0001591763-20-000009 | 10-K | XBRL Viewer | Enable Midstream Partners LP

Equity Method Investments and Joint Ventures [Abstract]

In the fourth quarter of 2017, as a result of the acquisition of ETGP, the Partnership recorded $12 million of goodwill associated with the Ark-La-Tex Basin reporting unit, included in the gathering and processing reportable segment. In the fourth quarter of 2018, as a result of the acquisition of EOCS, the Partnership recorded $86 million of goodwill associated with the Anadarko Basin reporting unit, included in the gathering and processing reportable segment.

The Partnership tests its goodwill for impairment annually on October 1st, or more frequently if events or changes in circumstances indicate that the carrying value of goodwill may not be recoverable. Goodwill is assessed for impairment by comparing the fair value of the reporting unit with its book value, including goodwill. During 2019, the crude oil and natural gas industry was impacted by current and forward commodity price declines. Amid such crude oil, natural gas and NGL price declines, producers have been cutting back spending and shifting their focus from emphasizing reserves growth, to increasing net cash flows and reducing outstanding debt, which consequently resulted in a decrease in rig count and in forecasted producer activity in the Anadarko Basin reporting unit during the fourth quarter of 2019. At the same time, unit prices and market multiples for midstream companies with gathering and processing operations have dropped to their lowest levels in the last three years. Due to the continuing decrease in forward commodity prices, the reduction in forecasted producer activities, the resulting decrease in our forecasted cash flows and the increase in the weighted average cost of capital, the Partnership determined that the fair value of the goodwill associated with our Anadarko Basin reporting unit would more likely than not be impaired. As a result, 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.

While the fair value of the Ark-La-Tex Basin reporting unit exceeded its carrying value as of December 31, 2019, a lower fair value estimate and an impairment of the Partnership’s $12 million of goodwill could result from sustained commodity price declines, throughput declines, contracted capacity declines, cost increases, regulatory or political environment changes and other changes in market conditions, such as decreased prices in market-based transactions for similar assets. The change in carrying amount of goodwill in each of our reportable segments is as follows:



	Gathering and Processing			Transportation and Storage		Total

	(in millions)
Balance as of December 31, 2017	$	12		$	—	$	12
EOCS Acquisition ⁽¹⁾	86			—		86
Balance as of December 31, 2018	$	98		$	—	$	98
Goodwill impairment	$	(86	)	$	—	$	(86	)
Balance as of December 31, 2019	$	12		$	—	$	12

_____________________

(1)

See Note 5 for further discussion.

Investment in Equity Method Affiliate

12 Months Ended

Dec. 31, 2019

Investment in Equity Method Affiliate

The Partnership uses the equity method of accounting for investments in entities in which it has an ownership interest between 20% and 50% and exercises significant influence.

SESH is owned 50% by Enbridge Inc. and 50% by the Partnership for the years ended December 31, 2019 and 2018. Pursuant to the terms of the SESH LLC Agreement, if, at any time, CenterPoint Energy has a right to receive less than 50% of our distributions through its limited partner interest in the Partnership and its economic interest in Enable GP, or does not have the ability to exercise certain control rights, Enbridge Inc. may, under certain circumstances, have the right to purchase the Partnership’s interest in SESH at fair market value, subject to certain exceptions.

The Partnership shares operations of SESH with Enbridge Inc. under service agreements. The Partnership is responsible for the field operations of SESH. SESH reimburses each party for actual costs incurred, which are billed based upon a combination of direct charges and allocations. During the years ended December 31, 2019, 2018 and 2017, the Partnership billed SESH $17 million, $18 million and $17 million, respectively, associated with these service agreements.

The Partnership includes equity in earnings of equity method affiliate under the Other Income (Expense) caption in the Consolidated Statements of Income for the years ended December 31, 2019, 2018 and 2017.

SESH:



	Year Ended December 31,
	2019		2018		2017

	(In millions)
Equity in Earnings of Equity Method Affiliate	$	17	$	26	$	28
Distributions from Equity Method Affiliate ⁽¹⁾	25		33		33

____________________


(1)	Distributions from equity method affiliate includes a $17 million, $26 million and $28 million return on investment and a $8 million, $7 million and $5 million return of investment for the years ended December 31, 2019, 2018 and 2017, respectively.

Summarized financial information of SESH:



	December 31,
	2019			2018

	(In millions)
Balance Sheets:
Current assets	$	49		$	30
Property, plant and equipment, net	1,060			1,078
Total assets	$	1,109		$	1,108
Current liabilities	$	30		$	13
Long-term debt	398			397
Members’ equity	681			698
Total liabilities and members’ equity	$	1,109		$	1,108
Reconciliation:
Investment in SESH	$	309		$	317
Less: Capitalized interest on investment in SESH	(1		)	(1		)
Add: Basis differential, net of amortization	33			33
The Partnership’s share of members’ equity	$	341		$	349



	Year Ended December 31,
	2019		2018		2017

	(In millions)
Income Statements:
Revenues	$	109	$	112	$	113
Operating income	50		67		72
Net income	33		50		54

Debt

12 Months Ended

Dec. 31, 2019

Debt Disclosure [Abstract]

Debt

The following table presents the Partnership’s outstanding debt as of December 31, 2019 and 2018.



	December 31, 2019							December 31, 2018
	Outstanding Principal		Premium (Discount)⁽¹⁾			Total Debt		Outstanding Principal		Premium (Discount)⁽¹⁾			Total Debt

	(In millions)
Commercial Paper	$	155	$	—		$	155	$	649	$	—		$	649
Revolving Credit Facility	—		—			—		250		—			250
2019 Term Loan Agreement	800		—			800		—		—			—
2019 Notes	—		—			—		500		—			500
2024 Notes	600		—			600		600		—			600
2027 Notes	700		(2		)	698		700		(2		)	698
2028 Notes	800		(5		)	795		800		(6		)	794
2029 Notes	550		(1		)	549		—		—			—
2044 Notes	550		—			550		550		—			550
EOIT Senior Notes	250		1			251		250		7			257
Total debt	$	4,405	$	(7	)	$	4,398	$	4,299	$	(1	)	$	4,298
Less: Short-term debt ⁽²⁾						155							649
Less: Current portion of long-term debt ⁽³⁾						251							500
Less: Unamortized debt expense ⁽⁴⁾						23							20
Total long-term debt						$	3,969						$	3,129

___________________


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


(2)	Short-term debt includes $155 million and $649 million of commercial paper outstanding as of December 31, 2019 and 2018, respectively.


(3)	As of December 31, 2019, Current portion of long-term debt includes the $251 million outstanding balance of the EOIT Senior Notes due March 15, 2020. At December 31, 2018, Current portion of long-term debt included the $500 million outstanding balance of the 2019 Notes due May 15, 2019.


(4)	As of December 31, 2019 and 2018, there was an additional $4 million and $6 million, respectively, of unamortized debt expense related to the Revolving Credit Facility included in Other assets, not included above. Unamortized debt expense is amortized over the life of the respective debt.

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



2020	$	405
2021	—
2022	800
2023	—
2024	600
Thereafter	$	2,600

Commercial Paper

The Partnership has a commercial paper program, pursuant to which the Partnership is authorized to issue up to $1.4 billion of commercial paper. The commercial paper program is supported by our Revolving Credit Facility, and outstanding commercial paper effectively reduces our borrowing capacity thereunder. There were $155 million and $649 million outstanding under our commercial paper program at December 31, 2019 and December 31, 2018, respectively. The weighted average interest rate for the outstanding commercial paper was 2.29% as of December 31, 2019.

Revolving Credit Facility

On April 6, 2018, the Partnership amended and restated its Revolving Credit Facility. As amended and restated, the Revolving Credit Facility is a $1.75 billion, five-year senior unsecured revolving credit facility, which under certain circumstances may be increased from time to time up to an additional $875 million. The Revolving Credit Facility is scheduled to mature on April 6, 2023, subject to an extension option, which could be exercised two times to extend the term of the Revolving Credit facility, in each case, for an additional one-year term. As of December 31, 2019, there were no principal advances and $3 million in letters of credit outstanding under the restated Revolving Credit Facility.

The Revolving Credit Facility provides that outstanding borrowings bear interest at LIBOR and/or an alternate base rate, at the Partnership’s election, plus an applicable margin. The applicable margin is based on the Partnership’s designated credit ratings from S&P, Moody’s and Fitch Ratings. As of December 31, 2019, the applicable margin for LIBOR-based borrowings under the Revolving Credit Facility was 1.50% based on the Partnership’s credit ratings. In addition, the Revolving Credit Facility requires the Partnership to pay a fee on unused commitments. The commitment fee is based on the Partnership’s applicable credit ratings. As of December 31, 2019, the commitment fee under the Revolving Credit Facility was 0.20% per annum based on the Partnership’s credit ratings. The commitment fee is recorded as interest expense in the Partnership’s Consolidated Statements of Income.

The Revolving Credit Facility contains a financial covenant requiring us to maintain a ratio of consolidated funded debt to consolidated EBITDA as defined under the Revolving Credit Facility as of the last day of each fiscal quarter of less than or equal to 5.00 to 1.00; provided that, for any three fiscal quarters including and following any fiscal quarter in which the aggregate value of one or more acquisitions by us or certain of our subsidiaries with a purchase price of at least $25 million in the aggregate, the consolidated funded debt to consolidated EBITDA ratio as of the last day of each such fiscal quarter during such period would be permitted to be up to 5.50 to 1.00.

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

2019 Term Loan Agreement

On January 29, 2019, the Partnership entered into an unsecured term loan agreement with Bank of America, N.A., as administrative agent, and the several lenders thereto. The 2019 Term Loan Agreement has a scheduled maturity date of January 29, 2022, but contains an option, which may be exercised up to two times, to extend the maturity date for an additional one-year term, subject to lender approval. The 2019 Term Loan Agreement provides that outstanding borrowings bear interest at the eurodollar rate and/or an alternate base rate, at the Partnership’s election, plus an applicable margin. The applicable margin is based on the Partnership’s credit ratings. The applicable margin shall equal, (1) in the case of interest rates determined by reference to the eurodollar rate, between 0.75% and 1.50% per annum and (2) in the case of interest rates determined by reference to the alternate base rate, between 0% and 0.50% per annum. As of December 31, 2019, the applicable margin for LIBOR-based advances under the 2019 Term Loan Facility was 1.25% based on the Partnership’s credit ratings. As of December 31, 2019, the weighted average interest rate of the 2019 Term Loan Agreement was 3.10%.

Prior to the expiration of the availability period for advances on July 26, 2019, the Partnership drew $1 billion in advances under the Term Loan Agreement, which were used for general partnership purposes and repayment of the 2019 Notes. Advances under the 2019 Term Loan Agreement can be prepaid, in whole or in part, at any time without premium or penalty, other than usual and customary LIBOR breakage costs, if applicable. On September 16, 2019, the Partnership prepaid $200 million of the advances under the Term Loan Agreement, the repayment of which was not subject to LIBOR breakage costs. As of December 31, 2019, there was $800 million outstanding under the 2019 Term Loan Agreement.

The 2019 Term Loan Agreement contains a financial covenant requiring the Partnership to maintain a ratio of consolidated funded debt to consolidated EBITDA as of the last day of each fiscal quarter of less than or equal to 5.00 to 1.00; provided that, for a certain period time following an acquisition by the Partnership or certain of its subsidiaries with a purchase price that when combined with the aggregate purchase price for all other such acquisitions in any rolling 12-month period, is equal to or greater

than $25 million, the consolidated funded debt to consolidated EBITDA ratio as of the last day of each such fiscal quarter during such period would be permitted to be up to 5.50 to 1.00.

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

Senior Notes

On September 13, 2019, the Partnership completed the public offering of $550 million aggregate principal amount of its 4.150% Senior Notes due 2029. The Partnership received net proceeds of approximately $544 million, after deducting the underwriting discount and offering expenses. The net proceeds were used to repay $200 million of borrowings outstanding under the 2019 Term Loan Agreement, to repay amounts outstanding under the commercial paper program, and for general partnership purposes. The 2029 Notes had an unamortized discount of $1 million and unamortized debt expense of $5 million at December 31, 2019, resulting in an effective interest rate of 4.31% from the issue date through December 31, 2019.

As of December 31, 2019, the Partnership’s debt also included the 2024 Notes, 2027 Notes, 2028 Notes and 2044 Notes, which had $7 million of unamortized discount and $18 million of unamortized debt expense at December 31, 2019, resulting in effective interest rates of 4.01%, 4.57%, 5.20% and 5.08%, respectively, during the year ended December 31, 2019. In May 2019, the Partnership’s 2019 Notes matured and were paid using proceeds from the 2019 Term Loan Agreement.

The indenture governing the 2024 Notes, 2027 Notes, 2028 Notes, 2029 Notes and 2044 Notes contains certain restrictions, including, among others, limitations on our ability and the ability of our principal subsidiaries to: (i) consolidate or merge and sell all or substantially all of our and our subsidiaries’ assets and properties; (ii) create, or permit to be created or to exist, any lien upon any of our or our principal subsidiaries’ principal property, or upon any shares of stock of any principal subsidiary, to secure any debt; and (iii) enter into certain sale-leaseback transactions. These covenants are subject to certain exceptions and qualifications.

As of December 31, 2019, the Partnership’s debt included EOIT’s Senior Notes. The EOIT Senior Notes had $1 million of unamortized premium at December 31, 2019, resulting in an effective interest rate of 3.84% during the year ended December 31, 2019. These senior notes do not contain any financial covenants other than a limitation on liens. This limitation on liens is subject to certain exceptions and qualifications.

As of December 31, 2019, the Partnership and EOIT were in compliance with all of their debt agreements, including financial covenants.

Derivative Instruments and Hedging Activities

12 Months Ended

Dec. 31, 2019

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments and Hedging Activities

The Partnership is exposed to certain risks relating to its ongoing business operations. The primary risks managed using derivative instruments are commodity price and interest rate risks. The Partnership is also exposed to credit risk in its business operations.

Commodity Price Risk

The Partnership uses forward physical contracts, commodity price swap contracts and commodity price option features to manage its commodity price risk exposures. Commodity derivative instruments used by the Partnership are as follows:


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


•	natural gas futures and swaps, natural gas options, natural gas swaptions and natural gas commodity purchases and sales are used to manage the Partnership’s natural gas price exposure associated with its gathering, processing, transportation and storage assets, contracts and asset management activities.

Normal purchases and normal sales contracts are not recorded in Other Assets or Liabilities in the Consolidated Balance Sheets and earnings are recognized and recorded in the period in which physical delivery of the commodity occurs. Management applies normal purchases and normal sales treatment to: (i) commodity contracts for the purchase and sale of natural gas used in or produced by the Partnership’s operations and (ii) commodity contracts for the purchase and sale of NGLs produced by its gathering and processing business.

The Partnership recognizes its non-exchange traded derivative instruments as Other Assets or Liabilities in the Consolidated Balance Sheets at fair value with such amounts classified as current or long-term based on their anticipated settlement. Exchange traded transactions are settled on a net basis daily through margin accounts with a clearing broker and are recorded as Other Assets or Liabilities in the Consolidated Balance Sheets at fair value on a net basis with such amounts classified as current or long-term based on their anticipated settlement.

As of December 31, 2019 and 2018, the Partnership had no commodity derivative instruments that were designated as cash flow or fair value hedges for accounting purposes.

Interest Rate Risk

The Partnership uses interest rate swap contracts to manage its interest rate risk exposures. The Partnership recognizes its interest rate derivative instruments as Other Assets or Liabilities in the Consolidated Balance Sheets at fair value with such amounts classified as current or long-term based on their anticipated settlement. The Partnership’s interest rate swap contracts are designated as cash flow hedging instruments for accounting purposes. For interest rate derivative instruments designated as cash flow hedging instruments, the gain or loss on the derivative is recognized currently in Accumulated other comprehensive loss and will be reclassified to Interest expense in the same period the hedged transaction affects earnings. As of December 31, 2019, the Partnership had no interest rate derivative instruments that were designated as fair value hedges for accounting purposes. As of December 31, 2018, the Partnership had no outstanding interest rate derivative instruments.

Credit Risk

Credit risk includes the risk that counterparties that owe the Partnership money or energy will breach their obligations. If the counterparties to these arrangements fail to perform, the Partnership may seek or be forced to enter into alternative arrangements. In that event, the Partnership’s financial results could be adversely affected, and the Partnership could incur losses.

Derivatives Not Designated as Hedging Instruments

Derivative instruments not designated as hedging instruments for accounting purposes are utilized to manage the Partnership’s exposure to commodity price risk. For derivative instruments not designated as hedging instruments, the gain or loss on the derivative is recognized currently in earnings.

Quantitative Disclosures Related to Derivative Instruments Not Designated as Hedging Instruments

The majority of natural gas physical purchases and sales not designated as hedges for accounting purposes are priced based on a monthly or daily index, and the fair value is subject to little or no market price risk. Natural gas physical sales volumes exceed natural gas physical purchase volumes due to the marketing of natural gas volumes purchased via the Partnership’s processing contracts, which are not derivative instruments.

As of December 31, 2019 and 2018, the Partnership had the following derivative instruments that were not designated as hedging instruments for accounting purposes:



	December 31, 2019		December 31, 2018
	Gross Notional Volume
	Purchases	Sales	Purchases	Sales
Natural gas—TBtu ⁽¹⁾
Financial fixed futures/swaps	10	19	16	28
Financial basis futures/swaps	11	30	18	29
Financial swaptions ⁽²⁾	—	2	—	1
Physical purchases/sales	—	6	—	11
Crude oil (for condensate)—MBbl ⁽³⁾
Financial futures/swaps	—	990	—	945
Financial swaptions ⁽²⁾	—	225	—	30
Natural gas liquids—MBbl ⁽⁴⁾
Financial futures/swaps	2,490	2,415	270	2,535

____________________


(1)	As of December 31, 2019, 86.6% of the natural gas contracts had durations of one year or less and 13.4% had durations of more than one year and less than two years. As of December 31, 2018, 74.0% of the natural gas contracts had durations of one year or less, 24.2% had durations of more than one year and less than two years and 1.8% had durations of more than two years.


(2)	The notional value contains a combined derivative instrument consisting of a fixed price swap and a sold option, which gives the counterparties the right, but not the obligation, to increase the notional quantity hedged under the fixed price swap until the option expiration date. The notional volume represents the volume prior to option exercise.


(3)	As of December 31, 2019, 72.8% of the crude oil (for condensate) contracts had durations of one year or less and 27.2% had durations of more than one year and less than two years. As of December 31, 2018, 76.9% of the crude oil (for condensate) contracts had durations of one year or less and 23.1% had durations of more than one year and less than two years.


(4)	As of December 31, 2019, 72.2% of the natural gas liquids contracts had durations of one year or less and 27.8% had durations of more than one year and less than two years. As of December 31, 2018, 86.1% of the natural gas liquids contracts had durations of one year or less and 13.9% had durations of more than one year and less than two years.

Derivatives Designated as Hedging Instruments

Derivative instruments designated as hedging instruments for accounting purposes are utilized in managing the Partnership’s interest rate risk exposures.

Quantitative Disclosures Related to Derivative Instruments Designated as Hedging Instruments

The derivative instruments designated as hedges for accounting purposes are interest rate derivative instruments priced on monthly interest rates.

As of December 31, 2019 and December 31, 2018, the Partnership had the following derivative instruments that were designated as hedging instruments for accounting purposes:



	December 31, 2019		December 31, 2018
	Gross Notional Value
	(In millions)
Interest rate swaps	$	300	$	—

Balance Sheet Presentation Related to Derivative Instruments

The fair value of the derivative instruments that are presented in the Partnership’s Consolidated Balance Sheets at December 31, 2019 and 2018 that were not designated as hedging instruments for accounting purposes are as follows:



		December 31, 2019				December 31, 2018
		Fair Value
Instrument	Balance Sheet Location	Assets		Liabilities		Assets		Liabilities

		(In millions)
Natural gas
Financial futures/swaps	Other Current	$	7	$	5	$	3	$	5
Financial futures/swaps	Other	—		1		—		2
Physical purchases/sales	Other Current	5		—		3		—
Physical purchases/sales	Other	—		—		4		—
Crude oil (for condensate)
Financial futures/swaps	Other Current	1		19		9		3
Financial futures/swaps	Other	—		8		2		—
Natural gas liquids
Financial futures/swaps	Other Current	25		3		10		1
Financial futures/swaps	Other	11		2		2		—
Total gross derivatives ⁽¹⁾		$	49	$	38	$	33	$	11

_____________________


(1)	See Note 14 for a reconciliation of the Partnership’s total derivatives fair value to the Partnership’s Consolidated Balance Sheets as of December 31, 2019 and 2018.

The fair value of the derivative instruments that are presented in the Partnership’s Consolidated Balance Sheets as of December 31, 2019 and December 31, 2018 that were designated as hedging instruments for accounting purposes are as follows:



		December 31, 2019				December 31, 2018
		Fair Value
Instrument	Balance Sheet Location	Assets		Liabilities		Assets		Liabilities

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

_____________________


(1)	All interest rate derivative instruments that were designated as cash flow hedges are considered Level 2 as of December 31, 2019.

Income Statement Presentation Related to Derivative Instruments

The following table presents the effect of derivative instruments on the Partnership’s Consolidated Statements of Income for the years ended December 31, 2019, 2018 and 2017:



	Amounts Recognized in Income
	Year Ended December 31,
	2019			2018			2017

	(In millions)
Natural Gas
Financial futures/swaps gains (losses)	$	13		$	(8	)	$	20
Physical purchases/sales gains	2			7			9
Crude oil (for condensate)
Financial futures/swaps (losses) gains	(41		)	6			(1		)
Natural gas liquids
Financial futures/swaps gains (losses)	42			6			(9		)
Total	$	16		$	11		$	19

For derivatives not designated as hedges in the tables above, amounts recognized in income for the years ended December 31, 2019, 2018 and 2017 are reported in Product sales. For derivatives designated as hedges, amounts recognized in income and reported in Interest expense for the year ended December 31, 2019 were approximately zero.

The following table presents the components of gain (loss) on derivative activity in the Partnership’s Consolidated Statements of Income for the years ended December 31, 2019, 2018 and 2017:



	Year Ended December 31,
	2019			2018			2017

	(In millions)
Change in fair value of derivatives	$	(11	)	$	26		$	28
Realized gain (loss) on derivatives	27			(15		)	(9		)
Gain on derivative activity	$	16		$	11		$	19

Credit-Risk Related Contingent Features in Derivative Instruments

In the event Moody’s or S&P were to lower the Partnership’s senior unsecured debt rating to a below investment grade rating, the Partnership could be required to provide additional credit assurances to third parties, which could include letters or credit or cash collateral to satisfy its obligation under its financial and physical contracts relating to derivative instruments that are in a net liability position. As of December 31, 2019, under these obligations, the Partnership has posted no cash collateral related to natural gas swaps and swaptions, crude oil swaps and swaptions, and NGL swaps and no additional collateral would be required to be posted by the Partnership in the event of a credit ratings downgrade to a below investment grade rating. In certain situations where the Partnership’s credit rating is lowered by Moody’s or S&P, the Partnership could be subject to an early termination event related to certain derivative instruments, which could result in a cash settlement of the instruments at market values on the date of such early termination.

Fair Value Measurements

12 Months Ended

Dec. 31, 2019

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, 2019, there were no contracts classified as Level 3.

The Partnership determines the appropriate level for each financial asset and liability on a quarterly basis and recognizes transfers between levels at the end of the reporting period. For the year ended December 31, 2019, there were no transfers between levels.

The impact to the fair value of derivatives due to credit risk is calculated using the probability of default based on S& P’s and/or internally generated ratings. The fair value of derivative assets is adjusted for credit risk. The fair value of derivative liabilities is adjusted for credit risk only if the impact is deemed material.

Estimated Fair Value of Financial Instruments

The fair values of all accounts receivable, notes receivable, accounts payable, commercial paper and other such financial instruments on the Consolidated Balance Sheets are estimated to be approximately equivalent to their carrying amounts due to their short-term nature and have been excluded from the table below. The following table summarizes the fair value and carrying amount of the Partnership’s financial instruments at December 31, 2019 and 2018:



	December 31, 2019				December 31, 2018
	Carrying Amount		Fair Value		Carrying Amount		Fair Value

	(In millions)
Debt
Revolving Credit Facility (Level 2) ⁽¹⁾	$	—	$	—	$	250	$	250
2019 Term Loan Agreement (Level 2)	800		800		—		—
2019 Notes (Level 2)	—		—		500		497
2024 Notes (Level 2)	600		614		600		571
2027 Notes (Level 2)	698		698		698		642
2028 Notes (Level 2)	795		811		794		764
2029 Notes (Level 2)	549		526		—		—
2044 Notes (Level 2)	550		506		550		445
EOIT Senior Notes (Level 2)	251		252		257		256

______________________


(1)	Borrowing capacity is effectively reduced by our borrowings outstanding under the commercial paper program. $155 million and $649 million of commercial paper was outstanding as of December 31, 2019 and 2018, respectively.

The fair value of the Partnership’s Revolving Credit Facility, 2019 Term Loan Agreement, 2019 Notes, 2024 Notes, 2027 Notes, 2028 Notes, 2029 Notes, 2044 Notes, and EOIT Senior Notes, is based on quoted market prices and estimates of current rates available for similar issues with similar maturities and is classified as Level 2 in the fair value hierarchy.

Non-Financial Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Certain assets and liabilities are measured at fair value on a nonrecurring basis; that is, the assets and liabilities are not measured at fair value on an ongoing basis but are subject to fair value adjustments in certain circumstances (e.g., when there is evidence of impairment). As of December 31, 2019, no material fair value adjustments or fair value measurements were required for these non-financial assets or liabilities.

Based upon review of forecasted undiscounted cash flows as of December 31, 2019, all of the asset groups were considered recoverable. Future price declines, throughput declines, contracted capacity declines, cost increases, regulatory or political environment changes and other changes in market conditions could reduce forecasted undiscounted cash flows.

Contracts with Master Netting Arrangements

Fair value amounts recognized for forward, interest rate swap, option and other conditional or exchange contracts executed with the same counterparty under a master netting arrangement may be offset. The reporting entity’s choice to offset or not must be applied consistently. A master netting arrangement exists if the reporting entity has multiple contracts, whether for the same type of conditional or exchange contract or for different types of contracts, with a single counterparty that are subject to a contractual agreement that provides for the net settlement of all contracts through a single payment in a single currency in the event of default on or termination of any one contract. Offsetting the fair values recognized for forward, interest rate swap, option and other conditional or exchange contracts outstanding with a single counterparty results in the net fair value of the transactions being reported as an asset or a liability in the Consolidated Balance Sheets. The Partnership has presented the fair values of its derivative contracts under master netting agreements using a net fair value presentation.

As of December 31, 2019, the Partnership’s Level 2 interest rate derivatives are recorded as liabilities with no netting adjustments. The following tables summarize the Partnership’s other assets and liabilities that are measured at fair value on a recurring basis as of December 31, 2019 and December 31, 2018:



December 31, 2019	Commodity Contracts						Gas Imbalances ⁽¹⁾
	Assets			Liabilities			Assets ⁽²⁾		Liabilities ⁽³⁾

	(In millions)
Quoted market prices in active market for identical assets (Level 1)	$	5		$	31		$	—	$	—
Significant other observable inputs (Level 2)	44			7			14		11
Unobservable inputs (Level 3)	—			—			—		—
Total fair value	49			38			14		11
Netting adjustments	(37		)	(37		)	—		—
Total	$	12		$	1		$	14	$	11



December 31, 2018	Commodity Contracts						Gas Imbalances ⁽¹⁾
	Assets			Liabilities			Assets ⁽²⁾		Liabilities ⁽³⁾

	(In millions)
Quoted market prices in active market for identical assets (Level 1)	$	4		$	9		$	—	$	—
Significant other observable inputs (Level 2)	29			2			18		17
Unobservable inputs (Level 3)	—			—			—		—
Total fair value	33			11			18		17
Netting adjustments	(9		)	(9		)	—		—
Total	$	24		$	2		$	18	$	17

______________________


(1)	The Partnership uses the market approach to fair value its gas imbalance assets and liabilities at individual, or where appropriate an average of, current market indices applicable to the Partnership’s operations, not to exceed net realizable value. There were no netting adjustments as of December 31, 2019 and 2018.


(2)	Gas imbalance assets exclude fuel reserves for under retained fuel due from shippers of $21 million and $11 million at December 31, 2019 and 2018, respectively, which fuel reserves are based on the value of natural gas at the time the imbalance was created and which are not subject to revaluation at fair market value.


(3)	Gas imbalance liabilities exclude fuel reserves for over retained fuel due to shippers of $8 million and $5 million at December 31, 2019 and 2018, respectively, which fuel reserves are based on the value of natural gas at the time the imbalance was created and which are not subject to revaluation at fair market value.

Changes in Level 3 Fair Value Measurements

The following tables provides a reconciliation of changes in the fair value of our Level 3 commodity contracts between the periods presented. Transfers out of Level 3 represent liabilities that were previously classified as Level 3 for which the inputs became observable for classification in Level 2. Because the activity and liquidity of commodity markets vary substantially between regions and time periods, the availability of observable inputs for substantially the full term and value of the Partnership’s derivative contracts is subject to change.



	Commodity Contracts
	Natural gas liquids financial futures/swaps
	(In millions)
Balance as of December 31, 2017	$	(5	)
Losses included in earnings	(23		)
Settlements	7
Transfers out of Level 3	21
Balance as of December 31, 2018	$	—

For the year ended December 31, 2019, there were no Level 3 commodity contracts.

- 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, 2019

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,
	2019		2018		2017

	(In millions)
Supplemental Disclosure of Cash Flow Information:
Cash Payments:
Interest, net of capitalized interest	$	185	$	148	$	114
Income taxes, net of refunds	1		3		—
Non-cash transactions:
Accounts payable related to capital expenditures	10		54		39
Lease liabilities arising from the application of ASC 842	45		—		—

The following table reconciles cash and cash equivalents and restricted cash on the Consolidated Balance Sheets to cash, cash equivalents and restricted cash on the Consolidated Statements of Cash Flows:



	December 31,
	2019		2018

	(In millions)
Cash and cash equivalents	$	4	$	8
Restricted cash	—		14
Cash, cash equivalents and restricted cash shown in the Consolidated Statement of Cash Flows	$	4	$	22

As of December 31, 2018, Restricted cash included $14 million of cash collateral which was provided by a third party as credit assurance. The cash collateral was released in 2019.

Related Party Transactions

12 Months Ended

Dec. 31, 2019

Related Party Transactions

The material related party transactions with CenterPoint Energy, OGE Energy and their respective subsidiaries are summarized below. There were no material related party transactions with other affiliates.

Transportation and Storage Agreements

Transportation and Storage Agreements with CenterPoint Energy

EGT provides natural gas transportation and storage services to CenterPoint Energy’s LDCs in Arkansas, Louisiana, Oklahoma and Northeast Texas under a combination of contracts that include the following types of services: firm transportation, firm transportation with seasonal demand, firm storage, firm no-notice transportation with storage and maximum rate firm transportation. The term of these contracts is through March 31, 2021. MRT provides firm transportation and firm storage services to CenterPoint Energy’s LDCs in Arkansas and Louisiana. Contracts for these services are in effect through May 15, 2023 and will remain in effect thereafter unless and until terminated by either party upon twelve months’ prior written notice.

The Partnership may agree to reimburse the costs that its customers incur to make required modifications for the repair and maintenance of pipelines that impact customer delivery points. For the years ended December 31, 2019 and 2018, we reimbursed CenterPoint Energy’s LDCs $2 million and $1 million, respectively, in connection with receipt facility modifications that were necessitated by the repair and maintenance of our pipelines and in connection with a reimbursement associated with an unplanned pipeline outage. For the year ended December 31, 2017, we reimbursed CenterPoint Energy’s LDCs $1 million in connection with receipt facility modifications that were necessitated by the repair and maintenance of our pipelines.

Transportation and Storage Agreement with OGE Energy

EOIT provides no-notice load-following transportation and storage services to four of OGE Energy’s generating facilities. Service is provided to three generating facilities under a transportation agreement with a primary term of April 1, 2019 through May 1, 2024, which will remain in effect from year to year thereafter unless either party provides notice of termination to the other party at least 180 days prior to the commencement of the succeeding annual period. Service is provided to one additional generating facility in Muskogee, Oklahoma under a transportation agreement with a primary term of December 1, 2018 through December 1, 2038. EOIT has agreed to pay OGE Energy $2 million and to waive $5 million of demand fee charges as a result of damage that occurred to the Muskogee facility during commissioning as a result of the failure of certain filters on the connected transportation pipeline, which is included in the Partnership’s results of operations as of December 31, 2019.

Gas Sales and Purchases Transactions

The Partnership sells natural gas volumes to affiliates of CenterPoint Energy and OGE Energy or purchases natural gas volumes from affiliates of CenterPoint Energy through a combination of forward, monthly and daily transactions. The Partnership enters into these physical natural gas transactions in the normal course of business based upon relevant market prices.

The Partnership’s revenues from affiliated companies accounted for 6%, 5% and 5% of total revenues during the years ended December 31, 2019, 2018 and 2017, respectively. Amounts of total revenues from affiliated companies included in the Partnership’s Consolidated Statements of Income are summarized as follows:



	Year Ended December 31,
	2019		2018		2017

	(In millions)
Gas transportation and storage service revenues — CenterPoint Energy	$	108	$	111	$	110
Natural gas product sales — CenterPoint Energy	8		11		6
Gas transportation and storage service revenues — OGE Energy	41		37		35
Natural gas product sales — OGE Energy	10		4		2
Total revenues — affiliated companies	$	167	$	163	$	153

Amounts of natural gas purchased from affiliated companies included in the Partnership’s Consolidated Statements of Income are summarized as follows:



	Year Ended December 31,
	2019		2018		2017

	(In millions)
Cost of natural gas purchases — CenterPoint Energy	$	—	$	3	$	1
Cost of natural gas purchases — OGE Energy	33		23		19
Total cost of natural gas purchases — affiliated companies	$	33	$	26	$	20

Corporate services, operating lease expense and seconded employee

The Partnership receives services and support functions from each of CenterPoint Energy and OGE Energy under services agreements for an initial term that ended on April 30, 2016. The services agreements automatically extend year-to-year at the end of the initial term, unless terminated by the Partnership with at least 90 days’ notice prior to the end of any extension. Additionally, the Partnership may terminate these services agreements at any time with 180 days’ notice, if approved by the Board of Enable GP. The Partnership reimburses CenterPoint Energy and OGE Energy for these services up to annual caps, which for 2019 are $1 million and $1 million, respectively.

The Partnership leased office and data center space from an affiliate of CenterPoint Energy in Shreveport, Louisiana. The term of the lease was effective on October 1, 2016 and ended on December 31, 2019.

During the years ended December 31, 2019, 2018 and 2017, the Partnership had certain employees who are participants under OGE Energy’s defined benefit and retiree medical plans, who will remain seconded to the Partnership, subject to certain termination rights of the Partnership and OGE Energy. The Partnership’s reimbursement of OGE Energy for seconded employee costs arising out of OGE Energy’s defined benefit and retiree medical plans is fixed at actual cost subject to a cap of $5 million in 2019 and thereafter, unless and until secondment is terminated.

Amounts charged to the Partnership by affiliates for corporate services, operating lease and seconded employees, are primarily included in Operation and maintenance expenses and General and administrative expenses in the Partnership’s Consolidated Statements of Income are as follows:



	Year Ended December 31,
	2019		2018		2017

	(In millions)
Corporate Services — CenterPoint Energy	$	—	$	1	$	3
Operating Lease — CenterPoint Energy	1		1		1
Seconded Employee Costs — OGE Energy	18		29		31
Corporate Services — OGE Energy	—		1		3
Total corporate services, operating lease and seconded employee expense	$	19	$	32	$	38

Commitments and Contingencies	12 Months Ended
Commitments and Contingencies	Dec. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies Commercial Obligations On January 1, 2017, the Partnership entered into a 10-year gathering and processing agreement, which became effective on July 1, 2018, with an affiliate of Energy Transfer, LP for 400 MMcf/d of deliveries to the Godley Plant in Johnson County, Texas. As of December 31, 2019, the Partnership estimates the remaining associated minimum volume commitment fee to be $192 million in the aggregate. Minimum volume commitment fees are expected to be $23 million per year from 2020 through 2027 and $11 million in 2028. On September 13, 2018, the Partnership executed a precedent agreement for the development of the Gulf Run Pipeline, an interstate natural gas transportation project. On January 30, 2019, a final investment decision was made by Golden Pass LNG, the cornerstone shipper for the LNG facility to be served by the Gulf Run Pipeline project. Subject to approval of the project by FERC, the Partnership will be required to construct a large-diameter pipeline from northern Louisiana to Gulf Coast markets. In addition, the Partnership may transfer existing EGT transportation infrastructure to the Gulf Run Pipeline. Under the precedent agreement, the Partnership estimates the cost to complete the Gulf Run Pipeline project would be as much as $500 million and the project is backed by a 20-year firm transportation service. The Gulf Run Pipeline connects natural gas producing regions in the U.S., including the Haynesville, Marcellus, Utica and Barnett shales and the Mid-Continent region. The project is expected to be placed into service in 2022. On September 23, 2019, the Partnership entered into an agreement to sell its undivided 1/12th interest in the Bistineau Storage Facility in Louisiana for approximately $19 million. Until such time as the sale closes, the Partnership will continue to utilize this facility to provide storage services to its customers. On January 27, 2020, FERC approved the sale. The Partnership anticipates closing the sale on April 1, 2020. Legal, Regulatory and Other Matters The Partnership is involved in legal, environmental, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business. Some of these proceedings involve substantial amounts. The Partnership regularly analyzes current information and, as necessary, provides accruals for probable liabilities on the eventual disposition of these matters. The Partnership does not expect the disposition of these matters to have a material adverse effect on its financial condition, results of operations or cash flows.

Income Taxes

12 Months Ended

Dec. 31, 2019

Income Tax Disclosure [Abstract]

Income Taxes

The Partnership’s earnings are generally not subject to income tax (other than Texas state margin taxes and taxes associated with the Partnership’s corporate subsidiary Enable Midstream Services) and are taxable at the individual partner level. The Partnership and its non-corporate subsidiaries are pass-through entities for federal income tax purposes. For these entities, all income, expenses, gains, losses and tax credits generated flow through to their owners and, accordingly, do not result in a provision for income taxes in the consolidated financial statements. Consequently, the Consolidated Statements of Income do not include an income tax provision (other than Texas state margin taxes and taxes associated with the Partnership’s corporate subsidiary). On December 22, 2017, the act known as the “Tax Cuts and Jobs Act,” was signed into law which lowered the corporate tax rate from 35% to 21% for tax years beginning after December 31, 2017. As a result of this new law, the Partnership’s corporate subsidiaries re-valued their deferred income tax assets and liabilities as of December 31, 2017, which resulted in recording a federal deferred income tax benefit of $1 million for the year ended December 31, 2017.

The items comprising income tax expense are as follows:



	Year Ended December 31,
	2019			2018			2017

	(In millions)
Provision for current income taxes
Federal	$	—		$	—		$	1
State	—			—			1
Total provision for current income taxes	—			—			2
Benefit for deferred income taxes, net
Federal	$	(1	)	$	(1	)	$	(2	)
State	—			—			(1		)
Total benefit for deferred income taxes, net	(1		)	(1		)	(3		)
Total income tax benefit	$	(1	)	$	(1	)	$	(1	)

The components of Deferred Income Taxes as of December 31, 2019 and 2018 were as follows:



	December 31,
	2019			2018

	(In millions)
Deferred tax liabilities, net:
Non-current:
Intercompany management fee	$	17		$	16
Depreciation	6			5
Accrued compensation	(19		)	(16		)
Total deferred tax liabilities, net	$	4		$	5

Uncertain Income Tax Positions

There were no unrecognized tax benefits as of December 31, 2019, 2018 and 2017.

Tax Audits and Settlements

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

Equity Based Compensation

12 Months Ended

Dec. 31, 2019

Share-based Payment Arrangement [Abstract]

Equity Based Compensation

Equity-Based Compensation

Enable GP has adopted the Enable Midstream Partners, LP Long Term Incentive Plan (LTIP) for officers, directors and employees of the Partnership and its affiliates, including any individual who provides services to the Partnership as a seconded employee. The LTIP provides for the following types of awards: restricted units, phantom units, appreciations rights, option rights, cash incentive awards, performance units, distribution equivalent rights, and other awards denominated in, payable in, valued in or otherwise based on or related to common units.

The LTIP is administered by the Compensation Committee of the Board of Directors. With respect to any grant of equity as long-term incentive awards to our independent directors and our officers subject to reporting under Section 16 of the Exchange Act, the Compensation Committee makes recommendations to the Board of Directors and any such awards will only be effective upon the approval of the Board of Directors. The LTIP limits the number of units that may be delivered pursuant to vested awards to 13,100,000 common units, subject to proportionate adjustment in the event of unit splits and similar events. Common units cancelled, forfeited, expired or cash settled are available for delivery pursuant to other awards.

The Board of Directors may terminate or amend the long-term incentive plan at any time with respect to any units for which a grant has not yet been made, including amending the long-term incentive plan to increase the number of units that may be granted subject to the requirements of the exchange upon which the common units are listed at that time. However, no change in any outstanding grant may be made that would be adverse to the participant without the consent of the participant.

Performance unit, restricted unit and phantom unit awards are classified as equity on the Partnership’s Consolidated Balance Sheet. The following table summarizes the Partnership’s equity-based compensation expense for the years ended December 31, 2019, 2018 and 2017 related to performance units, restricted units and phantom units for the Partnership’s employees and independent directors:



	Year Ended December 31,
	2019		2018		2017

	(In millions)
Performance units	$	9	$	9	$	10
Restricted units	—		1		2
Phantom units	7		6		3
Total equity-based compensation expense	$	16	$	16	$	15

Performance Units

Awards of performance based phantom units (performance units) have been made under the LTIP in 2019, 2018 and 2017 to certain officers and employees providing services to the Partnership. Subject to the achievement of performance goals, the performance unit awards cliff vest three years from the grant date, with distribution equivalent rights paid at vesting. The performance goals for 2019, 2018 and 2017 awards are based on total unitholder return over a three-calendar year performance cycle. Total unitholder return is based on the relative performance of the Partnership’s common units against a peer group. The performance unit awards have a payout from zero to 200% of the target based on the level of achievement of the performance goal. Performance unit awards are paid out in common units, with distribution equivalent rights paid in cash at vesting. Any unearned performance units are cancelled. Pay out requires the confirmation of the achievement of the performance level by the Compensation Committee. Prior to vesting, performance units are subject to forfeiture if the recipient’s employment with the Partnership is terminated for any reason other than death, disability, retirement or termination other than for cause within two years of a change in control. In the event of retirement, a participant will receive a prorated payment based on the target performance or a prorated payment based on the actual performance of the performance goals during the award cycle, based on the grant year.

The fair value of each performance unit award was estimated on the grant date using a lattice-based valuation model. The valuation information factored into the model includes the expected distribution yield, expected price volatility, risk-free interest rate and the probable outcome of the market condition over the expected life of the performance units. Equity-based compensation expense for each performance unit award is a fixed amount determined at the grant date fair value and is recognized over the three-year award cycle regardless of whether performance units are awarded at the end of the award cycle. Distributions are accumulated and paid at vesting and, therefore, are included in the fair value calculation of the performance unit award. The expected price volatility for the awards granted in 2019, 2018 and 2017 is based on three years of daily stock price observations, to determine the total unitholder return ranking. The risk-free interest rate for the performance unit grants is based on the three-year U.S. Treasury yield curve in effect at the time of the grant. There are no post-vesting restrictions related to the Partnership’s performance units.

The number of performance units granted based on total unitholder return and the assumptions used to calculate the grant date fair value of the performance units based on total unitholder return are shown in the following table.



	2019			2018			2017
Number of units granted	638,798			551,742			468,626
Fair value of units granted	$	19.95		$	17.70		$	19.27
Expected price volatility	34.2		%	44.2		%	47.3		%
Risk-free interest rate	2.54		%	2.36		%	1.57		%
Distribution yield	8.38		%	8.56		%	9.10		%
Expected life of units (in years)	3			3			3

Phantom Units

Awards of phantom units have been made under the LTIP in 2019, 2018 and 2017 to certain officers and employees providing services to the Partnership. Except for Phantom units granted to retirement eligible employees, which vest in annual tranches, phantom units cliff-vest on the first, second or third anniversary of the grant date with distribution equivalent rights paid during the vesting period. Phantom unit awards are paid out in common units, with distribution equivalent rights paid in cash. Any unearned phantom units are cancelled. Prior to vesting, phantom units are subject to forfeiture if the recipient’s employment with the Partnership is terminated for any reason other than death, disability, retirement or termination other than for cause within two years of a change in control.

The fair value of the phantom units was based on the closing market price of the Partnership’s common unit on the grant date. Equity-based compensation expense for the phantom unit is a fixed amount determined at the grant date fair value and is recognized as services are rendered by employees over the vesting period. Distributions on phantom units are paid during the vesting period and, therefore, are included in the fair value calculation. The expected life of the phantom unit is based on the applicable vesting period. The number of phantom units granted and the grant date fair value are shown in the following table.



	2019	2018	2017
Phantom units granted	695,486	546,708	392,338
Fair value of phantom units granted	$8.95 - $15.04	$13.74 - $17.00	$15.44 - $16.93

Other Awards

In 2019, 2018 and 2017, the Board of Directors granted common units to the independent directors of Enable GP, for their service as directors, which vested immediately. The fair value of the common units was based on the closing market price of the Partnership’s common unit on the grant date.



	2019		2018		2017
Common units granted	28,221		16,335		16,653
Fair value of common units granted	$	10.43	$	14.94	$	15.03

Units Outstanding

A summary of the activity for the Partnership’s performance units and phantom units as of December 31, 2019 and changes during 2019 are shown in the following table.



	Performance Units					Phantom Units
	Number of Units			Weighted Average Grant-Date Fair Value, Per Unit		Number of Units			Weighted Average Grant-Date Fair Value, Per Unit

	(In millions, except unit data)
Units outstanding at 12/31/2018	2,109,835			$	14.33	1,447,590			$	12.38
Granted ⁽¹⁾	638,798			19.95		695,486			14.26
Vested ⁽²⁾⁽³⁾	(1,174,597		)	11.09		(608,755		)	8.71
Forfeited	(180,707		)	18.96		(141,761		)	14.89
Units outstanding at 12/31/2019	1,393,329			19.04		1,392,560			14.65
Aggregate intrinsic value of units outstanding at December 31, 2019	$	14				$	14

_____________________


(1)	For performance units, this represents the target number of performance units granted. The actual number of performance units earned, if any, is dependent upon performance and may range from 0% to 200% of the target.

(2)

Performance units vested as of December 31, 2019 include 1,097,846 and 26,986 units from 2016 grants, which were approved by the Board of Directors in 2016 and paid out at 200%, or 2,195,692 units on March 1, 2019 and 53,972 units on September 6, 2019, based on the level of achievement of a performance goal established by the Board of Directors over the performance period of January 1, 2016 through December 31, 2018.

(3)

Performance units outstanding as of December 31, 2019 include 378,109 units from the 2017 annual grants, which were approved by the Board of Directors in 2017 and, based on the level of achievement of a performance goal established by the Board of Directors over a performance period of January 1, 2017 through December 31, 2019, will not vest. The decrease in outstanding units for a payout percentage of an amount other than 100% is not reflected above until the vesting date.

A summary of the Partnership’s performance, restricted and phantom units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for each of the years ended December 31, 2019, 2018 and 2017 are shown in the following tables.



	Year Ended December 31, 2019
	Performance Units		Restricted Stock		Phantom Units

	(In millions)
Aggregate intrinsic value of units vested	$	34	$	—	$	9
Fair value of units vested	13		—		5



	Year Ended December 31, 2018
	Performance Units		Restricted Stock		Phantom Units

	(In millions)
Aggregate intrinsic value of units vested	$	11	$	3	$	1
Fair value of units vested	7		4		—



	Year Ended December 31, 2017
	Performance Units		Restricted Stock		Phantom Units

	(In millions)
Aggregate intrinsic value of units vested	$	5	$	2	$	—
Fair value of units vested	10		4		—

Unrecognized Compensation Expense

A summary of the Partnership’s unrecognized compensation expense for its non-vested performance units and phantom units, and the weighted-average periods over which the compensation cost is expected to be recognized are shown in the following table.



	December 31, 2019
	Unrecognized Compensation Cost (In millions)		Weighted Average to be Recognized (In years)
Performance Units	$	12	1.32
Phantom Units	9		1.24
Total	$	21

As of December 31, 2019, there were 6,353,205 units available for issuance under the long-term incentive plan.

Reportable Segments

12 Months Ended

Dec. 31, 2019

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. The gathering and processing segment primarily provides natural gas and crude oil gathering and natural gas processing services to our producer customers. The transportation and storage segment provides interstate and intrastate natural gas pipeline transportation and storage services primarily to our producer, power plant, LDC and industrial end-user customers.

Financial data for reportable segments are as follows:



Year Ended December 31, 2019	Gathering and 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	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
Impairments	—		—		—			—
Taxes other than income tax	38		27		—			65
Operating Income	$	464	$	183	$	1		$	648
Total Assets	$	9,874	$	5,805	$	(3,235	)	$	12,444
Capital expenditures, including acquisitions	$	981	$	190	$	—		$	1,171



Year Ended December 31, 2017	Gathering and Processing		Transportation and Storage⁽¹⁾		Eliminations			Total

	(In millions)
Product sales	$	1,538	$	621	$	(506	)	$	1,653
Service revenues	632		525		(7		)	1,150
Total Revenues	2,170		1,146		(513		)	2,803
Cost of natural gas and natural gas liquids, excluding depreciation and amortization shown separately	1,285		604		(508		)	1,381
Operation and maintenance, General and administrative	289		179		(4		)	464
Depreciation and amortization	232		134		—			366
Impairments	—		—		—			—
Taxes other than income tax	37		27		—			64
Operating Income	$	327	$	202	$	(1	)	$	528
Total Assets	$	9,079	$	5,616	$	(3,102	)	$	11,593
Capital expenditures	$	601	$	113	$	—		$	714

_____________________

(1)

Equity in earnings of equity method affiliate is included in Other Income (Expense) on the Consolidated Statements of Income and is not included in the table above. See Note 11 for discussion regarding ownership interest in SESH and related equity earnings included in the transportation and storage reportable segment for the years ended December 31, 2019, 2018 and 2017.

Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2019

Quarterly Financial Information Disclosure [Abstract]

Quarterly Financial Data (Unaudited)

Summarized unaudited quarterly financial data for 2019 and 2018 are as follows:



	Quarters Ended
	March 31, 2019		June 30, 2019		September 30, 2019		December 31, 2019

	(in millions, except per unit data)
Total Revenues	$	795	$	735	$	699	$	731
Cost of natural gas and natural gas liquids	378		317		263		321
Operating income ⁽¹⁾	165		167		175		62
Net income	123		124		133		20
Net income attributable to limited partners	122		124		132		18
Net income attributable to common units	113		115		123		9

Basic earnings per unit
Common units	$	0.26	$	0.26	$	0.28	$	0.02
Diluted earnings per unit
Common units	$	0.26	$	0.26	$	0.28	$	0.02

	Quarters Ended
	March 31, 2018		June 30, 2018		September 30, 2018		December 31, 2018

	(in millions, except per unit data)
Total Revenues	$	748	$	805	$	928	$	950
Cost of natural gas and natural gas liquids	375		444		516		484
Operating income	139		126		171		212
Net income	114		95		139		175
Net income attributable to limited partners	114		95		138		174
Net income attributable to common units	105		86		129		165

Basic earnings per unit
Common Units	$	0.24	$	0.20	$	0.30	$	0.38
Diluted earnings per unit
Common Units	$	0.24	$	0.20	$	0.30	$	0.38

_____________________

(1)

The Partnership recorded an impairment to goodwill of $86 million during the fourth quarter related to the Anadarko Basin reporting unit, included in the gathering and processing reportable segment. See Note 10 for further information.

Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2019

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization

Basis of Presentation

The accompanying consolidated financial statements and related notes of the Partnership have been prepared pursuant to the rules and regulations of the SEC and GAAP.

Use of Estimates

Revenue Recognition

Service revenues: Service revenues represent all other revenue generated as a result of performing the Partnership’s midstream services.

The Partnership records deferred revenue when it receives consideration from a third party before achieving certain criteria that must be met for revenue to be recognized in accordance with GAAP.

Natural Gas and Natural Gas Liquids Purchases

Operation and Maintenance and General and Administrative Expense

Environmental Costs

Depreciation and Amortization

Depreciation and Amortization Expense

Income Taxes

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.

Restricted Cash

Restricted cash consists of cash which is restricted by agreements with third parties.

Accounts Receivable and Allowance for Doubtful Accounts

Inventory

Gas Imbalances

Long-Lived Assets (including Intangible Assets) and Assessing Impairment of Long-lived Assets (including Intangible Assets) and Goodwill

Long-Lived Assets (including Intangible Assets)

Assessing Impairment of Long-lived Assets (including Intangible Assets) and Goodwill

Regulatory Assets and Liabilities

Capitalization of Interest and Allowance for Funds Used During Construction

Derivative Instruments

Commodity Price Risk


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


•	natural gas futures and swaps, natural gas options, natural gas swaptions and natural gas commodity purchases and sales are used to manage the Partnership’s natural gas price exposure associated with its gathering, processing, transportation and storage assets, contracts and asset management activities.

As of December 31, 2019 and 2018, the Partnership had no commodity derivative instruments that were designated as cash flow or fair value hedges for accounting purposes.

Interest Rate Risk

Credit Risk

Derivatives Not Designated as Hedging Instruments

Quantitative Disclosures Related to Derivative Instruments Not Designated as Hedging Instruments

Fair Value Measurements

Equity Based Compensation

Equity-Based Compensation

New Accounting Pronouncements

Accounting Standards to be Adopted in Future Periods

Financial Instruments—Credit Losses

In June 2016, the FASB issued ASU No. 2016-13, “Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments.” This standard requires entities to measure all expected credit losses of financial assets held at a reporting date based on historical experience, current conditions, and reasonable and supportable forecasts in order to

record credit losses in a more timely manner. ASU 2016-13 also amends the accounting for credit losses on available-for-sale debt securities and purchased financial assets with credit deterioration. The standard is effective for interim and annual reporting periods beginning after December 15, 2019, although early adoption is permitted for interim and annual periods beginning after December 15, 2018. The Partnership expects to adopt this standard in the first quarter of 2020 and does not expect the adoption of this standard to have a material impact on our Consolidated Financial Statements and related disclosures.

Intangibles—Goodwill and Other

In January 2017, the FASB issued ASU No. 2017-04, “Intangibles-Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment.” This standard requires entities to test goodwill for impairment by eliminating Step 2 from the goodwill impairment test. The standard is effective for interim and annual reporting periods beginning after December 15, 2019, although early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. The Partnership elected to adopt the guidance in ASU 2017-04 effective October 1, 2019, and as a result applied the new guidance to its annual goodwill impairment test performed as of October 1, 2019. The impairment resulting from the October 1, 2019 annual impairment test was based upon the amount by which the carrying amount exceeded the reporting unit’s fair value up to the actual amount of goodwill recorded for the Anadarko Basin reporting unit.

Fair Value Measurement—Disclosure Framework-Changes to the Disclosure Requirements for Fair Value Measurement

In August 2018, the FASB issued ASU No. 2018-13, “Fair Value Measurement (Topic 820): Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement” which focuses on improving the effectiveness of disclosures in the notes to the financial statements by facilitating clear communication of the information required by U.S. GAAP that is most important to users of each entity’s financial statements. The standard is effective for interim and annual reporting periods beginning after December 15, 2019, although early adoption is permitted. The Partnership expects to adopt this standard in the first quarter of 2020 and does not expect the adoption of this standard to have a material impact on our Consolidated Financial Statements and related disclosures.

Intangibles—Goodwill and Other—Internal-Use Software

In August 2018, the FASB issued ASU No. 2018-15, “Intangibles—Goodwill and Other—Internal-Use Software: Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract,” which aims to reduce complexity in the accounting for costs of implementing a cloud computing service arrangement. ASU No. 2018-15 aligns the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. The standard is effective for interim and annual periods beginning after December 15, 2019. The Partnership expects to adopt this standard in the first quarter of 2020 and does not expect the adoption of this standard to have a material impact on our Consolidated Financial Statements and related disclosures.

Collaborative Arrangements

In November 2018, the FASB issued ASU No. 2018-18, “Collaborative Arrangements (Topic 808): Clarifying the Interaction between Topic 808 and Topic 606.” This standard resolves the diversity in practice concerning the manner in which entities account for transactions on the basis of their view of the economics of the collaborative arrangement. The amendments (1) clarify that certain transactions between collaborative participants should be accounted for as revenue under topic 606 when the collaborative participant is a customer in the context of the unit of account; (2) add unit-of-account guidance in Topic 808 to align with the guidance in Topic 606; and (3) clarify that in a transaction that is not directly related to sales to third parties, presenting the transaction as revenue would be precluded if the collaborative participant counterparty was not a customer. The standard is effective for interim and annual periods beginning after December 15, 2019. The Partnership expects to adopt this standard in the first quarter of 2020 and does not expect the adoption of this standard to have a material impact on our Consolidated Financial Statements and related disclosures.

Codification Improvements

In April 2019, the FASB issued ASU No. 2019-04, “Codification Improvements to Topic 326, Financial Instruments-Credit Losses, Topic 815, Derivatives and Hedging, and Topic 825, Financial Instruments,” which clarifies and improves areas of guidance related to recently issued standards on credit losses, hedging and recognition and measurement. The standard is effective for interim and annual periods beginning after December 15, 2019. The Partnership expects to adopt this standard in the first quarter of 2020 and does not expect the adoption of this standard to have a material impact on our Consolidated Financial Statements and related disclosures.

In November 2019, FASB issued ASU No. 2019-11, “Codification Improvements to Topic 326, Financial Instruments-Credit Losses,” which introduced an expected credit loss model for the impairment of financial assets measured at amortized cost basis to replace the probable, incurred loss model for those assets. The standard is effective for interim and annual periods beginning after December 15, 2019. The Partnership expects to adopt this standard in the first quarter of 2020 and does not expect the adoption of this standard to have a material impact on our Consolidated Financial Statements and related disclosures.

Contracts with Master Netting Arrangements

Reportable Segments

Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2019

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Schedule of Inventory

The cost of gas associated with sales of natural gas and natural gas liquids inventory is presented in Cost of natural gas and natural gas liquids, excluding depreciation and amortization on the Consolidated Statements of Income.



	December 31,
	2019		2018

	(In millions)
Materials and supplies	$	32	$	31
Natural gas and natural gas liquids	14		19
Total Inventory	$	46	$	50

Revenues (Tables)

12 Months Ended

Dec. 31, 2019

Revenue from Contract with Customer [Abstract]

Disaggregation of Revenue

The following tables disaggregate total revenues by major source from contracts with customers and the gain on derivative activity for the years ended December 31, 2019 and 2018.



	Year Ended December 31, 2019
	Gathering and 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:



	December 31, 2019		December 31, 2018

	(In millions)
Accounts Receivable:
Customers	$	239	$	297
Contract assets ⁽¹⁾	18		6
Non-customers	12		6
Total Accounts Receivable ⁽²⁾	$	269	$	309

____________________

(1)

(2)

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

Summary of Timing Recognition of Contract Liabilities

The table below summarizes the change in the contract liabilities for the year ended December 31, 2019:



	December 31, 2019		December 31, 2018		Amounts recognized in revenues

	(In millions)
Deferred revenues ⁽¹⁾	$	48	$	48	$	24

The table below summarizes the timing of recognition of these contract liabilities as of December 31, 2019:



	2020		2021		2022		2023		2024 and After

	(In millions)
Deferred revenues ⁽¹⁾	$	25	$	6	$	6	$	5	$	6

____________________

(1)

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

Summary of Timing Recognition of Remaining Performance Obligations

The table below summarizes the timing of recognition of the remaining performance obligations as of December 31, 2019:



	2020		2021		2022		2023		2024 and After

	(In millions)
Transportation and Storage ⁽¹⁾	$	461	$	298	$	238	$	225	$	699
Gathering and Processing	137		121		123		121		313
Total remaining performance obligations	$	598	$	419	$	361	$	346	$	1,012

Leases (Tables)

12 Months Ended

Dec. 31, 2019

Leases [Abstract]

Lease, Cost

The table below summarizes lease cost for the year ended December 31, 2019:



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

	(In millions)
Lease Cost:
Operating lease cost	$	11	$	—	$	11
Short-term lease cost	22		2		24
Variable lease cost	1		—		1
Total Lease Cost	$	34	$	2	$	36

Lessee, Operating Lease, Liability, Maturity



	Year Ended December 31,
	2020		2021		2022		2023		2024		2025 and After		Total

	(In millions)
Noncancellable operating leases	$	11	$	7	$	6	$	6	$	4	$	10	$	44

Schedule of Future Minimum Rental Payments for Operating Leases

s of December 31, 2018, the Partnership had the following future minimum payments for operating lease obligations as follows:



	Year Ended December 31,
	2019		2020-2021		2022-2023		After 2023		Total

	(In millions)
Noncancellable operating leases	$	14	$	6	$	6	$	14	$	40

Acquisitions (Tables)

12 Months Ended

Dec. 31, 2019

Business Combinations [Abstract]

Schedule of Assets Acquired and Liabilities Assumed

The following table presents the fair value of the identified assets acquired and liabilities assumed at the acquisition date:



Purchase price allocation (in millions):
Assets acquired:
Cash	$	1
Current Assets	3
Property, plant and equipment	124
Intangibles	259
Goodwill	86
Liabilities assumed:
Current liabilities	1
Less: Noncontrolling interest at fair value	28
Total identifiable net assets	$	444

The following table presents the fair value of the identified assets acquired and liabilities assumed at the acquisition date:



Purchase price allocation (in millions):
Assets acquired:
Accounts receivable	$	5
Property, plant and equipment	111
Intangibles	176
Goodwill	12
Liabilities assumed:
Current liabilities	6
Total identifiable net assets	$	298

Earnings Per Limited Partner Unit (Tables)

12 Months Ended

Dec. 31, 2019

Earnings Per Share [Abstract]

Schedule Of Earnings Per Unit For Common And Subordinated Limited Partner Units

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



	Year Ended December 31,
	2019		2018		2017

	(In millions, except per unit data)
Net income	$	400	$	523	$	437
Net income attributable to noncontrolling interests	4		2		1
Series A Preferred Unit distributions	36		36		36
General partner interest in net income	—		—		—
Net income available to common and subordinated units	$	360	$	485	$	400

Net income allocable to common units	$	360	$	485	$	273
Net income allocable to subordinated units	—		—		127
Net income available to common and subordinated units	$	360	$	485	$	400

Net income allocable to common units	$	360	$	485	$	273
Dilutive effect of Series A Preferred Unit distribution	—		—		—
Diluted net income allocable to common units	360		485		273
Diluted net income allocable to subordinated units	—		—		127
Total	$	360	$	485	$	400

Basic weighted average number of outstanding
Common units ⁽¹⁾	436		434		296
Subordinated units	—		—		137
Total	436		434		433

Basic earnings per unit
Common units	$	0.83	$	1.12	$	0.92
Subordinated units	$	—	$	—	$	0.93

Basic weighted average number of outstanding common units ⁽¹⁾	436		434		296
Dilutive effect of Series A Preferred Units	—		—		—
Dilutive effect of performance units	1		2		1
Diluted weighted average number of outstanding common units	437		436		297
Diluted weighted average number of outstanding subordinated units	—		—		137
Total	437		436		434

Diluted earnings per unit
Common units	$	0.82	$	1.11	$	0.92
Subordinated units	$	—	$	—	$	0.93

____________________


(1)	Basic weighted average number of outstanding common units for the years ended December 31, 2019, 2018, and 2017 includes approximately one million time-based phantom units.

Partners' Equity (Tables)

12 Months Ended

Dec. 31, 2019

Equity [Abstract]

Schedule Of Equity Transactions With Limited Partner



Quarter Ended	Record Date	Payment Date	Per Unit Distribution		Total Cash Distribution
2019
December 31, 2019 ⁽¹⁾	February 18, 2020	February 25, 2020	$	0.3305	$	144
September 30, 2019	November 19, 2019	November 26, 2019	$	0.3305	$	144
June 30, 2019	August 20, 2019	August 27, 2019	$	0.3305	$	144
March 31, 2019	May 21, 2019	May 29, 2019	$	0.318	$	138

2018
December 31, 2018	February 19, 2019	February 26, 2019	$	0.318	$	138
September 30, 2018	November 16, 2018	November 29, 2018	$	0.318	$	138
June 30, 2018	August 21, 2018	August 28, 2018	$	0.318	$	138
March 31, 2018	May 22, 2018	May 29, 2018	$	0.318	$	138

2017
December 31, 2017	February 20, 2018	February 27, 2018	$	0.318	$	138
September 30, 2017	November 14, 2017	November 21, 2017	$	0.318	$	138
June 30, 2017	August 22, 2017	August 29, 2017	$	0.318	$	138
March 31, 2017	May 23, 2017	May 30, 2017	$	0.318	$	137

_____________________


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

Schedule of Cash Distributions to Series A Preferred Unitholders

The Partnership paid or has authorized payment of the following cash distributions to holders of the Series A Preferred Units during 2019, 2018, and 2017 (in millions, except for per unit amounts):



Quarter Ended	Record Date	Payment Date	Per Unit Distribution		Total Cash Distribution
2019
December 31, 2019 ⁽¹⁾	February 7, 2020	February 14, 2020	$	0.625	$	9
September 30, 2019	November 5, 2019	November 14, 2019	$	0.625	$	9
June 30, 2019	August 2, 2019	August 14, 2019	$	0.625	$	9
March 31, 2019	April 29, 2019	May 15, 2019	$	0.625	$	9

2018
December 31, 2018	February 8, 2019	February 14, 2019	$	0.625	$	9
September 30, 2018	November 6, 2018	November 14, 2018	$	0.625	$	9
June 30, 2018	August 1, 2018	August 14, 2018	$	0.625	$	9
March 31, 2018	May 1, 2018	May 15, 2018	$	0.625	$	9

2017
December 31, 2017	February 9, 2018	February 15, 2018	$	0.625	$	9
September 30, 2017	October 31, 2017	November 14, 2017	$	0.625	$	9
June 30, 2017	July 31, 2017	August 14, 2017	$	0.625	$	9
March 31, 2017	May 2, 2017	May 12, 2017	$	0.625	$	9

_____________________


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

Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2019

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

Property, plant and equipment includes the following:



	Weighted Average Useful Lives (Years)	December 31,
	Weighted Average Useful Lives (Years)	2019		2018

		(In millions)
Property, plant and equipment, gross:
Gathering and Processing	33	$	8,252	$	8,011
Transportation and Storage	39	4,778		4,740
Construction work-in-progress		131		148
Total		$	13,161	$	12,899
Accumulated depreciation:
Gathering and Processing		1,252		1,063
Transportation and Storage		1,039		965
Total accumulated depreciation		2,291		2,028
Property, plant and equipment, net		$	10,870	$	10,871

Intangible Assets, Net (Tables)

12 Months Ended

Dec. 31, 2019

Goodwill and Intangible Assets Disclosure [Abstract]

Schedule of Finite-Lived Intangible Assets

The Partnership has intangible assets associated with customer relationships related to the acquisitions of Enogex LLC, Monarch Natural Gas, LLC, ETGP and EOCS as follows:



	December 31,
	2019		2018

	(In millions)
Customer relationships:
Total intangible assets ⁽¹⁾	$	840	$	840
Accumulated amortization	239		177
Net intangible assets	$	601	$	663

____________________

(1)

See Note 5 for discussion of the acquisition of EOCS and ETGP during the years ended December 31, 2018 and 2017, respectively.

Schedule of Finite-Lived Intangible Assets, Future Amortization Expense

The following table summarizes the Partnership’s expected amortization of intangible assets for each of the next five years:



	2020		2021		2022		2023		2024

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

Goodwill (Tables)

12 Months Ended

Dec. 31, 2019

Goodwill and Intangible Assets Disclosure [Abstract]

Schedule of Goodwill

The change in carrying amount of goodwill in each of our reportable segments is as follows:



	Gathering and Processing			Transportation and Storage		Total

	(in millions)
Balance as of December 31, 2017	$	12		$	—	$	12
EOCS Acquisition ⁽¹⁾	86			—		86
Balance as of December 31, 2018	$	98		$	—	$	98
Goodwill impairment	$	(86	)	$	—	$	(86	)
Balance as of December 31, 2019	$	12		$	—	$	12

_____________________

(1)

See Note 5 for further discussion.

Investment in Equity Method Affiliate (Tables)

12 Months Ended

Dec. 31, 2019

Equity Method Investments and Joint Ventures [Abstract]

Schedule of Investments Detail

SESH:



	Year Ended December 31,
	2019		2018		2017

	(In millions)
Equity in Earnings of Equity Method Affiliate	$	17	$	26	$	28
Distributions from Equity Method Affiliate ⁽¹⁾	25		33		33

____________________


(1)	Distributions from equity method affiliate includes a $17 million, $26 million and $28 million return on investment and a $8 million, $7 million and $5 million return of investment for the years ended December 31, 2019, 2018 and 2017, respectively.

Summarized financial information of SESH:



	December 31,
	2019			2018

	(In millions)
Balance Sheets:
Current assets	$	49		$	30
Property, plant and equipment, net	1,060			1,078
Total assets	$	1,109		$	1,108
Current liabilities	$	30		$	13
Long-term debt	398			397
Members’ equity	681			698
Total liabilities and members’ equity	$	1,109		$	1,108
Reconciliation:
Investment in SESH	$	309		$	317
Less: Capitalized interest on investment in SESH	(1		)	(1		)
Add: Basis differential, net of amortization	33			33
The Partnership’s share of members’ equity	$	341		$	349



	Year Ended December 31,
	2019		2018		2017

	(In millions)
Income Statements:
Revenues	$	109	$	112	$	113
Operating income	50		67		72
Net income	33		50		54

Debt (Tables)

12 Months Ended

Dec. 31, 2019

Debt Disclosure [Abstract]

Schedule of Debt

The following table presents the Partnership’s outstanding debt as of December 31, 2019 and 2018.



	December 31, 2019							December 31, 2018
	Outstanding Principal		Premium (Discount)⁽¹⁾			Total Debt		Outstanding Principal		Premium (Discount)⁽¹⁾			Total Debt

	(In millions)
Commercial Paper	$	155	$	—		$	155	$	649	$	—		$	649
Revolving Credit Facility	—		—			—		250		—			250
2019 Term Loan Agreement	800		—			800		—		—			—
2019 Notes	—		—			—		500		—			500
2024 Notes	600		—			600		600		—			600
2027 Notes	700		(2		)	698		700		(2		)	698
2028 Notes	800		(5		)	795		800		(6		)	794
2029 Notes	550		(1		)	549		—		—			—
2044 Notes	550		—			550		550		—			550
EOIT Senior Notes	250		1			251		250		7			257
Total debt	$	4,405	$	(7	)	$	4,398	$	4,299	$	(1	)	$	4,298
Less: Short-term debt ⁽²⁾						155							649
Less: Current portion of long-term debt ⁽³⁾						251							500
Less: Unamortized debt expense ⁽⁴⁾						23							20
Total long-term debt						$	3,969						$	3,129

___________________


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


(2)	Short-term debt includes $155 million and $649 million of commercial paper outstanding as of December 31, 2019 and 2018, respectively.


(3)	As of December 31, 2019, Current portion of long-term debt includes the $251 million outstanding balance of the EOIT Senior Notes due March 15, 2020. At December 31, 2018, Current portion of long-term debt included the $500 million outstanding balance of the 2019 Notes due May 15, 2019.


(4)	As of December 31, 2019 and 2018, there was an additional $4 million and $6 million, respectively, of unamortized debt expense related to the Revolving Credit Facility included in Other assets, not included above. Unamortized debt expense is amortized over the life of the respective debt.

Schedule of Maturities of Long-term Debt

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



2020	$	405
2021	—
2022	800
2023	—
2024	600
Thereafter	$	2,600

Derivative Instruments and Hedging Activities (Tables)

12 Months Ended

Dec. 31, 2019

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Derivative Instruments

As of December 31, 2019 and December 31, 2018, the Partnership had the following derivative instruments that were designated as hedging instruments for accounting purposes:



	December 31, 2019		December 31, 2018
	Gross Notional Value
	(In millions)
Interest rate swaps	$	300	$	—

As of December 31, 2019 and 2018, the Partnership had the following derivative instruments that were not designated as hedging instruments for accounting purposes:



	December 31, 2019		December 31, 2018
	Gross Notional Volume
	Purchases	Sales	Purchases	Sales
Natural gas—TBtu ⁽¹⁾
Financial fixed futures/swaps	10	19	16	28
Financial basis futures/swaps	11	30	18	29
Financial swaptions ⁽²⁾	—	2	—	1
Physical purchases/sales	—	6	—	11
Crude oil (for condensate)—MBbl ⁽³⁾
Financial futures/swaps	—	990	—	945
Financial swaptions ⁽²⁾	—	225	—	30
Natural gas liquids—MBbl ⁽⁴⁾
Financial futures/swaps	2,490	2,415	270	2,535

____________________


(1)	As of December 31, 2019, 86.6% of the natural gas contracts had durations of one year or less and 13.4% had durations of more than one year and less than two years. As of December 31, 2018, 74.0% of the natural gas contracts had durations of one year or less, 24.2% had durations of more than one year and less than two years and 1.8% had durations of more than two years.


(2)	The notional value contains a combined derivative instrument consisting of a fixed price swap and a sold option, which gives the counterparties the right, but not the obligation, to increase the notional quantity hedged under the fixed price swap until the option expiration date. The notional volume represents the volume prior to option exercise.


(3)	As of December 31, 2019, 72.8% of the crude oil (for condensate) contracts had durations of one year or less and 27.2% had durations of more than one year and less than two years. As of December 31, 2018, 76.9% of the crude oil (for condensate) contracts had durations of one year or less and 23.1% had durations of more than one year and less than two years.

(4)

As of December 31, 2019, 72.2% of the natural gas liquids contracts had durations of one year or less and 27.8% had durations of more than one year and less than two years. As of December 31, 2018, 86.1% of the natural gas liquids contracts had durations of one year or less and 13.9% had durations of more than one year and less than two years.

Schedule of Derivative Assets at Fair Value



		December 31, 2019				December 31, 2018
		Fair Value
Instrument	Balance Sheet Location	Assets		Liabilities		Assets		Liabilities

		(In millions)
Natural gas
Financial futures/swaps	Other Current	$	7	$	5	$	3	$	5
Financial futures/swaps	Other	—		1		—		2
Physical purchases/sales	Other Current	5		—		3		—
Physical purchases/sales	Other	—		—		4		—
Crude oil (for condensate)
Financial futures/swaps	Other Current	1		19		9		3
Financial futures/swaps	Other	—		8		2		—
Natural gas liquids
Financial futures/swaps	Other Current	25		3		10		1
Financial futures/swaps	Other	11		2		2		—
Total gross derivatives ⁽¹⁾		$	49	$	38	$	33	$	11

_____________________


(1)	See Note 14 for a reconciliation of the Partnership’s total derivatives fair value to the Partnership’s Consolidated Balance Sheets as of December 31, 2019 and 2018.



		December 31, 2019				December 31, 2018
		Fair Value
Instrument	Balance Sheet Location	Assets		Liabilities		Assets		Liabilities

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

_____________________


(1)	All interest rate derivative instruments that were designated as cash flow hedges are considered Level 2 as of December 31, 2019.

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

The following table presents the components of gain (loss) on derivative activity in the Partnership’s Consolidated Statements of Income for the years ended December 31, 2019, 2018 and 2017:



	Year Ended December 31,
	2019			2018			2017

	(In millions)
Change in fair value of derivatives	$	(11	)	$	26		$	28
Realized gain (loss) on derivatives	27			(15		)	(9		)
Gain on derivative activity	$	16		$	11		$	19

The following table presents the effect of derivative instruments on the Partnership’s Consolidated Statements of Income for the years ended December 31, 2019, 2018 and 2017:



	Amounts Recognized in Income
	Year Ended December 31,
	2019			2018			2017

	(In millions)
Natural Gas
Financial futures/swaps gains (losses)	$	13		$	(8	)	$	20
Physical purchases/sales gains	2			7			9
Crude oil (for condensate)
Financial futures/swaps (losses) gains	(41		)	6			(1		)
Natural gas liquids
Financial futures/swaps gains (losses)	42			6			(9		)
Total	$	16		$	11		$	19

- 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.

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+ Details

Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2019

Fair Value Disclosures [Abstract]

Schedule of Fair Value and Carrying Amount of Financial Instruments

The following table summarizes the fair value and carrying amount of the Partnership’s financial instruments at December 31, 2019 and 2018:



	December 31, 2019				December 31, 2018
	Carrying Amount		Fair Value		Carrying Amount		Fair Value

	(In millions)
Debt
Revolving Credit Facility (Level 2) ⁽¹⁾	$	—	$	—	$	250	$	250
2019 Term Loan Agreement (Level 2)	800		800		—		—
2019 Notes (Level 2)	—		—		500		497
2024 Notes (Level 2)	600		614		600		571
2027 Notes (Level 2)	698		698		698		642
2028 Notes (Level 2)	795		811		794		764
2029 Notes (Level 2)	549		526		—		—
2044 Notes (Level 2)	550		506		550		445
EOIT Senior Notes (Level 2)	251		252		257		256

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



December 31, 2019	Commodity Contracts						Gas Imbalances ⁽¹⁾
	Assets			Liabilities			Assets ⁽²⁾		Liabilities ⁽³⁾

	(In millions)
Quoted market prices in active market for identical assets (Level 1)	$	5		$	31		$	—	$	—
Significant other observable inputs (Level 2)	44			7			14		11
Unobservable inputs (Level 3)	—			—			—		—
Total fair value	49			38			14		11
Netting adjustments	(37		)	(37		)	—		—
Total	$	12		$	1		$	14	$	11



December 31, 2018	Commodity Contracts						Gas Imbalances ⁽¹⁾
	Assets			Liabilities			Assets ⁽²⁾		Liabilities ⁽³⁾

	(In millions)
Quoted market prices in active market for identical assets (Level 1)	$	4		$	9		$	—	$	—
Significant other observable inputs (Level 2)	29			2			18		17
Unobservable inputs (Level 3)	—			—			—		—
Total fair value	33			11			18		17
Netting adjustments	(9		)	(9		)	—		—
Total	$	24		$	2		$	18	$	17

______________________


(1)	The Partnership uses the market approach to fair value its gas imbalance assets and liabilities at individual, or where appropriate an average of, current market indices applicable to the Partnership’s operations, not to exceed net realizable value. There were no netting adjustments as of December 31, 2019 and 2018.


(2)	Gas imbalance assets exclude fuel reserves for under retained fuel due from shippers of $21 million and $11 million at December 31, 2019 and 2018, respectively, which fuel reserves are based on the value of natural gas at the time the imbalance was created and which are not subject to revaluation at fair market value.

(3)

Gas imbalance liabilities exclude fuel reserves for over retained fuel due to shippers of $8 million and $5 million at December 31, 2019 and 2018, respectively, which fuel reserves are based on the value of natural gas at the time the imbalance was created and which are not subject to revaluation at fair market value.

Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation



	Commodity Contracts
	Natural gas liquids financial futures/swaps
	(In millions)
Balance as of December 31, 2017	$	(5	)
Losses included in earnings	(23		)
Settlements	7
Transfers out of Level 3	21
Balance as of December 31, 2018	$	—

Supplemental Disclosure of Cash Flow Information (Tables)

12 Months Ended

Dec. 31, 2019

Supplemental Cash Flow Information [Abstract]

Schedule of Cash Flow, Supplemental Disclosures

The following table provides information regarding supplemental cash flow information:



	Year Ended December 31,
	2019		2018		2017

	(In millions)
Supplemental Disclosure of Cash Flow Information:
Cash Payments:
Interest, net of capitalized interest	$	185	$	148	$	114
Income taxes, net of refunds	1		3		—
Non-cash transactions:
Accounts payable related to capital expenditures	10		54		39
Lease liabilities arising from the application of ASC 842	45		—		—

Schedule of Restricted Cash and Cash Equivalents



	December 31,
	2019		2018

	(In millions)
Cash and cash equivalents	$	4	$	8
Restricted cash	—		14
Cash, cash equivalents and restricted cash shown in the Consolidated Statement of Cash Flows	$	4	$	22

As of December 31, 2018, Restricted cash included $14 million of cash collateral which was provided by a third party as credit assurance. The cash collateral was released in 2019.

Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2019

Schedule of Revenues from Related Parties

Amounts of total revenues from affiliated companies included in the Partnership’s Consolidated Statements of Income are summarized as follows:



	Year Ended December 31,
	2019		2018		2017

	(In millions)
Gas transportation and storage service revenues — CenterPoint Energy	$	108	$	111	$	110
Natural gas product sales — CenterPoint Energy	8		11		6
Gas transportation and storage service revenues — OGE Energy	41		37		35
Natural gas product sales — OGE Energy	10		4		2
Total revenues — affiliated companies	$	167	$	163	$	153

Schedule of Natural Gas Purchased From Related Parties

Amounts of natural gas purchased from affiliated companies included in the Partnership’s Consolidated Statements of Income are summarized as follows:



	Year Ended December 31,
	2019		2018		2017

	(In millions)
Cost of natural gas purchases — CenterPoint Energy	$	—	$	3	$	1
Cost of natural gas purchases — OGE Energy	33		23		19
Total cost of natural gas purchases — affiliated companies	$	33	$	26	$	20

Schedule of Amounts Charged to Partnership by Related Parties



	Year Ended December 31,
	2019		2018		2017

	(In millions)
Corporate Services — CenterPoint Energy	$	—	$	1	$	3
Operating Lease — CenterPoint Energy	1		1		1
Seconded Employee Costs — OGE Energy	18		29		31
Corporate Services — OGE Energy	—		1		3
Total corporate services, operating lease and seconded employee expense	$	19	$	32	$	38

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2019

Income Tax Disclosure [Abstract]

Schedule of Components of Income Tax Expense (Benefit)

The items comprising income tax expense are as follows:



	Year Ended December 31,
	2019			2018			2017

	(In millions)
Provision for current income taxes
Federal	$	—		$	—		$	1
State	—			—			1
Total provision for current income taxes	—			—			2
Benefit for deferred income taxes, net
Federal	$	(1	)	$	(1	)	$	(2	)
State	—			—			(1		)
Total benefit for deferred income taxes, net	(1		)	(1		)	(3		)
Total income tax benefit	$	(1	)	$	(1	)	$	(1	)

Schedule of Deferred Tax Assets and Liabilities

The components of Deferred Income Taxes as of December 31, 2019 and 2018 were as follows:



	December 31,
	2019			2018

	(In millions)
Deferred tax liabilities, net:
Non-current:
Intercompany management fee	$	17		$	16
Depreciation	6			5
Accrued compensation	(19		)	(16		)
Total deferred tax liabilities, net	$	4		$	5

Equity Based Compensation (Tables)

12 Months Ended

Dec. 31, 2019

Share-based Payment Arrangement [Abstract]

Disclosure of Share-based Compensation Arrangements by Share-based Payment Award

The following table summarizes the Partnership’s equity-based compensation expense for the years ended December 31, 2019, 2018 and 2017 related to performance units, restricted units and phantom units for the Partnership’s employees and independent directors:



	Year Ended December 31,
	2019		2018		2017

	(In millions)
Performance units	$	9	$	9	$	10
Restricted units	—		1		2
Phantom units	7		6		3
Total equity-based compensation expense	$	16	$	16	$	15

Schedule of Valuation Assumptions



	2019			2018			2017
Number of units granted	638,798			551,742			468,626
Fair value of units granted	$	19.95		$	17.70		$	19.27
Expected price volatility	34.2		%	44.2		%	47.3		%
Risk-free interest rate	2.54		%	2.36		%	1.57		%
Distribution yield	8.38		%	8.56		%	9.10		%
Expected life of units (in years)	3			3			3

Phantom Units, Grants in Period And Grant Date Fair Value

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



	2019	2018	2017
Phantom units granted	695,486	546,708	392,338
Fair value of phantom units granted	$8.95 - $15.04	$13.74 - $17.00	$15.44 - $16.93

Common units, Grants in Period and Grant Date Fair Value

The fair value of the common units was based on the closing market price of the Partnership’s common unit on the grant date.



	2019		2018		2017
Common units granted	28,221		16,335		16,653
Fair value of common units granted	$	10.43	$	14.94	$	15.03

Schedule of Share-based Compensation, Activity

A summary of the activity for the Partnership’s performance units and phantom units as of December 31, 2019 and changes during 2019 are shown in the following table.



	Performance Units					Phantom Units
	Number of Units			Weighted Average Grant-Date Fair Value, Per Unit		Number of Units			Weighted Average Grant-Date Fair Value, Per Unit

	(In millions, except unit data)
Units outstanding at 12/31/2018	2,109,835			$	14.33	1,447,590			$	12.38
Granted ⁽¹⁾	638,798			19.95		695,486			14.26
Vested ⁽²⁾⁽³⁾	(1,174,597		)	11.09		(608,755		)	8.71
Forfeited	(180,707		)	18.96		(141,761		)	14.89
Units outstanding at 12/31/2019	1,393,329			19.04		1,392,560			14.65
Aggregate intrinsic value of units outstanding at December 31, 2019	$	14				$	14

_____________________


(1)	For performance units, this represents the target number of performance units granted. The actual number of performance units earned, if any, is dependent upon performance and may range from 0% to 200% of the target.

(2)

(3)



	Year Ended December 31, 2019
	Performance Units		Restricted Stock		Phantom Units

	(In millions)
Aggregate intrinsic value of units vested	$	34	$	—	$	9
Fair value of units vested	13		—		5



	Year Ended December 31, 2018
	Performance Units		Restricted Stock		Phantom Units

	(In millions)
Aggregate intrinsic value of units vested	$	11	$	3	$	1
Fair value of units vested	7		4		—



	Year Ended December 31, 2017
	Performance Units		Restricted Stock		Phantom Units

	(In millions)
Aggregate intrinsic value of units vested	$	5	$	2	$	—
Fair value of units vested	10		4		—

Schedule of Unrecognized Compensation Cost, Nonvested Awards



	December 31, 2019
	Unrecognized Compensation Cost (In millions)		Weighted Average to be Recognized (In years)
Performance Units	$	12	1.32
Phantom Units	9		1.24
Total	$	21

Reportable Segments (Tables)

12 Months Ended

Dec. 31, 2019

Segment Reporting [Abstract]

Schedule of Financial Data for Business Segments and Services

Financial data for reportable segments are as follows:



Year Ended December 31, 2019	Gathering and 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	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
Impairments	—		—		—			—
Taxes other than income tax	38		27		—			65
Operating Income	$	464	$	183	$	1		$	648
Total Assets	$	9,874	$	5,805	$	(3,235	)	$	12,444
Capital expenditures, including acquisitions	$	981	$	190	$	—		$	1,171



Year Ended December 31, 2017	Gathering and Processing		Transportation and Storage⁽¹⁾		Eliminations			Total

	(In millions)
Product sales	$	1,538	$	621	$	(506	)	$	1,653
Service revenues	632		525		(7		)	1,150
Total Revenues	2,170		1,146		(513		)	2,803
Cost of natural gas and natural gas liquids, excluding depreciation and amortization shown separately	1,285		604		(508		)	1,381
Operation and maintenance, General and administrative	289		179		(4		)	464
Depreciation and amortization	232		134		—			366
Impairments	—		—		—			—
Taxes other than income tax	37		27		—			64
Operating Income	$	327	$	202	$	(1	)	$	528
Total Assets	$	9,079	$	5,616	$	(3,102	)	$	11,593
Capital expenditures	$	601	$	113	$	—		$	714

_____________________


(1)	Equity in earnings of equity method affiliate is included in Other Income (Expense) on the Consolidated Statements of Income and is not included in the table above. See Note 11 for discussion regarding ownership interest in SESH and related equity earnings included in the transportation and storage reportable segment for the years ended December 31, 2019, 2018 and 2017.

Quarterly Financial Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2019

Quarterly Financial Information Disclosure [Abstract]

Schedule of Quarterly Financial Information

Summarized unaudited quarterly financial data for 2019 and 2018 are as follows:



	Quarters Ended
	March 31, 2019		June 30, 2019		September 30, 2019		December 31, 2019

	(in millions, except per unit data)
Total Revenues	$	795	$	735	$	699	$	731
Cost of natural gas and natural gas liquids	378		317		263		321
Operating income ⁽¹⁾	165		167		175		62
Net income	123		124		133		20
Net income attributable to limited partners	122		124		132		18
Net income attributable to common units	113		115		123		9

Basic earnings per unit
Common units	$	0.26	$	0.26	$	0.28	$	0.02
Diluted earnings per unit
Common units	$	0.26	$	0.26	$	0.28	$	0.02

	Quarters Ended
	March 31, 2018		June 30, 2018		September 30, 2018		December 31, 2018

	(in millions, except per unit data)
Total Revenues	$	748	$	805	$	928	$	950
Cost of natural gas and natural gas liquids	375		444		516		484
Operating income	139		126		171		212
Net income	114		95		139		175
Net income attributable to limited partners	114		95		138		174
Net income attributable to common units	105		86		129		165

Basic earnings per unit
Common Units	$	0.24	$	0.20	$	0.30	$	0.38
Diluted earnings per unit
Common Units	$	0.24	$	0.20	$	0.30	$	0.38

_____________________

(1)

Summary of Significant Accounting Policies - Narrative (Details)

2 Months Ended

3 Months Ended

12 Months Ended

Dec. 31, 2018

USD ($)

Dec. 31, 2019

USD ($)

board_member

Sep. 30, 2019

USD ($)

^[1]

Jun. 30, 2019

USD ($)

^[1]

Mar. 31, 2019

USD ($)

^[1]

Dec. 31, 2018

USD ($)

Sep. 30, 2018

USD ($)

^[1]

Jun. 30, 2018

USD ($)

^[1]

Mar. 31, 2018

USD ($)

^[1]

Dec. 31, 2019

USD ($)

board_member

segment

Dec. 31, 2018

USD ($)

Dec. 31, 2017

USD ($)

Number of reportable segments | segment

Number of representatives designated by each of CenterPoint Energy and OGE Energy | board_member

Number of independent board members | board_member

Minimum percentage of vote required by all unitholders

75.00%

Cash and cash equivalents

$ 731,000,000

^[1]

$ 699,000,000

$ 735,000,000

$ 795,000,000

$ 950,000,000

^[1]

$ 928,000,000

$ 805,000,000

$ 748,000,000

$ 2,960,000,000

$ 3,431,000,000

$ 2,803,000,000

Environmental exit costs

$ 0

8,000,000

4,000,000

8,000,000

4,000,000

8,000,000

Restricted cash

14,000,000

Allowance for doubtful accounts receivable

2,000,000

Regulatory liabilities

$ 23,000,000

$ 24,000,000

$ 23,000,000

24,000,000

23,000,000

AFUDC, capitalized interest

$ 2,000,000

6,000,000

1,000,000

Participant contribution percentage, maximum

70.00%

Employer matching contribution percentage

100.00%

Employer matching contribution percentage, percent of participant's eligible compensation

6.00%

Partnership contributions

$ 20,000,000

19,000,000

18,000,000

Materials and Supplies

Write down of materials and supplies inventory

1,000,000

Natural gas

Write down of materials and supplies inventory

$ 8,000,000

$ 4,000,000

$ 2,000,000

SESH

Total revenue | Customer Concentration Risk

50.00%

Ownership percentage

50.00%

11.00%

0.00%

CenterPoint | Common Units

$ 328,000,000

Units outstanding (in units) | shares

233,856,623

OGE Energy | Common Units

Units outstanding (in units) | shares

110,982,805

Atoka

Limited Partner | CenterPoint

50.00%

Percentage share of management rights

50.00%

Percentage share of incentive distribution rights

40.00%

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

53.70%

Preferred units issued | shares

14,520,000

Limited Partner | OGE Energy

Percentage share of management rights

50.00%

Percentage share of incentive distribution rights

60.00%

Third Party One | Volume of natural gas liquids | Customer Concentration Risk

25.50%

Third Party One | Total revenue | Customer Concentration Risk

12.00%

13.00%

4.00%

6.00%

5.00%

Third Party Two | Volume of natural gas liquids | Customer Concentration Risk

^[1]

$ 131,000,000

$ 214,000,000

$ 140,000,000

Third Party Two | Total revenue | Customer Concentration Risk

12.00%

8.00%

12.00%

4.00%

^[1]

$ 119,000,000

$ 152,000,000

$ 127,000,000

VPP

Defined Benefit And Retiree Medical Plans | OGE Energy

60.00%

Reimbursement of benefits

$ 3,000,000

$ 5,000,000

[1]	Text selection found with no content.

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

Revenues - Disaggregation of Revenue (Details) - USD ($)
$ in Millions

3 Months Ended

12 Months Ended

Dec. 31, 2019

^[1]

Sep. 30, 2019

^[1]

Jun. 30, 2019

^[1]

Mar. 31, 2019

^[1]

Dec. 31, 2018

^[1]

Sep. 30, 2018

^[1]

Jun. 30, 2018

^[1]

Mar. 31, 2018

^[1]

Dec. 31, 2019

Dec. 31, 2018

Dec. 31, 2017

Total revenues from natural gas, natural gas liquids, and condensate

$ 1,517

$ 2,095

$ 19

$ 731

$ 699

$ 735

$ 795

$ 950

$ 928

$ 805

$ 748

2,960

3,431

2,803

Natural gas

Total revenues from natural gas, natural gas liquids, and condensate

448

564

Natural gas liquids

Total revenues from natural gas, natural gas liquids, and condensate

943

1,405

Condensate Natural Gas

Total revenues from natural gas, natural gas liquids, and condensate

126

Product

1,533

2,106

1,653

Demand Service Revenue

Volume Dependant Service Revenue

763

724

Natural Gas, Gathering, Transportation, Marketing and Processing

664

601

Operating Segments | Gathering and Processing

1,427

1,325

1,150

Total revenues from natural gas, natural gas liquids, and condensate

1,437

2,011

Operating Segments | Gathering and Processing | Natural gas

2,338

2,818

2,170

Total revenues from natural gas, natural gas liquids, and condensate

368

480

Operating Segments | Gathering and Processing | Natural gas liquids

Total revenues from natural gas, natural gas liquids, and condensate

943

1,405

Operating Segments | Gathering and Processing | Condensate Natural Gas

Total revenues from natural gas, natural gas liquids, and condensate

126

Operating Segments | Gathering and Processing | Product

Operating Segments | Gathering and Processing | Demand Service Revenue

1,449

2,016

1,538

Operating Segments | Gathering and Processing | Volume Dependant Service Revenue

274

252

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

615

550

Operating Segments | Transportation and Storage

889

802

632

Total revenues from natural gas, natural gas liquids, and condensate

483

620

Operating Segments | Transportation and Storage | Natural gas

1,038

1,162

1,146

Total revenues from natural gas, natural gas liquids, and condensate

464

590

Operating Segments | Transportation and Storage | Natural gas liquids

Total revenues from natural gas, natural gas liquids, and condensate

Operating Segments | Transportation and Storage | Condensate Natural Gas

Total revenues from natural gas, natural gas liquids, and condensate

Operating Segments | Transportation and Storage | Product

Operating Segments | Transportation and Storage | Demand Service Revenue

487

625

621

Operating Segments | Transportation and Storage | Volume Dependant Service Revenue

489

472

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

551

537

525

Eliminations

Total revenues from natural gas, natural gas liquids, and condensate

(403)

(536)

Eliminations | Natural gas

(416)

(549)

(513)

Total revenues from natural gas, natural gas liquids, and condensate

(384)

(506)

Eliminations | Natural gas liquids

Total revenues from natural gas, natural gas liquids, and condensate

(19)

(30)

Eliminations | Condensate Natural Gas

Total revenues from natural gas, natural gas liquids, and condensate

Eliminations | Product

Eliminations | Demand Service Revenue

(403)

(535)

(506)

Eliminations | Volume Dependant Service Revenue

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

(13)

(14)

$ (13)

$ (14)

$ (7)

[1]	Text selection found with no content.

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

Dec. 31, 2019

Dec. 31, 2018

Total Accounts Receivable

Customers

$ 239

$ 297

Contract assets

^[1]

Non-customers

^[2]

269

$ 309

Firm Service Transportation [Member]

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

Contract assets

$ 6

[1]

(1)

[2]

(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	Dec. 31, 2019	Dec. 31, 2018
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Deferred revenues	$ 48
Calculated under Revenue Guidance in Effect before Topic 606
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Deferred revenues		$ 48
Accounting Standards Update 2014-09 \| Difference between Revenue Guidance in Effect before and after Topic 606
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Deferred revenues	$ 24

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

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

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

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

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

Acquisitions - Narrative (Details) $ in Millions			12 Months Ended
Acquisitions - Narrative (Details) $ in Millions	Nov. 01, 2018 USD ($) mi	Oct. 04, 2017 USD ($)	Dec. 31, 2019	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)
General and Administrative Expense
Business Acquisition [Line Items]
Acquisition costs associated with the transaction (less than $1 million)				$ 6
Velocity Holdings, LLC
Business Acquisition [Line Items]
Aggregate purchase price	$ 444
Percentage of Pipeline System Acquired	60.00%
Number of miles in pipeline system acquired \| mi	26
Less: Noncontrolling interest at fair value	$ 28
Align Midstream, LLC
Business Acquisition [Line Items]
Aggregate purchase price		$ 298
Align Midstream, LLC \| General and Administrative Expense
Business Acquisition [Line Items]
Acquisition costs associated with the transaction (less than $1 million)					$ 2
Customer Relationships
Business Acquisition [Line Items]
Weighted average useful life (in years)			14 years
Customer Relationships \| Velocity Holdings, LLC
Business Acquisition [Line Items]
Weighted average useful life (in years)				15 years
Customer Relationships \| Align Midstream, LLC
Business Acquisition [Line Items]
Weighted average useful life (in years)		10 years

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

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

3 Months Ended

12 Months Ended

Dec. 31, 2019

Sep. 30, 2019

Jun. 30, 2019

Mar. 31, 2019

Dec. 31, 2018

Sep. 30, 2018

Jun. 30, 2018

Mar. 31, 2018

Dec. 31, 2019

Dec. 31, 2018

Dec. 31, 2017

Net income

$ 20,000,000

$ 133,000,000

$ 124,000,000

$ 123,000,000

$ 175,000,000

$ 139,000,000

$ 95,000,000

$ 114,000,000

$ 400,000,000

$ 523,000,000

$ 437,000,000

Net income attributable to noncontrolling interests

4,000,000

2,000,000

1,000,000

Series A Preferred Unit distributions

36,000,000

General partner interest in net income

Net Income Attributable to Common and Subordinated Units (Note 6)

$ 9,000,000

$ 123,000,000

$ 115,000,000

$ 113,000,000

$ 165,000,000

$ 129,000,000

$ 86,000,000

$ 105,000,000

360,000,000

485,000,000

400,000,000

Dilutive effect of Series A Preferred Unit distribution

Diluted net income (loss)

$ 360,000,000

$ 485,000,000

$ 400,000,000

Diluted weighted average number of outstanding units

436

434

433

Basic earnings (loss) per unit

437

436

434

Common Units

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

Net Income Attributable to Common and Subordinated Units (Note 6)

$ 360,000,000

$ 485,000,000

$ 273,000,000

Diluted net income (loss)

$ 360,000,000

$ 485,000,000

$ 273,000,000

^[1]

436

434

296

Basic earnings (loss) per unit

Dilutive effect of Series A Preferred Units (in units)

$ 0.02

$ 0.28

$ 0.26

$ 0.38

$ 0.30

$ 0.20

$ 0.24

$ 0.83

$ 1.12

$ 0.92

Dilutive effect of performance units (in units)

Diluted weighted average number of outstanding units

437

436

297

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

$ 0.02

$ 0.28

$ 0.26

$ 0.38

$ 0.30

$ 0.20

$ 0.24

$ 0.82

$ 1.11

$ 0.92

Subordinated Units

Net Income Attributable to Common and Subordinated Units (Note 6)

$ 0

$ 127,000,000

Diluted net income (loss)

$ 0

$ 127,000,000

137

Basic earnings (loss) per unit

Diluted weighted average number of outstanding units

$ 0

$ 0.93

137

Performance Units, Restricted Units, and Phantom Units

$ 0

$ 0.93

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

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

$ 0.01

Phantom units

Distribution Made to Limited Partner [Line Items]

1,000,000

[1]	Basic weighted average number of outstanding common units for the years ended December 31, 2019, 2018, and 2017 includes approximately one million time-based phantom units.

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

Feb. 25, 2020

Feb. 18, 2020

Feb. 14, 2020

Feb. 07, 2020

Nov. 26, 2019

Nov. 19, 2019

Nov. 14, 2019

Nov. 05, 2019

Aug. 27, 2019

Aug. 20, 2019

Aug. 14, 2019

Aug. 02, 2019

May 29, 2019

May 21, 2019

May 15, 2019

Apr. 29, 2019

Feb. 26, 2019

Feb. 19, 2019

Feb. 14, 2019

Feb. 08, 2019

Nov. 29, 2018

Nov. 16, 2018

Nov. 14, 2018

Nov. 06, 2018

Aug. 28, 2018

Aug. 21, 2018

Aug. 14, 2018

Aug. 01, 2018

May 29, 2018

May 22, 2018

May 15, 2018

May 14, 2018

May 01, 2018

Feb. 27, 2018

Feb. 20, 2018

Feb. 15, 2018

Feb. 09, 2018

Nov. 21, 2017

Nov. 14, 2017

Oct. 31, 2017

Aug. 29, 2017

Aug. 22, 2017

Aug. 14, 2017

Jul. 31, 2017

May 30, 2017

May 23, 2017

May 12, 2017

May 02, 2017

Nov. 19, 2019

Aug. 20, 2019

May 21, 2019

Feb. 19, 2019

Nov. 16, 2018

Aug. 21, 2018

May 22, 2018

Feb. 20, 2018

Nov. 14, 2017

Aug. 22, 2017

May 23, 2017

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

Nov. 26, 2019

Aug. 27, 2019

May 29, 2019

Feb. 26, 2019

Nov. 29, 2018

Aug. 28, 2018

May 29, 2018

Feb. 27, 2018

Nov. 21, 2017

Aug. 29, 2017

May 30, 2017

Distribution Made to Limited Partner [Line Items]

Nov. 05, 2019

Aug. 02, 2019

Apr. 29, 2019

Feb. 08, 2019

Nov. 06, 2018

Aug. 01, 2018

May 01, 2018

Feb. 09, 2018

Oct. 31, 2017

Jul. 31, 2017

May 02, 2017

Distribution Made to Limited Partner [Line Items]

Nov. 14, 2019

Aug. 14, 2019

May 15, 2019

Feb. 14, 2019

Nov. 14, 2018

Aug. 14, 2018

May 15, 2018

Feb. 15, 2018

Nov. 14, 2017

Aug. 14, 2017

May 12, 2017

Cash Distribution

$ 0.3305

$ 0.318

Common unit cash distribution declared (in dollars per unit)

$ 144

$ 138

$ 137

$ 0.318

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

Distribution Made to Limited Partner [Line Items]

$ 0.625

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

$ 9

Distribution Made to Limited Partner [Line Items]

^[1]

Feb. 07, 2020

Subsequent Event | Cash Distribution

^[1]

Feb. 14, 2020

Distribution Made to Limited Partner [Line Items]

Common unit cash distribution declared (in dollars per unit)

$ 0.3305

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

Distribution Made to Limited Partner [Line Items]

^[1]

$ 0.625

Common unit cash distribution declared (in dollars per unit)

^[1]

$ 9

$ 0.625

Subsequent Event | Scenario, Forecast

Distribution Made to Limited Partner [Line Items]

^[2]

Feb. 18, 2020

^[2]

Feb. 25, 2020

^[2]

$ 0.3305

Finite-Lived Intangible Assets [Line Items]

^[2]

$ 144

[1]	The Board of Directors declared a $0.625 per Series A Preferred Unit cash distribution on February 7, 2020, to be paid on February 14, 2020 to Series A Preferred unitholders of record at the close of business on February 7, 2020.
[2]	The Board of Directors declared a $0.3305 per common unit cash distribution on February 7, 2020, to be paid on February 25, 2020, to common unitholders of record at the close of business on February 18, 2020.

Partners' Equity - Narrative (Details) - USD ($)				12 Months Ended
Partners' Equity - Narrative (Details) - USD ($)	Aug. 30, 2017	May 12, 2017	Feb. 18, 2016	Dec. 31, 2019	Dec. 31, 2018
Distribution Made to Limited Partner [Line Items]
Limited partners' capital account, required quarterly distribution period				60 days
Conversion ratio	100.00%
Limited partners capital account, minimum quarterly distribution, annualized				150.00%
Aggregate offering price				$ 2,000,000
Number of common units in public offering				0	140,920
Common units remained available for issuance through the ATM Program				$ 197,000,000
Commissions				$ 25,000
Series A 10% Fixed to Floating Non Cumulative Redeemable Perpetual Preferred Units
Distribution Made to Limited Partner [Line Items]
Annual percentage rate			10.00%
Liquidation preference (in dollars per share)			$ 25.00
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
Subordinated Units \| Limited Partner \| OGE Energy
Distribution Made to Limited Partner [Line Items]
Units outstanding (in units)					68,150,514
Subordinated Units \| Limited Partner \| CenterPoint
Distribution Made to Limited Partner [Line Items]
Units outstanding (in units)					139,704,916
Distribution Subordination Period 1
Distribution Made to Limited Partner [Line Items]
Limited partners' capital account, minimum annualized quarterly distribution (in dollars per unit)				$ 1.15
Distribution Subordination Period 2
Distribution Made to Limited Partner [Line Items]
Limited partners' capital account, maximum annualized quarterly distribution (in dollars per unit)				$ 1.725
Maximum
Distribution Made to Limited Partner [Line Items]
Limited partners' capital account, incentive distribution rights, percentage				50.00%	50.00%
Minimum
Distribution Made to Limited Partner [Line Items]
Incentive distribution, distribution (in dollars per unit)				$ 0.330625	$ 0.330625
Subordinated Units
Distribution Made to Limited Partner [Line Items]
Units outstanding (in units)	207,855,430

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

Intangible Assets, Net - Narrative (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2019

Dec. 31, 2018

Dec. 31, 2017

Intangible assets with indefinite useful lives

$ 0

Amortization expense

$ 47

$ 31

Expected amortization of intangible assets, 2020

Expected amortization of intangible assets, 2021

Expected amortization of intangible assets, 2022

Expected amortization of intangible assets, 2023

Expected amortization of intangible assets, 2024

Customer Relationships

Finite-Lived Intangible Assets [Line Items]

Total intangible assets

^[1]

840

Accumulated amortization

239

177

Net intangible assets

$ 601

$ 663

Weighted average useful life (in years)

14 years

[1]	(1) See Note 5 for discussion of the acquisition of EOCS and ETGP during the years ended December 31, 2018 and 2017, respectively.

Goodwill (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2019

Dec. 31, 2018

$ 98

$ 12

(86)

Gathering and Processing

(86)

Transportation and Storage

Velocity Holdings, LLC | Gathering and Processing

$ 0

Velocity Holdings, LLC | Transportation and Storage

Goodwill acquired

^[1]

Schedule of Equity Method Investments [Line Items]

Goodwill acquired

^[1]

$ 0

[1]	(1) See Note 5 for further discussion.

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

3 Months Ended

12 Months Ended

Dec. 31, 2019

Sep. 30, 2019

^[1]

Jun. 30, 2019

^[1]

Mar. 31, 2019

^[1]

Dec. 31, 2018

Sep. 30, 2018

^[1]

Jun. 30, 2018

^[1]

Mar. 31, 2018

^[1]

Dec. 31, 2019

Dec. 31, 2018

Dec. 31, 2017

Schedule of Equity Method Investments [Line Items]

$ 731

^[1]

$ 699

$ 735

$ 795

$ 950

^[1]

$ 928

$ 805

$ 748

$ 2,960

$ 3,431

$ 2,803

SESH

Ownership percentage

50.00%

SESH | Shared Operations Service Agreements | Equity Method Investee

Schedule of Equity Method Investments [Line Items]

SESH | Spectra Energy Partners, LP

$ 17

$ 18

$ 17

Schedule of Equity Method Investments [Line Items]

Ownership percentage

50.00%

Percentage distributions

50.00%

[1]	Text selection found with no content.

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

12 Months Ended

Dec. 31, 2019

Dec. 31, 2018

Dec. 31, 2017

Investment in Equity Method Affiliates:

Equity in earnings of equity method affiliate

$ 17

$ 26

$ 28

Distributions from unconsolidated affiliates

Return of investment

(8)

(7)

(5)

SESH

Investment in Equity Method Affiliates:

Equity in earnings of equity method affiliate

Distributions from equity method affiliate

^[1]

(25)

(33)

Distributions from unconsolidated affiliates

Return of investment

$ (8)

$ (7)

$ (5)

[1]	Distributions from equity method affiliate includes a $17 million, $26 million and $28 million return on investment and a $8 million, $7 million and $5 million return of investment for the years ended December 31, 2019, 2018 and 2017, respectively.

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

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

Dec. 31, 2019

Sep. 13, 2019

Jan. 29, 2019

Dec. 31, 2018

Debt Instrument, Unamortized Discount (Premium), Net

$ 4,405,000,000

$ 4,299,000,000

7,000,000

1,000,000

^[1]

Debt Issuance Costs, Gross

4,398,000,000

4,298,000,000

^[2]

23,000,000

20,000,000

Long-term Debt, Excluding Current Maturities

3,969,000,000

3,129,000,000

2019 Term Loan Agreement [Member]

Loans Payable | 2019 Term Loan Agreement [Member]

$ 1,000,000,000

Debt Instrument, Unamortized Discount (Premium), Net

800,000,000

^[1]

Senior Notes | 2019 Notes (Level 2)

800,000,000

Debt Instrument, Unamortized Discount (Premium), Net

500,000,000

^[1]

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

500,000,000

^[3]

500,000,000

Senior Notes | 2024 Notes (Level 2)

Debt Instrument, Unamortized Discount (Premium), Net

600,000,000

^[1]

Senior Notes | 2027 Notes (Level 2)

600,000,000

Debt Instrument, Unamortized Discount (Premium), Net

700,000,000

(2,000,000)

^[1]

Senior Notes | 2028 Notes (Level 2)

698,000,000

Debt Instrument, Unamortized Discount (Premium), Net

800,000,000

(5,000,000)

(6,000,000)

^[1]

Senior Notes | Senior Notes, Due in 2029 [Member]

795,000,000

794,000,000

Debt Instrument, Unamortized Discount (Premium), Net

550,000,000

(1,000,000)

^[1]

549,000,000

Less: Unamortized debt expense

$ 550,000,000

5,000,000

Senior Notes | 2044 Notes (Level 2)

Debt Instrument, Unamortized Discount (Premium), Net

550,000,000

^[1]

Senior Notes | Senior Notes, Due March 2020 at 6.25%

550,000,000

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

^[3]

251,000,000

Revolving Credit Facility

Debt Instrument, Unamortized Discount (Premium), Net

250,000,000

^[1]

Debt Issuance Costs, Line of Credit Arrangements, Net

250,000,000

4,000,000

6,000,000

Debt Instrument, Unamortized Discount (Premium), Net

^[1]

Short-term debt

^[4]

155,000,000

649,000,000

Subsidiary of Common Parent | Senior Notes | Senior Notes, Due March 2020 at 6.25%

Debt Instrument, Unamortized Discount (Premium), Net

250,000,000

1,000,000

7,000,000

^[1]

Premium (Discount) on long-term debt

251,000,000

$ 257,000,000

$ 1,000,000

[1]	Unamortized premium (discount) on long-term debt is amortized over the life of the respective debt.
[2]	As of December 31, 2019 and 2018, there was an additional $4 million and $6 million, respectively, of unamortized debt expense related to the Revolving Credit Facility included in Other assets, not included above. Unamortized debt expense is amortized over the life of the respective debt.
[3]	As of December 31, 2019, Current portion of long-term debt includes the $251 million outstanding balance of the EOIT Senior Notes due March 15, 2020. At December 31, 2018, Current portion of long-term debt included the $500 million outstanding balance of the
[4]	Short-term debt includes $155 million and $649 million of commercial paper outstanding as of December 31, 2019 and 2018, respectively.

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

Debt - Narrative (Details)

12 Months Ended

Sep. 16, 2019

USD ($)

Sep. 13, 2019

USD ($)

Apr. 06, 2018

USD ($)

time

Dec. 31, 2019

USD ($)

Jan. 29, 2019

USD ($)

Dec. 31, 2018

USD ($)

Commercial paper, authorized

$ 1,400,000,000

Debt Instrument, Unamortized Discount (Premium), Net

$ (7,000,000)

(1,000,000)

^[1]

Revolving Credit Facility

Debt Issuance Costs, Line of Credit Arrangements, Net

$ 4,000,000

6,000,000

Maximum borrowing capacity

$ 1,750,000,000

Letters of credit principal advances

Letters of credit outstanding amount

3,000,000

Unused capacity, commitment fee percentage

0.20%

Covenant, acceleration of indebtedness, threshold amount

100,000,000

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

100,000,000

Term loan facility, term

5 years

Line of Credit Facility, Increase in Maximum Borrowing Capacity

$ 875,000,000

Number of times option may be exercised | time

Additional term of loan

1 year

Debt Instrument, Unamortized Discount (Premium), Net

$ 0

^[1]

Revolving Credit Facility | LIBOR

Basis spread on variable rate percentage

1.50%

Revolving Credit Facility | Minimum

Threshold for debt covenant ratio

$ 25,000,000

Revolving Credit Facility | Maximum

Consolidated debt to EBITDA ratio

5.00

Threshold for debt covenant ratio for acquisitions

5.50

2019 Term Loan Agreement [Member]

Weighted average interest rate percentage

3.10%

Threshold for debt covenant ratio for acquisitions

5.50

Covenant, acceleration of indebtedness, threshold amount

$ 100,000,000

Debt Instrument, Repaid Amount

$ 1,000,000,000

$ 200,000,000

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

2019 Term Loan Agreement [Member] | Minimum | Eurodollar [Member]

1.25%

2019 Term Loan Agreement [Member] | Minimum | Base Rate [Member]

0.75%

2019 Term Loan Agreement [Member] | Maximum | Eurodollar [Member]

0.00%

2019 Term Loan Agreement [Member] | Maximum | Base Rate [Member]

1.50%

Senior Notes | Senior Notes, Due in 2029 [Member]

0.50%

$ 550,000,000

Proceeds from Issuance of Senior Long-term Debt

4.15%

$ 544,000,000

Unamortized debt expense

$ 5,000,000

Debt Instrument, Unamortized Discount (Premium), Net

4.31%

$ 1,000,000

$ 0

^[1]

Senior Notes | 2028 Notes (Level 2)

Debt Instrument, Unamortized Discount (Premium), Net

5.20%

$ 5,000,000

6,000,000

^[1]

Senior Notes | 2044 Notes (Level 2)

Debt Instrument, Unamortized Discount (Premium), Net

5.08%

$ 0

^[1]

Senior Notes | 2027 Notes (Level 2)

Debt Instrument, Unamortized Discount (Premium), Net

4.57%

$ 2,000,000

2,000,000

^[1]

Senior Notes | Senior Notes including 2019 Notes, 2024 Notes, and 2044 Notes

Senior Notes | 2024 Notes (Level 2)

Unamortized discount

7,000,000

Unamortized debt expense

$ 18,000,000

Debt Instrument, Unamortized Discount (Premium), Net

4.01%

$ 0

^[1]

Weighted average interest rate percentage

2.29%

Debt Instrument, Unamortized Discount (Premium), Net

^[2]

155,000,000

$ 649,000,000

$ 0

^[1]

Subsidiary of Common Parent | Senior Notes | Senior Notes, Due March 2020 at 6.25%

Premium (Discount) on long-term debt

3.84%

$ 1,000,000

Debt Instrument, Unamortized Discount (Premium), Net

$ (1,000,000)

$ (7,000,000)

^[1]

[1]	Unamortized premium (discount) on long-term debt is amortized over the life of the respective debt.
[2]	Short-term debt includes $155 million and $649 million of commercial paper outstanding as of December 31, 2019 and 2018, respectively.

Derivative Instruments and Hedging Activities - Quantitative Disclosures Related to Derivative Instruments (Details)
bbl in Thousands, MMBTU in Millions, $ in Millions

12 Months Ended

Dec. 31, 2019

USD ($)

MMBTU

bbl

Dec. 31, 2018

USD ($)

MMBTU

bbl

Designated as Hedging Instrument

Fair value hedges

$ 0.0

0.0

Designated cash flow hedges

3.0

0.0

0.0

Designated as Hedging Instrument | Interest rate swaps

Derivative, notional amount

300.0

0.0

Not Designated as Hedging Instrument

^[1]

49.0

33.0

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

^[1]

$ 38.0

$ 11.0

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

^[2]

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

^[2]

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

^[2]

Not Designated as Hedging Instrument | Financial swaptions - natural gas | Purchases

^[2]

Not Designated as Hedging Instrument | Financial swaptions - natural gas | Sales

^[2]

Not Designated as Hedging Instrument | Physical purchases/sales | Purchases

^[2]

Not Designated as Hedging Instrument | Physical purchases/sales | Sales

^[2]

Not Designated as Hedging Instrument | Financial futures/swaps- Crude oil (for condensate) | Purchases

^[2]

Not Designated as Hedging Instrument | Financial futures/swaps- Crude oil (for condensate) | Sales

^[3]

Not Designated as Hedging Instrument | Financial swaptions - crude oil | Purchases

^[3]

990

945

Not Designated as Hedging Instrument | Financial swaptions - crude oil | Sales

^[3]

Not Designated as Hedging Instrument | Financial futures/swaps- Natural gas liquids | Purchases

^[3]

225

Not Designated as Hedging Instrument | Financial futures/swaps- Natural gas liquids | Sales

^[4]

2,490

270

Not Designated as Hedging Instrument | Natural gas

^[4]

2,415

2,535

Percent of contract with durations of one year or less

86.60%

74.00%

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

13.40%

24.20%

Percent of contracts having durations of more than two years

1.80%

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

Percent of contract with durations of one year or less

72.80%

76.90%

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

27.20%

23.10%

Not Designated as Hedging Instrument | Volume of natural gas liquids

Percent of contract with durations of one year or less

72.20%

86.10%

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

27.80%

13.90%

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

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

$ 0.0

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

0.0

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

0.0

4.0

Other Noncurrent Assets | Not Designated as Hedging Instrument | Volume of natural gas liquids | Financial futures/swaps

0.0

2.0

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

11.0

2.0

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

2.0

0.0

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

1.0

2.0

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

0.0

Other Noncurrent Liabilities | Not Designated as Hedging Instrument | Volume of natural gas liquids | Financial futures/swaps

8.0

0.0

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

2.0

0.0

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

0.0

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

7.0

3.0

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

5.0

3.0

Other Current Assets | Not Designated as Hedging Instrument | Volume of natural gas liquids | Financial futures/swaps

1.0

9.0

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

25.0

10.0

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

1.0

0.0

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

5.0

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

0.0

Other Current Liabilities | Not Designated as Hedging Instrument | Volume of natural gas liquids | Financial futures/swaps

19.0

3.0

$ 3.0

$ 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, 2019 and 2018.
[2]	As of December 31, 2019, 86.6% of the natural gas contracts had durations of one year or less and 13.4% had durations of more than one year and less than two years. As of December 31, 2018, 74.0% of the natural gas contracts had durations of one year or less, 24.2% had durations of more than one year and less than two years and 1.8% had durations of more than two years.
[3]	As of December 31, 2019, 72.8% of the crude oil (for condensate) contracts had durations of one year or less and 27.2% had durations of more than one year and less than two years. As of December 31, 2018, 76.9% of the crude oil (for condensate) contracts had durations of one year or less
[4]	As of December 31, 2019, 72.2% of the natural gas liquids contracts had durations of one year or less and 27.8% had durations of more than one year and less than two years. As of December 31, 2018, 86.1% of the natural gas liquids contracts had durations of one year or less and 13.9% had durations of more than one year and less than two years.

Derivative Instruments and Hedging Activities - Balance Sheet Location (Details) - Not Designated as Hedging Instrument - USD ($)
$ in Millions

Dec. 31, 2019

Dec. 31, 2018

^[1]

$ 49

$ 33

Natural gas | Financial futures/swaps | Other Current Assets

^[1]

Natural gas | Financial futures/swaps | Other Current Liabilities

Natural gas | Financial futures/swaps | Other Noncurrent Assets

Natural gas | Financial futures/swaps | Other Noncurrent Liabilities

Natural gas | Physical purchases/sales | Other Current Assets

Natural gas | Physical purchases/sales | Other Current Liabilities

Natural gas | Physical purchases/sales | Other Noncurrent Assets

Natural gas | Physical purchases/sales | Other Noncurrent Liabilities

Crude oil (for condensate) | Financial futures/swaps | Other Current Assets

Crude oil (for condensate) | Financial futures/swaps | Other Current Liabilities

Crude oil (for condensate) | Financial futures/swaps | Other Noncurrent Assets

Crude oil (for condensate) | Financial futures/swaps | Other Noncurrent Liabilities

Natural gas liquids financial futures/swaps | Financial futures/swaps | Other Current Assets

Natural gas liquids financial futures/swaps | Financial futures/swaps | Other Current Liabilities

Natural gas liquids financial futures/swaps | Financial futures/swaps | Other Noncurrent Assets

Natural gas liquids financial futures/swaps | Financial futures/swaps | Other Noncurrent Liabilities

$ 2

$ 0

[1]	See Note 14 for a reconciliation of the Partnership’s total derivatives fair value to the Partnership’s Consolidated Balance Sheets as of December 31, 2019 and 2018.

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

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

Fair Value Measurements - Estimated Fair Value of Financial Instruments and Non-Financial Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis (Details) - USD ($)

Dec. 31, 2019

Dec. 31, 2018

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

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

^[1]

$ 155,000,000

$ 649,000,000

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

Lines of Credit, Fair Value Disclosure

^[2]

250,000,000

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

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

Lines of Credit, Fair Value Disclosure

^[2]

250,000,000

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

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

Loans Payable, Fair Value Disclosure

800,000,000

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

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

Loans Payable, Fair Value Disclosure

800,000,000

Senior Notes | Carrying Amount | 2028 Notes (Level 2)

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

Senior Notes | Carrying Amount | Senior Notes, Due in 2029 [Member]

795,000,000

794,000,000

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

Senior Notes | Carrying Amount | Significant other observable inputs (Level 2) | 2019 Notes (Level 2)

549,000,000

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

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

500,000,000

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

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

600,000,000

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

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

698,000,000

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

Senior Notes | Fair Value | 2028 Notes (Level 2)

550,000,000

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

Senior Notes | Fair Value | Senior Notes, Due in 2029 [Member]

811,000,000

764,000,000

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

Senior Notes | Fair Value | Significant other observable inputs (Level 2) | 2019 Notes (Level 2)

526,000,000

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

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

497,000,000

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

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

614,000,000

571,000,000

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

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

698,000,000

642,000,000

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

Subsidiary of Common Parent | Senior Notes | Carrying Amount | Significant other observable inputs (Level 2) | Senior Notes, Due March 2020 at 6.25%

506,000,000

445,000,000

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

Subsidiary of Common Parent | Senior Notes | Fair Value | Significant other observable inputs (Level 2) | Senior Notes, Due March 2020 at 6.25%

251,000,000

257,000,000

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

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

$ 252,000,000

$ 256,000,000

[1]	Short-term debt includes $155 million and $649 million of commercial paper outstanding as of December 31, 2019 and 2018, respectively.
[2]	Borrowing capacity is effectively reduced by our borrowings outstanding under the commercial paper program. $155 million and $649 million of commercial paper was outstanding as of December 31, 2019 and 2018, respectively.

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

Dec. 31, 2019

Dec. 31, 2018

Fuel reserves for under retained fuel due from shippers

$ 21,000,000

$ 11,000,000

Fuel reserves for over retained fuel due from shippers

8,000,000

5,000,000

Fair Value, Recurring | Commodity Contracts

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

Derivative asset, fair value, before netting adjustments

49,000,000

33,000,000

Derivative liability, fair value, before netting adjustments

38,000,000

11,000,000

Derivative asset, netting adjustment

(37,000,000)

(9,000,000)

Derivative liability, netting adjustment

(37,000,000)

(9,000,000)

Derivative Asset

12,000,000

24,000,000

Fair Value

1,000,000

2,000,000

Fair Value, Recurring | Gas Imbalances

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

Derivative asset, fair value, before netting adjustments

14,000,000

18,000,000

^[1],[2]

Derivative liability, fair value, before netting adjustments

11,000,000

17,000,000

^[2],[3]

Derivative asset, netting adjustment

^[1],[2]

Derivative liability, netting adjustment

^[2],[3]

Derivative Asset

14,000,000

18,000,000

^[1],[2]

Fair Value

11,000,000

17,000,000

^[2],[3]

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

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

5,000,000

4,000,000

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

31,000,000

9,000,000

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

^[1],[2]

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

^[2],[3]

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

44,000,000

29,000,000

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

7,000,000

2,000,000

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

14,000,000

18,000,000

^[1],[2]

Fair Value, Recurring | Unobservable inputs (Level 3) | Commodity Contracts

11,000,000

17,000,000

^[2],[3]

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

Fair Value, Recurring | Unobservable inputs (Level 3) | Gas Imbalances

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

^[1],[2]

$ 0

^[2],[3]

[1]	Gas imbalance assets exclude fuel reserves for under retained fuel due from shippers of $21 million and $11 million at December 31, 2019 and 2018, respectively, which fuel reserves are based on the value of natural gas at the time the imbalance was created and which are not subject to revaluation at fair market value.
[2]	The Partnership uses the market approach to fair value its gas imbalance assets and liabilities at individual, or where appropriate an average of, current market indices applicable to the Partnership’s operations, not to exceed net realizable value. There were no netting adjustments as of December 31, 2019 and 2018.
[3]	Gas imbalance liabilities exclude fuel reserves for over retained fuel due to shippers of $8 million and $5 million at December 31, 2019 and 2018, respectively, which fuel reserves are based on the value of natural gas at the time the imbalance was created and which are not subject to revaluation at fair market value.

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

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

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

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

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

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

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

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

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

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

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

Equity Based Compensation - Phantom Units (Details) - $ / shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Phantom units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Period from change in control	2 years
Units granted (in units)	695,486	546,708	392,338
Fair value of units granted (in dollars per share)	$ 14.26
Phantom units \| Certain Partnership Employees and Independent Directors of Enable GP \| Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value of units granted (in dollars per share)	8.95	$ 13.74	$ 15.44
Phantom units \| Certain Partnership Employees and Independent Directors of Enable GP \| Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value of units granted (in dollars per share)	$ 15.04	$ 17.00	$ 16.93
Other Awards \| Independent Directors Of Enable GP
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units granted (in units)	28,221	16,335	16,653
Fair value of units granted (in dollars per share)	$ 10.43	$ 14.94	$ 15.03

Equity Based Compensation - Equity Units Activity (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Performance units
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Units Outstanding at 12/31/2018 (in units)	2,109,835
Units granted (in units)	638,798	551,742	468,626
Vested (in units)	(1,174,597)
Forfeited (in units)	(180,707)
Units Outstanding at 12/31/2019 (in units)	1,393,329	2,109,835
Weighted Average Grant-Date Fair Value, Per Unit
Units Outstanding at 12/31/2018 (in dollars per share)	$ 14.33
Granted (in dollars per share)	19.95	$ 17.70	$ 19.27
Vested (in dollars per share)	11.09
Forfeited (in dollars per share)	18.96
Units Outstanding at 12/31/2019 (in dollars per share)	$ 19.04	$ 14.33
December 31, 2019	$ 14
Aggregate intrinsic value of units vested	34	$ 11	$ 5
Fair value of units vested	$ 13	7	10
Performance units \| Minimum
Weighted Average Grant-Date Fair Value, Per Unit
Payout percentage from target level of achievement of performance goal	0.00%
Performance units \| Maximum
Weighted Average Grant-Date Fair Value, Per Unit
Payout percentage from target level of achievement of performance goal	200.00%
Restricted units
Weighted Average Grant-Date Fair Value, Per Unit
Aggregate intrinsic value of units vested	$ 0	3	2
Fair value of units vested	$ 0	$ 4	$ 4
Phantom units
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Units Outstanding at 12/31/2018 (in units)	1,447,590
Units granted (in units)	695,486	546,708	392,338
Vested (in units)	(608,755)
Forfeited (in units)	(141,761)
Units Outstanding at 12/31/2019 (in units)	1,392,560	1,447,590
Weighted Average Grant-Date Fair Value, Per Unit
Units Outstanding at 12/31/2018 (in dollars per share)	$ 12.38
Granted (in dollars per share)	14.26
Vested (in dollars per share)	8.71
Forfeited (in dollars per share)	14.89
Units Outstanding at 12/31/2019 (in dollars per share)	$ 14.65	$ 12.38
December 31, 2019	$ 14
Aggregate intrinsic value of units vested	9	$ 1	$ 0
Fair value of units vested	$ 5	$ 0	$ 0
Annual Grant in 2016 \| Performance units
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Units granted (in units)	1,097,846
Annual Grant in 2016 \| Performance units \| Maximum
Weighted Average Grant-Date Fair Value, Per Unit
Payout percentage from target level of achievement of performance goal	200.00%
Officer Annual Grant in 2016 \| Performance units
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Units granted (in units)	26,986
Annual Grant in 2016 at 200% \| Performance units
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Vested (in units)	(2,195,692)
Officer Annual Grant in 2016 at 200% \| Performance units
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Vested (in units)	(53,972)
Awards Granted in 2017 \| Performance units
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Units granted (in units)	378,109
Annual Grant in 2017 at 0% \| Performance units \| Maximum
Weighted Average Grant-Date Fair Value, Per Unit
Payout percentage from target level of achievement of performance goal	0.00%
Certain Partnership Employees and Independent Directors of Enable GP \| Phantom units \| Minimum
Weighted Average Grant-Date Fair Value, Per Unit
Granted (in dollars per share)	$ 8.95	$ 13.74	$ 15.44
Certain Partnership Employees and Independent Directors of Enable GP \| Phantom units \| Maximum
Weighted Average Grant-Date Fair Value, Per Unit
Granted (in dollars per share)	$ 15.04	$ 17.00	$ 16.93

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

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

3 Months Ended

12 Months Ended

Dec. 31, 2019

USD ($)

Sep. 30, 2019

USD ($)

Jun. 30, 2019

USD ($)

Mar. 31, 2019

USD ($)

Dec. 31, 2018

USD ($)

Sep. 30, 2018

USD ($)

Jun. 30, 2018

USD ($)

Mar. 31, 2018

USD ($)

Dec. 31, 2019

USD ($)

segment

Dec. 31, 2018

USD ($)

Dec. 31, 2017

USD ($)

Number of reportable segments | segment

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

$ 731

^[1]

$ 699

^[1]

$ 735

^[1]

$ 795

^[1]

$ 950

^[1]

$ 928

^[1]

$ 805

^[1]

$ 748

^[1]

$ 2,960

$ 3,431

$ 2,803

321

263

317

378

484

516

444

375

1,279

1,819

1,381

Operation and maintenance, General and administrative

526

501

464

433

398

366

$ 175

$ 167

$ 165

212

$ 171

$ 126

$ 139

569

648

528

12,266

12,444

12,266

12,444

11,593

Operating Segments | Gathering and Processing

432

1,171

714

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

2,338

2,818

2,170

1,203

1,741

1,285

Operation and maintenance, General and administrative

320

312

289

308

263

232

380

464

327

9,739

9,874

9,739

9,874

9,079

Operating Segments | Transportation and Storage

314

981

601

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

1,038

1,162

1,146

491

628

604

Operation and maintenance, General and administrative

207

189

179

125

135

134

^[2]

189

183

202

5,886

5,805

5,886

5,805

5,616

118

190

113

Eliminations

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

(416)

(549)

(513)

(415)

(550)

(508)

Operation and maintenance, General and administrative

(1)

(4)

(1)

$ (3,359)

$ (3,235)

(3,359)

(3,235)

(3,102)

Product

Product | Operating Segments | Gathering and Processing

1,533

2,106

1,653

Product | Operating Segments | Transportation and Storage

1,449

2,016

1,538

487

625

621

Product | Eliminations

Natural Gas, Gathering, Transportation, Marketing and Processing

(403)

(535)

(506)

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

1,427

1,325

1,150

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

889

802

632

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

551

537

525

Total revenue | Customer Concentration Risk

(13)

$ (14)

$ (7)

$ 328

Effect of Fourth Quarter Events [Line Items]

11.00%

0.00%

[1]	Text selection found with no content.
[2]	Equity in earnings of equity method affiliate is included in Other Income (Expense) on the Consolidated Statements of Income and is not included in the table above. See Note 11 for discussion regarding ownership interest in SESH and related equity earnings included in the transportation and storage reportable segment for the years ended December 31, 2019, 2018 and 2017.

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

3 Months Ended

12 Months Ended

Dec. 31, 2019

Sep. 30, 2019

Jun. 30, 2019

Mar. 31, 2019

Dec. 31, 2018

Sep. 30, 2018

Jun. 30, 2018

Mar. 31, 2018

Dec. 31, 2019

Dec. 31, 2018

Dec. 31, 2017

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

$ 731

^[1]

$ 699

^[1]

$ 735

^[1]

$ 795

^[1]

$ 950

^[1]

$ 928

^[1]

$ 805

^[1]

$ 748

^[1]

$ 2,960

$ 3,431

$ 2,803

321

263

317

378

484

516

444

375

1,279

1,819

1,381

Operating income (loss)

175

167

165

212

171

126

139

569

648

528

Net income

133

124

123

175

139

114

400

523

437

Net income attributable to limited partners

132

124

122

174

138

114

396

521

436

Net income attributable to common units

$ 9

$ 123

$ 115

$ 113

$ 165

$ 129

$ 86

$ 105

360

485

400

Effect of Fourth Quarter Events [Line Items]

Common Units

Net income attributable to common units

$ 360

$ 485

$ 273

$ 0.02

$ 0.28

$ 0.26

$ 0.38

$ 0.30

$ 0.20

$ 0.24

$ 0.83

$ 1.12

$ 0.92

Effect of Fourth Quarter Events [Line Items]

$ 0.02

$ 0.28

$ 0.26

$ 0.38

$ 0.30

$ 0.20

$ 0.24

$ 0.82

$ 1.11

$ 0.92

Subordinated Units

Net income attributable to common units

$ 0

$ 127

$ 0

$ 0.93