liquids— MBbl (4)
Financial futures/swaps	855	1,210	2,490	2,415
Financial swaptions (2)	—	45	—	—

____________________

As of December 31, 2020 and 2019, the Partnership had the following derivative instruments that were designated as hedging instruments for accounting purposes:


	December 31, 2020		December 31, 2019
	Gross Notional Value
	(In millions)
Interest rate swaps	$	300	$	300

Schedule of Derivative Assets at Fair Value


		December 31, 2020				December 31, 2019
		Fair Value
Instrument	Balance Sheet Location	Assets		Liabilities		Assets		Liabilities

		(In millions)
Natural gas
Financial futures/swaps	Other Current	$	2	$	2	$	7	$	5
Financial swaptions	Other Current	1		2		—		—
Physical purchases/sales	Other Current	—		—		5		—
Financial futures/swaps	Other	—		—		—		1

Crude oil (for condensate)
Financial futures/swaps	Other Current	1		13		1		19
Financial futures/swaps	Other	—		—		—		8

Natural gas liquids
Financial futures/swaps	Other Current	15		3		25		3
Financial swaptions	Other Current	—		1		—		—
Financial futures/swaps	Other	—		—		11		2
Total gross derivatives (1)		$	19	$	21	$	49	$	38

_____________________

(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, 2020 and 2019.


		December 31, 2020				December 31, 2019
		Fair Value
Instrument	Balance Sheet Location	Assets		Liabilities		Assets		Liabilities

		(In millions)
Interest rate swaps	Other Current	$	—	$	6	$	—	$	1
Interest rate swaps	Other	—		—		—		2
Total gross interest rate derivatives (1)		$	—	$	6	$	—	$	3

_____________________

(1)All interest rate derivative instruments that were designated as cash flow hedges are considered Level 2 as of December 31, 2020.

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

The following table presents the effect of derivative instruments on the Partnership’s Consolidated Statements of Income for the years ended December 31, 2020, 2019 and 2018:


	Amounts Recognized in Income
	Year Ended December 31,
	2020		2019		2018

	(In millions)
Natural Gas
Financial futures/swaps gains (losses)	$	4	$	13	$	(8)
Financial swaptions gains (losses)	(2)		—		—
Physical purchases/sales gains	—		2		7
Crude oil (for condensate)
Financial futures/swaps gains (losses)	10		(41)		6

Natural gas liquids
Financial futures/swaps gains (losses)	(2)		42		6
Total	$	10	$	16	$	11

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, 2020, 2019 and 2018:


	Year Ended December 31,
	2020		2019		2018

	(In millions)
Change in fair value of derivatives	$	(13)	$	(11)	$	26
Realized gain (loss) on derivatives	23		27		(15)
Gain on derivative activity	$	10	$	16	$	11

- Definition

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

+ References

Reference 1: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4B
-URI http://asc.fasb.org/extlink&oid=121590274&loc=SL5624163-113959

Reference 2: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
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-Section 50
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-URI http://asc.fasb.org/extlink&oid=121590274&loc=SL5580258-113959

Reference 3: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
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-URI http://asc.fasb.org/extlink&oid=121590274&loc=d3e41620-113959

Reference 4: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
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-URI http://asc.fasb.org/extlink&oid=121590274&loc=SL5579245-113959

Reference 5: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
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-URI http://asc.fasb.org/extlink&oid=121590274&loc=d3e41638-113959

Reference 6: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
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-URI http://asc.fasb.org/extlink&oid=121590274&loc=d3e41678-113959

Reference 7: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
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Reference 8: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
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Reference 9: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
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+ Details

Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2020

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, 2020 and 2019:


	December 31, 2020				December 31, 2019
	Carrying Amount		Fair Value		Carrying Amount		Fair Value

	(In millions)
Debt
Revolving Credit Facility (Level 2) (1)	$	—	$	—	$	—	$	—
2019 Term Loan Agreement (Level 2)	800		800		800		800

2024 Notes (Level 2)	600		612		600		614
2027 Notes (Level 2)	698		709		698		698
2028 Notes (Level 2)	795		817		795		811
2029 Notes (Level 2)	546		544		549		526
2044 Notes (Level 2)	531		499		550		506
EOIT Senior Notes (Level 2)	—		—		251		252

Schedule of Assets and Liabilities Measured at Fair Value on a Recurring Basis


December 31, 2020	Commodity Contracts				Gas Imbalances (1)
	Assets		Liabilities		Assets (2)		Liabilities (3)

	(In millions)
Quoted market prices in active market for identical assets (Level 1)	$	2	$	14	$	—	$	—
Significant other observable inputs (Level 2)	17		7		23		16

Total fair value	19		21		23		16
Netting adjustments	(19)		(19)		—		—
Total	$	—	$	2	$	23	$	16


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

Total fair value	49		38		14		11
Netting adjustments	(37)		(37)		—		—
Total	$	12	$	1	$	14	$	11

______________________

Supplemental Disclosure of Cash Flow Information (Tables)

12 Months Ended

Dec. 31, 2020

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,
	2020		2019		2018

	(In millions)
Supplemental Disclosure of Cash Flow Information:
Cash Payments:
Interest, net of capitalized interest	$	180	$	185	$	148
Income tax, net of refunds	1		1		3
Non-cash transactions:
Accounts payable related to capital expenditures	9		10		54
Lease liabilities related to (derecognition) recognition of right-of-use assets	(5)		45		—
Impact of adoption of financial instruments-credit losses accounting standard (Note 1)	(3)		—		—

Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2020

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,
	2020		2019		2018

	(In millions)
Gas transportation and storage service revenues — CenterPoint Energy	$	100	$	108	$	111
Natural gas product sales — CenterPoint Energy	1		8		11
Gas transportation and storage service revenues — OGE Energy	38		41		37
Natural gas product sales — OGE Energy	10		10		4
Total revenues — affiliated companies	$	149	$	167	$	163

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,
	2020		2019		2018

	(In millions)
Cost of natural gas purchases — CenterPoint Energy	$	1	$	—	$	3
Cost of natural gas purchases — OGE Energy	24		33		23
Total cost of natural gas purchases — affiliated companies	$	25	$	33	$	26

Schedule of Amounts Charged to Partnership by Related Parties


	Year Ended December 31,
	2020		2019		2018

	(In millions)
Corporate Services — CenterPoint Energy	$	—	$	—	$	1
Operating Lease — CenterPoint Energy	—		1		1
Seconded Employee Costs — OGE Energy	17		18		29
Corporate Services — OGE Energy	—		—		1
Total corporate services, operating lease and seconded employee expense	$	17	$	19	$	32

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2020

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,
	2020		2019		2018

	(In millions)
Provision for current income tax
Federal	$	(2)	$	—	$	—
State	1		—		—
Total provision for current income tax	(1)		—		—
Benefit for deferred income tax, net
Federal	$	1	$	(1)	$	(1)
State	—		—		—
Total benefit for deferred income tax, net	1		(1)		(1)
Total income tax benefit	$	—	$	(1)	$	(1)

Schedule of Deferred Tax Assets and Liabilities

The components of Deferred Income Tax as of December 31, 2020 and 2019 were as follows:


	December 31,
	2020		2019

	(In millions)
Deferred tax liabilities, net:
Non-current:
Intercompany management fee	$	16	$	17
Depreciation	5		6
Net operating loss	(1)		(2)
Accrued compensation	(15)		(17)
Total deferred tax liabilities, net	$	5	$	4

Equity Based Compensation (Tables)

12 Months Ended

Dec. 31, 2020

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, 2020, 2019 and 2018 related to performance units, restricted units and phantom units for the Partnership’s employees and independent directors:


	Year Ended December 31,
	2020		2019		2018

	(In millions)
Performance units	$	7	$	9	$	9
Restricted units	—		—		1
Phantom units	6		7		6
Total equity-based compensation expense	$	13	$	16	$	16


	2020			2019			2018
Number of units granted	933,738			638,798			551,742
Fair value of units granted	$	7.00		$	19.95		$	17.70
Expected price volatility	27.7		%	34.2		%	44.2		%
Risk-free interest rate	0.85		%	2.54		%	2.36		%
Distribution yield	12.27		%	8.38		%	8.56		%
Expected life of units (in years)	3			3			3

The number of phantom units granted and the grant date fair value are shown in the following table.


	2020	2019	2018
Phantom units granted	1,002,345	695,486	546,708
Fair value of phantom units granted	$2.67 - $10.13	$8.95 - $15.04	$13.74 - $17.00

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.


	2020		2019		2018
Common units granted	63,963		28,221		16,335
Fair value of common units granted	$	4.23	$	10.43	$	14.94

Schedule of Share-based Compensation, Activity

A summary of the activity for the Partnership’s performance units and phantom units as of December 31, 2020 and changes during 2020 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 12/31/2019	1,393,329		$	19.04	1,392,560		$	14.65
Granted (1)	933,738		7.00		1,002,345		6.44
Vested (2)(3)	(390,079)		19.21		(399,406)		15.76
Forfeited	(171,480)		14.25		(204,654)		10.46
Units outstanding at 12/31/2020	1,765,508		13.10		1,790,845		$	10.29
Aggregate intrinsic value of units outstanding at December 31, 2020	$	9			$	9

_____________________


	Year Ended December 31, 2020
	Performance Units		Restricted Stock		Phantom Units

	(In millions)
Aggregate intrinsic value of units vested	$	—	$	—	$	3
Fair value of units vested	7		—		6


	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		—

Schedule of Unrecognized Compensation Cost, Nonvested Awards


	December 31, 2020
	Unrecognized Compensation Cost (In millions)		Weighted Average Period for Recognition (In years)
Performance Units	$	9	1.43

Phantom Units	6		1.30
Total	$	15

Reportable Segments (Tables)

12 Months Ended

Dec. 31, 2020

Segment Reporting [Abstract]

Schedule of Financial Data for Business Segments and Services

Financial data for reportable segments are as follows:


Year Ended December 31, 2020	Gathering and Processing		Transportation and Storage (1)		Eliminations		Total

	(In millions)
Product sales	$	1,087	$	340	$	(295)	$	1,132
Service revenues	799		541		(9)		1,331
Total Revenues	1,886		881		(304)		2,463
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)	936		332		(303)		965
Operation and maintenance, General and administrative	334		183		(1)		516
Depreciation and amortization	299		121		—		420
Impairments of property, plant and equipment and goodwill	28		—		—		28
Taxes other than income tax	42		27		—		69
Operating Income	$	247	$	218	$	—	$	465
Total Assets	$	10,830	$	5,729	$	(4,830)	$	11,729
Capital expenditures	$	107	$	108	$	—	$	215


Year Ended December 31, 2019	Gathering and Processing		Transportation and Storage (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 of property, plant and equipment and goodwill	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 Processing		Transportation and Storage (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

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

_____________________

Quarterly Financial Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2020

Quarterly Financial Information Disclosure [Abstract]

Schedule of Quarterly Financial Information

Summarized unaudited quarterly financial data for 2020 and 2019 are as follows:


	Quarters Ended
	March 31, 2020		June 30, 2020		September 30, 2020		December 31, 2020

	(in millions, except per unit data)
Total Revenues	$	648	$	515	$	596	$	704
Cost of natural gas and natural gas liquids	226		177		250		312
Operating income	146		80		100		139
Net income (loss) (1)	105		44		(163)		97
Net income (loss) attributable to limited partners	112		44		(164)		96
Net income (loss) attributable to common units	103		35		(173)		87

Basic and diluted earnings per unit
Basic	$	0.24	$	0.08	$	(0.40)	$	0.20
Diluted	$	0.19	$	0.08	$	(0.40)	$	0.19


	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 (2)	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 and diluted earnings per unit
Basic	$	0.26	$	0.26	$	0.28	$	0.02
Diluted	$	0.26	$	0.26	$	0.28	$	0.02

_____________________

Summary of Significant Accounting Policies - Narrative (Details)	2 Months Ended	3 Months Ended								12 Months Ended
	Dec. 31, 2018 USD ($)	Dec. 31, 2020 USD ($) board_member shares	Sep. 30, 2020 USD ($)	Jun. 30, 2020 USD ($)	Mar. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)	Sep. 30, 2019 USD ($)	Jun. 30, 2019 USD ($)	Mar. 31, 2019 USD ($)	Dec. 31, 2020 USD ($) segment board_member shares	Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)	Jan. 01, 2020 USD ($)	Dec. 31, 2017 USD ($)
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
Percentage vote by all unitholders (at least 75%)										75.00%
Total Revenues		$ 704,000,000	$ 596,000,000	$ 515,000,000	$ 648,000,000	$ 731,000,000	$ 699,000,000	$ 735,000,000	$ 795,000,000	$ 2,463,000,000	$ 2,960,000,000	$ 3,431,000,000
Environmental exit costs		3,000,000				0				3,000,000	0
Cash and cash equivalents		3,000,000				4,000,000				3,000,000	4,000,000
Partners' Capital, Including Portion Attributable to Noncontrolling Interest	$ 7,618,000,000	7,095,000,000				7,409,000,000				7,095,000,000	7,409,000,000	7,618,000,000		$ 7,654,000,000
Accounts receivable		1,000,000								1,000,000			$ 2,000,000
Other assets		3,000,000								3,000,000			3,000,000
Total Allowance for doubtful accounts		4,000,000								4,000,000			$ 5,000,000
Regulatory liabilities		$ 25,000,000				$ 24,000,000				25,000,000	24,000,000
AFUDC, capitalized interest										$ 2,000,000	2,000,000	6,000,000
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	20,000,000	19,000,000
Materials and Supplies
Significant Accounting Policies [Line Items]
Inventory adjustments										0	0	0
Natural Gas and Natural Gas Liquids
Significant Accounting Policies [Line Items]
Inventory adjustments										10,000,000	8,000,000	$ 4,000,000
Total revenue \| Customer Concentration Risk
Significant Accounting Policies [Line Items]
Total Revenues										$ 310,000,000	$ 328,000,000
Concentration risk percentage										13.00%	11.00%	0.00%
SESH
Significant Accounting Policies [Line Items]
Ownership percentage	50.00%	50.00%				50.00%				50.00%	50.00%	50.00%
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
Partners' Capital \| 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%
Partners' Capital \| CenterPoint \| Series A 10% Fixed to Floating Non Cumulative Redeemable Perpetual Preferred Units
Significant Accounting Policies [Line Items]
Series A preferred units held by CenterPoint Energy \| shares		14,520,000								14,520,000
Partners' Capital \| 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%
OGE Energy \| Defined Benefit And Retiree Medical Plans
Significant Accounting Policies [Line Items]
Reimbursement of benefits										$ 2,000,000	$ 3,000,000	$ 3,000,000
Atoka
Significant Accounting Policies [Line Items]
Ownership interest (as a percentage)										50.00%	50.00%	50.00%
ESCP
Significant Accounting Policies [Line Items]
Ownership interest (as a percentage)	60.00%									60.00%	60.00%
OGE Energy \| Partners' Capital
Significant Accounting Policies [Line Items]
Limited partner ownership percentage interest										25.50%
CenterPoint \| Partners' Capital
Significant Accounting Policies [Line Items]
Limited partner ownership percentage interest										53.70%
Partners' Capital \| Common Units
Significant Accounting Policies [Line Items]
Partners' Capital, Including Portion Attributable to Noncontrolling Interest	$ 7,218,000,000	$ 6,713,000,000				$ 7,013,000,000				$ 6,713,000,000	$ 7,013,000,000	$ 7,218,000,000		$ 7,280,000,000
Cumulative Effect, Period of Adoption, Adjustment [Member]
Significant Accounting Policies [Line Items]
Partners' Capital, Including Portion Attributable to Noncontrolling Interest						(3,000,000)					(3,000,000)
Cumulative Effect, Period of Adoption, Adjustment [Member] \| Partners' Capital \| Common Units
Significant Accounting Policies [Line Items]
Partners' Capital, Including Portion Attributable to Noncontrolling Interest						$ (3,000,000)					$ (3,000,000)

Summary of Significant Accounting Policies - Inventory (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Materials and supplies	$ 32	$ 32
Natural gas and natural gas liquids	10	14
Total Inventory	$ 42	$ 46

Revenues - Disaggregation of Revenue (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Disaggregation of Revenue [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate									$ 1,122	$ 1,517	$ 2,095
Gain on derivative activity									10	16	11
Total Revenues	$ 704	$ 596	$ 515	$ 648	$ 731	$ 699	$ 735	$ 795	2,463	2,960	3,431
Natural gas
Disaggregation of Revenue [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate									292	448	564
Natural gas liquids
Disaggregation of Revenue [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate									762	943	1,405
Condensate Natural Gas
Disaggregation of Revenue [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate									68	126	126
Product
Disaggregation of Revenue [Line Items]
Total Revenues									1,132	1,533	2,106
Demand Service Revenue
Disaggregation of Revenue [Line Items]
Total Revenues									626	763	724
Volume Dependant Service Revenue
Disaggregation of Revenue [Line Items]
Total Revenues									705	664	601
Natural Gas, Gathering, Transportation, Marketing and Processing
Disaggregation of Revenue [Line Items]
Total Revenues									1,331	1,427	1,325
Operating Segments \| Gathering and Processing
Disaggregation of Revenue [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate									1,079	1,437	2,011
Gain on derivative activity									8	12	5
Total Revenues									1,886	2,338	2,818
Operating Segments \| Gathering and Processing \| Natural gas
Disaggregation of Revenue [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate									249	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									762	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									68	126	126
Operating Segments \| Gathering and Processing \| Product
Disaggregation of Revenue [Line Items]
Total Revenues									1,087	1,449	2,016
Operating Segments \| Gathering and Processing \| Demand Service Revenue
Disaggregation of Revenue [Line Items]
Total Revenues									135	274	252
Operating Segments \| Gathering and Processing \| Volume Dependant Service Revenue
Disaggregation of Revenue [Line Items]
Total Revenues									664	615	550
Operating Segments \| Gathering and Processing \| Natural Gas, Gathering, Transportation, Marketing and Processing
Disaggregation of Revenue [Line Items]
Total Revenues									799	889	802
Operating Segments \| Transportation and Storage
Disaggregation of Revenue [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate									338	483	620
Gain on derivative activity									2	4	5
Total Revenues									881	1,038	1,162
Operating Segments \| Transportation and Storage \| Natural gas
Disaggregation of Revenue [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate									328	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									10	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	0
Operating Segments \| Transportation and Storage \| Product
Disaggregation of Revenue [Line Items]
Total Revenues									340	487	625
Operating Segments \| Transportation and Storage \| Demand Service Revenue
Disaggregation of Revenue [Line Items]
Total Revenues									491	489	472
Operating Segments \| Transportation and Storage \| Volume Dependant Service Revenue
Disaggregation of Revenue [Line Items]
Total Revenues									50	62	65
Operating Segments \| Transportation and Storage \| Natural Gas, Gathering, Transportation, Marketing and Processing
Disaggregation of Revenue [Line Items]
Total Revenues									541	551	537
Eliminations
Disaggregation of Revenue [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate									(295)	(403)	(536)
Gain on derivative activity									0	0	1
Total Revenues									(304)	(416)	(549)
Eliminations \| Natural gas
Disaggregation of Revenue [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate									(285)	(384)	(506)
Eliminations \| Natural gas liquids
Disaggregation of Revenue [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate									(10)	(19)	(30)
Eliminations \| Condensate Natural Gas
Disaggregation of Revenue [Line Items]
Total revenues from natural gas, natural gas liquids, and condensate									0	0	0
Eliminations \| Product
Disaggregation of Revenue [Line Items]
Total Revenues									(295)	(403)	(535)
Eliminations \| Demand Service Revenue
Disaggregation of Revenue [Line Items]
Total Revenues									0	0	0
Eliminations \| Volume Dependant Service Revenue
Disaggregation of Revenue [Line Items]
Total Revenues									(9)	(13)	(14)
Eliminations \| Natural Gas, Gathering, Transportation, Marketing and Processing
Disaggregation of Revenue [Line Items]
Total Revenues									$ (9)	$ (13)	$ (14)

Revenue - Narrative (Details) - USD ($) $ in Millions	3 Months Ended
Revenue - Narrative (Details) - USD ($) $ in Millions	Jun. 30, 2020	Mar. 31, 2020
Revenue from Contract with Customer [Abstract]
Revenue recognized related to rate case settlement		$ 17
Regulatory liabilities, refund to customers	$ 21

Revenues - Accounts Receivable (Details) - USD ($)
$ in Millions

Dec. 31, 2020

Dec. 31, 2019

Disaggregation of Revenue [Line Items]

Customers

$ 245

$ 239

Contract assets

^[1]

Non-customers

Total Accounts Receivable

^[2]

263

269

Firm Service Transportation [Member]

Disaggregation of Revenue [Line Items]

Contract assets

$ 9

$ 6

[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 contract assets related to firm transportation contracts with tiered rates of $9 million as of December 31, 2020 and $6 million as of December 31, 2019, which are reflected in Other Assets.

[2]

Total Accounts Receivable includes Accounts receivables, net of allowance for doubtful accounts and Accounts receivable—affiliated companies.

Revenues - Summary of Changes in Contract Liabilities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Revenue from Contract with Customer [Abstract]
Deferred revenues	$ 44	$ 48	$ 48
Amounts recognized in revenues related to the beginning balance	(25)	(24)
Net additions	$ 21	$ 24

Revenues - Summary of Recognition Contract Liabilities (Details)
$ in Millions

12 Months Ended

Dec. 31, 2020

USD ($)

^[1]

Revenue from Contract with Customer [Abstract]

$ 23

$ 2

[1]	Deferred revenues includes deferred revenue—affiliated companies. This amount is included in Other current liabilities and Other long-term liabilities.

Leases - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
Leases - Narrative (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2018	Dec. 31, 2019	Jan. 01, 2019
Lessee, Lease, Description [Line Items]
Weighted average remaining lease term	7 years
Weighted average discount rate	5.47%
Operating lease right-of-use asset	$ 25		$ 37	$ 35
Operating lease liability	$ 28		$ 40
Rental expense		$ 35
Office space
Lessee, Lease, Description [Line Items]
Renewal options (up to)	15 years
Operating lease right-of-use asset	$ 17
Operating lease liability	$ 20
Minimum \| Field equipment
Lessee, Lease, Description [Line Items]
Expected lease term (in years)	3 years
Lease term	1 year
Minimum \| Office space
Lessee, Lease, Description [Line Items]
Lease term	7 years
Maximum \| Field equipment
Lessee, Lease, Description [Line Items]
Expected lease term (in years)	5 years
Lease term	3 years
Maximum \| Office space
Lessee, Lease, Description [Line Items]
Lease term	10 years

Leases - Schedule of Leasing Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019	Jan. 01, 2019
Lessee, Lease, Description [Line Items]
Operating lease right-of-use asset	$ 25	$ 37	$ 35
Operating Lease, Total liability	$ 28	$ 40
Operating Lease, Liability, Current, Statement of Financial Position [Extensible List]	us-gaap:OtherLiabilitiesCurrent	us-gaap:OtherLiabilitiesCurrent
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]	us-gaap:OtherLiabilitiesNoncurrent	us-gaap:OtherLiabilitiesNoncurrent
Other Assets
Lessee, Lease, Description [Line Items]
Operating lease right-of-use asset	$ 25	$ 37
Other Current Liabilities
Lessee, Lease, Description [Line Items]
Operating lease, Current liabilities	4	9
Other Liabilities
Lessee, Lease, Description [Line Items]
Operating lease, Other liabilities	$ 24	$ 31

Leases - Summary of Lease Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Lessee, Lease, Description [Line Items]
Operating lease cost	$ 8	$ 11
Short-term lease cost	12	24
Variable lease cost	2	1
Total Lease Cost	22	36
Rental costs	22	36
Transportation and Storage
Lessee, Lease, Description [Line Items]
Short-term lease cost	1	2
Field equipment
Lessee, Lease, Description [Line Items]
Total Lease Cost	16	29
Rental costs	16	29
Office space
Lessee, Lease, Description [Line Items]
Total Lease Cost	6	7
Rental costs	$ 6	$ 7

Leases - Schedule of Operating Lease Obligations Expiration (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Leases [Abstract]
2021	$ 6
2022	5
2023	5
2024	4
2025	3
After 2025	8
Total	31
Less: impact of the applicable discount rate	3
Operating lease liability	$ 28	$ 40

Acquisitions - Narrative (Details) $ in Millions		12 Months Ended
Acquisitions - Narrative (Details) $ in Millions	Nov. 01, 2018 USD ($) mi	Dec. 31, 2020	Dec. 31, 2018 USD ($)
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
Velocity Holdings, LLC \| General and Administrative Expense
Business Acquisition [Line Items]
Acquisition costs associated with the transaction			$ 6
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

Acquisitions - Schedule of Assets and Liabilities Assumed (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Nov. 01, 2018
Assets acquired:
Goodwill	$ 0	$ 12	$ 98
Velocity Holdings, LLC
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

Earnings Per Limited Partner Unit (Details) - USD ($)
$ / shares in Units, shares in Millions, $ in Millions

3 Months Ended

12 Months Ended

Dec. 31, 2020

Sep. 30, 2020

Jun. 30, 2020

Mar. 31, 2020

Dec. 31, 2019

Sep. 30, 2019

Jun. 30, 2019

Mar. 31, 2019

Dec. 31, 2020

Dec. 31, 2019

Dec. 31, 2018

Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]

Net income

$ 97

$ (163)

$ 44

$ 105

$ 20

$ 133

$ 124

$ 123

$ 83

$ 400

$ 523

Net income (loss) attributable to noncontrolling interests

(5)

Series A Preferred Unit distributions

General partner interest in net income

Net Income Attributable to Common Units (Note 6)

$ 87

$ (173)

$ 35

$ 103

$ 9

$ 123

$ 115

$ 113

$ 52

$ 360

$ 485

Basic and diluted earnings (loss) per unit

Dilutive effect of unit-based awards (in dollars per unit) (less than $.01)

$ 0.01

Phantom units

Basic weighted average number of outstanding common units

Basic weighted average number of outstanding common units

Common Units

Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]

Net Income Attributable to Common Units (Note 6)

$ 52

$ 360

$ 485

Dilutive effect of Series A Preferred Unit distribution (1)

^[1]

Diluted net income allocable to common units

$ 52

$ 360

$ 485

Basic weighted average number of outstanding common units

Basic weighted average number of outstanding common units

^[2]

437

436

434

Dilutive effect of Series A Preferred Units (in units)

^[1]

Dilutive effect of performance units (in units)

^[3]

Diluted weighted average number of outstanding common units

438

437

436

Basic and diluted earnings (loss) per unit

Basic earnings per unit

$ 0.20

$ (0.40)

$ 0.08

$ 0.24

$ 0.02

$ 0.28

$ 0.26

$ 0.12

$ 0.83

$ 1.12

Diluted earnings per unit

$ 0.19

$ (0.40)

$ 0.08

$ 0.19

$ 0.02

$ 0.28

$ 0.26

$ 0.12

$ 0.82

$ 1.11

[1]	For the years ended December 31, 2020, 2019, and 2018, the issuance of “if-converted” common units attributable to the Series A Preferred Units were excluded in the calculation of diluted earnings per common unit as the impact was anti-dilutive.
[2]	Basic weighted average number of outstanding common units for the years ended December 31, 2020, 2019, and 2018 includes approximately 2 million, 1 million, and 1 million time-based phantom units, respectively.
[3]	The dilutive effect of the performance unit awards was less than $0.01 per unit for the years ended December 31, 2020, 2019, and 2018.

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

Mar. 01, 2021

Feb. 22, 2021

Feb. 12, 2021

Nov. 24, 2020

Nov. 17, 2020

Nov. 13, 2020

Nov. 03, 2020

Aug. 25, 2020

Aug. 18, 2020

Aug. 14, 2020

Aug. 04, 2020

May 27, 2020

May 19, 2020

May 15, 2020

May 05, 2020

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. 14, 2018

Aug. 01, 2018

May 29, 2018

May 22, 2018

May 15, 2018

May 14, 2018

May 01, 2018

Distribution Made to Limited Partner [Line Items]

Record Date

Nov. 17, 2020

Aug. 18, 2020

May 19, 2020

Feb. 18, 2020

Nov. 19, 2019

Aug. 20, 2019

May 21, 2019

Feb. 19, 2019

Nov. 16, 2018

Aug. 21, 2018

May 22, 2018

Payment Date

Nov. 24, 2020

Aug. 25, 2020

May 27, 2020

Feb. 25, 2020

Nov. 26, 2019

Aug. 27, 2019

May 29, 2019

Feb. 26, 2019

Nov. 29, 2018

Aug. 28, 2018

May 29, 2018

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

Distribution Made to Limited Partner [Line Items]

Record Date

Nov. 03, 2020

Aug. 04, 2020

May 05, 2020

Feb. 07, 2020

Nov. 05, 2019

Aug. 02, 2019

Apr. 29, 2019

Feb. 08, 2019

Nov. 06, 2018

Aug. 01, 2018

May 01, 2018

Payment Date

Nov. 13, 2020

Aug. 14, 2020

May 15, 2020

Feb. 14, 2020

Nov. 14, 2019

Aug. 14, 2019

May 15, 2019

Feb. 14, 2019

Nov. 14, 2018

Aug. 14, 2018

May 15, 2018

Cash Distribution

Distribution Made to Limited Partner [Line Items]

Per unit distribution, paid (in dollars per unit)

$ 0.16525

$ 0.3305

$ 0.318

Total Cash Distribution

$ 72

$ 144

$ 138

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

Total Cash Distribution

$ 9

Subsequent Event | Scenario, Forecast

Distribution Made to Limited Partner [Line Items]

Record Date

^[1]

Feb. 22, 2021

Payment Date

^[1]

Mar. 01, 2021

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

Distribution Made to Limited Partner [Line Items]

Record Date

^[2]

Feb. 12, 2021

Payment Date

^[2]

Feb. 12, 2021

Subsequent Event | Scenario, Forecast | Cash Distribution

Distribution Made to Limited Partner [Line Items]

Per unit distribution, paid (in dollars per unit)

^[1]

$ 0.16525

Total Cash Distribution

^[1]

$ 72

Common unit cash distribution declared (in dollars per unit)

$ 0.16525

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

Distribution Made to Limited Partner [Line Items]

Per unit distribution, paid (in dollars per unit)

^[2]

$ 0.625

Total Cash Distribution

^[2]

$ 9

Common unit cash distribution declared (in dollars per unit)

$ 0.625

[1]	The Board of Directors declared a $0.16525 per common unit cash distribution on February 12, 2021, to be paid on March 1, 2021, to common unitholders of record at the close of business on February 22, 2021.
[2]	The Board of Directors declared a $0.625 per Series A Preferred Unit cash distribution on February 12, 2021, to be paid on February 12, 2021 to Series A Preferred unitholders of record at the close of business on February 12, 2021.

Partners' Equity - Narrative (Details) - USD ($)			12 Months Ended
Partners' Equity - Narrative (Details) - USD ($)	May 12, 2017	Feb. 18, 2016	Dec. 31, 2020	Dec. 31, 2019
Distribution Made to Limited Partner [Line Items]
Limited partners' capital account, required quarterly distribution period			60 days
Number of common units in public offering			0
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)		$ 25.00
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)		$ 25.00
ATM Program
Distribution Made to Limited Partner [Line Items]
Aggregate offering price	$ 200,000,000			$ 2,000,000
Number of common units in public offering				140,920
Commissions				$ 25,000
Maximum
Distribution Made to Limited Partner [Line Items]
Limited partners' capital account, incentive distribution rights, percentage			50.00%
Minimum
Distribution Made to Limited Partner [Line Items]
Incentive distribution, distribution (in dollars per unit)			$ 0.330625

Property, Plant and Equipment - Narrative (Details) - USD ($) $ in Millions			12 Months Ended
	Apr. 08, 2020	Apr. 01, 2020	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross			$ 13,220	$ 13,161
Accumulated depreciation			2,555	2,291
Property, plant and equipment, net			10,665	10,870
Depreciation expense			358	371	$ 351
Sale of interest		$ 19
Net loss on sale or retirement of assets			$ (24)	$ (8)	$ (1)
Gathering and Processing
Property, Plant and Equipment [Line Items]
Net loss on sale or retirement of assets	$ 20
Atoka
Property, Plant and Equipment [Line Items]
Ownership interest (as a percentage)			50.00%	50.00%	50.00%
Atoka \| Gathering and Processing
Property, Plant and Equipment [Line Items]
Impairment			$ 16
Gathering and Processing
Property, Plant and Equipment [Line Items]
Weighted Average Useful Lives (Years)			34 years 6 months
Property, plant and equipment, gross			$ 8,275	$ 8,252
Accumulated depreciation			$ 1,429	1,252
Transportation and Storage
Property, Plant and Equipment [Line Items]
Weighted Average Useful Lives (Years)			40 years 7 months 6 days
Property, plant and equipment, gross			$ 4,802	4,778
Accumulated depreciation			1,126	1,039
Construction work-in-progress
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross			143	131
Other property, plant and equipment
Property, Plant and Equipment [Line Items]
Net loss on sale or retirement of assets			$ 4	$ 8	$ 1

Intangible Assets, Net - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Finite-Lived Intangible Assets [Line Items]
Intangible assets with indefinite useful lives	$ 0
Amortization expense	62	$ 62	$ 47
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
Expected amortization of intangible assets, 2025	62
Customer Relationships
Finite-Lived Intangible Assets [Line Items]
Total intangible assets	840	840
Accumulated amortization	301	239
Net intangible assets	$ 539	$ 601
Weighted average useful life (in years)	14 years

Goodwill (Details) - USD ($) $ in Millions	12 Months Ended
Goodwill (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Goodwill [Roll Forward]
Goodwill	$ 12	$ 98
Goodwill impairment	(12)	(86)
Goodwill	0	12	$ 98
Gathering and Processing
Goodwill [Roll Forward]
Goodwill	12	98
Goodwill acquired				$ 12
Goodwill impairment	(12)	(86)
Goodwill	0	12	98
Gathering and Processing \| Velocity Holdings, LLC
Goodwill [Roll Forward]
Goodwill acquired			86
Transportation and Storage
Goodwill [Roll Forward]
Goodwill	0	0
Goodwill impairment	0	0
Goodwill	$ 0	$ 0	$ 0

Investment in Equity Method Affiliate - Narrative (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Schedule of Equity Method Investments [Line Items]
Amount billed associated with service agreements	$ 704	$ 596	$ 515	$ 648	$ 731	$ 699	$ 735	$ 795	$ 2,463	$ 2,960	$ 3,431
SESH
Schedule of Equity Method Investments [Line Items]
Ownership percentage	50.00%				50.00%				50.00%	50.00%	50.00%
Impairment of equity method affiliate investment									$ (225)	$ 0	$ 0
SESH \| Enbridge, Inc. [Member]
Schedule of Equity Method Investments [Line Items]
Ownership percentage	50.00%				50.00%				50.00%	50.00%
SESH \| Enable Midstream [Member]
Schedule of Equity Method Investments [Line Items]
Ownership percentage	50.00%				50.00%				50.00%	50.00%
SESH \| Equity Method Investee \| Shared Operations Service Agreements
Schedule of Equity Method Investments [Line Items]
Amount billed associated with service agreements									$ 15	$ 17	$ 18
SESH \| CenterPoint
Schedule of Equity Method Investments [Line Items]
Percentage distributions									50.00%

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

12 Months Ended

Dec. 31, 2020

Dec. 31, 2019

Dec. 31, 2018

Schedule of Equity Method Investments [Line Items]

Equity in earnings (losses) of equity method affiliate, net

$ (210)

$ 17

$ 26

Return on investment in equity method affiliate

Return of investment in equity method affiliate

SESH

Schedule of Equity Method Investments [Line Items]

Equity in Earnings of Equity Method Affiliate

Impairment of equity method affiliate investment

(225)

Equity in earnings (losses) of equity method affiliate, net

(210)

Distributions from Equity Method Affiliate (1)

^[1]

Return on investment in equity method affiliate

Return of investment in equity method affiliate

$ 8

$ 7

[1]	Distributions from equity method affiliate includes a $15 million, $17 million and $26 million return on investment and a $8 million, $8 million and $7 million return of investment for the years ended December 31, 2020, 2019 and 2018, respectively.

Investment in Equity Method Affiliate - Financial Information of SESH (Details) - USD ($)
$ in Millions

3 Months Ended

12 Months Ended

Dec. 31, 2020

Sep. 30, 2020

Jun. 30, 2020

Mar. 31, 2020

Dec. 31, 2019

Sep. 30, 2019

Jun. 30, 2019

Mar. 31, 2019

Dec. 31, 2020

Dec. 31, 2019

Dec. 31, 2018

Balance Sheets:

Current assets

$ 381

$ 389

$ 381

$ 389

Total Assets

11,729

12,266

11,729

12,266

$ 12,444

Current liabilities

582

780

582

780

Investment in SESH

309

Income Statements:

Operating income

139

^[1]

$ 100

^[1]

$ 80

^[1]

$ 146

^[1]

^[2]

$ 175

^[2]

$ 167

^[2]

$ 165

^[2]

465

569

648

Net income

$ (163)

$ 44

$ 105

$ 133

$ 124

$ 123

400

523

SESH

Income Statements:

Impairment of equity method affiliate investment

225

SESH

Balance Sheets:

Current assets

Property, plant and equipment, net

1,043

1,060

1,043

1,060

Total Assets

1,092

1,109

1,092

1,109

Current liabilities

Long-term debt

398

Members’ equity

663

681

663

681

Total liabilities and members’ equity

1,092

1,109

1,092

1,109

Investment in SESH

309

Add: Capitalized interest on investment in SESH

(1)

Add: Basis difference, net of amortization (1)

^[3]

256

The Partnership’s share of members’ equity

$ 331

$ 341

331

341

Income Statements:

Revenues

109

112

Operating income

Net income

$ 26

$ 33

$ 50

[1]	The Partnership recorded an impairment of $225 million in Equity in earnings (losses) of equity method affiliate, net during the third quarter related to its investment in SESH. See Note 11 for further information.
[2]	The Partnership recorded impairments to goodwill of $12 million and $86 million during the first quarter 2020 related to the Ark-La-Tex Basin reporting unit and the fourth quarter of 2019 related to the Anadarko Basin reporting unit, respectively, included in the gathering and processing reportable segment. See Note 10 for further information.
[3]	Includes the Partnership’s impairment of investment in equity method affiliate of $225 million recorded during the year ended December 31, 2020.

Debt - Schedule of Outstanding Debt (Details) - USD ($)

Dec. 31, 2020

Dec. 31, 2019

Debt Instrument [Line Items]

Short-term debt

$ 250,000,000

$ 155,000,000

Outstanding Principal

4,228,000,000

4,405,000,000

Premium (Discount)

8,000,000

7,000,000

^[1]

Total Debt

4,220,000,000

4,398,000,000

Debt Issuance Costs, Gross

^[2]

19,000,000

23,000,000

Long-term Debt, Excluding Current Maturities

3,951,000,000

3,969,000,000

Long-term Debt, before Debt Issuance Costs, Net, Current Maturities

^[3]

251,000,000

Loans Payable | 2019 Term Loan Agreement [Member]

Debt Instrument [Line Items]

Outstanding Principal

800,000,000

Premium (Discount)

^[1]

Total Debt

800,000,000

Senior Notes | 2024 Notes (Level 2)

Debt Instrument [Line Items]

Outstanding Principal

600,000,000

Premium (Discount)

^[1]

Total Debt

600,000,000

Senior Notes | 2027 Notes (Level 2)

Debt Instrument [Line Items]

Outstanding Principal

700,000,000

Premium (Discount)

(2,000,000)

^[1]

Total Debt

698,000,000

Senior Notes | 2028 Notes (Level 2)

Debt Instrument [Line Items]

Outstanding Principal

800,000,000

Premium (Discount)

(5,000,000)

^[1]

Total Debt

795,000,000

Senior Notes | 2029 Notes (Level 2)

Debt Instrument [Line Items]

Outstanding Principal

547,000,000

550,000,000

Premium (Discount)

(1,000,000)

^[1]

Total Debt

546,000,000

549,000,000

Senior Notes | 2044 Notes (Level 2)

Debt Instrument [Line Items]

Outstanding Principal

531,000,000

550,000,000

Premium (Discount)

^[1]

Total Debt

531,000,000

550,000,000

Revolving Credit Facility

Debt Instrument [Line Items]

Outstanding Principal

Premium (Discount)

^[1]

Total Debt

Debt Issuance Costs, Line of Credit Arrangements, Net

3,000,000

4,000,000

Commercial Paper

Debt Instrument [Line Items]

Short-term debt

^[4]

250,000,000

155,000,000

Premium (Discount)

^[1]

Subsidiary of Common Parent | Senior Notes | EOIT Senior Notes

Debt Instrument [Line Items]

Outstanding Principal

250,000,000

Premium (Discount)

1,000,000

^[1]

Total Debt

$ 0

$ 251,000,000

[1]	Unamortized premium (discount) on long-term debt is amortized over the life of the respective debt.
[2]	As of December 31, 2020 and 2019, there was an additional $3 million and $4 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 included the $251 million outstanding balance of the EOIT Senior Notes which were repaid in March 2020
[4]	Short-term debt includes $250 million and $155 million of commercial paper outstanding as of December 31, 2020 and 2019, respectively.

Debt - Maturities of Long Term Debt (Details) $ in Millions	Dec. 31, 2020 USD ($)
Debt Disclosure [Abstract]
Long-term debt maturities in 2021	$ 250
Long-term debt maturities in 2022	800
Long-term debt maturities in 2023	0
Long-term debt maturities in 2024	600
Long-term debt maturities in 2025	0
Thereafter	$ 2,578

Debt - Narrative (Details)

12 Months Ended

Jan. 29, 2019

USD ($)

Apr. 06, 2018

USD ($)

time

Dec. 31, 2020

USD ($)

Dec. 31, 2019

USD ($)

Dec. 31, 2018

USD ($)

Debt Instrument [Line Items]

Short-term debt

$ 250,000,000

$ 155,000,000

Gain (Loss) on Repurchase of Debt Instrument

5,000,000

$ 0

Revolving Credit Facility

Debt Instrument [Line Items]

Maximum borrowing capacity

$ 1,750,000,000

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

Additional term of loan

2 years

Letters of credit principal advances

Letters of credit outstanding amount

$ 0

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

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

Threshold for qualified project cost

$ 15

Revolving Credit Facility | Maximum

Debt Instrument [Line Items]

Consolidated debt to EBITDA ratio

5.00

Threshold for debt covenant ratio for acquisitions

5.50

Debt Instrument, Covenant Terms, Threshold for Qualified Project, Total Actual Consolidated EBITDA

2000.00%

2019 Term Loan Agreement [Member]

Debt Instrument [Line Items]

Weighted average interest rate percentage

2.10%

Number of times option may be exercised

Additional term of loan

1 year

Covenant, acceleration of indebtedness, threshold amount

$ 100,000,000

Covenant, acceleration of indebtedness, nonpayment of uninsured money judgments, threshold amount

100,000,000

Debt Instrument, Principle Advance

$ 800,000,000

Debt Instrument, Covenant, Consolidated Debt to EBITDA Ratio, Maximum

5.00

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

Debt Instrument [Line Items]

Threshold for debt covenant ratio for acquisitions

5.50

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%

2029 Notes and 2044 Notes

Debt Instrument [Line Items]

Debt Instrument, Repurchased Face Amount

$ 22,000,000

Debt Instrument, Repurchase Amount

17,000,000

Gain (Loss) on Repurchase of Debt Instrument

$ 5,000,000

Senior Notes | 2029 Notes (Level 2)

Debt Instrument [Line Items]

Effective interest rate percentage

4.29%

Senior Notes | 2028 Notes (Level 2)

Debt Instrument [Line Items]

Effective interest rate percentage

5.19%

Senior Notes | 2044 Notes (Level 2)

Debt Instrument [Line Items]

Effective interest rate percentage

4.99%

Senior Notes | 2027 Notes (Level 2)

Debt Instrument [Line Items]

Effective interest rate percentage

4.56%

Senior Notes | Senior Notes including 2024 Notes, 2027 Notes, 2028 Notes, 2029 Notes and 2044 Notes

Debt Instrument [Line Items]

Unamortized discount

$ 8,000,000

Unamortized debt expense

$ 19,000,000

Senior Notes | 2024 Notes (Level 2)

Debt Instrument [Line Items]

Effective interest rate percentage

4.01%

Commercial Paper

Debt Instrument [Line Items]

Commercial paper, authorized

$ 1,400,000,000

Short-term debt

^[1]

$ 250,000,000

$ 155,000,000

Weighted average interest rate percentage

0.86%

[1]	Short-term debt includes $250 million and $155 million of commercial paper outstanding as of December 31, 2020 and 2019, respectively.

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, 2020

USD ($)

MMBTU

bbl

Dec. 31, 2019

USD ($)

MMBTU

bbl

Derivative [Line Items]

Fair value hedges | $

$ 0

Not Designated as Hedging Instrument | Natural gas, Financial fixed futures/swaps | Purchases

Derivative [Line Items]

Derivative, gross notional volume (TBtu) | MMBTU

^[1]

Not Designated as Hedging Instrument | Natural gas, Financial fixed futures/swaps | Sales

Derivative [Line Items]

Derivative, gross notional volume (TBtu) | MMBTU

^[1]

Not Designated as Hedging Instrument | Natural gas, Financial basis futures/swaps | Purchases

Derivative [Line Items]

Derivative, gross notional volume (TBtu) | MMBTU

^[1]

Not Designated as Hedging Instrument | Natural gas, Financial basis futures/swaps | Sales

Derivative [Line Items]

Derivative, gross notional volume (TBtu) | MMBTU

^[1]

Not Designated as Hedging Instrument | Natural gas, Financial swaptions | Purchases

Derivative [Line Items]

Derivative, gross notional volume (TBtu) | MMBTU

^[1],[2]

Not Designated as Hedging Instrument | Natural gas, Financial swaptions | Sales

Derivative [Line Items]

Derivative, gross notional volume (TBtu) | MMBTU

^[1],[2]

Not Designated as Hedging Instrument | Natural gas, Physical purchases/sales | Purchases

Derivative [Line Items]

Derivative, gross notional volume (TBtu) | MMBTU

^[1]

Not Designated as Hedging Instrument | Natural gas, Physical purchases/sales | Sales

Derivative [Line Items]

Derivative, gross notional volume (TBtu) | MMBTU

^[1]

Not Designated as Hedging Instrument | Crude oil, Financial Futures/swaps | Purchases

Derivative [Line Items]

Derivative, gross notional volume (MBbl) | bbl

^[3]

Not Designated as Hedging Instrument | Crude oil, Financial Futures/swaps | Sales

Derivative [Line Items]

Derivative, gross notional volume (MBbl) | bbl

^[3]

465

990

Not Designated as Hedging Instrument | Crude oil, Financial swaptions | Purchases

Derivative [Line Items]

Derivative, gross notional volume (MBbl) | bbl

^[2],[3]

Not Designated as Hedging Instrument | Crude oil, Financial swaptions | Sales

Derivative [Line Items]

Derivative, gross notional volume (MBbl) | bbl

^[2],[3]

225

Not Designated as Hedging Instrument | Natural gas liquids, Financial Futures/swaps | Purchases

Derivative [Line Items]

Derivative, gross notional volume (MBbl) | bbl

^[4]

855

2,490

Not Designated as Hedging Instrument | Natural gas liquids, Financial Futures/swaps | Sales

Derivative [Line Items]

Derivative, gross notional volume (MBbl) | bbl

^[4]

1,210

2,415

Not Designated as Hedging Instrument | Natural gas liquids, Financial swaptions | Purchases

Derivative [Line Items]

Derivative, gross notional volume (MBbl) | bbl

^[2]

Not Designated as Hedging Instrument | Natural gas liquids, Financial swaptions | Sales

Derivative [Line Items]

Derivative, gross notional volume (MBbl) | bbl

^[2]

Not Designated as Hedging Instrument | Natural gas

Derivative [Line Items]

Percent of contract with durations of one year or less

95.70%

86.60%

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

4.30%

13.40%

Not Designated as Hedging Instrument | Crude oil (for condensate)

Derivative [Line Items]

Percent of contract with durations of one year or less

100.00%

72.80%

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

27.20%

Not Designated as Hedging Instrument | Volume of natural gas liquids

Derivative [Line Items]

Percent of contract with durations of one year or less

100.00%

72.20%

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

27.80%

Designated as Hedging Instrument

Derivative [Line Items]

Designated cash flow hedges | $

$ 0

[1]	As of December 31, 2020, 95.7% of the natural gas contracts had durations of one year or less and 4.3% had durations of more than one year and less than two years. 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.
[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, 2020, 100.0% of the crude oil (for condensate) contracts had durations of one year or less. 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.
[4]	As of December 31, 2020, 100.0% of the natural gas liquids contracts had durations of one year or less. 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.

Derivative Instruments and Hedging Activities - Derivative Instruments Designated as Hedging Instruments (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Designated as Hedging Instrument \| Interest rate swaps
Derivative [Line Items]
Interest rate swaps	$ 300	$ 300

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

Dec. 31, 2020

Dec. 31, 2019

Not Designated as Hedging Instrument

Derivatives, Fair Value [Line Items]

Derivative asset

^[1]

$ 19

$ 49

Derivative liability

^[1]

Designated as Hedging Instrument

Derivatives, Fair Value [Line Items]

Derivative asset

^[2]

Derivative liability

^[2]

Interest rate swaps | Designated as Hedging Instrument | Other Current Assets

Derivatives, Fair Value [Line Items]

Derivative asset

Interest rate swaps | Designated as Hedging Instrument | Other Current Liabilities

Derivatives, Fair Value [Line Items]

Derivative liability

Interest rate swaps | Designated as Hedging Instrument | Other Noncurrent Assets

Derivatives, Fair Value [Line Items]

Derivative asset

Interest rate swaps | Designated as Hedging Instrument | Other Noncurrent Liabilities

Derivatives, Fair Value [Line Items]

Derivative liability

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

Derivatives, Fair Value [Line Items]

Derivative asset

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

Derivatives, Fair Value [Line Items]

Derivative liability

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

Derivatives, Fair Value [Line Items]

Derivative asset

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

Derivatives, Fair Value [Line Items]

Derivative liability

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

Derivatives, Fair Value [Line Items]

Derivative asset

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

Derivatives, Fair Value [Line Items]

Derivative liability

Natural gas | Financial swaption | Not Designated as Hedging Instrument | Other Current Assets

Derivatives, Fair Value [Line Items]

Derivative asset

Natural gas | Financial swaption | Not Designated as Hedging Instrument | Other Current Liabilities

Derivatives, Fair Value [Line Items]

Derivative liability

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

Derivatives, Fair Value [Line Items]

Derivative asset

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

Derivatives, Fair Value [Line Items]

Derivative liability

Crude oil (for condensate) | Financial futures/swaps | Not Designated as Hedging Instrument | Other Noncurrent Assets

Derivatives, Fair Value [Line Items]

Derivative asset

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

Derivatives, Fair Value [Line Items]

Derivative liability

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

Derivatives, Fair Value [Line Items]

Derivative asset

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

Derivatives, Fair Value [Line Items]

Derivative liability

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

Derivatives, Fair Value [Line Items]

Derivative asset

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

Derivatives, Fair Value [Line Items]

Derivative liability

Natural gas liquids | Financial swaption | Not Designated as Hedging Instrument | Other Current Assets

Derivatives, Fair Value [Line Items]

Derivative asset

Natural gas liquids | Financial swaption | Not Designated as Hedging Instrument | Other Current Liabilities

Derivatives, Fair Value [Line Items]

Derivative liability

$ 1

$ 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, 2020 and 2019.
[2]	All interest rate derivative instruments that were designated as cash flow hedges are considered Level 2 as of December 31, 2020.

Derivative Instruments and Hedging Activities - Amounts Recognized in Income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative, net	$ 10	$ 16	$ 11
Change in fair value of derivatives	(13)	(11)	26
Realized gain (loss) on derivatives	23	27	(15)
Gain on derivative activity	10	16	11
Cash collateral already posted	0
Additional cash collateral that would be required to be posted	1
Interest rate swaps
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain on Derivative	4	0
Natural gas \| Natural gas, Physical purchases/sales
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative, net	0	2	7
Natural gas \| Financial futures/swaps
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative, net	4	13	(8)
Natural gas \| Financial swaption
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative, net	(2)	0	0
Crude oil (for condensate) \| Financial futures/swaps
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative, net	10	(41)	6
Natural gas liquids \| Financial futures/swaps
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative, net	$ (2)	$ 42	$ 6

Derivative Instruments and Hedging Activities - Derivative Instruments Designated as Hedging Instruments (Details) - Designated as Hedging Instrument - USD ($)
$ in Millions

Dec. 31, 2020

Dec. 31, 2019

Derivative [Line Items]

Derivative asset

^[1]

$ 0

Derivative liability

^[1]

Other Current Assets | Interest rate swaps

Derivative [Line Items]

Derivative asset

Other Noncurrent Liabilities | Interest rate swaps

Derivative [Line Items]

Derivative liability

Other Current Liabilities | Interest rate swaps

Derivative [Line Items]

Derivative liability

Other Noncurrent Assets | Interest rate swaps

Derivative [Line Items]

Derivative asset

$ 0

[1]	All interest rate derivative instruments that were designated as cash flow hedges are considered Level 2 as of December 31, 2020.

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

Dec. 31, 2020

Dec. 31, 2019

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

Short-term debt

$ 250,000,000

$ 155,000,000

Carrying Amount | Significant other observable inputs (Level 2) | Loans Payable | 2019 Term Loan Agreement (Level 2)

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

2019 Term Loan Agreement (Level 2)

800,000,000

Carrying Amount | Significant other observable inputs (Level 2) | Senior Notes | 2024 Notes (Level 2)

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

Senior Notes (Level 2)

600,000,000

Carrying Amount | Significant other observable inputs (Level 2) | Senior Notes | 2027 Notes (Level 2)

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

Senior Notes (Level 2)

698,000,000

Carrying Amount | Significant other observable inputs (Level 2) | Senior Notes | 2028 Notes (Level 2)

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

Senior Notes (Level 2)

795,000,000

Carrying Amount | Significant other observable inputs (Level 2) | Senior Notes | 2029 Notes (Level 2)

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

Senior Notes (Level 2)

546,000,000

549,000,000

Carrying Amount | Significant other observable inputs (Level 2) | Senior Notes | 2044 Notes (Level 2)

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

Senior Notes (Level 2)

531,000,000

550,000,000

Carrying Amount | Significant other observable inputs (Level 2) | Senior Notes | EOIT Senior Notes | Subsidiary of Common Parent

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

Senior Notes (Level 2)

251,000,000

Carrying Amount | Significant other observable inputs (Level 2) | Revolving Credit Facility (Level 2) | Revolving Credit Facility (Level 2)

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

Revolving Credit Facility (Level 2)

^[1]

Fair Value | Significant other observable inputs (Level 2) | Loans Payable | 2019 Term Loan Agreement (Level 2)

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

2019 Term Loan Agreement (Level 2)

800,000,000

Fair Value | Significant other observable inputs (Level 2) | Senior Notes | 2024 Notes (Level 2)

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

Senior Notes (Level 2)

612,000,000

614,000,000

Fair Value | Significant other observable inputs (Level 2) | Senior Notes | 2027 Notes (Level 2)

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

Senior Notes (Level 2)

709,000,000

698,000,000

Fair Value | Significant other observable inputs (Level 2) | Senior Notes | 2028 Notes (Level 2)

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

Senior Notes (Level 2)

817,000,000

811,000,000

Fair Value | Significant other observable inputs (Level 2) | Senior Notes | 2029 Notes (Level 2)

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

Senior Notes (Level 2)

544,000,000

526,000,000

Fair Value | Significant other observable inputs (Level 2) | Senior Notes | 2044 Notes (Level 2)

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

Senior Notes (Level 2)

499,000,000

506,000,000

Fair Value | Significant other observable inputs (Level 2) | Senior Notes | EOIT Senior Notes | Subsidiary of Common Parent

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

Senior Notes (Level 2)

252,000,000

Fair Value | Significant other observable inputs (Level 2) | Revolving Credit Facility (Level 2) | Revolving Credit Facility (Level 2)

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

Revolving Credit Facility (Level 2)

^[1]

Commercial Paper

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

Short-term debt

^[2]

$ 250,000,000

$ 155,000,000

[1]	Borrowing capacity is effectively reduced by our borrowings outstanding under the commercial paper program. $250 million and $155 million of commercial paper was outstanding as of December 31, 2020 and 2019, respectively.
[2]	Short-term debt includes $250 million and $155 million of commercial paper outstanding as of December 31, 2020 and 2019, respectively.

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

Dec. 31, 2020

Dec. 31, 2019

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

Retained fuel due from shippers

$ 19

$ 21

Retained fuel due to shippers

Commodity Contracts | Fair Value, Recurring

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

Assets, total fair value

Liabilities, total fair value

Asset netting adjustment

(19)

(37)

Liability netting adjustment

(19)

(37)

Total assets

Total liabilities

Commodity Contracts | Fair Value, Recurring | Quoted market prices in active market for identical assets (Level 1)

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

Assets

Liabilities

Commodity Contracts | Fair Value, Recurring | Significant other observable inputs (Level 2)

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

Assets

Liabilities

Gas Imbalances | Fair Value, Recurring

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

Assets, total fair value

^[1],[2]

Liabilities, total fair value

^[2],[3]

Asset netting adjustment

^[1],[2]

Liability netting adjustment

^[2],[3]

Total assets

^[1],[2]

Total liabilities

^[2],[3]

Gas Imbalances | Fair Value, Recurring | Quoted market prices in active market for identical assets (Level 1)

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

Assets

^[1],[2]

Liabilities

^[2],[3]

Gas Imbalances | Fair Value, Recurring | Significant other observable inputs (Level 2)

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

Assets

^[1],[2]

Liabilities

^[2],[3]

$ 16

$ 11

[1]	Gas imbalance assets exclude fuel reserves for under retained fuel due from shippers of $19 million and $21 million at December 31, 2020 and 2019, 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, 2020 and 2019.
[3]	Gas imbalance liabilities exclude fuel reserves for over retained fuel due to shippers of $3 million and $8 million at December 31, 2020 and 2019, respectively, which fuel reserves are based on the value of natural gas at the time the imbalance was created and which are not subject to revaluation at fair market value.

Supplemental Disclosure of Cash Flow Information - Supplemental Disclosure of Cash Flow Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Interest, net of capitalized interest	$ 180	$ 185	$ 148
Income tax, net of refunds	1	1	3
Accounts payable related to capital expenditures	9	10	54
Lease liabilities related to derecognition of right-of-use assets	(5)
Lease liabilities related to recognition of right-of-use assets		45	0
Impact of adoption of financial instruments-credit losses accounting standard (Note 1)	7,095	7,409	7,618	$ 7,654
Common Units \| Partners' Capital
Impact of adoption of financial instruments-credit losses accounting standard (Note 1)	$ 6,713	7,013	$ 7,218	$ 7,280
Cumulative Effect, Period of Adoption, Adjustment [Member]
Impact of adoption of financial instruments-credit losses accounting standard (Note 1)		(3)
Cumulative Effect, Period of Adoption, Adjustment [Member] \| Common Units \| Partners' Capital
Impact of adoption of financial instruments-credit losses accounting standard (Note 1)		$ (3)

Related Party Transactions - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Related Party Transaction [Line Items]
Partnership's revenues from affiliated companies as a percent of total revenues	6.00%	6.00%	5.00%
Subsidiary of Common Parent \| Amount Reimbursed to Customers for Costs Incurred \| Pipelines
Related Party Transaction [Line Items]
Amount of reimbursement	$ 1	$ 2	$ 1
Subsidiary of Common Parent \| CenterPoint \| Three Services included in Transportation and Storage Agreements
Related Party Transaction [Line Items]
Period of written notice prior to contract termination	180 days
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
Related Party Transaction [Line Items]
Damages paid	2
OGE Energy \| Demand Service Revenue
Related Party Transaction [Line Items]
Waiver of revenue	$ (5)
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 annual caps	$ 5	$ 5	$ 5
OGE Energy \| Certain Services and Support Functions
Related Party Transaction [Line Items]
Expense reimbursement annual caps	$ 1

Related Party Transactions - Related Party Activity (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Related Party Transaction [Line Items]
Revenues from affiliated companies	$ 149	$ 167	$ 163
Cost of goods sold from affiliated companies	25	33	26
Corporate services, operating lease and seconded employee expense from affiliated companies	17	19	32
CenterPoint
Related Party Transaction [Line Items]
Cost of goods sold from affiliated companies	1	0	3
CenterPoint \| Gas Transportation and Storage
Related Party Transaction [Line Items]
Revenues from affiliated companies	100	108	111
CenterPoint \| Gas Sales
Related Party Transaction [Line Items]
Revenues from affiliated companies	1	8	11
CenterPoint \| Corporate Services
Related Party Transaction [Line Items]
Corporate services, operating lease and seconded employee expense from affiliated companies	0	0	1
CenterPoint \| Operating Lease
Related Party Transaction [Line Items]
Corporate services, operating lease and seconded employee expense from affiliated companies	0	1	1
OGE Energy
Related Party Transaction [Line Items]
Cost of goods sold from affiliated companies	24	33	23
OGE Energy \| Gas Transportation and Storage
Related Party Transaction [Line Items]
Revenues from affiliated companies	38	41	37
OGE Energy \| Gas Sales
Related Party Transaction [Line Items]
Revenues from affiliated companies	10	10	4
OGE Energy \| Seconded Employee Costs
Related Party Transaction [Line Items]
Corporate services, operating lease and seconded employee expense from affiliated companies	17	18	29
OGE Energy \| Corporate Services
Related Party Transaction [Line Items]
Corporate services, operating lease and seconded employee expense from affiliated companies	$ 0	$ 0	$ 1

Commitments and Contingencies - Narrative (Details) $ in Millions	Sep. 13, 2018	Jan. 01, 2017 MMcf	Dec. 31, 2020 USD ($)
Commitments and Contingencies Disclosure [Abstract]
Gathering and processing agreement term		10 years
Energy deliveries (in MMcf/d) \| MMcf		400
Minimum volume commitment fee			$ 172
Minimum volume commitment fees per year from 2021 through 2027			23
Minimum volume commitment fees in 2028			11
Estimated cost to complete			$ 500
Firm transportation term	20 years

Income Taxes - Narrative (Details) - USD ($)	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Unrecognized tax benefits	$ 0	$ 0	$ 0

Income Taxes - Schedule of Expense (Benefit) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Provision for current income tax
Federal	$ (2)	$ 0	$ 0
State	1	0	0
Total provision for current income tax	(1)	0	0
Benefit for deferred income tax, net
Federal	1	(1)	(1)
State	0	0	0
Total benefit for deferred income tax, net	1	(1)	(1)
Total income tax benefit	$ 0	$ (1)	$ (1)

- Definition

Amount of current income tax expense (benefit) and deferred income tax expense (benefit) pertaining to continuing operations.

+ References + Details

Income Taxes - Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Operating Loss Carryforwards [Line Items]
Deferred Tax Assets, Operating Loss Carryforwards	$ 1	$ 2
Deferred tax liabilities, net:
Intercompany management fee	16	17
Depreciation	5	6
Deferred Tax Assets, Operating Loss Carryforwards	1	2
Accrued compensation	(15)	(17)
Total deferred tax liabilities, net	5	$ 4
Domestic Tax Authority [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards	4
Deferred Tax Assets, Operating Loss Carryforwards	1
Deferred tax liabilities, net:
Deferred Tax Assets, Operating Loss Carryforwards	1
State and Local Jurisdiction [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards	8
Deferred Tax Assets, Operating Loss Carryforwards, Subject to Expiration	2
Deferred Tax Assets, Operating Loss Carryforwards	0
Deferred tax liabilities, net:
Deferred Tax Assets, Operating Loss Carryforwards	$ 0

Equity-Based Compensation - (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total equity-based compensation expense	$ 13	$ 16	$ 16
Performance units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total equity-based compensation expense	7	9	9
Restricted units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total equity-based compensation expense	0	0	1
Phantom units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total equity-based compensation expense	$ 6	$ 7	$ 6
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 - Performance Units (Details) - Performance units - $ / shares

12 Months Ended

Dec. 31, 2020

Dec. 31, 2019

Dec. 31, 2018

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

Duration of daily stock price observations to determine expected price volatility

3 years

Number of units granted (in units)

933,738

^[1]

638,798

551,742

Fair value of units granted (in dollars per share)

$ 7.00

^[1]

$ 19.95

$ 17.70

Expected price volatility percentage

27.70%

34.20%

44.20%

Risk-free interest rate percentage

0.85%

2.54%

2.36%

Distribution yield percentage

12.27%

8.38%

8.56%

Expected life of units (in years)

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%

[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.

Equity-Based Compensation - Phantom Units (Details) - $ / shares

12 Months Ended

Dec. 31, 2020

Dec. 31, 2019

Dec. 31, 2018

Phantom units

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Period from change in control

2 years

Units granted (in units)

1,002,345

^[1]

695,486

546,708

Fair value of units granted (in dollars per share)

^[1]

$ 6.44

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)

2.67

$ 8.95

$ 13.74

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)

$ 10.13

$ 15.04

$ 17.00

Other Awards | Independent Directors Of Enable GP

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Units granted (in units)

63,963

28,221

16,335

Fair value of units granted (in dollars per share)

$ 4.23

$ 10.43

$ 14.94

[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.

Equity-Based Compensation - Equity Units Activity (Details) - USD ($)
$ / shares in Units, $ in Millions

12 Months Ended

Dec. 31, 2020

Dec. 31, 2019

Dec. 31, 2018

Performance units

Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]

Units Outstanding at 12/31/2019 (in units)

1,393,329

Units granted (in units)

933,738

^[1]

638,798

551,742

Vested (in units)

^[2],[3]

(390,079)

Forfeited (in units)

(171,480)

Units Outstanding at 12/31/2020 (in units)

1,765,508

1,393,329

Weighted Average Grant-Date Fair Value, Per Unit

Units Outstanding at 12/31/2019 (in dollars per share)

$ 19.04

Granted (in dollars per share)

7.00

^[1]

$ 19.95

$ 17.70

Vested (in dollars per share)

^[2],[3]

19.21

Forfeited (in dollars per share)

14.25

Units Outstanding at 12/31/2020 (in dollars per share)

$ 13.10

$ 19.04

Aggregate intrinsic value of units outstanding

$ 9

Aggregate intrinsic value of units vested

$ 34

$ 11

Fair value of units vested

$ 7

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%

Performance units | Awards Granted in 2017

Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]

Units granted (in units)

376,292

Performance units | Awards Granted in 2018

Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]

Units granted (in units)

389,817

Performance units | Awards Granted in 2018 | Maximum

Weighted Average Grant-Date Fair Value, Per Unit

Payout percentage from target level of achievement of performance goal

0.00%

Restricted units

Weighted Average Grant-Date Fair Value, Per Unit

Aggregate intrinsic value of units vested

$ 0

Fair value of units vested

$ 0

$ 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 12/31/2019 (in units)

1,392,560

Units granted (in units)

1,002,345

^[1]

695,486

546,708

Vested (in units)

^[2],[3]

(399,406)

Forfeited (in units)

(204,654)

Units Outstanding at 12/31/2020 (in units)

1,790,845

1,392,560

Weighted Average Grant-Date Fair Value, Per Unit

Units Outstanding at 12/31/2019 (in dollars per share)

$ 14.65

Granted (in dollars per share)

^[1]

6.44

Vested (in dollars per share)

^[2],[3]

15.76

Forfeited (in dollars per share)

10.46

Units Outstanding at 12/31/2020 (in dollars per share)

$ 10.29

$ 14.65

Aggregate intrinsic value of units outstanding

$ 9

Aggregate intrinsic value of units vested

$ 9

$ 1

Fair value of units vested

$ 6

$ 5

$ 0

[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 outstanding as of December 31, 2020 include 389,817 units from the 2018 annual grants, which were approved by the Board of Directors in 2018 and, based on the level of achievement of a performance goal established by the Board of Directors over a performance period of January 1, 2018 through December 31, 2020, will vest at 0%. The decrease in outstanding units for a payout percentage of an amount other than 100% is not reflected above until the vesting date.
[3]	Performance units vested as of December 31, 2020 include 376,292 from the 2017 annual grant, 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 the performance period of January 1, 2017 through December 31, 2019, no performance units vested.

Equity-Based Compensation - Unrecognized Compensation Cost (Details) $ in Millions	12 Months Ended
	Dec. 31, 2020 USD ($) shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized Compensation Cost (In millions)	$ 15
Long Term Incentive Plan \| Common Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares available for issuance \| shares	5,234,214
Performance units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized Compensation Cost (In millions)	$ 9
Weighted Average Period for Recognition (In years)	1 year 5 months 4 days
Phantom units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized Compensation Cost (In millions)	$ 6
Weighted Average Period for Recognition (In years)	1 year 3 months 18 days

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

3 Months Ended

12 Months Ended

Dec. 31, 2020

USD ($)

Sep. 30, 2020

USD ($)

Jun. 30, 2020

USD ($)

Mar. 31, 2020

USD ($)

Dec. 31, 2019

USD ($)

Sep. 30, 2019

USD ($)

Jun. 30, 2019

USD ($)

Mar. 31, 2019

USD ($)

Dec. 31, 2020

USD ($)

segment

Dec. 31, 2019

USD ($)

Dec. 31, 2018

USD ($)

Segment Reporting Information [Line Items]

Number of reportable segments | segment

Total Revenues

$ 704

$ 596

$ 515

$ 648

$ 731

$ 699

$ 735

$ 795

$ 2,463

$ 2,960

$ 3,431

Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)

312

250

177

226

321

263

317

378

965

1,279

1,819

Operation and maintenance, General and administrative

516

526

501

Depreciation and amortization

420

433

398

Impairments of property, plant and equipment and goodwill

Taxes other than income tax

Operating Income

139

^[1]

$ 100

^[1]

$ 80

^[1]

$ 146

^[1]

^[2]

$ 175

^[2]

$ 167

^[2]

$ 165

^[2]

465

569

648

Assets

11,729

12,266

11,729

12,266

12,444

Capital expenditures

215

432

1,171

Operating Segments | Gathering and Processing

Segment Reporting Information [Line Items]

Total Revenues

1,886

2,338

2,818

Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)

936

1,203

1,741

Operation and maintenance, General and administrative

334

320

312

Depreciation and amortization

299

308

263

Impairments of property, plant and equipment and goodwill

Taxes other than income tax

Operating Income

247

380

464

Assets

10,830

9,739

10,830

9,739

9,874

Capital expenditures

107

314

981

Operating Segments | Transportation and Storage

Segment Reporting Information [Line Items]

Total Revenues

881

1,038

1,162

Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)

332

491

628

Operation and maintenance, General and administrative

183

207

189

Depreciation and amortization

121

125

135

Impairments of property, plant and equipment and goodwill

Taxes other than income tax

Operating Income

218

189

183

Assets

5,729

5,886

^[3]

5,729

5,886

^[3]

5,805

^[3]

Capital expenditures

108

118

190

Eliminations

Segment Reporting Information [Line Items]

Total Revenues

(304)

(416)

(549)

Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)

(303)

(415)

(550)

Operation and maintenance, General and administrative

(1)

Depreciation and amortization

Impairments of property, plant and equipment and goodwill

Taxes other than income tax

Operating Income

Assets

$ (4,830)

$ (3,359)

(4,830)

(3,359)

(3,235)

Capital expenditures

Product

Segment Reporting Information [Line Items]

Total Revenues

1,132

1,533

2,106

Product | Operating Segments | Gathering and Processing

Segment Reporting Information [Line Items]

Total Revenues

1,087

1,449

2,016

Product | Operating Segments | Transportation and Storage

Segment Reporting Information [Line Items]

Total Revenues

340

487

625

Product | Eliminations

Segment Reporting Information [Line Items]

Total Revenues

(295)

(403)

(535)

Natural Gas, Gathering, Transportation, Marketing and Processing

Segment Reporting Information [Line Items]

Total Revenues

1,331

1,427

1,325

Natural Gas, Gathering, Transportation, Marketing and Processing | Operating Segments | Gathering and Processing

Segment Reporting Information [Line Items]

Total Revenues

799

889

802

Natural Gas, Gathering, Transportation, Marketing and Processing | Operating Segments | Transportation and Storage

Segment Reporting Information [Line Items]

Total Revenues

541

551

537

Natural Gas, Gathering, Transportation, Marketing and Processing | Eliminations

Segment Reporting Information [Line Items]

Total Revenues

$ (9)

$ (13)

$ (14)

[1]	The Partnership recorded an impairment of $225 million in Equity in earnings (losses) of equity method affiliate, net during the third quarter related to its investment in SESH. See Note 11 for further information.
[2]	The Partnership recorded impairments to goodwill of $12 million and $86 million during the first quarter 2020 related to the Ark-La-Tex Basin reporting unit and the fourth quarter of 2019 related to the Anadarko Basin reporting unit, respectively, included in the gathering and processing reportable segment. See Note 10 for further information.
[3]	See Note 11 for discussion regarding ownership interests in SESH and related equity earnings (losses) included in the transportation and storage reportable segment for the years ended December 31, 2020, 2019 and 2018.

Quarterly Financial Data (Unaudited) (Details) - USD ($)
$ / shares in Units, $ in Millions

3 Months Ended

12 Months Ended

Dec. 31, 2020

Sep. 30, 2020

Jun. 30, 2020

Mar. 31, 2020

Dec. 31, 2019

Sep. 30, 2019

Jun. 30, 2019

Mar. 31, 2019

Dec. 31, 2020

Dec. 31, 2019

Dec. 31, 2018

Effect of Fourth Quarter Events [Line Items]

Total Revenues

$ 704

$ 596

$ 515

$ 648

$ 731

$ 699

$ 735

$ 795

$ 2,463

$ 2,960

$ 3,431

Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)

312

250

177

226

321

263

317

378

965

1,279

1,819

Operating income (loss)

139

^[1]

100

^[1]

146

^[1]

^[2]

175

^[2]

167

^[2]

165

^[2]

465

569

648

Net income (loss)

(163)

105

133

124

123

400

523

Net income attributable to limited partners

(164)

112

132

124

122

396

521

Net income attributable to common units

$ 87

$ (173)

$ 35

$ 103

$ 9

$ 123

$ 115

$ 113

360

485

Goodwill impairment

Common Units

Effect of Fourth Quarter Events [Line Items]

Net income attributable to common units

$ 52

$ 360

$ 485

Basic earnings (loss) per unit

$ 0.20

$ (0.40)

$ 0.08

$ 0.24

$ 0.02

$ 0.28

$ 0.26

$ 0.12

$ 0.83

$ 1.12

Diluted earnings (loss) per unit

$ 0.19

$ (0.40)

$ 0.08

$ 0.19

$ 0.02

$ 0.28

$ 0.26

$ 0.12

$ 0.82

$ 1.11

[1]	The Partnership recorded an impairment of $225 million in Equity in earnings (losses) of equity method affiliate, net during the third quarter related to its investment in SESH. See Note 11 for further information.
[2]	The Partnership recorded impairments to goodwill of $12 million and $86 million during the first quarter 2020 related to the Ark-La-Tex Basin reporting unit and the fourth quarter of 2019 related to the Anadarko Basin reporting unit, respectively, included in the gathering and processing reportable segment. See Note 10 for further information.

Subsequent Event (Details) - USD ($) $ in Millions		12 Months Ended
Subsequent Event (Details) - USD ($) $ in Millions	Feb. 17, 2021	Dec. 31, 2020
CenterPoint and OGE Energy \| Partners' Capital
Subsequent Event [Line Items]
Limited partner ownership percentage interest		79.20%
Subsequent Event \| Scenario, Forecast \| Partnership Interest
Subsequent Event [Line Items]
Aggregate purchase price	$ 10
Subsequent Event \| Scenario, Forecast \| Common Units
Subsequent Event [Line Items]
Merger agreement, right to receive number of common units per share	0.8595
Subsequent Event \| Scenario, Forecast \| Series A Preferred Units
Subsequent Event [Line Items]
Merger agreement, right to receive number of common units per share	0.0265

Revenues - Summary of Recognition of Remaining Performance Obligations (Details) $ in Millions	Dec. 31, 2020 USD ($)
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	$ 563
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
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	$ 443
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
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	$ 120
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
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	$ 494
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
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	$ 371
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
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, Period	1 year
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	$ 457
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
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	$ 336
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
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, Period	1 year
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	$ 351
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
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	$ 250
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
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	$ 101
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total remaining performance obligations	$ 1,151
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	22 years 5 months 1 day
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 \| Transportation and Storage
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total remaining performance obligations	$ 938
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	22 years 5 months 1 day
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 \| Gathering and Processing
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total remaining performance obligations	$ 213
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	4 years 2 months 1 day