EnLink Midstream Partners (ENLK) 10-Q 8 May 20 2020 Q1 Quarterly report Financial data

Cover Page

Cover Page - shares	3 Months Ended
	Mar. 31, 2020	Apr. 30, 2020
Cover [Abstract]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Mar. 31, 2020
Document Transition Report	false
Entity File Number	001-36340
Entity Registrant Name	ENLINK MIDSTREAM PARTNERS, LP
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	16-1616605
Entity Address, Address Line One	1722 Routh St., Suite 1300
Entity Address, City or Town	Dallas,
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	75201
City Area Code	214
Local Phone Number	953-9500
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Non-accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding (in shares)		144,358,720
Document Fiscal Period Focus	Q1
Document Fiscal Year Focus	2020
Amendment Flag	false
Entity Central Index Key	0001179060
Current Fiscal Year End Date	--12-31

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions	Mar. 31, 2020	Dec. 31, 2019
Current assets:
Cash and cash equivalents	$ 258.1	$ 77.4
Accounts receivable:
Trade, net of allowance for bad debt of $0.6 and $0.5, respectively	34.2	36.2
Accrued revenue and other	337.4	460.1
Related party	14.8	18.1
Fair value of derivative assets	75	12.9
Other current assets	17.8	56.9
Total current assets	737.3	661.6
Property and equipment, net of accumulated depreciation of $3,545.2 and $3,418.6, respectively	6,896.3	7,081.3
Intangible assets, net of accumulated amortization of $576.8 and $545.9, respectively	1,219	1,249.9
Investment in unconsolidated affiliates	43	43.1
Fair value of derivative assets	8.2	4.3
Other assets, net	93.3	94.4
Total assets	8,997.1	9,134.6
Current liabilities:
Accounts payable and drafts payable	51.2	70.6
Accounts payable to related party	0.5	1.1
Accrued gas, NGLs, condensate, and crude oil purchases	176.1	354.8
Fair value of derivative liabilities	77.9	14.4
Other current liabilities	205.2	201.7
Total current liabilities	510.9	642.6
Long-term debt, including $1,900.0 and $1,700.0 from related parties, respectively	4,954.8	4,764.3
Asset retirement obligations	15.7	15.5
Other long-term liabilities	87.7	90.8
Deferred tax liability	44.7	44.5
Fair value of derivative liabilities	13.4	6.8
Redeemable non-controlling interest	0	5.2
Partners’ equity:
Common unitholders (144,358,720 and 144,358,720 units issued and outstanding, respectively)	1,465.6	1,681.2
General partner interest (1,594,974 equivalent units outstanding)	215.2	216.6
Accumulated other comprehensive loss	(31.6)	(14.5)
Non-controlling interest	424.3	391.4
Total partners’ equity	3,369.9	3,564.9
Total liabilities and partners’ equity	8,997.1	9,134.6
Long term debt due from affiliates	1,900	1,700
Series B Preferred Unitholders
Partners’ equity:
Preferred unitholders	895.3	895.1
Series C Preferred Unitholders
Partners’ equity:
Preferred unitholders	$ 401.1	$ 395.1

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Mar. 31, 2020	Dec. 31, 2019
Assets [Abstract]
Allowance for bad debt	$ 0.6	$ 0.5
Accumulated depreciation	3,545.2	3,418.6
Accumulated amortization	576.8	545.9
Long term debt due from affiliates	$ 1,900	$ 1,700
Partners’ equity:
Common units issued (in shares)	144,358,720	144,358,720
Common units outstanding (in shares)	144,358,720	144,358,720
General partner interest, equivalent units outstanding (in shares)	1,594,974	1,594,974
Series B Preferred Unitholders
Partners’ equity:
Preferred units issued (in shares)	59,748,549	59,599,550
Preferred unit outstanding (in shares)	59,748,549	59,599,550
Series C Preferred Unitholders
Partners’ equity:
Preferred unit outstanding (in shares)	400,000	400,000

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Revenues:
Revenue from contracts with customers	$ 1,136.9	$ 1,777.4
Gain on derivative activity	19.2	1.8
Total revenues	1,156.1	1,779.2
Operating costs and expenses:
Cost of sales	755.3	1,363.4
Operating expenses	100.7	114.5
General and administrative	30.9	38.6
Gain on disposition of assets	(0.6)	0
Depreciation and amortization	162.8	152.1
Asset Impairment Charges	168.4	0
Total operating costs and expenses	1,217.5	1,668.6
Operating income (loss)	(61.4)	110.6
Other income (expense):
Interest expense, net of interest income	(55.6)	(49.3)
Gain on extinguishment of debt	5.3	0
Income from unconsolidated affiliates	1.7	5.3
Total other expense	(48.6)	(44)
Income (loss) before non-controlling interest and income taxes	(110)	66.6
Income tax expense	(0.5)	(0.9)
Net income (loss)	(110.5)	65.7
Net income attributable to non-controlling interest	3.4	2.9
Net income (loss) attributable to ENLK	(113.9)	62.8
Product sales
Revenues:
Revenue from contracts with customers	892.9	1,530.9
Midstream services
Revenues:
Revenue from contracts with customers	$ 244	$ 246.5

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income (Loss) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Statement of Comprehensive Income [Abstract]
Net income (loss)	$ (110.5)	$ 65.7
Loss on designated cash flow hedge	(17.1)	0
Comprehensive income (loss)	(127.6)	65.7
Comprehensive income attributable to non-controlling interest	3.4	2.9
Comprehensive income (loss) attributable to ENLK	$ (131)	$ 62.8

Consolidated Statements of Chan

Consolidated Statements of Changes in Partners' Equity - USD ($) shares in Millions, $ in Millions	Total	Non-Controlling Interest	Redeemable Noncontrolling Interest	Accumulated Other Comprehensive Loss	General Partner Interest	Common UnitsLimited Partner	Series B Preferred UnitsLimited Partner	Series C Preferred UnitsLimited Partner
Beginning balance at Dec. 31, 2018	$ 4,284.1	$ 309.8		$ (2.1)	$ 231.2	$ 2,460.8	$ 889.3	$ 395.1
Beginning balance (in shares) at Dec. 31, 2018					1.6	353.1	58.7	0.4
Increase (Decrease) in Partners' Capital
Conversion of restricted units for common units, net of units withheld for taxes	(2.8)					$ (2.8)
Conversion of restricted units for common units, net of units withheld for taxes (in shares)						0.5
Unit-based compensation	13.5				$ 12.1	$ 1.4
Distributions	(177.8)	(6.3)			(15.6)	(139.4)	$ (16.5)
Distributions (in shares)							0.5
Contributions from non-controlling interests	15.7	15.7
Fair value adjustment related to redeemable non-controlling interest	2.1		$ (2.1)			$ 2.1
Issuance of common units (in shares)						55.8
Loss on designated cash flow hedge	0
Conversion of ENLK common units into ENLC units (in shares)						(265)
Net income (loss)	65.7	2.9			(9.3)	$ 47.5	$ 18.6	$ 6
Ending balance at Mar. 31, 2019	4,200.8	322.1		(2.1)	$ 218.4	$ 2,369.9	$ 891.4	$ 401.1
Ending balance (in shares) at Mar. 31, 2019					1.6	144.4	59.2	0.4
Beginning balance at Dec. 31, 2018			9.3
Increase (Decrease) in Temporary Equity
Redemption of non-controlling interest	0
Fair value adjustment related to redeemable non-controlling interest	2.1		(2.1)			$ 2.1
Ending balance at Mar. 31, 2019			7.2
Beginning balance at Dec. 31, 2019	3,564.9	391.4		(14.5)	$ 216.6	$ 1,681.2	$ 895.1	$ 395.1
Beginning balance (in shares) at Dec. 31, 2019					1.6	144.4	59.6	0.4
Increase (Decrease) in Partners' Capital
Unit-based compensation	12.3				$ 12.3
Distributions	(117.7)	(7.6)	(0.3)		0	$ (93.3)	$ (16.8)
Distributions (in shares)							0.1
Contributions from non-controlling interests	37.1	37.1
Fair value adjustment related to redeemable non-controlling interest	0.9		(0.9)
Loss on designated cash flow hedge	(17.1)			(17.1)
Net income (loss)	(110.5)	3.4			(13.7)	(123.2)	$ 17	$ 6
Ending balance at Mar. 31, 2020	3,369.9	$ 424.3		$ (31.6)	$ 215.2	$ 1,465.6	$ 895.3	$ 401.1
Ending balance (in shares) at Mar. 31, 2020					1.6	144.4	59.7	0.4
Beginning balance at Dec. 31, 2019			5.2
Increase (Decrease) in Temporary Equity
Redemption of non-controlling interest	4		(4)
Fair value adjustment related to redeemable non-controlling interest	$ 0.9		(0.9)
Ending balance at Mar. 31, 2020			$ 0

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Cash flows from operating activities:
Net income (loss)	$ (110.5)	$ 65.7
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Asset Impairment Charges	168.4	0
Depreciation and amortization	162.8	152.1
Non-cash unit-based compensation	8.8	10.9
Gain on derivatives recognized in net income (loss)	(19.2)	(1.8)
Cash settlements on derivatives	1.2	4.6
Gain on extinguishment of debt	(5.3)	0
Amortization of debt issue costs, net discount (premium) of notes	1	1.8
Distribution of earnings from unconsolidated affiliates	1.6	2.2
Income from unconsolidated affiliates	(1.7)	(5.3)
Other operating activities	(1)	(0.4)
Changes in assets and liabilities:
Accounts receivable, accrued revenue, and other	128	76.2
Natural gas and NGLs inventory, prepaid expenses, and other	44.8	3.6
Accounts payable, accrued product purchases, and other accrued liabilities	(200.9)	(51.5)
Net cash provided by operating activities	178	258.1
Cash flows from investing activities:
Additions to property and equipment	(112)	(241.5)
Other investing activities	(3.5)	0.5
Net cash used in investing activities	(115.5)	(241)
Cash flows from financing activities:
Proceeds from borrowings	440	1,368.4
Payments on borrowings	(241)	(1,320)
Debt financing costs	0	(5.6)
Distributions to non-controlling interests	(7.9)	(6.3)
Contributions by non-controlling interests	37.1	15.7
Distributions to common unitholders and to general partner	(93.3)	(155)
Other financing activities	0.1	2.8
Net cash provided by (used in) financing activities	118.2	(116.5)
Net increase (decrease) in cash and cash equivalents	180.7	(99.4)
Cash and cash equivalents, beginning of period	77.4	99.5
Cash and cash equivalents, end of period	258.1	0.1
Supplemental disclosures of cash flow information:
Cash paid for interest	22.3	13.9
Cash paid for income taxes	0.2	0
Non-cash investing activities:
Non-cash accrual of property and equipment	2.8	9.5
Non-cash financing activities:
Redemption of non-controlling interest	(4)	0
Series B Preferred Unitholders
Cash flows from financing activities:
Distributions to Series B Preferred Units	$ (16.8)	$ (16.5)

General

General	3 Months Ended
	Mar. 31, 2020
Organization, Consolidation and Presentation of Financial Statements [Abstract]
General	(1) General In this report, the term “Partnership,” as well as the terms “ENLK,” “our,” “we,” “us,” and “its” are sometimes used as abbreviated references to EnLink Midstream Partners, LP itself or EnLink Midstream Partners, LP together with its consolidated subsidiaries. Please read the notes to the consolidated financial statements in conjunction with the Definitions page set forth in this report prior to Part I—Financial Information. a. Organization of Business ENLK is a Delaware limited partnership formed in 2002. Our business activities are conducted through the Operating Partnership and the subsidiaries of the Operating Partnership. EnLink Midstream GP, LLC, a Delaware limited liability company, is our general partner. Our general partner manages our operations and activities. Our general partner is a direct, wholly-owned subsidiary of ENLC. ENLC’s units are traded on the New York Stock Exchange under the symbol “ENLC.” ENLC’s managing member is a wholly-owned subsidiary of GIP. b. Nature of Business We primarily focus on providing midstream energy services, including: • gathering, compressing, treating, processing, transporting, storing, and selling natural gas; • fractionating, transporting, storing, and selling NGLs; and • gathering, transporting, stabilizing, storing, trans-loading, and selling crude oil and condensate, in addition to brine disposal services. Our natural gas business includes connecting the wells of producers in our market areas to our gathering systems. Our gathering systems consist of networks of pipelines that collect natural gas from points at or near producing wells and transport it to our processing plants or to larger pipelines for further transmission. We operate processing plants that remove NGLs from the natural gas stream that is transported to the processing plants by our own gathering systems or by third-party pipelines. In conjunction with our gathering and processing business, we may purchase natural gas and NGLs from producers and other supply sources and sell that natural gas or NGLs to utilities, industrial consumers, marketers, and pipelines. Our transmission pipelines receive natural gas from our gathering systems and from third-party gathering and transmission systems and deliver natural gas to industrial end-users, utilities, and other pipelines. Our fractionators separate NGLs into separate purity products, including ethane, propane, iso-butane, normal butane, and natural gasoline. Our fractionators receive NGLs primarily through our transmission lines that transport NGLs from East Texas and from our South Louisiana processing plants. Our fractionators also have the capability to receive NGLs by truck or rail terminals. We also have agreements pursuant to which third parties transport NGLs from our West Texas and Central Oklahoma operations to our NGL transmission lines that then transport the NGLs to our fractionators. In addition, we have NGL storage capacity to provide storage for customers. Our crude oil and condensate business includes the gathering and transmission of crude oil and condensate via pipelines, barges, rail, and trucks, in addition to condensate stabilization and brine disposal. We also purchase crude oil and condensate from producers and other supply sources and sell that crude oil and condensate through our terminal facilities to various markets. Across our businesses, we primarily earn our fees through various fee-based contractual arrangements, which include stated fee-only contract arrangements or arrangements with fee-based components where we purchase and resell commodities in connection with providing the related service and earn a net margin as our fee. We earn our net margin under our purchase and resell contract arrangements primarily as a result of stated service-related fees that are deducted from the price of the

Significant Accounting Policies

Significant Accounting Policies	3 Months Ended
	Mar. 31, 2020
Accounting Policies [Abstract]
Significant Accounting Policies	(2) Significant Accounting Policies a. Basis of Presentation The accompanying consolidated financial statements have been prepared in accordance with the instructions to Form 10-Q, are unaudited, and do not include all the information and disclosures required by GAAP for complete financial statements. All adjustments that, in the opinion of management, are necessary for a fair presentation of the results of operations for the interim periods have been made and are of a recurring nature unless otherwise disclosed herein. The results of operations for such interim periods are not necessarily indicative of results of operations for a full year. These consolidated financial statements should be read in conjunction with the consolidated financial statements and accompanying notes included in our Annual Report on Form 10-K for the year ended December 31, 2019. Certain reclassifications were made to the financial statements for the prior period to conform to current period presentation. The effect of these reclassifications had no impact on previously reported partners’ equity or net income (loss). All significant intercompany balances and transactions have been eliminated in consolidation. b. Revenue Recognition Minimum Volume Commitments and Firm Transportation Contracts Certain of our gathering and processing agreements provide for quarterly or annual MVCs. Under these agreements, our customers or suppliers agree to ship and/or process a minimum volume of product on our systems over an agreed time period. If a customer or supplier under such an agreement fails to meet its MVC for a specified period, the customer is obligated to pay a contractually-determined fee based upon the shortfall between actual product volumes and the MVC for that period. Some of these agreements also contain make-up right provisions that allow a customer or supplier to utilize gathering or processing fees in excess of the MVC in subsequent periods to offset shortfall amounts in previous periods. We record revenue under MVC contracts during periods of shortfall when it is known that the customer cannot, or will not, make up the deficiency in subsequent periods. Deficiency fee revenue is included in midstream services revenue. For our firm transportation contracts, we transport commodities owned by others for a stated monthly fee for a specified monthly quantity with an additional fee based on actual volumes. We include transportation fees from firm transportation contracts in our midstream services revenue. The following table summarizes the contractually committed fees that we expect to recognize in our consolidated statements of operations, in either revenue or reductions to cost of sales, from MVC and firm transportation contractual provisions. All amounts in the table below are determined using the contractually-stated MVC or firm transportation volumes specified for each period multiplied by the relevant deficiency or reservation fee. Actual amounts could differ due to the timing of revenue recognition or reductions to cost of sales resulting from make-up right provisions included in our agreements, as well as due to nonpayment or nonperformance by our customers. These fees do not represent the shortfall amounts we expect to collect under our MVC contracts, as we generally do not expect volume shortfalls to equal the full amount of the contractual MVCs during these periods. For example, for the three months ended March 31, 2020, we had contractual commitments of $41.8 million under our MVC contracts and recorded $11.8 million of revenue due to volume shortfalls. MVC and Firm Transportation Commitments (in millions) (1) 2020 (remaining) $ 199.5 2021 116.7 2022 103.3 2023 94.8 2024 81.3 Thereafter 158.2 Total $ 753.8 ____________________________ (1) Amounts do not represent expected shortfall under these commitments. c. Property and Equipment Impairment Review. In accordance with ASC 360 , Property, Plant, and Equipment , we evaluate long-lived assets of identifiable business activities for potential impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable. The carrying amount of a long-lived asset is not recoverable when it exceeds the undiscounted sum of the future cash flows expected to result from the use and eventual disposition of the asset. Estimates of expected future cash flows represent management’s best estimate based on reasonable and supportable assumptions. When the carrying amount of a long-lived asset is not recoverable, an impairment is recognized equal to the excess of the asset’s carrying value over its fair value, which is based on inputs that are not observable in the market, and thus represent Level 3 inputs. For the three months ended March 31, 2020, we recognized a $168.0 million impairment on property and equipment related to a portion of our Louisiana reporting segment because the carrying amounts were not recoverable based on our expected future cash flows. Additionally, we recorded a $0.4 million impairment related to certain cancelled projects. d. Redeemable Non-Controlling Interest Non-controlling interests that contain an option for the non-controlling interest holder to require us to purchase such interests for cash are considered to be redeemable non-controlling interests because the redemption feature is not deemed to be a freestanding financial instrument and because the redemption is not solely within our control. Redeemable non-controlling interests are not considered to be a component of partners’ equity and are reported as temporary equity in the mezzanine section on the consolidated balance sheets. The amount recorded as a redeemable non-controlling interest at each balance sheet date is the greater of the redemption value and the carrying value of the redeemable non-controlling interest (the initial carrying value increased or decreased for the non-controlling interest holder’s share of net income or loss and distributions). When the redemption feature is exercised the redemption value of the non-controlling interest is reclassified to a liability on the consolidated balance sheets. During the first quarter of 2020, a non-controlling interest holder in one of our non-wholly owned subsidiaries exercised its option to require us to purchase its remaining interest. We have recorded an estimated liability of $4.0 million related to the redemption of the non-controlling interest on the consolidated balance sheet as of March 31, 2020, but we have not yet agreed to a redemption value with the non-controlling interest holder. e. Adopted Accounting Standards Effective January 1, 2020, we adopted ASU 2018-15, Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract (Topic 350): Internal-Use Software. ASU 2018-15 aligns the accounting for costs incurred to implement a cloud computing arrangement that is a service arrangement with the guidance on capitalizing costs associated with developing or obtaining internal-use software. Specifically, the ASU amends ASC 350-40 to include in its scope implementation costs of a cloud computing arrangement that is a service contract and clarifies that a customer should apply ASC 350-40 to determine which implementation costs should be capitalized in a cloud computing arrangement that is considered a service contract. For the three months ended March 31, 2020, we did not capitalize any cloud computing costs. However, to the extent future costs incurred in a cloud computing arrangement are capitalizable, the corresponding amortization will be included in “Operating expenses” or “General and administrative” in the consolidated statements of operations, rather than “Depreciation and amortization.” Effective January 1, 2020, we adopted ASU 2016-13, Financial Instruments—Credit Losses (Topic 326). The updates in ASU 2016-13 provide financial statement users with more information about the expected credit losses on financial instruments and other commitments to extend credit held by a reporting entity at each reporting date. Following the adoption of ASU 2016-13, we record an allowance for doubtful accounts based on our expectation of future losses. Because our receivables are typically paid within 30 days, and because we closely monitor the credit-worthiness of all our counterparties, adopting ASU 2016-13 did not have a material effect on our financial statements. However, in the event we foresee further or sustained deterioration in the current market environment, or other factors indicating an increased likelihood of defaults by our customers, we may recognize additional losses.

Intangible Assets

Intangible Assets	3 Months Ended
	Mar. 31, 2020
Goodwill and Intangible Assets Disclosure [Abstract]
Intangible Assets	(3) Intangible Assets The following table represents our change in carrying value of intangible assets (in millions): Gross Carrying Amount Accumulated Amortization Net Carrying Amount Three Months Ended March 31, 2020 Customer relationships, beginning of period $ 1,795.8 $ (545.9) $ 1,249.9 Amortization expense — (30.9) (30.9) Customer relationships, end of period $ 1,795.8 $ (576.8) $ 1,219.0 Intangible assets associated with customer relationships are amortized on a straight-line basis over the expected period of benefits of the customer relationships, which range from 5 to 20 years. The weighted average amortization period is 15.0 years. Amortization expense was $30.9 million for each of the three months ended March 31, 2020 and 2019, respectively. The following table summarizes our estimated aggregate amortization expense for the next five years and thereafter (in millions): 2020 (remaining) $ 92.8 2021 123.7 2022 123.7 2023 123.6 2024 123.4 Thereafter 631.8 Total $ 1,219.0

Related Party Transactions

Related Party Transactions	3 Months Ended
	Mar. 31, 2020
Related Party Transactions [Abstract]
Related Party Transactions	(4) Related Party Transactions a. Transactions with ENLC Related Party Debt. Related party debt includes borrowings under the Consolidated Credit Facility, the Term Loan, and ENLC’s 5.375% senior unsecured notes to fund the operations and growth capital expenditures of ENLK through a related party arrangement with ENLC. See “Note 6—Long-Term Debt” for more information on this arrangement. We had accounts receivable balances related to transactions with ENLC of $14.8 million and $18.1 million as of March 31, 2020 and December 31, 2019, respectively. b. Transactions with Cedar Cove JV For the three months ended March 31, 2020 and 2019, we recorded cost of sales of $2.9 million and $8.1 million, respectively, related to our purchase of residue gas and NGLs from the Cedar Cove JV subsequent to processing at its Central Oklahoma processing facilities. Additionally, we had accounts payable balances related to transactions with the Cedar Cove JV of $0.5 million and $1.1 million at March 31, 2020 and December 31, 2019, respectively.

Leases

Leases	3 Months Ended
	Mar. 31, 2020
Leases [Abstract]
Leases	(5) Leases Lease balances are recorded on the consolidated balance sheets as follows (in millions): March 31, 2020 December 31, 2019 Operating leases: Other assets, net $ 74.5 $ 80.4 Other current liabilities $ 17.6 $ 21.1 Other long-term liabilities $ 78.8 $ 81.9 Other lease information Weighted-average remaining lease term—Operating leases 11.0 years 10.6 years Weighted-average discount rate—Operating leases 5.2 % 5.1 % Certain of our lease agreements have options to extend the lease for a certain period after the expiration of the initial term. We recognize the cost of a lease over the expected total term of the lease, including optional renewal periods that we can reasonably expect to exercise. We do not have material obligations whereby we guarantee a residual value on assets we lease, nor do our lease agreements impose restrictions or covenants that could affect our ability to make distributions. Lease expense is recognized on the consolidated statements of operations as “Operating expenses” and “General and administrative” depending on the nature of the leased asset. The components of total lease expense are as follows (in millions): Three Months Ended 2020 2019 Finance lease expense: Amortization of right-of-use asset $ — $ 0.7 Operating lease expense: Long-term operating lease expense 6.4 6.3 Short-term lease expense 5.5 6.9 Variable lease expense 2.8 1.6 Total lease expense $ 14.7 $ 15.5 Other information about our leases is presented below (in millions): Three Months Ended 2020 2019 Supplemental cash flow information: Cash payments for finance leases included in cash flows from financing activities $ — $ 0.4 Cash payments for operating leases included in cash flows from operating activities $ 7.2 $ 7.0 Right-of-use assets obtained in exchange for operating lease liabilities $ 4.8 $ 80.6 The following table summarizes the maturity of our lease liability as of March 31, 2020 (in millions): Total 2020 (remaining) 2021 2022 2023 2024 Thereafter Undiscounted operating lease liability $ 133.9 $ 16.3 $ 17.0 $ 12.2 $ 10.2 $ 9.5 $ 68.7 Reduction due to present value (37.5) (3.5) (4.0) (3.6) (3.2) (2.8) (20.4) Operating lease liability $ 96.4 $ 12.8 $ 13.0 $ 8.6 $ 7.0 $ 6.7 $ 48.3
Leases	(5) Leases Lease balances are recorded on the consolidated balance sheets as follows (in millions): March 31, 2020 December 31, 2019 Operating leases: Other assets, net $ 74.5 $ 80.4 Other current liabilities $ 17.6 $ 21.1 Other long-term liabilities $ 78.8 $ 81.9 Other lease information Weighted-average remaining lease term—Operating leases 11.0 years 10.6 years Weighted-average discount rate—Operating leases 5.2 % 5.1 % Certain of our lease agreements have options to extend the lease for a certain period after the expiration of the initial term. We recognize the cost of a lease over the expected total term of the lease, including optional renewal periods that we can reasonably expect to exercise. We do not have material obligations whereby we guarantee a residual value on assets we lease, nor do our lease agreements impose restrictions or covenants that could affect our ability to make distributions. Lease expense is recognized on the consolidated statements of operations as “Operating expenses” and “General and administrative” depending on the nature of the leased asset. The components of total lease expense are as follows (in millions): Three Months Ended 2020 2019 Finance lease expense: Amortization of right-of-use asset $ — $ 0.7 Operating lease expense: Long-term operating lease expense 6.4 6.3 Short-term lease expense 5.5 6.9 Variable lease expense 2.8 1.6 Total lease expense $ 14.7 $ 15.5 Other information about our leases is presented below (in millions): Three Months Ended 2020 2019 Supplemental cash flow information: Cash payments for finance leases included in cash flows from financing activities $ — $ 0.4 Cash payments for operating leases included in cash flows from operating activities $ 7.2 $ 7.0 Right-of-use assets obtained in exchange for operating lease liabilities $ 4.8 $ 80.6 The following table summarizes the maturity of our lease liability as of March 31, 2020 (in millions): Total 2020 (remaining) 2021 2022 2023 2024 Thereafter Undiscounted operating lease liability $ 133.9 $ 16.3 $ 17.0 $ 12.2 $ 10.2 $ 9.5 $ 68.7 Reduction due to present value (37.5) (3.5) (4.0) (3.6) (3.2) (2.8) (20.4) Operating lease liability $ 96.4 $ 12.8 $ 13.0 $ 8.6 $ 7.0 $ 6.7 $ 48.3

Long-Term Debt

Long-Term Debt	3 Months Ended
	Mar. 31, 2020
Debt Disclosure [Abstract]
Long-Term Debt	(6) Long-Term Debt As of March 31, 2020 and December 31, 2019, long-term debt consisted of the following (in millions): March 31, 2020 December 31, 2019 Outstanding Principal Premium (Discount) Long-Term Debt Outstanding Principal Premium (Discount) Long-Term Debt Related party debt $ 1,900.0 $ — $ 1,900.0 $ 1,700.0 $ — $ 1,700.0 4.40% Senior unsecured notes due 2024 545.0 1.4 546.4 550.0 1.5 551.5 4.15% Senior unsecured notes due 2025 747.5 (0.7) 746.8 750.0 (0.7) 749.3 4.85% Senior unsecured notes due 2026 497.0 (0.4) 496.6 500.0 (0.5) 499.5 5.60% Senior unsecured notes due 2044 350.0 (0.2) 349.8 350.0 (0.2) 349.8 5.05% Senior unsecured notes due 2045 450.0 (5.9) 444.1 450.0 (5.9) 444.1 5.45% Senior unsecured notes due 2047 500.0 (0.1) 499.9 500.0 (0.1) 499.9 Debt classified as long-term, including current maturities of long-term debt $ 4,989.5 $ (5.9) 4,983.6 $ 4,800.0 $ (5.9) 4,794.1 Debt issuance cost (1) (28.8) (29.8) Long-term debt, net of unamortized issuance cost $ 4,954.8 $ 4,764.3 ____________________________ (1) Net of amortization of $11.9 million and $10.9 million at March 31, 2020 and December 31, 2019, respectively. Related Party Debt Related party debt includes borrowings under the Consolidated Credit Facility, the Term Loan, and ENLC’s 5.375% senior unsecured notes to fund the operations and growth capital expenditures of ENLK through a related party arrangement with ENLC. Interest charged to ENLK for borrowings made through the related party arrangement will be the same as interest charged to ENLC on borrowings under the Consolidated Credit Facility, the Term Loan, and ENLC’s 5.375% senior unsecured notes. As of March 31, 2020 and December 31, 2019, $1.9 billion and $1.7 billion, respectively, of related party debt is included in “Long-term debt” in the consolidated balance sheet related to these borrowings. The indebtedness under ENLC's 5.375% senior unsecured notes due June 1, 2029, the Consolidated Credit Facility, and the Term Loan was incurred by ENLC but is guaranteed by ENLK. Therefore, the covenants in the agreements governing such indebtedness described below affect balances owed by ENLK on the related party debt. Consolidated Credit Facility The Consolidated Credit Facility permits ENLC to borrow up to $1.75 billion on a revolving credit basis and includes a $500.0 million letter of credit subfacility. The Consolidated Credit Facility became available for borrowings and letters of credit upon closing of the Merger. In addition, ENLK became a guarantor under the Consolidated Credit Facility upon the closing of the Merger. In the event that ENLC defaults on the Consolidated Credit Facility, ENLK will be liable for the entire outstanding balance ($550.0 million as of March 31, 2020), and 105% of the outstanding letters of credit under the Consolidated Credit Facility ($18.8 million as of March 31, 2020). The obligations under the Consolidated Credit Facility are unsecured. The Consolidated Credit Facility includes provisions for additional financial institutions to become lenders, or for any existing lender to increase its revolving commitment thereunder, subject to an aggregate maximum of $2.25 billion for all commitments under the Consolidated Credit Facility. The Consolidated Credit Facility will mature on January 25, 2024, unless ENLC requests, and the requisite lenders agree, to extend it pursuant to its terms. The Consolidated Credit Facility contains certain financial, operational, and legal covenants. The financial covenants are tested on a quarterly basis, based on the rolling four-quarter period that ends on the last day of each fiscal quarter. The financial covenants include (i) maintaining a ratio of consolidated EBITDA (as defined in the Consolidated Credit Facility, which term includes projected EBITDA from certain capital expansion projects) to consolidated interest charges of no less than 2.5 to 1.0 at all times prior to the occurrence of an investment grade event (as defined in the Consolidated Credit Facility) and (ii) maintaining a ratio of consolidated indebtedness to consolidated EBITDA of no more than 5.0 to 1.0. If ENLC consummates one or more acquisitions in which the aggregate purchase price is $50.0 million or more, ENLC can elect to increase the maximum allowed ratio of consolidated indebtedness to consolidated EBITDA to 5.5 to 1.0 for the quarter in which the acquisition occurs and the three subsequent quarters. Borrowings under the Consolidated Credit Facility bear interest at ENLC’s option at the Eurodollar Rate (LIBOR) plus an applicable margin (ranging from 1.125% to 2.00%) or the Base Rate (the highest of the Federal Funds Rate plus 0.50%, the 30-day Eurodollar Rate plus 1.0% or the administrative agent’s prime rate) plus an applicable margin (ranging from 0.125% to 1.00%). The applicable margins vary depending on ENLC’s debt rating. Upon breach by ENLC of certain covenants governing the Consolidated Credit Facility, amounts outstanding under the Consolidated Credit Facility, if any, may become due and payable immediately. At March 31, 2020, ENLC was in compliance with and expects to be in compliance with the financial covenants of the Consolidated Credit Facility for at least the next twelve months. Accordingly, we do not expect to make payments related to our guarantee of the $550.0 million outstanding on the Consolidated Credit Facility. Term Loan On December 11, 2018, ENLK entered into the Term Loan with Bank of America, N.A., as Administrative Agent, Bank of Montreal and Royal Bank of Canada, as Co-Syndication Agents, Citibank, N.A. and Wells Fargo Bank, National Association, as Co-Documentation Agents, and the lenders party thereto. Upon the closing of the Merger, ENLC assumed ENLK’s obligations under the Term Loan, and ENLK became a guarantor of the Term Loan. In the event that ENLC defaults on the Term Loan and the outstanding balance becomes due, ENLK will be liable for any amount owed on the Term Loan not paid by ENLC. The outstanding balance of the Term Loan was $850.0 million as of March 31, 2020. The obligations under the Term Loan are unsecured. The Term Loan will mature on December 10, 2021. The Term Loan contains certain financial, operational, and legal covenants. The financial covenants are tested on a quarterly basis, based on the rolling four-quarter period that ends on the last day of each fiscal quarter. The financial covenants include (i) maintaining a ratio of consolidated EBITDA (as defined in the Term Loan, which term includes projected EBITDA from certain capital expansion projects) to consolidated interest charges of no less than 2.5 to 1.0 at all times prior to the occurrence of an investment grade event (as defined in the Term Loan) and (ii) maintaining a ratio of consolidated indebtedness to consolidated EBITDA of no more than 5.0 to 1.0. If ENLC consummates one or more acquisitions in which the aggregate purchase price is $50.0 million or more, ENLC can elect to increase the maximum allowed ratio of consolidated indebtedness to consolidated EBITDA to 5.5 to 1.0 for the quarter in which the acquisition occurs and the three subsequent quarters. Borrowings under the Term Loan bear interest at ENLC’s option at LIBOR plus an applicable margin (ranging from 1.0% to 1.75%) or the Base Rate (the highest of the Federal Funds Rate plus 0.5%, the 30-day Eurodollar Rate plus 1.0% or the administrative agent’s prime rate) plus an applicable margin (ranging from 0.0% to 0.75%). The applicable margins vary depending on ENLC’s debt rating. Upon breach by ENLC of certain covenants included in the Term Loan, amounts outstanding under the Term Loan may become due and payable immediately. At March 31, 2020, ENLC was in compliance with and expects to be in compliance with the financial covenants of the Term Loan for at least the next twelve months. Accordingly, we do not expect to make payments related to our guarantee of the $850.0 million outstanding on the Term Loan. Senior Unsecured Notes Repurchases For the three months ended March 31, 2020, we made aggregate payments of $5.2 million to repurchase $10.5 million of the 2024, 2025, and 2026 Notes in open market transactions, which resulted in a $5.3 million gain on extinguishment of debt.

Partners' Capital

Partners' Capital	3 Months Ended
	Mar. 31, 2020
Partners' Capital Notes [Abstract]
Partners' Capital	(7) Partners’ Capital a. Series B Preferred Units Income is allocated to the Series B Preferred Units in an amount equal to the quarterly distribution with respect to the period earned. A summary of the distribution activity relating to the Series B Preferred Units during the three months ended March 31, 2020 and 2019 is provided below: Declaration period Distribution paid as additional Series B Preferred Units Cash Distribution (in millions) Date paid/payable 2020 Fourth Quarter of 2019 148,999 $ 16.8 February 13, 2020 First Quarter of 2020 149,371 $ 16.8 May 13, 2020 2019 Fourth Quarter of 2018 425,785 $ 16.5 February 13, 2019 First Quarter of 2019 147,887 $ 16.7 May 14, 2019 b. Series C Preferred Units There was no distribution activity relating to the Series C Preferred Units during the three months ended March 31, 2020 and 2019. c. Common Unit Distributions On February 13, 2019, we paid $0.39 per ENLK common unit related to the fourth quarter of 2018. Subsequent to the closing of the Merger, we no longer have publicly held common units. ENLC owns all of our outstanding common units and we make quarterly distributions to ENLC related to its ownership of our common units. For the three months ended March 31, 2020, we distributed $93.3 million to ENLC related to its ownership of our common units. d. Allocation of ENLK Income The net income (loss) allocated to our general partner is as follows (in millions): Three Months Ended 2020 2019 Unit-based compensation attributable to ENLC’s restricted and performance units $ (12.3) $ (12.1) General partner share of net income (loss) (1.4) 0.4 General partner interest in EOGP acquisition — 2.4 General partner interest in net income (loss) $ (13.7) $ (9.3)

Investment in Unconsolidated Af

Investment in Unconsolidated Affiliates	3 Months Ended
	Mar. 31, 2020
Equity Method Investments and Joint Ventures [Abstract]
Investment in Unconsolidated Affiliates	(8) Investment in Unconsolidated Affiliates As of March 31, 2020, our unconsolidated investments consisted of a 38.75% ownership in GCF and a 30% ownership in the Cedar Cove JV. The following table shows the activity related to our investment in unconsolidated affiliates for the periods indicated (in millions): Three Months Ended 2020 2019 GCF Distributions $ 1.6 $ 2.2 Equity in income $ 1.8 $ 5.7 Cedar Cove JV Distributions $ 0.2 $ 0.3 Equity in loss $ (0.1) $ (0.4) Total Distributions $ 1.8 $ 2.5 Equity in income $ 1.7 $ 5.3 The following table shows the balances related to our investment in unconsolidated affiliates as of March 31, 2020 and December 31, 2019 (in millions): March 31, 2020 December 31, 2019 GCF $ 39.4 $ 39.2 Cedar Cove JV 3.6 3.9 Total investment in unconsolidated affiliates $ 43.0 $ 43.1

Employee Incentive Plans

Employee Incentive Plans	3 Months Ended
	Mar. 31, 2020
Share-based Payment Arrangement [Abstract]
Employee Incentive Plans	(9) Employee Incentive Plans a. Long-Term Incentive Plans We account for unit-based compensation in accordance with ASC 718, which requires that compensation related to all unit-based awards be recognized in the consolidated financial statements. Unit-based compensation cost is valued at fair value at the date of grant, and that grant date fair value is recognized as expense over each award’s requisite service period with a corresponding increase to equity or liability based on the terms of each award and the appropriate accounting treatment under ASC 718. Unit-based compensation associated with ENLC’s unit-based compensation plan awarded to directors, officers, and employees of our general partner and the managing member of ENLC is recorded by ENLK since ENLC has no substantial or managed operating activities other than its interests in ENLK. Amounts recognized on the consolidated financial statements with respect to these plans are as follows (in millions): Three Months Ended 2020 2019 Cost of unit-based compensation charged to operating expense $ 2.2 $ 0.3 Cost of unit-based compensation charged to general and administrative expense 6.6 10.6 Total unit-based compensation expense $ 8.8 $ 10.9 b. ENLC Restricted Incentive Units ENLC restricted incentive units were valued at their fair value at the date of grant, which is equal to the market value of ENLC common units on such date. A summary of the restricted incentive unit activity for the three months ended March 31, 2020 is provided below: Three Months Ended ENLC Restricted Incentive Units: Number of Units Weighted Average Grant-Date Fair Value Non-vested, beginning of period 4,063,605 $ 13.85 Granted (1) 4,554,493 5.66 Vested (1)(2) (1,978,817) 9.56 Forfeited (53,105) 11.34 Non-vested, end of period 6,586,176 $ 9.50 Aggregate intrinsic value, end of period (in millions) $ 7.2 ____________________________ (1) Restricted incentive units typically vest at the end of three years. In February 2020, ENLC granted 1,144,842 restricted incentive units with a fair value of $5.2 million to officers and certain employees as bonus payments for 2019, and these restricted incentive units vested immediately and are included in the restricted incentive units granted and vested line items. (2) Vested units included 732,473 units withheld for payroll taxes paid on behalf of employees. A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for the three months ended March 31, 2020 and 2019 is provided below (in millions): Three Months Ended ENLC Restricted Incentive Units: 2020 2019 Aggregate intrinsic value of units vested $ 10.1 $ 12.4 Fair value of units vested $ 18.9 $ 12.6 As of March 31, 2020, there was $37.3 million of unrecognized compensation cost related to non-vested ENLC restricted incentive units. This cost is expected to be recognized over a weighted-average period of 1.9 years. c. ENLC Performance Units ENLC grants performance awards under the 2014 Plan. The performance award agreements provide that the vesting of performance units (i.e., performance-based restricted incentive units) granted thereunder is dependent on the achievement of certain performance goals over the applicable performance period. At the end of the vesting period, recipients receive distribution equivalents, if any, with respect to the number of performance units vested. The vesting of such units ranges from zero to 200% of the units granted depending on the extent to which the related performance goals are achieved over the relevant performance period. The following table presents a summary of the performance units: Three Months Ended ENLC Performance Units: Number of Units Weighted Average Grant-Date Fair Value Non-vested, beginning of period 1,317,856 $ 14.22 Granted 1,161,986 7.32 Vested (1) (160,002) 31.13 Non-vested, end of period 2,319,840 $ 9.60 Aggregate intrinsic value, end of period (in millions) $ 2.6 ____________________________ (1) Vested units included 60,920 units withheld for payroll taxes paid on behalf of employees. A summary of the performance units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for the three months ended March 31, 2020 and 2019 is provided below (in millions). Three Months Ended ENLC Performance Units: 2020 2019 Aggregate intrinsic value of units vested $ 0.9 $ 1.8 Fair value of units vested $ 5.0 $ 1.9 As of March 31, 2020, there was $16.8 million of unrecognized compensation cost that related to non-vested ENLC performance units. That cost is expected to be recognized over a weighted-average period of 1.8 years. The following table presents a summary of the grant-date fair value assumptions by performance unit grant date: ENLC Performance Units: January 2020 March 2020 Grant-Date Fair Value $ 7.69 $ 1.13 Beginning TSR price $ 6.13 $ 1.25 Risk-free interest rate 1.62 % 0.42 % Volatility factor 37.00 % 51.00 % d. ENLK Restricted Incentive Units A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for the three months ended March 31, 2019 is provided below (in millions). Since the Legacy ENLK Awards converted into ENLC unit-based awards as a result of the Merger, no additional restricted incentive units will vest as ENLK units under the GP Plan (such restricted incentive units, as converted, are eligible to vest as ENLC units) and no additional expense will be recognized after January 25, 2019 under the GP Plan. Three Months Ended ENLK Restricted Incentive Units: 2019 Aggregate intrinsic value of units vested $ 8.0 Fair value of units vested $ 7.2 e. ENLK Performance Units A summary of the performance units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for the three months ended March 31, 2019 is provided below (in millions). Since the Legacy ENLK Awards converted into ENLC unit-based awards as a result of the Merger, no additional performance units will vest as ENLK units under the GP Plan (such performance units, as converted, are eligible to vest as ENLC units) and no additional expense will be recognized after January 25, 2019 under the GP Plan. Three Months Ended ENLK Performance Units: 2019 Aggregate intrinsic value of units vested $ 2.1 Fair value of units vested $ 1.7

Derivatives

Derivatives	3 Months Ended
	Mar. 31, 2020
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivatives	(10) Derivatives Interest Rate Swaps In April 2019, we entered into an $850.0 million interest rate swap to manage the interest rate risk associated with our floating-rate, LIBOR-based borrowings. Under this arrangement, we pay a fixed interest rate of 2.28% in exchange for LIBOR-based variable interest through December 2021. There was no ineffectiveness related to this hedge. For the three months ended March 31, 2020, we recorded $17.1 million into accumulated other comprehensive loss related to changes in fair value of our interest rate swaps. For the three months ended March 31, 2020, we realized a loss of $1.3 million related to the monthly settlements of our interest rate swaps, which we recorded into interest expense, net of interest income from accumulated other comprehensive loss. We expect to recognize an additional $16.3 million of interest expense out of accumulated other comprehensive loss over the next twelve months. The fair value of our interest rate swaps included in our consolidated balance sheets were as follows (in millions): March 31, 2020 December 31, 2019 Fair value of derivative liabilities—current $ (16.1) $ (5.6) Fair value of derivative liabilities—long-term (13.4) (6.8) Net fair value of interest rate swaps $ (29.5) $ (12.4) Commodity Swaps The components of gain on derivative activity in the consolidated statements of operations related to commodity swaps are (in millions): Three Months Ended 2020 2019 Change in fair value of derivatives $ 13.0 $ (2.0) Realized gain on derivatives 6.2 3.8 Gain on derivative activity $ 19.2 $ 1.8 The fair value of derivative assets and liabilities related to commodity swaps are as follows (in millions): March 31, 2020 December 31, 2019 Fair value of derivative assets—current $ 75.0 $ 12.9 Fair value of derivative assets—long-term 8.2 4.3 Fair value of derivative liabilities—current (61.8) (8.8) Net fair value of commodity swaps $ 21.4 $ 8.4 Set forth below are the summarized notional volumes and fair values of all instruments related to commodity swaps that we held for price risk management purposes and the related physical offsets at March 31, 2020 (in millions). The remaining term of the contracts extend no later than December 2022. March 31, 2020 Commodity Instruments Unit Volume Net Fair Value NGL (short contracts) Swaps Gallons (155.8) $ 8.9 NGL (long contracts) Swaps Gallons 8.1 (0.3) Natural gas (short contracts) Swaps MMBtu (20.3) 0.5 Natural gas (long contracts) Swaps MMBtu 15.0 (0.5) Crude and condensate (short contracts) Swaps MMbbls (13.2) (46.0) Crude and condensate (long contracts) Swaps MMbbls 2.1 58.8 Total fair value of commodity swaps $ 21.4

Fair Value Measurements

Fair Value Measurements	3 Months Ended
	Mar. 31, 2020
Fair Value Disclosures [Abstract]
Fair Value Measurements	(11) Fair Value Measurements Assets and liabilities measured at fair value on a recurring basis are summarized below (in millions): Level 2 March 31, 2020 December 31, 2019 Interest rate swaps (1) $ (29.5) $ (12.4) Commodity swaps (2) $ 21.4 $ 8.4 ____________________________ (1) The fair values of the interest rate swaps are estimated based on the difference between expected cash flows calculated at the contracted interest rates and the expected cash flows using observable benchmarks for the variable interest rates. (2) The fair values of commodity swaps represent the amount at which the instruments could be exchanged in a current arms-length transaction adjusted for our credit risk and/or the counterparty credit risk as required under ASC 820. Fair Value of Financial Instruments The estimated fair value of our financial instruments has been determined using available market information and valuation methodologies. Considerable judgment is required to develop the estimates of fair value; thus, the estimates provided below are not necessarily indicative of the amount we could realize upon the sale or refinancing of such financial instruments (in millions): March 31, 2020 December 31, 2019 Carrying Fair Carrying Fair Long-term debt (1) $ 4,954.8 $ 3,021.6 $ 4,764.3 $ 4,444.2 ____________________________ (1) The carrying value of long-term debt is reduced by debt issuance costs of $28.8 million and $29.8 million as of March 31, 2020 and December 31, 2019, respectively. The respective fair values do not factor in debt issuance costs. The carrying amounts of our cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the short-term maturities of these assets and liabilities.

Segment Information

Segment Information	3 Months Ended
	Mar. 31, 2020
Segment Reporting [Abstract]
Segment Information	(12) Segment Information Identification of the majority of our operating segments is based principally upon geographic regions served: • Permian Segment. The Permian segment includes our natural gas gathering, processing, and transmission activities and our crude oil operations in the Midland and Delaware Basins in West Texas and Eastern New Mexico and our crude operations in South Texas; • North Texas Segment. The North Texas segment includes our natural gas gathering, processing, and transmission activities in North Texas; • Oklahoma Segment. The Oklahoma segment includes our natural gas gathering, processing, and transmission activities, and our crude oil operations in the Cana-Woodford, Arkoma-Woodford, northern Oklahoma Woodford, STACK, and CNOW shale areas; • Louisiana Segment. The Louisiana segment includes our natural gas pipelines, natural gas processing plants, storage facilities, fractionation facilities, and NGL assets located in Louisiana and our crude oil operations in ORV; and • Corporate Segment. The Corporate segment includes our unconsolidated affiliate investments in the Cedar Cove JV in Oklahoma, our ownership interest in GCF in South Texas, our derivative activity, and our general corporate assets and expenses. We evaluate the performance of our operating segments based on segment profits. Summarized financial information for our reportable segments is shown in the following tables (in millions): Permian North Texas Oklahoma Louisiana Corporate Totals Three Months Ended March 31, 2020 Natural gas sales $ 15.1 $ 20.1 $ 41.1 $ 81.6 $ — $ 157.9 NGL sales 0.2 0.3 1.2 373.7 — 375.4 Crude oil and condensate sales 285.0 — 16.2 58.4 — 359.6 Product sales 300.3 20.4 58.5 513.7 — 892.9 NGL sales—related parties 45.9 17.2 67.6 6.8 (137.6) (0.1) Crude oil and condensate sales—related parties 0.1 1.5 (0.2) — (1.3) 0.1 Product sales—related parties 46.0 18.7 67.4 6.8 (138.9) — Gathering and transportation 16.3 45.9 56.3 11.7 — 130.2 Processing 4.3 35.4 33.3 0.7 — 73.7 NGL services — — — 19.6 — 19.6 Crude services 4.2 — 4.3 10.6 — 19.1 Other services 0.6 0.3 0.1 0.4 — 1.4 Midstream services 25.4 81.6 94.0 43.0 — 244.0 Crude services—related parties — — 0.1 — (0.1) — Midstream services—related parties — — 0.1 — (0.1) — Revenue from contracts with customers 371.7 120.7 220.0 563.5 (139.0) 1,136.9 Cost of sales (313.9) (27.0) (93.7) (459.7) 139.0 (755.3) Operating expenses (25.5) (20.5) (22.9) (31.8) — (100.7) Gain on derivative activity — — — — 19.2 19.2 Segment profit $ 32.3 $ 73.2 $ 103.4 $ 72.0 $ 19.2 $ 300.1 Depreciation and amortization $ (29.2) $ (37.2) $ (56.6) $ (37.8) $ (2.0) $ (162.8) Impairments $ — $ — $ — $ (168.4) $ — $ (168.4) Capital expenditures $ 86.0 $ 4.7 $ 8.5 $ 15.2 $ 0.4 $ 114.8 Permian North Texas Oklahoma Louisiana Corporate Totals Three Months Ended March 31, 2019 Natural gas sales $ 36.1 $ 50.6 $ 61.6 $ 122.2 $ — $ 270.5 NGL sales (0.2) 9.3 8.9 573.1 — 591.1 Crude oil and condensate sales 580.8 — 29.6 58.8 — 669.2 Other — — 0.1 — — 0.1 Product sales 616.7 59.9 100.2 754.1 — 1,530.9 NGL sales—related parties 97.2 28.5 126.1 3.2 (255.0) — Crude oil and condensate sales—related parties 4.0 1.0 — — (5.0) — Product sales—related parties 101.2 29.5 126.1 3.2 (260.0) — Gathering and transportation 10.3 63.6 55.3 17.2 — 146.4 Processing 7.7 21.1 34.1 0.9 — 63.8 NGL services — — — 11.7 — 11.7 Crude services 5.2 — 4.0 13.8 — 23.0 Other services 1.5 0.2 (0.3) 0.2 — 1.6 Midstream services 24.7 84.9 93.1 43.8 — 246.5 NGL services—related parties — — — (3.0) 3.0 — Crude services—related parties — — 0.3 — (0.3) — Midstream services—related parties — — 0.3 (3.0) 2.7 — Revenue from contracts with customers 742.6 174.3 319.7 798.1 (257.3) 1,777.4 Cost of sales (676.2) (73.7) (184.2) (686.6) 257.3 (1,363.4) Operating expenses (27.8) (25.7) (25.4) (35.6) — (114.5) Gain on derivative activity — — — — 1.8 1.8 Segment profit $ 38.6 $ 74.9 $ 110.1 $ 75.9 $ 1.8 $ 301.3 Depreciation and amortization $ (27.9) $ (34.3) $ (46.1) $ (41.8) $ (2.0) $ (152.1) Goodwill $ — $ — $ 190.3 $ — $ — $ 190.3 Capital expenditures $ 95.9 $ 4.3 $ 108.2 $ 41.0 $ 1.6 $ 251.0 The following table reconciles the segment profits reported above to the operating income (loss) as reported on the consolidated statements of operations (in millions): Three Months Ended March 31, 2020 2019 Segment profit $ 300.1 $ 301.3 General and administrative expenses (30.9) (38.6) Gain on disposition of assets 0.6 — Depreciation and amortization (162.8) (152.1) Impairments (168.4) — Operating income (loss) $ (61.4) $ 110.6 The table below represents information about segment assets as of March 31, 2020 and December 31, 2019 (in millions): Segment Identifiable Assets: March 31, 2020 December 31, 2019 Permian $ 2,362.3 $ 2,281.1 North Texas 1,091.0 1,135.8 Oklahoma 2,974.6 3,035.0 Louisiana 2,233.9 2,562.0 Corporate 335.3 120.7 Total identifiable assets $ 8,997.1 $ 9,134.6

Other Information

Other Information	3 Months Ended
	Mar. 31, 2020
Other Liabilities Disclosure [Abstract]
Other Information	(13) Other Information The following tables present additional detail for other current assets and other current liabilities, which consists of the following (in millions): Other current assets: March 31, 2020 December 31, 2019 Natural gas and NGLs inventory $ 7.3 $ 43.4 Prepaid expenses and other 10.5 13.5 Other current assets $ 17.8 $ 56.9 Other current liabilities: March 31, 2020 December 31, 2019 Accrued interest $ 57.7 $ 32.6 Accrued wages and benefits, including taxes 16.1 31.5 Accrued ad valorem taxes 17.0 28.5 Capital expenditure accruals 45.0 42.4 Retention liability 8.9 8.7 Short-term lease liability 17.6 21.1 Suspense producer payments 13.8 13.8 Operating expense accruals 9.5 10.8 Other 19.6 12.3 Other current liabilities $ 205.2 $ 201.7

Subsequent Event

Subsequent Event	3 Months Ended
	Mar. 31, 2020
Subsequent Events [Abstract]
Subsequent Event	(14) Subsequent Event Current Market Environment. On March 11, 2020, the World Health Organization declared the ongoing coronavirus (COVID-19) outbreak a pandemic and recommended containment and mitigation measures worldwide. The pandemic has reached more than 200 countries and has resulted in widespread adverse impacts on the global economy, the energy industry as a whole and midstream companies, and on our employees, customers, suppliers, and other parties with whom we have business relations. The pandemic and related travel and operational restrictions, as well as business closures and curtailed consumer activity, have resulted in a significant reduction in global demand for crude oil, condensate, natural gas, and NGLs. For example, global demand for crude oil has dropped by nearly one-third since mid-February. The decline in demand has been met with a decline in the market price for these commodities, particularly for crude oil, and especially following the announcement by Saudi Arabia of a significant increase in its maximum crude oil production capacity, as well as the announcement by Russia that previously agreed upon oil production cuts between members of OPEC+ would expire. On April 12, 2020, members of OPEC+ agreed to certain production cuts; however, these cuts are not expected to be enough to offset near-term demand loss attributable to the COVID-19 pandemic. In addition, crude oil stockpiles and the decision of end users, such as refineries, not to take a normal level of crude oil shipments has led to a severe and growing shortage of storage capacity for oil and significantly higher costs for available storage. In the case of the oil markets, both the decline in demand and storage concerns have caused the price of oil to reach historic lows. As a result of the supply/demand imbalance, reduced commodity prices, limited storage capacity, and an uncertain timeline for recovery, oil and natural gas producers, including our customers, have sharply curtailed their current drilling and production activity as well as their plans for future drilling and production activity. As a result of these decreases in activity, our business

Significant Accounting Polici_2

Significant Accounting Policies (Policies)	3 Months Ended
	Mar. 31, 2020
Accounting Policies [Abstract]
Basis of Presentation	Basis of PresentationThe accompanying consolidated financial statements have been prepared in accordance with the instructions to Form 10-Q, are unaudited, and do not include all the information and disclosures required by GAAP for complete financial statements. All adjustments that, in the opinion of management, are necessary for a fair presentation of the results of operations for the interim periods have been made and are of a recurring nature unless otherwise disclosed herein. The results of operations for such interim periods are not necessarily indicative of results of operations for a full year. These consolidated financial statements should be read in conjunction with the consolidated financial statements and accompanying notes included in our Annual Report on Form 10-K for the year ended December 31, 2019. Certain reclassifications were made to the financial statements for the prior period to conform to current period presentation. The effect of these reclassifications had no impact on previously reported partners’ equity or net income (loss). All significant intercompany balances and transactions have been eliminated in consolidation.
Revenue Recognition	Revenue Recognition Minimum Volume Commitments and Firm Transportation Contracts Certain of our gathering and processing agreements provide for quarterly or annual MVCs. Under these agreements, our customers or suppliers agree to ship and/or process a minimum volume of product on our systems over an agreed time period. If a customer or supplier under such an agreement fails to meet its MVC for a specified period, the customer is obligated to pay a contractually-determined fee based upon the shortfall between actual product volumes and the MVC for that period. Some of these agreements also contain make-up right provisions that allow a customer or supplier to utilize gathering or processing fees in excess of the MVC in subsequent periods to offset shortfall amounts in previous periods. We record revenue under MVC contracts during periods of shortfall when it is known that the customer cannot, or will not, make up the deficiency in subsequent periods. Deficiency fee revenue is included in midstream services revenue. For our firm transportation contracts, we transport commodities owned by others for a stated monthly fee for a specified monthly quantity with an additional fee based on actual volumes. We include transportation fees from firm transportation contracts in our midstream services revenue.
Property and Equipment	Property and Equipment Impairment Review. In accordance with ASC 360 , Property, Plant, and Equipment , we evaluate long-lived assets of identifiable business activities for potential impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable. The carrying amount of a long-lived asset is not recoverable when it exceeds the undiscounted sum of the future cash flows expected to result from the use and eventual disposition of the asset. Estimates of expected future cash flows represent management’s best estimate based on reasonable and supportable assumptions. When the carrying amount of a long-lived asset is not recoverable, an impairment is recognized equal to the excess of the asset’s carrying value over its fair value, which is based on inputs that are not observable in the market, and thus represent Level 3 inputs.
Adopted Accounting Standards	Adopted Accounting Standards Effective January 1, 2020, we adopted ASU 2018-15, Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract (Topic 350): Internal-Use Software. ASU 2018-15 aligns the accounting for costs incurred to implement a cloud computing arrangement that is a service arrangement with the guidance on capitalizing costs associated with developing or obtaining internal-use software. Specifically, the ASU amends ASC 350-40 to include in its scope implementation costs of a cloud computing arrangement that is a service contract and clarifies that a customer should apply ASC 350-40 to determine which implementation costs should be capitalized in a cloud computing arrangement that is considered a service contract. For the three months ended March 31, 2020, we did not capitalize any cloud computing costs. However, to the extent future costs incurred in a cloud computing arrangement are capitalizable, the corresponding amortization will be included in “Operating expenses” or “General and administrative” in the consolidated statements of operations, rather than “Depreciation and amortization.” Effective January 1, 2020, we adopted ASU 2016-13, Financial Instruments—Credit Losses (Topic 326). The updates in ASU 2016-13 provide financial statement users with more information about the expected credit losses on financial instruments and other commitments to extend credit held by a reporting entity at each reporting date. Following the adoption of ASU 2016-13, we record an allowance for doubtful accounts based on our expectation of future losses. Because our receivables are typically paid within 30 days, and because we closely monitor the credit-worthiness of all our counterparties, adopting ASU 2016-13 did not have a material effect on our financial statements. However, in the event we foresee further or sustained deterioration in the current market environment, or other factors indicating an increased likelihood of defaults by our customers, we may recognize additional losses.
Derivatives

(Tables)

(Tables)	3 Months Ended
	Mar. 31, 2020
Accounting Policies [Abstract]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction	The following table summarizes the contractually committed fees that we expect to recognize in our consolidated statements of operations, in either revenue or reductions to cost of sales, from MVC and firm transportation contractual provisions. All amounts in the table below are determined using the contractually-stated MVC or firm transportation volumes specified for each period multiplied by the relevant deficiency or reservation fee. Actual amounts could differ due to the timing of revenue recognition or reductions to cost of sales resulting from make-up right provisions included in our agreements, as well as due to nonpayment or nonperformance by our customers. These fees do not represent the shortfall amounts we expect to collect under our MVC contracts, as we generally do not expect volume shortfalls to equal the full amount of the contractual MVCs during these periods. For example, for the three months ended March 31, 2020, we had contractual commitments of $41.8 million under our MVC contracts and recorded $11.8 million of revenue due to volume shortfalls. MVC and Firm Transportation Commitments (in millions) (1) 2020 (remaining) $ 199.5 2021 116.7 2022 103.3 2023 94.8 2024 81.3 Thereafter 158.2 Total $ 753.8 ____________________________

Intangible Assets (Tables)

Intangible Assets (Tables)	3 Months Ended
	Mar. 31, 2020
Goodwill and Intangible Assets Disclosure [Abstract]
Summary of Change in Carrying Value	The following table represents our change in carrying value of intangible assets (in millions): Gross Carrying Amount Accumulated Amortization Net Carrying Amount Three Months Ended March 31, 2020 Customer relationships, beginning of period $ 1,795.8 $ (545.9) $ 1,249.9 Amortization expense — (30.9) (30.9) Customer relationships, end of period $ 1,795.8 $ (576.8) $ 1,219.0
Summary of Estimated Aggregate Amortization Expense	The following table summarizes our estimated aggregate amortization expense for the next five years and thereafter (in millions): 2020 (remaining) $ 92.8 2021 123.7 2022 123.7 2023 123.6 2024 123.4 Thereafter 631.8 Total $ 1,219.0

Leases (Tables)

Leases (Tables)	3 Months Ended
	Mar. 31, 2020
Leases [Abstract]
Assets and Liabilities, Lessee	Lease balances are recorded on the consolidated balance sheets as follows (in millions): March 31, 2020 December 31, 2019 Operating leases: Other assets, net $ 74.5 $ 80.4 Other current liabilities $ 17.6 $ 21.1 Other long-term liabilities $ 78.8 $ 81.9 Other lease information Weighted-average remaining lease term—Operating leases 11.0 years 10.6 years Weighted-average discount rate—Operating leases 5.2 % 5.1 %
Lease, Cost	Lease expense is recognized on the consolidated statements of operations as “Operating expenses” and “General and administrative” depending on the nature of the leased asset. The components of total lease expense are as follows (in millions): Three Months Ended 2020 2019 Finance lease expense: Amortization of right-of-use asset $ — $ 0.7 Operating lease expense: Long-term operating lease expense 6.4 6.3 Short-term lease expense 5.5 6.9 Variable lease expense 2.8 1.6 Total lease expense $ 14.7 $ 15.5 Other information about our leases is presented below (in millions): Three Months Ended 2020 2019 Supplemental cash flow information: Cash payments for finance leases included in cash flows from financing activities $ — $ 0.4 Cash payments for operating leases included in cash flows from operating activities $ 7.2 $ 7.0 Right-of-use assets obtained in exchange for operating lease liabilities $ 4.8 $ 80.6
Lessee, Operating Lease, Liability, Maturity	The following table summarizes the maturity of our lease liability as of March 31, 2020 (in millions): Total 2020 (remaining) 2021 2022 2023 2024 Thereafter Undiscounted operating lease liability $ 133.9 $ 16.3 $ 17.0 $ 12.2 $ 10.2 $ 9.5 $ 68.7 Reduction due to present value (37.5) (3.5) (4.0) (3.6) (3.2) (2.8) (20.4) Operating lease liability $ 96.4 $ 12.8 $ 13.0 $ 8.6 $ 7.0 $ 6.7 $ 48.3
Finance Lease, Liability, Maturity	The following table summarizes the maturity of our lease liability as of March 31, 2020 (in millions): Total 2020 (remaining) 2021 2022 2023 2024 Thereafter Undiscounted operating lease liability $ 133.9 $ 16.3 $ 17.0 $ 12.2 $ 10.2 $ 9.5 $ 68.7 Reduction due to present value (37.5) (3.5) (4.0) (3.6) (3.2) (2.8) (20.4) Operating lease liability $ 96.4 $ 12.8 $ 13.0 $ 8.6 $ 7.0 $ 6.7 $ 48.3

Long-Term Debt (Tables)

Long-Term Debt (Tables)	3 Months Ended
	Mar. 31, 2020
Debt Disclosure [Abstract]
Schedule of Long-Term Debt	As of March 31, 2020 and December 31, 2019, long-term debt consisted of the following (in millions): March 31, 2020 December 31, 2019 Outstanding Principal Premium (Discount) Long-Term Debt Outstanding Principal Premium (Discount) Long-Term Debt Related party debt $ 1,900.0 $ — $ 1,900.0 $ 1,700.0 $ — $ 1,700.0 4.40% Senior unsecured notes due 2024 545.0 1.4 546.4 550.0 1.5 551.5 4.15% Senior unsecured notes due 2025 747.5 (0.7) 746.8 750.0 (0.7) 749.3 4.85% Senior unsecured notes due 2026 497.0 (0.4) 496.6 500.0 (0.5) 499.5 5.60% Senior unsecured notes due 2044 350.0 (0.2) 349.8 350.0 (0.2) 349.8 5.05% Senior unsecured notes due 2045 450.0 (5.9) 444.1 450.0 (5.9) 444.1 5.45% Senior unsecured notes due 2047 500.0 (0.1) 499.9 500.0 (0.1) 499.9 Debt classified as long-term, including current maturities of long-term debt $ 4,989.5 $ (5.9) 4,983.6 $ 4,800.0 $ (5.9) 4,794.1 Debt issuance cost (1) (28.8) (29.8) Long-term debt, net of unamortized issuance cost $ 4,954.8 $ 4,764.3 ____________________________

Partners' Capital (Tables)

Partners' Capital (Tables)	3 Months Ended
	Mar. 31, 2020
Partners' Capital Notes [Abstract]
Summary of Distribution Activity	A summary of the distribution activity relating to the Series B Preferred Units during the three months ended March 31, 2020 and 2019 is provided below: Declaration period Distribution paid as additional Series B Preferred Units Cash Distribution (in millions) Date paid/payable 2020 Fourth Quarter of 2019 148,999 $ 16.8 February 13, 2020 First Quarter of 2020 149,371 $ 16.8 May 13, 2020 2019 Fourth Quarter of 2018 425,785 $ 16.5 February 13, 2019 First Quarter of 2019 147,887 $ 16.7 May 14, 2019
Incentive Distributions	The net income (loss) allocated to our general partner is as follows (in millions): Three Months Ended 2020 2019 Unit-based compensation attributable to ENLC’s restricted and performance units $ (12.3) $ (12.1) General partner share of net income (loss) (1.4) 0.4 General partner interest in EOGP acquisition — 2.4 General partner interest in net income (loss) $ (13.7) $ (9.3)

Investment in Unconsolidated _2

Investment in Unconsolidated Affiliates (Tables)	3 Months Ended
	Mar. 31, 2020
Equity Method Investments and Joint Ventures [Abstract]
Summary of Activity and Investment in Unconsolidated Affiliates	The following table shows the activity related to our investment in unconsolidated affiliates for the periods indicated (in millions): Three Months Ended 2020 2019 GCF Distributions $ 1.6 $ 2.2 Equity in income $ 1.8 $ 5.7 Cedar Cove JV Distributions $ 0.2 $ 0.3 Equity in loss $ (0.1) $ (0.4) Total Distributions $ 1.8 $ 2.5 Equity in income $ 1.7 $ 5.3 The following table shows the balances related to our investment in unconsolidated affiliates as of March 31, 2020 and December 31, 2019 (in millions): March 31, 2020 December 31, 2019 GCF $ 39.4 $ 39.2 Cedar Cove JV 3.6 3.9 Total investment in unconsolidated affiliates $ 43.0 $ 43.1

Employee Incentive Plans (Table

Employee Incentive Plans (Tables)	3 Months Ended
	Mar. 31, 2020
Share-based Payment Arrangement [Abstract]
Schedule of Amounts Recognized in Consolidated Financial Statements	Amounts recognized on the consolidated financial statements with respect to these plans are as follows (in millions): Three Months Ended 2020 2019 Cost of unit-based compensation charged to operating expense $ 2.2 $ 0.3 Cost of unit-based compensation charged to general and administrative expense 6.6 10.6 Total unit-based compensation expense $ 8.8 $ 10.9
Summary of Restricted Incentive Unit Activity	three months ended March 31, 2020 is provided below: Three Months Ended ENLC Restricted Incentive Units: Number of Units Weighted Average Grant-Date Fair Value Non-vested, beginning of period 4,063,605 $ 13.85 Granted (1) 4,554,493 5.66 Vested (1)(2) (1,978,817) 9.56 Forfeited (53,105) 11.34 Non-vested, end of period 6,586,176 $ 9.50 Aggregate intrinsic value, end of period (in millions) $ 7.2 ____________________________ (1) Restricted incentive units typically vest at the end of three years. In February 2020, ENLC granted 1,144,842 restricted incentive units with a fair value of $5.2 million to officers and certain employees as bonus payments for 2019, and these restricted incentive units vested immediately and are included in the restricted incentive units granted and vested line items.
Summary of Restricted Units' Aggregate Intrinsic Value	A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for the three months ended March 31, 2020 and 2019 is provided below (in millions): Three Months Ended ENLC Restricted Incentive Units: 2020 2019 Aggregate intrinsic value of units vested $ 10.1 $ 12.4 Fair value of units vested $ 18.9 $ 12.6 A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for the three months ended March 31, 2019 is provided below (in millions). Since the Legacy ENLK Awards converted into ENLC unit-based awards as a result of the Merger, no additional restricted incentive units will vest as ENLK units under the GP Plan (such restricted incentive units, as converted, are eligible to vest as ENLC units) and no additional expense will be recognized after January 25, 2019 under the GP Plan. Three Months Ended ENLK Restricted Incentive Units: 2019 Aggregate intrinsic value of units vested $ 8.0 Fair value of units vested $ 7.2
Summary of Performance Units	The following table presents a summary of the performance units: Three Months Ended ENLC Performance Units: Number of Units Weighted Average Grant-Date Fair Value Non-vested, beginning of period 1,317,856 $ 14.22 Granted 1,161,986 7.32 Vested (1) (160,002) 31.13 Non-vested, end of period 2,319,840 $ 9.60 Aggregate intrinsic value, end of period (in millions) $ 2.6 ____________________________ (1) Vested units included 60,920 units withheld for payroll taxes paid on behalf of employees. A summary of the performance units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for the three months ended March 31, 2020 and 2019 is provided below (in millions). Three Months Ended ENLC Performance Units: 2020 2019 Aggregate intrinsic value of units vested $ 0.9 $ 1.8 Fair value of units vested $ 5.0 $ 1.9 A summary of the performance units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for the three months ended March 31, 2019 is provided below (in millions). Since the Legacy ENLK Awards converted into ENLC unit-based awards as a result of the Merger, no additional performance units will vest as ENLK units under the GP Plan (such performance units, as converted, are eligible to vest as ENLC units) and no additional expense will be recognized after January 25, 2019 under the GP Plan. Three Months Ended ENLK Performance Units: 2019 Aggregate intrinsic value of units vested $ 2.1 Fair value of units vested $ 1.7
Summary of Grant-Date Fair Values	The following table presents a summary of the grant-date fair value assumptions by performance unit grant date: ENLC Performance Units: January 2020 March 2020 Grant-Date Fair Value $ 7.69 $ 1.13 Beginning TSR price $ 6.13 $ 1.25 Risk-free interest rate 1.62 % 0.42 % Volatility factor 37.00 % 51.00 %

Derivatives (Tables)

Derivatives (Tables)	3 Months Ended
	Mar. 31, 2020
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Fair Value of Derivative Assets and Liabilities	The fair value of our interest rate swaps included in our consolidated balance sheets were as follows (in millions): March 31, 2020 December 31, 2019 Fair value of derivative liabilities—current $ (16.1) $ (5.6) Fair value of derivative liabilities—long-term (13.4) (6.8) Net fair value of interest rate swaps $ (29.5) $ (12.4)
Components of Gain (Loss)	The components of gain on derivative activity in the consolidated statements of operations related to commodity swaps are (in millions): Three Months Ended 2020 2019 Change in fair value of derivatives $ 13.0 $ (2.0) Realized gain on derivatives 6.2 3.8 Gain on derivative activity $ 19.2 $ 1.8
Schedule Of Derivative Instruments In Statement Of Financial Position, Fair Value1	The fair value of derivative assets and liabilities related to commodity swaps are as follows (in millions): March 31, 2020 December 31, 2019 Fair value of derivative assets—current $ 75.0 $ 12.9 Fair value of derivative assets—long-term 8.2 4.3 Fair value of derivative liabilities—current (61.8) (8.8) Net fair value of commodity swaps $ 21.4 $ 8.4
Summary of Notional Volumes and Fair Value of Instruments	Set forth below are the summarized notional volumes and fair values of all instruments related to commodity swaps that we held for price risk management purposes and the related physical offsets at March 31, 2020 (in millions). The remaining term of the contracts extend no later than December 2022. March 31, 2020 Commodity Instruments Unit Volume Net Fair Value NGL (short contracts) Swaps Gallons (155.8) $ 8.9 NGL (long contracts) Swaps Gallons 8.1 (0.3) Natural gas (short contracts) Swaps MMBtu (20.3) 0.5 Natural gas (long contracts) Swaps MMBtu 15.0 (0.5) Crude and condensate (short contracts) Swaps MMbbls (13.2) (46.0) Crude and condensate (long contracts) Swaps MMbbls 2.1 58.8 Total fair value of commodity swaps $ 21.4

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	3 Months Ended
	Mar. 31, 2020
Fair Value Disclosures [Abstract]
Schedule of Net Assets (Liabilities) Measured on a Recurring Basis	measured at fair value on a recurring basis are summarized below (in millions): Level 2 March 31, 2020 December 31, 2019 Interest rate swaps (1) $ (29.5) $ (12.4) Commodity swaps (2) $ 21.4 $ 8.4 ____________________________ (1) The fair values of the interest rate swaps are estimated based on the difference between expected cash flows calculated at the contracted interest rates and the expected cash flows using observable benchmarks for the variable interest rates. (2) The fair values of commodity swaps represent the amount at which the instruments could be exchanged in a current arms-length transaction adjusted for our credit risk and/or the counterparty credit risk as required under ASC 820.
Fair Value of Financial Instruments	The estimated fair value of our financial instruments has been determined using available market information and valuation methodologies. Considerable judgment is required to develop the estimates of fair value; thus, the estimates provided below are not necessarily indicative of the amount we could realize upon the sale or refinancing of such financial instruments (in millions): March 31, 2020 December 31, 2019 Carrying Fair Carrying Fair Long-term debt (1) $ 4,954.8 $ 3,021.6 $ 4,764.3 $ 4,444.2 ____________________________

Segment Information (Tables)

Segment Information (Tables)	3 Months Ended
	Mar. 31, 2020
Segment Reporting [Abstract]
Summarized Financial Information	We evaluate the performance of our operating segments based on segment profits. Summarized financial information for our reportable segments is shown in the following tables (in millions): Permian North Texas Oklahoma Louisiana Corporate Totals Three Months Ended March 31, 2020 Natural gas sales $ 15.1 $ 20.1 $ 41.1 $ 81.6 $ — $ 157.9 NGL sales 0.2 0.3 1.2 373.7 — 375.4 Crude oil and condensate sales 285.0 — 16.2 58.4 — 359.6 Product sales 300.3 20.4 58.5 513.7 — 892.9 NGL sales—related parties 45.9 17.2 67.6 6.8 (137.6) (0.1) Crude oil and condensate sales—related parties 0.1 1.5 (0.2) — (1.3) 0.1 Product sales—related parties 46.0 18.7 67.4 6.8 (138.9) — Gathering and transportation 16.3 45.9 56.3 11.7 — 130.2 Processing 4.3 35.4 33.3 0.7 — 73.7 NGL services — — — 19.6 — 19.6 Crude services 4.2 — 4.3 10.6 — 19.1 Other services 0.6 0.3 0.1 0.4 — 1.4 Midstream services 25.4 81.6 94.0 43.0 — 244.0 Crude services—related parties — — 0.1 — (0.1) — Midstream services—related parties — — 0.1 — (0.1) — Revenue from contracts with customers 371.7 120.7 220.0 563.5 (139.0) 1,136.9 Cost of sales (313.9) (27.0) (93.7) (459.7) 139.0 (755.3) Operating expenses (25.5) (20.5) (22.9) (31.8) — (100.7) Gain on derivative activity — — — — 19.2 19.2 Segment profit $ 32.3 $ 73.2 $ 103.4 $ 72.0 $ 19.2 $ 300.1 Depreciation and amortization $ (29.2) $ (37.2) $ (56.6) $ (37.8) $ (2.0) $ (162.8) Impairments $ — $ — $ — $ (168.4) $ — $ (168.4) Capital expenditures $ 86.0 $ 4.7 $ 8.5 $ 15.2 $ 0.4 $ 114.8 Permian North Texas Oklahoma Louisiana Corporate Totals Three Months Ended March 31, 2019 Natural gas sales $ 36.1 $ 50.6 $ 61.6 $ 122.2 $ — $ 270.5 NGL sales (0.2) 9.3 8.9 573.1 — 591.1 Crude oil and condensate sales 580.8 — 29.6 58.8 — 669.2 Other — — 0.1 — — 0.1 Product sales 616.7 59.9 100.2 754.1 — 1,530.9 NGL sales—related parties 97.2 28.5 126.1 3.2 (255.0) — Crude oil and condensate sales—related parties 4.0 1.0 — — (5.0) — Product sales—related parties 101.2 29.5 126.1 3.2 (260.0) — Gathering and transportation 10.3 63.6 55.3 17.2 — 146.4 Processing 7.7 21.1 34.1 0.9 — 63.8 NGL services — — — 11.7 — 11.7 Crude services 5.2 — 4.0 13.8 — 23.0 Other services 1.5 0.2 (0.3) 0.2 — 1.6 Midstream services 24.7 84.9 93.1 43.8 — 246.5 NGL services—related parties — — — (3.0) 3.0 — Crude services—related parties — — 0.3 — (0.3) — Midstream services—related parties — — 0.3 (3.0) 2.7 — Revenue from contracts with customers 742.6 174.3 319.7 798.1 (257.3) 1,777.4 Cost of sales (676.2) (73.7) (184.2) (686.6) 257.3 (1,363.4) Operating expenses (27.8) (25.7) (25.4) (35.6) — (114.5) Gain on derivative activity — — — — 1.8 1.8 Segment profit $ 38.6 $ 74.9 $ 110.1 $ 75.9 $ 1.8 $ 301.3 Depreciation and amortization $ (27.9) $ (34.3) $ (46.1) $ (41.8) $ (2.0) $ (152.1) Goodwill $ — $ — $ 190.3 $ — $ — $ 190.3 Capital expenditures $ 95.9 $ 4.3 $ 108.2 $ 41.0 $ 1.6 $ 251.0
Reconciliation of Profits Reported to Operating Income (Loss)	The following table reconciles the segment profits reported above to the operating income (loss) as reported on the consolidated statements of operations (in millions): Three Months Ended March 31, 2020 2019 Segment profit $ 300.1 $ 301.3 General and administrative expenses (30.9) (38.6) Gain on disposition of assets 0.6 — Depreciation and amortization (162.8) (152.1) Impairments (168.4) — Operating income (loss) $ (61.4) $ 110.6
Schedule of Assets	Segment Identifiable Assets: March 31, 2020 December 31, 2019 Permian $ 2,362.3 $ 2,281.1 North Texas 1,091.0 1,135.8 Oklahoma 2,974.6 3,035.0 Louisiana 2,233.9 2,562.0 Corporate 335.3 120.7 Total identifiable assets $ 8,997.1 $ 9,134.6

Other Information (Tables)

Other Information (Tables)	3 Months Ended
	Mar. 31, 2020
Other Liabilities Disclosure [Abstract]
Schedule of Other Current Liabilities	The following tables present additional detail for other current assets and other current liabilities, which consists of the following (in millions): Other current assets: March 31, 2020 December 31, 2019 Natural gas and NGLs inventory $ 7.3 $ 43.4 Prepaid expenses and other 10.5 13.5 Other current assets $ 17.8 $ 56.9 Other current liabilities: March 31, 2020 December 31, 2019 Accrued interest $ 57.7 $ 32.6 Accrued wages and benefits, including taxes 16.1 31.5 Accrued ad valorem taxes 17.0 28.5 Capital expenditure accruals 45.0 42.4 Retention liability 8.9 8.7 Short-term lease liability 17.6 21.1 Suspense producer payments 13.8 13.8 Operating expense accruals 9.5 10.8 Other 19.6 12.3 Other current liabilities $ 205.2 $ 201.7

Significant Accounting Polici_3

Significant Accounting Policies - Narrative (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Impairment charges	$ 0.4
Redemption of non-controlling interest	(4)	$ 0
Redeemable Noncontrolling Interest
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Redemption of non-controlling interest	4
Louisiana Operating Segment
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Impairment charges	168
Minimum Volume Contract
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Contract with customer, liability	41.8
Contracts with customers, revenue recognition	$ 11.8

Significant Accounting Polici_4

Significant Accounting Policies - Summary of Expected Future Performance Obligations (Details) $ in Millions	Mar. 31, 2020USD ($)
Accounting Policies [Abstract]
Remaining performance obligations	$ 753.8
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-04-01
Accounting Policies [Abstract]
Remaining performance obligations	$ 199.5
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Expected gross operating margin, expected timing of satisfaction, period	9 months
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Accounting Policies [Abstract]
Remaining performance obligations	$ 116.7
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Expected gross operating margin, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Accounting Policies [Abstract]
Remaining performance obligations	$ 103.3
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Expected gross operating margin, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Accounting Policies [Abstract]
Remaining performance obligations	$ 94.8
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Expected gross operating margin, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Accounting Policies [Abstract]
Remaining performance obligations	$ 81.3
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Expected gross operating margin, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Accounting Policies [Abstract]
Remaining performance obligations	$ 158.2
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Expected gross operating margin, expected timing of satisfaction, period

Intangible Assets - Changes in

Intangible Assets - Changes in Carrying Value (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Finite-lived Intangible Assets [Roll Forward]
Accumulated amortization, beginning balance	$ (545.9)
Amortization expense	(30.9)	$ (30.9)
Accumulated amortization, ending balance	(576.8)
Net carrying amount, ending balance	1,219
Customer relationships
Finite-lived Intangible Assets [Roll Forward]
Gross carrying amount, beginning balance	1,795.8
Accumulated amortization, beginning balance	(545.9)
Net carrying amount, beginning balance	1,249.9
Amortization expense	(30.9)
Gross carrying amount, ending balance	1,795.8
Accumulated amortization, ending balance	(576.8)
Net carrying amount, ending balance	$ 1,219

Intangible Assets - Narrative (

Intangible Assets - Narrative (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Goodwill
Amortization expense	$ 30.9	$ 30.9
Minimum
Goodwill
Amortization period	5 years
Maximum
Goodwill
Amortization period	20 years
Weighted average
Goodwill
Amortization period	15 years

Intangible Assets - Amortizatio

Intangible Assets - Amortization Expense (Details) $ in Millions	Mar. 31, 2020USD ($)
Summary of estimated amortization expense
2020 (remaining)	$ 92.8
2021	123.7
2022	123.7
2023	123.6
2024	123.4
Thereafter	631.8
Total	$ 1,219

Related Party Transactions - Na

Related Party Transactions - Narrative (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019	Dec. 31, 2019	Apr. 09, 2019
Related Party Transaction
Cost of sales	$ 755.3	$ 1,363.4
Accounts payable to related party	0.5		$ 1.1
Term Loan Due 2029 | Unsecured Debt
Related Party Transaction
Stated interest rate				5.375%
ENLC
Related Party Transaction
Accounts receivable, related parties	14.8		18.1
Cedar Cove Joint Venture
Related Party Transaction
Cost of sales	2.9	$ 8.1
Accounts payable to related party	$ 0.5		$ 1.1

Leases - Lease Balances Recorde

Leases - Lease Balances Recorded on the Consolidated Balance Sheet (Details) - USD ($) $ in Millions	Mar. 31, 2020	Dec. 31, 2019
Operating leases:
Other assets, net	$ 74.5	$ 80.4
Other current liabilities	17.6	21.1
Other long-term liabilities	$ 78.8	$ 81.9
Other lease information
Weighted-average remaining lease term—Operating leases	11 years	10 years 7 months 6 days
Weighted-average discount rate—Operating leases	5.20%	5.10%

Leases - Components of Total Le

Leases - Components of Total Lease Expense (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Finance lease expense:
Amortization of right-of-use asset	$ 0	$ 0.7
Operating Lease Expense [Abstract]
Operating lease expense:	6.4	6.3
Short-term lease expense	5.5	6.9
Variable lease expense	2.8	1.6
Total lease expense	$ 14.7	$ 15.5

Leases - Other Information (Det

Leases - Other Information (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Supplemental cash flow information:
Cash payments for finance leases included in cash flows from financing activities	$ 0	$ 0.4
Cash payments for operating leases included in cash flows from operating activities	7.2	7
Right-of-use assets obtained in exchange for operating lease liabilities	$ 4.8	$ 80.6

Leases - Maturity of Lease Liab

Leases - Maturity of Lease Liability (Details) $ in Millions	Mar. 31, 2020USD ($)
Undiscounted operating lease liability
Total	$ 133.9
2020 (remaining)	16.3
2021	17
2022	12.2
2023	10.2
2024	9.5
Thereafter	68.7
Reduction due to present value
Total	(37.5)
2020 (remaining)	(3.5)
2021	(4)
2022	(3.6)
2023	(3.2)
2024	(2.8)
Thereafter	(20.4)
Operating lease liability
Total	96.4
2020 (remaining)	12.8
2021	13
2022	8.6
2023	7
2024	6.7
Thereafter	$ 48.3

Long-Term Debt - Summary (Detai

Long-Term Debt - Summary (Details) - USD ($) $ in Millions	Mar. 31, 2020	Dec. 31, 2019
Debt Instrument
Outstanding principal	$ 4,989.5	$ 4,800
Premium (discount)	(5.9)	(5.9)
Long-term debt	4,983.6	4,794.1
Debt issuance costs	(28.8)	(29.8)
Long-term debt, net of unamortized issuance cost	4,954.8	4,764.3
Amortization	11.9	10.9
Related party debt
Debt Instrument
Outstanding principal	1,900	1,700
Premium (discount)	0	0
Long-term debt	1,900	1,700
4.40% Senior unsecured notes due 2024
Debt Instrument
Outstanding principal	545	550
Premium (discount)	1.4	1.5
Long-term debt	$ 546.4	551.5
Stated interest rate	4.40%
4.15% Senior unsecured notes due 2025
Debt Instrument
Outstanding principal	$ 747.5	750
Premium (discount)	(0.7)	(0.7)
Long-term debt	$ 746.8	749.3
Stated interest rate	4.15%
4.85% Senior unsecured notes due 2026
Debt Instrument
Outstanding principal	$ 497	500
Premium (discount)	(0.4)	(0.5)
Long-term debt	$ 496.6	499.5
Stated interest rate	4.85%
5.60% Senior unsecured notes due 2044
Debt Instrument
Outstanding principal	$ 350	350
Premium (discount)	(0.2)	(0.2)
Long-term debt	$ 349.8	349.8
Stated interest rate	5.60%
5.05% Senior unsecured notes due 2045
Debt Instrument
Outstanding principal	$ 450	450
Premium (discount)	(5.9)	(5.9)
Long-term debt	$ 444.1	444.1
Stated interest rate	5.05%
5.45% Senior unsecured notes due 2047
Debt Instrument
Outstanding principal	$ 500	500
Premium (discount)	(0.1)	(0.1)
Long-term debt	$ 499.9	$ 499.9
Stated interest rate	5.45%

Long-Term Debt - Narrative (Det

Long-Term Debt - Narrative (Details)	Dec. 11, 2018USD ($)	Mar. 31, 2020USD ($)	Mar. 31, 2019USD ($)	Dec. 31, 2019USD ($)	Apr. 09, 2019
Debt Instrument
Debt instrument, net (discount) premium		$ 4,983,600,000		$ 4,794,100,000
Payments on borrowings		241,000,000	$ 1,320,000,000
Outstanding principal		4,989,500,000		4,800,000,000
Gain on extinguishment of debt		5,300,000	$ 0
Credit Facility
Debt Instrument
Debt instrument, net (discount) premium		1,900,000,000		1,700,000,000
Additional amount available (not to exceed)	$ 1,750,000,000	2,250,000,000
Line of credit facility, fair value of amount outstanding		550,000,000
Outstanding principal		$ 1,900,000,000		$ 1,700,000,000
Credit Facility | Unsecured Debt
Debt Instrument
Line of credit facility, consolidated EBITDA to consolidated interest charges, ratio	2.5
Ratio of consolidated indebtedness to consolidated EBITDA	5
Line of credit facility, consolidated indebtedness to consolidated EBITDA, during an acquisition period, ratio	5.5
Credit Facility | Unsecured Debt | Federal Funds
Debt Instrument
Variable interest rate	0.50%
Credit Facility | Unsecured Debt | Eurodollar
Debt Instrument
Variable interest rate	1.00%
Credit Facility | Unsecured Debt | Minimum
Debt Instrument
Conditional acquisition purchase price	$ 50,000,000
Credit Facility | Unsecured Debt | Minimum | LIBOR Rate
Debt Instrument
Variable interest rate	1.125%
Credit Facility | Unsecured Debt | Minimum | Eurodollar
Debt Instrument
Variable interest rate	0.125%
Credit Facility | Unsecured Debt | Maximum | LIBOR Rate
Debt Instrument
Variable interest rate	2.00%
Credit Facility | Unsecured Debt | Maximum | Eurodollar
Debt Instrument
Variable interest rate	1.00%
Credit Facility | Letter of Credit
Debt Instrument
Maximum borrowing capacity	$ 500,000,000
Letters of credit outstanding, liable, percentage		105.00%
Term Loan Due 2021
Debt Instrument
Ratio of consolidated indebtedness to consolidated EBITDA	5
Term Loan Due 2021 | Maximum
Debt Instrument
Ratio of consolidated indebtedness to consolidated EBITDA	5.5
Conditional acquisition purchase price	$ 50,000,000
Term Loan Due 2021 | Unsecured Debt
Debt Instrument
Face amount	$ 850,000,000	$ 850,000,000
Term Loan Due 2021 | Line of Credit
Debt Instrument
Line of credit facility, consolidated EBITDA to consolidated interest charges, ratio	2.5
Term Loan Due 2021 | Line of Credit | Federal Funds
Debt Instrument
Variable interest rate	0.50%
Term Loan Due 2021 | Line of Credit | Eurodollar
Debt Instrument
Variable interest rate	1.00%
Term Loan Due 2021 | Line of Credit | Minimum | LIBOR Rate
Debt Instrument
Variable interest rate	1.00%
Term Loan Due 2021 | Line of Credit | Minimum | Eurodollar
Debt Instrument
Variable interest rate	0.00%
Term Loan Due 2021 | Line of Credit | Maximum | LIBOR Rate
Debt Instrument
Variable interest rate	1.75%
Term Loan Due 2021 | Line of Credit | Maximum | Eurodollar
Debt Instrument
Variable interest rate	0.75%
Term Loan Due 2029 | Unsecured Debt
Debt Instrument
Stated interest rate					5.375%
Senior Notes due 2024, 2025, 2026
Debt Instrument
Payments on borrowings		5,200,000
Outstanding principal		10,500,000
ENLC | Credit Facility
Debt Instrument
Line of credit facility, fair value of amount outstanding		550,000,000
ENLC | Letter of Credit | Credit Facility
Debt Instrument
Line of credit facility, fair value of amount outstanding		$ 18,800,000

Partners' Capital - Narrative a

Partners' Capital - Narrative and Distribution Activity (Details) - USD ($) $ / shares in Units, $ in Millions	Feb. 13, 2019	Mar. 31, 2020	Dec. 31, 2019	Mar. 31, 2019	Dec. 31, 2018
Partners' capital
Cash distribution		$ (93.3)
Series B Preferred Unitholders
Partners' capital
Distribution paid as additional Series B Preferred Units (in shares)		149,371	148,999	147,887	425,785
Cash distribution (in millions)		$ 16.8	$ 16.8	$ 16.7	$ 16.5
Limited Partner | Common Units
Partners' capital
Distribution declared per unit (in dollars per share)	$ 0.39

Partners' Capital - Net Income

Partners' Capital - Net Income Allocated to the General Partner (Details) - General Partner Interest - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Incentive
Unit-based compensation attributable to ENLC’s restricted and performance units	$ (12.3)	$ (12.1)
General partner share of net income (loss)	(1.4)	0.4
General partner interest in EOGP acquisition	0	2.4
General partner interest in net income (loss)	$ (13.7)	$ (9.3)

Investment in Unconsolidated _3

Investment in Unconsolidated Affiliates (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019	Dec. 31, 2019
Schedule of Equity Method Investments
Distributions	$ 1.8	$ 2.5
Equity in income (loss)	1.7	5.3
Total investment in unconsolidated affiliates	$ 43		$ 43.1
GCF
Schedule of Equity Method Investments
Ownership interest	38.75%
Distributions	$ 1.6	2.2
Equity in income (loss)	1.8	5.7
Total investment in unconsolidated affiliates	$ 39.4		39.2
Cedar Cove JV
Schedule of Equity Method Investments
Ownership interest	30.00%
Distributions	$ 0.2	0.3
Equity in income (loss)	(0.1)	$ (0.4)
Total investment in unconsolidated affiliates	$ 3.6		$ 3.9

Employee Incentive Plans - Amou

Employee Incentive Plans - Amounts Recognized in Consolidated Financial Statements (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Compensation allocation
Total unit-based compensation expense	$ 8.8	$ 10.9
Cost of unit-based compensation charged to operating expense
Compensation allocation
Total unit-based compensation expense	2.2	0.3
Cost of unit-based compensation charged to operating expense
Compensation allocation
Total unit-based compensation expense	$ 6.6	$ 10.6

Employee Incentive Plans - Rest

Employee Incentive Plans - Restricted and Performance Awards (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended			3 Months Ended
	Mar. 31, 2020	Feb. 29, 2020	Jan. 31, 2020	Mar. 31, 2020	Mar. 31, 2019
Grant date fair value assumptions
Grant-date fair value (in dollars per share)	$ 1.13		$ 7.69
Beginning TSR price (in dollars per share)	$ 1.25		$ 6.13
Risk-free interest rate	0.42%		1.62%
Volatility factor	51.00%		37.00%
Unvested restricted units
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Aggregate intrinsic value of units vested					$ 8
Fair value of units vested					7.2
Unvested restricted units | ENLC
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Non-vested, beginning of period (in shares)			4,063,605	4,063,605
Granted (in shares)				4,554,493
Vested (in shares)		(1,144,842)		(1,978,817)
Forfeited (in shares)				(53,105)
Non-vested, end of period (in shares)	6,586,176			6,586,176
Aggregate intrinsic value, end of period (in dollars per share)	$ 7.2			$ 7.2
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Non-vested, beginning of period (in dollars per share)			$ 13.85	$ 13.85
Granted (in dollars per share)				5.66
Vested (in dollars per share)				9.56
Forfeited (in dollars per share)				11.34
Non-vested, end of period (in dollars per share)	$ 9.50			$ 9.50
Units withheld for payroll taxes (in shares)				732,473
Aggregate intrinsic value of units vested				$ 10.1	12.4
Fair value of units vested		$ 5.2		18.9	12.6
Unrecognized compensation cost related to non-vested restricted incentive units	$ 37.3			$ 37.3
Unrecognized compensation costs, weighted average period for recognition				1 year 10 months 24 days
Vesting period				3 years
Performance Units
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Aggregate intrinsic value of units vested					2.1
Fair value of units vested					1.7
Performance Units | ENLC
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Non-vested, beginning of period (in shares)			1,317,856	1,317,856
Granted (in shares)				1,161,986
Vested (in shares)				(160,002)
Non-vested, end of period (in shares)	2,319,840			2,319,840
Aggregate intrinsic value, end of period (in dollars per share)	$ 2.6			$ 2.6
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Non-vested, beginning of period (in dollars per share)			$ 14.22	$ 14.22
Granted (in dollars per share)				7.32
Vested (in dollars per share)				31.13
Non-vested, end of period (in dollars per share)	$ 9.60			$ 9.60
Units withheld for payroll taxes (in shares)				60,920
Aggregate intrinsic value of units vested				$ 0.9	1.8
Fair value of units vested				5	$ 1.9
Unrecognized compensation cost related to non-vested restricted incentive units	$ 16.8			$ 16.8
Unrecognized compensation costs, weighted average period for recognition				1 year 9 months 18 days
Performance Units | Minimum
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Percent of units vesting				0.00%
Performance Units | Maximum
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Percent of units vesting				200.00%

Derivatives - Interest Rate Swa

Derivatives - Interest Rate Swaps (Details) - USD ($)	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019	Dec. 31, 2019	Apr. 30, 2019	May 31, 2017
Derivative [Line Items]
Derivative, notional amount				$ 850,000,000
Derivative, fixed interest rate				2.28%
Settlement gain (loss)	$ (31,600,000)		$ (14,500,000)		$ (2,200,000)
Loss on designated cash flow hedge	(17,100,000)	$ 0
Gain (loss) on interest rate cash flow hedge ineffectiveness	(1,300,000)
Interest income (expense) expected to be reclassified out of accumulated other comprehensive income (loss) over the next twelve months	(16,300,000)
Fair value of derivative liabilities—current	(77,900,000)		(14,400,000)
Fair value of derivative liabilities—long-term	(13,400,000)		(6,800,000)
Interest rate swaps
Derivative [Line Items]
Fair value of derivative liabilities—current	(16,100,000)		(5,600,000)
Fair value of derivative liabilities—long-term	(13,400,000)		(6,800,000)
Net fair value of commodity swaps	$ (29,500,000)		$ (12,400,000)

Derivatives - Components of Gai

Derivatives - Components of Gain (Loss) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Derivative Instruments
Gain on derivative activity	$ 19.2	$ 1.8
Commodity Swaps
Derivative Instruments
Change in fair value of derivatives	13	(2)
Realized gain on derivatives	6.2	3.8
Gain on derivative activity	$ 19.2	$ 1.8

Derivatives - Assets and Liabil

Derivatives - Assets and Liabilities (Details) - USD ($) $ in Millions	Mar. 31, 2020	Dec. 31, 2019
Derivative [Line Items]
Fair value of derivative assets—current	$ 75	$ 12.9
Fair value of derivative assets—long-term	8.2	4.3
Fair value of derivative liabilities—current	(77.9)	(14.4)
Fair value of derivative liabilities—long-term	(13.4)	(6.8)
Commodity swaps
Derivative [Line Items]
Fair value of derivative assets—current	75	12.9
Fair value of derivative assets—long-term	8.2	4.3
Fair value of derivative liabilities—current	(61.8)	(8.8)
Net fair value of commodity swaps	$ 21.4	$ 8.4

Derivatives - Commodities (Deta

Derivatives - Commodities (Details) gal in Millions, MMBbls in Millions, MMBTU in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2020USD ($)MMBTUgalMMBbls
Derivative [Line Items]
Possible reduction in maximum loss if counterparties fail to perform	$ 21.4
Commodity
Derivative [Line Items]
Net Fair Value	21.4
Maximum loss if counterparties fail to perform	$ 83.2
Commodity | NGL | Short
Derivative [Line Items]
Notional amount (in gallons and mmbls) | gal	155.8
Net Fair Value	$ 8.9
Commodity | NGL | Long
Derivative [Line Items]
Notional amount (in gallons and mmbls) | gal	8.1
Net Fair Value	$ (0.3)
Commodity | Natural Gas | Short
Derivative [Line Items]
Notional amount (in mmbtu) | MMBTU	20.3
Net Fair Value	$ 0.5
Commodity | Natural Gas | Long
Derivative [Line Items]
Notional amount (in mmbtu) | MMBTU	15
Net Fair Value	$ (0.5)
Commodity | Crude and Condensate | Short
Derivative [Line Items]
Notional amount (in gallons and mmbls) | MMBbls	13.2
Net Fair Value	$ (46)
Commodity | Crude and Condensate | Long
Derivative [Line Items]
Notional amount (in gallons and mmbls) | MMBbls	2.1
Net Fair Value	$ 58.8

Fair Value Measurements - Measu

Fair Value Measurements - Measured on a Recurring Basis (Details) - USD ($) $ in Millions	Mar. 31, 2020	Dec. 31, 2019
Interest rate swaps
Measured at fair value
Net Fair Value	$ (29.5)	$ (12.4)
Commodity swaps
Measured at fair value
Net Fair Value	21.4	8.4
Level 2 | Interest rate swaps | Recurring
Measured at fair value
Net Fair Value	(29.5)	(12.4)
Level 2 | Commodity swaps | Recurring
Measured at fair value
Net Fair Value	$ 21.4	$ 8.4

Fair Value Measurements - Finan

Fair Value Measurements - Financial Instruments (Details) - USD ($) $ in Millions	Mar. 31, 2020	Dec. 31, 2019
Fair Value
Debt issuance costs	$ 28.8	$ 29.8
Carrying Value
Fair Value
Long-term debt	4,954.8	4,764.3
Fair Value
Fair Value
Long-term debt	$ 3,021.6	$ 4,444.2

Segment Information - Financial

Segment Information - Financial Information and Assets (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Segment Reporting
Revenue from contracts with customers	$ 1,136.9	$ 1,777.4
Cost of sales	(755.3)	(1,363.4)
Operating expenses	(100.7)	(114.5)
Gain on derivative activity	19.2	1.8
Segment profit	300.1	301.3
Depreciation and amortization	(162.8)	(152.1)
Goodwill		190.3
Impairments	(168.4)	0
Capital expenditures	114.8	251
Corporate
Segment Reporting
Revenue from contracts with customers	(139)	(257.3)
Cost of sales	139	257.3
Operating expenses	0	0
Gain on derivative activity	19.2	1.8
Segment profit	19.2	1.8
Depreciation and amortization	(2)	(2)
Goodwill		0
Impairments	0
Capital expenditures	0.4	1.6
Permian | Operating Segments
Segment Reporting
Revenue from contracts with customers	371.7	742.6
Cost of sales	(313.9)	(676.2)
Operating expenses	(25.5)	(27.8)
Gain on derivative activity	0	0
Segment profit	32.3	38.6
Depreciation and amortization	(29.2)	(27.9)
Goodwill		0
Impairments	0
Capital expenditures	86	95.9
North Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers	120.7	174.3
Cost of sales	(27)	(73.7)
Operating expenses	(20.5)	(25.7)
Gain on derivative activity	0	0
Segment profit	73.2	74.9
Depreciation and amortization	(37.2)	(34.3)
Goodwill		0
Impairments	0
Capital expenditures	4.7	4.3
Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers	220	319.7
Cost of sales	(93.7)	(184.2)
Operating expenses	(22.9)	(25.4)
Gain on derivative activity	0	0
Segment profit	103.4	110.1
Depreciation and amortization	(56.6)	(46.1)
Goodwill		190.3
Impairments	0
Capital expenditures	8.5	108.2
Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers	563.5	798.1
Cost of sales	(459.7)	(686.6)
Operating expenses	(31.8)	(35.6)
Gain on derivative activity	0	0
Segment profit	72	75.9
Depreciation and amortization	(37.8)	(41.8)
Goodwill		0
Impairments	(168.4)
Capital expenditures	15.2	41
Product sales
Segment Reporting
Revenue from contracts with customers	892.9	1,530.9
Product sales | Corporate
Segment Reporting
Revenue from contracts with customers	0	0
Product sales | Permian | Operating Segments
Segment Reporting
Revenue from contracts with customers	300.3	616.7
Product sales | North Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers	20.4	59.9
Product sales | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers	58.5	100.2
Product sales | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers	513.7	754.1
Product sales, Natural gas sales
Segment Reporting
Revenue from contracts with customers	157.9	270.5
Product sales, Natural gas sales | Corporate
Segment Reporting
Revenue from contracts with customers	0	0
Product sales, Natural gas sales | Permian | Operating Segments
Segment Reporting
Revenue from contracts with customers	15.1	36.1
Product sales, Natural gas sales | North Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers	20.1	50.6
Product sales, Natural gas sales | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers	41.1	61.6
Product sales, Natural gas sales | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers	81.6	122.2
Product sales, NGL sales
Segment Reporting
Revenue from contracts with customers	375.4	591.1
Product sales, NGL sales | Corporate
Segment Reporting
Revenue from contracts with customers	0	0
Product sales, NGL sales | Permian | Operating Segments
Segment Reporting
Revenue from contracts with customers	0.2	(0.2)
Product sales, NGL sales | North Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers	0.3	9.3
Product sales, NGL sales | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers	1.2	8.9
Product sales, NGL sales | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers	373.7	573.1
Product sales, Crude oil and condensate sales
Segment Reporting
Revenue from contracts with customers	359.6	669.2
Product sales, Crude oil and condensate sales | Corporate
Segment Reporting
Revenue from contracts with customers	0	0
Product sales, Crude oil and condensate sales | Permian | Operating Segments
Segment Reporting
Revenue from contracts with customers	285	580.8
Product sales, Crude oil and condensate sales | North Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers	0	0
Product sales, Crude oil and condensate sales | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers	16.2	29.6
Product sales, Crude oil and condensate sales | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers	58.4	58.8
Product sales, other
Segment Reporting
Revenue from contracts with customers		0.1
Product sales, other | Corporate
Segment Reporting
Revenue from contracts with customers		0
Product sales, other | Permian | Operating Segments
Segment Reporting
Revenue from contracts with customers		0
Product sales, other | North Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers		0
Product sales, other | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers		0.1
Product sales, other | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers		0
Product sales—related parties
Segment Reporting
Revenue from contracts with customers	0	0
Product sales—related parties | Corporate
Segment Reporting
Revenue from contracts with customers	(138.9)	(260)
Product sales—related parties | Permian | Operating Segments
Segment Reporting
Revenue from contracts with customers	46	101.2
Product sales—related parties | North Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers	18.7	29.5
Product sales—related parties | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers	67.4	126.1
Product sales—related parties | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers	6.8	3.2
Product sales, NGL sales, related party
Segment Reporting
Revenue from contracts with customers	(0.1)	0
Product sales, NGL sales, related party | Corporate
Segment Reporting
Revenue from contracts with customers	(137.6)	(255)
Product sales, NGL sales, related party | Permian | Operating Segments
Segment Reporting
Revenue from contracts with customers	45.9	97.2
Product sales, NGL sales, related party | North Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers	17.2	28.5
Product sales, NGL sales, related party | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers	67.6	126.1
Product sales, NGL sales, related party | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers	6.8	3.2
Product sales, Crude oil and condensate sales, related party
Segment Reporting
Revenue from contracts with customers	0.1	0
Product sales, Crude oil and condensate sales, related party | Corporate
Segment Reporting
Revenue from contracts with customers	(1.3)	(5)
Product sales, Crude oil and condensate sales, related party | Permian | Operating Segments
Segment Reporting
Revenue from contracts with customers	0.1	4
Product sales, Crude oil and condensate sales, related party | North Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers	1.5	1
Product sales, Crude oil and condensate sales, related party | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers	(0.2)	0
Product sales, Crude oil and condensate sales, related party | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers	0	0
Midstream services
Segment Reporting
Revenue from contracts with customers	244	246.5
Midstream services | Corporate
Segment Reporting
Revenue from contracts with customers	0	0
Midstream services | Permian | Operating Segments
Segment Reporting
Revenue from contracts with customers	25.4	24.7
Midstream services | North Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers	81.6	84.9
Midstream services | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers	94	93.1
Midstream services | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers	43	43.8
Midstream services, Gathering and transportation
Segment Reporting
Revenue from contracts with customers	130.2	146.4
Midstream services, Gathering and transportation | Corporate
Segment Reporting
Revenue from contracts with customers	0	0
Midstream services, Gathering and transportation | Permian | Operating Segments
Segment Reporting
Revenue from contracts with customers	16.3	10.3
Midstream services, Gathering and transportation | North Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers	45.9	63.6
Midstream services, Gathering and transportation | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers	56.3	55.3
Midstream services, Gathering and transportation | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers	11.7	17.2
Midstream services, Processing
Segment Reporting
Revenue from contracts with customers	73.7	63.8
Midstream services, Processing | Corporate
Segment Reporting
Revenue from contracts with customers	0	0
Midstream services, Processing | Permian | Operating Segments
Segment Reporting
Revenue from contracts with customers	4.3	7.7
Midstream services, Processing | North Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers	35.4	21.1
Midstream services, Processing | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers	33.3	34.1
Midstream services, Processing | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers	0.7	0.9
Midstream services, NGL services
Segment Reporting
Revenue from contracts with customers	19.6	11.7
Midstream services, NGL services | Corporate
Segment Reporting
Revenue from contracts with customers	0	0
Midstream services, NGL services | Permian | Operating Segments
Segment Reporting
Revenue from contracts with customers	0	0
Midstream services, NGL services | North Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers	0	0
Midstream services, NGL services | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers	0	0
Midstream services, NGL services | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers	19.6	11.7
Midstream services, Crude services
Segment Reporting
Revenue from contracts with customers	19.1	23
Midstream services, Crude services | Corporate
Segment Reporting
Revenue from contracts with customers	0	0
Midstream services, Crude services | Permian | Operating Segments
Segment Reporting
Revenue from contracts with customers	4.2	5.2
Midstream services, Crude services | North Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers	0	0
Midstream services, Crude services | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers	4.3	4
Midstream services, Crude services | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers	10.6	13.8
Midstream services, Other services
Segment Reporting
Revenue from contracts with customers	1.4	1.6
Midstream services, Other services | Corporate
Segment Reporting
Revenue from contracts with customers	0	0
Midstream services, Other services | Permian | Operating Segments
Segment Reporting
Revenue from contracts with customers	0.6	1.5
Midstream services, Other services | North Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers	0.3	0.2
Midstream services, Other services | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers	0.1	(0.3)
Midstream services, Other services | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers	0.4	0.2
Midstream services—related parties
Segment Reporting
Revenue from contracts with customers	0	0
Midstream services—related parties | Corporate
Segment Reporting
Revenue from contracts with customers	(0.1)	2.7
Midstream services—related parties | Permian | Operating Segments
Segment Reporting
Revenue from contracts with customers	0	0
Midstream services—related parties | North Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers	0	0
Midstream services—related parties | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers	0.1	0.3
Midstream services—related parties | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers	0	(3)
Midstream Services, NGL services, related party
Segment Reporting
Revenue from contracts with customers		0
Midstream Services, NGL services, related party | Corporate
Segment Reporting
Revenue from contracts with customers		3
Midstream Services, NGL services, related party | Permian | Operating Segments
Segment Reporting
Revenue from contracts with customers		0
Midstream Services, NGL services, related party | North Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers		0
Midstream Services, NGL services, related party | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers		0
Midstream Services, NGL services, related party | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers		(3)
Midstream services, Crude services, related party
Segment Reporting
Revenue from contracts with customers	0	0
Midstream services, Crude services, related party | Corporate
Segment Reporting
Revenue from contracts with customers	(0.1)	(0.3)
Midstream services, Crude services, related party | Permian | Operating Segments
Segment Reporting
Revenue from contracts with customers	0	0
Midstream services, Crude services, related party | North Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers	0	0
Midstream services, Crude services, related party | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers	0.1	0.3
Midstream services, Crude services, related party | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers	$ 0	$ 0

Segment Information - Reconcili

Segment Information - Reconciliation (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Segment Reporting [Abstract]
Segment profit	$ 300.1	$ 301.3
General and administrative expenses	(30.9)	(38.6)
Gain on disposition of assets	0.6	0
Depreciation and amortization	(162.8)	(152.1)
Impairments	(168.4)	0
Operating income (loss)	$ (61.4)	$ 110.6

Segment Information - Assets (D

Segment Information - Assets (Details) - USD ($) $ in Millions	Mar. 31, 2020	Dec. 31, 2019
Segment Reporting
Assets	$ 8,997.1	$ 9,134.6
Operating Segments | Permian
Segment Reporting
Assets	2,362.3	2,281.1
Operating Segments | North Texas
Segment Reporting
Assets	1,091	1,135.8
Operating Segments | Oklahoma
Segment Reporting
Assets	2,974.6	3,035
Operating Segments | Louisiana
Segment Reporting
Assets	2,233.9	2,562
Corporate
Segment Reporting
Assets	$ 335.3	$ 120.7

Other Information (Details)

Other Information (Details) - USD ($) $ in Millions	Mar. 31, 2020	Dec. 31, 2019
Other current assets:
Natural gas and NGLs inventory	$ 7.3	$ 43.4
Prepaid expenses and other	10.5	13.5
Other current assets	17.8	56.9
Other current liabilities:
Accrued interest	57.7	32.6
Accrued wages and benefits, including taxes	16.1	31.5
Accrued ad valorem taxes	17	28.5
Capital expenditure accruals	45	42.4
Retention liability	8.9	8.7
Short-term lease liability	17.6	21.1
Suspense producer payments	13.8	13.8
Operating expense accruals	9.5	10.8
Other	19.6	12.3
Other current liabilities	$ 205.2	$ 201.7

Uncategorized Items - enlc-2020

Label	Element	Value
Cumulative Effect of New Accounting Principle in Period of Adoption	us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption	$ 300,000
General Partner [Member]
Partners' Capital, Including Portion Attributable to Noncontrolling Interest	us-gaap_PartnersCapitalIncludingPortionAttributableToNoncontrollingInterest	$ 231,200,000
Partners' Capital Account, Units	us-gaap_PartnersCapitalAccountUnits	1,600,000
Redeemable Noncontrolling Interest [Member]
Redeemable Noncontrolling Interest, Equity, Carrying Amount	us-gaap_RedeemableNoncontrollingInterestEquityCarryingAmount	$ 9,300,000
Noncontrolling Interest [Member]
Partners' Capital, Including Portion Attributable to Noncontrolling Interest	us-gaap_PartnersCapitalIncludingPortionAttributableToNoncontrollingInterest	309,800,000
Common Unit [Member] | Limited Partner [Member]
Partners' Capital, Including Portion Attributable to Noncontrolling Interest	us-gaap_PartnersCapitalIncludingPortionAttributableToNoncontrollingInterest	$ 2,461,100,000
Partners' Capital Account, Units	us-gaap_PartnersCapitalAccountUnits	353,100,000
Cumulative Effect of New Accounting Principle in Period of Adoption	us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption	$ 300,000
Series B Preferred Stock [Member] | Limited Partner [Member]
Partners' Capital, Including Portion Attributable to Noncontrolling Interest	us-gaap_PartnersCapitalIncludingPortionAttributableToNoncontrollingInterest	$ 889,300,000
Partners' Capital Account, Units	us-gaap_PartnersCapitalAccountUnits	58,700,000
Series C Preferred Stock [Member] | Limited Partner [Member]
Partners' Capital, Including Portion Attributable to Noncontrolling Interest	us-gaap_PartnersCapitalIncludingPortionAttributableToNoncontrollingInterest	$ 395,100,000
Partners' Capital Account, Units	us-gaap_PartnersCapitalAccountUnits	400,000
AOCI Including Portion Attributable to Noncontrolling Interest [Member]
Partners' Capital, Including Portion Attributable to Noncontrolling Interest	us-gaap_PartnersCapitalIncludingPortionAttributableToNoncontrollingInterest	$ (2,100,000)