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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

Form 10-Q

☒ Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the quarterly period ended ~~September~~March 3031, ~~2019~~2020

☐ Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from to

Commission file number: 001-36340

ENLINK MIDSTREAM PARTNERS, LP

(Exact name of registrant as specified in its charter)


Delaware			16-1616605
(State of organization)			(I.R.S. Employer Identification No.)

1722 Routh St., Suite 1300
Dallas,	Texas	75201
(Address of principal executive offices)			(Zip Code)

(214) 953-9500

(Registrant’s telephone number, including area code)

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE SECURITIES EXCHANGE ACT OF 1934:

Title of Each Class

Trading Symbol

Name of Exchange on which Registered

None.

Indicate by check mark whether registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No ¨

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ý No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Securities Exchange Act. (Check one):

Large accelerated filer ☒☐ Accelerated filer ☐ Non-accelerated filer ☐☒ Smaller reporting company ☐ Emerging growth company ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ☒

As of ~~November~~April 430, ~~2019~~2020, the Registrant had 144,358,720 common units outstanding, all of which were held by our affiliate, EnLink Midstream, LLC.

Table of Contents

TABLE OF CONTENTS

Item	Description	Page
	PART I—FINANCIAL INFORMATION
1.	Financial Statements	5
2.	Management'’s Discussion and Analysis of Financial Condition and Results of Operations	3929
3.	Quantitative and Qualitative Disclosures About Market Risk	5341
4.	Controls and Procedures	5644
	PART II—OTHER INFORMATION
1.	Legal Proceedings	5745
1A.	Risk Factors	5745
6.	Exhibits	5746

Table of Contents

DEFINITIONS

The following terms as defined are used in this document:

Defined Term						Definition
/d						Per day.
2014 Plan						~~EnLink Midstream, LLC~~ENLC’s 2014 Long-Term Incentive Plan.
AMZ						Alerian MLP Index for Master Limited Partnerships.
ASC						The FASB Accounting Standards Codification.
ASC 842						ASC 842, Leases, a new accounting standard effective January 1, 2019 related to the accounting for lease agreements.
ASC 350						ASC 350, Intangibles—Goodwill and Other.
ASC 842						ASC 842, Leases.
Ascension JV						Ascension Pipeline Company, LLC, a joint venture between a subsidiary of ENLK and a subsidiary of Marathon Petroleum Corporation in which ENLK owns a 50% interest and Marathon Petroleum Corporation owns a 50% interest. The Ascension JV, which began operations in April 2017, owns an NGL pipeline that connects ENLK’s Riverside fractionator to Marathon Petroleum Corporation’s Garyville refinery.
ASU						The FASB Accounting Standards Update.
Avenger						Avenger crude oil gathering system, a crude oil gathering system in the northern Delaware Basin.
Bbls						Barrels.
Bcf						Billion cubic feet.
Cedar Cove JV						Cedar Cove Midstream LLC, a joint venture between a subsidiary of ENLK and a subsidiary of Kinder Morgan, Inc. in which ENLK owns a 30% interest and Kinder Morgan, Inc. owns a 70% interest. The Cedar Cove JV, which was formed in November 2016, owns gathering and compression assets in Blaine County, Oklahoma, located in the STACK play.
CFTC						U.S. Commodity Futures Trading Commission.
CNOW						Central Northern Oklahoma Woodford Shale.
Commission						U.S. Securities and Exchange Commission.
Consolidated Credit Facility						A $1.75 billion unsecured revolving credit facility entered into by ENLC that matures on January 25, 2024, which includes a $500.0 million letter of credit subfacility. ~~The Consolidated Credit Facility was available upon closing of the Merger and is guaranteed by ENLK.~~
Delaware Basin JV						Delaware G&P LLC, a joint venture between a subsidiary of ENLK and an affiliate of NGP in which ENLK owns a 50.1% interest and NGP owns a 49.9% interest. The Delaware Basin JV, which was formed in August 2016, owns the Lobo processing facilities located in the Delaware Basin in Texas.
Delaware Basin						A large sedimentary basin in West Texas and New Mexico.
Delaware Basin JV						Delaware G&P LLC, a joint venture between a subsidiary of ENLK and an affiliate of NGP in which ENLK owns a 50.1% interest and NGP owns a 49.9% interest. The Delaware Basin JV, which was formed in August 2016, owns the Lobo processing facilities and the Tiger Plant located in the Delaware Basin in Texas.
Devon						Devon Energy Corporation.
Enfield						Enfield Holdings, L.P.
ENLC						EnLink Midstream, LLC.
ENLC						EnLink Midstream, LLC or, when applicable, EnLink Midstream, LLC together with its consolidated subsidiaries.
ENLC Class C common Units						A class of non-economic ENLC common units issued to Enfield immediately prior to the Merger equal to the number of Series B Preferred Units of ENLK held by Enfield immediately prior to the effective time of the Merger, in order to provide Enfield with certain voting rights with respect to ENLC.
ENLK						EnLink Midstream Partners, LP or, when applicable, EnLink Midstream Partners, LP together with its consolidated subsidiaries. Also referred to as the “Partnership.”
ENLK Credit Facility						A $1.5 billion unsecured revolving credit facility entered into by ENLK that would have matured on March 6, 2020, which included a $500.0 million letter of credit subfacility. The ENLK Credit Facility was terminated on January 25, 2019 in connection with the consummation of the Merger.
EOGP						EnLink Oklahoma Gas Processing, LP or EnLink Oklahoma Gas Processing, LP together with, when applicable, its consolidated subsidiaries. As of January 31, 2019, EOGP isbecame a wholly-owned bysubsidiary of the Operating Partnership.
FASB						Financial Accounting Standards Board.
GAAP						Generally accepted accounting principles in the United States of America.
Gal						Gallons.
GCF						Gulf Coast Fractionators, which owns an NGL fractionator in Mont Belvieu, Texas. ENLK owns 38.75% of GCF.
GIP						Global Infrastructure Management, LLC, an independent infrastructure fund manager, itself, its affiliates, or managed fund vehicles, including GIP III Stetson I, L.P., GIP III Stetson II, L.P., and their affiliates.
GIP Transaction						On July 18, 2018, subsidiaries of Devon closed a transaction to sell all of their equity interests in ENLK, ENLC, and the managing member of ENLC to GIP.
GP Plan						Our general partner’s Long-Term Incentive Plan.
GP Plan						EnLink Midstream GP, LLC’s Long-Term Incentive Plan.
Gross Operating Margin						Revenue less cost of sales. Gross Operating Margin is a non-GAAP financial measure. See “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures” for additional information.
Gross Operating Margin						A non-GAAP financial measure. See “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures” for the definition and other information.
ISDAs						International Swaps and Derivatives Association Agreements.
Legacy ENLK Awards						Unit-based awards granted under the GP Plan prior to the Merger. As of the closing of the Merger, Legacy ENLK Awards converted into ENLC unit-based awards using the 1.15 exchange ratio from the Merger Agreement as the conversion rate. No additional awards will be granted under the GP Plan.
Merger						On January 25, 2019, NOLA Merger Sub merged with and into ENLK with ENLK continuing as the surviving entity and a subsidiary of ENLC.

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Merger						On January 25, 2019, NOLA Merger Sub merged with and into ENLK with ENLK continuing as the surviving entity and a subsidiary of ENLC.
Merger Agreement						The Agreement and Plan of Merger, dated as of October 21, 2018, by and among ENLK, our general partner, ENLC, the managing member of ENLC, and NOLA Merger Sub related to the Merger.
MMbbls						Million barrels.
MMbtu						Million British thermal units.
MMcf						Million cubic feet.
MVC						Minimum volume commitment.
NGL						Natural gas liquid.
NGP						NGP Natural Resources XI, LP.
NOLA Merger Sub						NOLA Merger Sub, LLC, previously a wholly-owned subsidiary of ENLC prior to the Merger.
OPEC+						Organization of the Petroleum Exporting Countries and its broader partners.
Operating Partnership						EnLink Midstream Operating, LP, a Delaware limited partnership and wholly owned subsidiary of ENLK.
ORV						ENLK’s Ohio River Valley crude oil, condensate stabilization, natural gas compression, and brine disposal assets in the Utica and Marcellus shales.
OTC						Over-the-counter.
Permian Basin						A large sedimentary basin that includes the Midland and Delaware Basins in west Texas and New Mexico.
POL contracts						Percentage-of-liquids contracts.
POP contracts						Percentage-of-proceeds contracts.
Series B Preferred Units						ENLK’s Series B Cumulative Convertible Preferred Units.
Series C Preferred Units						ENLK’s Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units.
STACK						Sooner Trend Anadarko Basin Canadian and Kingfisher Counties in Oklahoma.
Term Loan						An $850.0 million term loan entered into by ENLK on December 11, 2018 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, which ENLC assumed in connection with the Merger and the obligations of which ENLK guarantees.
Thunderbird Plant						A gas processing plant in ~~central~~Central Oklahoma.
Tiger Plant						A gas processing plant that is under construction in the Delaware Basin and is owned by the Delaware Basin JV.
White Star						White Star Petroleum Holdings, LLC.

Table of Contents

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

ENLINK MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

Consolidated Balance Sheets

(In millions, except unit data)

	September 30, 2019		December 31, 2018
	March 31, 2020		December 31, 2019
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	~~101~~258.71	$	9977.54
Accounts receivable:
Trade, net of allowance for bad debt of $0.5 and $0.3, respectively	44.1		126.3
Trade, net of allowance for bad debt of $0.6 and $0.5, respectively	34.2		36.2
Accrued revenue and other	~~450~~337.4		~~705~~460.91
Related party	814.28		218.1
Fair value of derivative assets	975.60		2812.69
Natural gas and NGLs inventory, prepaid expenses, and other	67.5		72.8
Other current assets	17.8		56.9
Total current assets	~~681~~737.53		~~1,035~~661.26
Property and equipment, net of accumulated depreciation of $3,304.4 and $2,967.4, respectively	7,084.2		6,846.7
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 $515.0 and $422.2, respectively	1,280.8		1,373.6
Intangible assets, net of accumulated amortization of $576.8 and $545.9, respectively	1,219.0		1,249.9
Goodwill	190.3		190.3
Investment in unconsolidated affiliates	43.0		43.1
Investment in unconsolidated affiliates	78.6		80.1
Fair value of derivative assets	8.2		4.3
Fair value of derivative assets	7.9		4.1
Other assets, net	93.3		94.4
Other assets, net	93.5		41.3
Total assets	$	8,997.1	$	9,134.6
Total assets	$	9,416.8	$	9,571.3
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable and drafts payable	$	9151.92	$	~~105~~70.56
Accounts payable to related party	30.65		41.31
Accrued gas, NGLs, condensate, and crude oil purchases	~~323~~176.81		~~500~~354.48
Fair value of derivative liabilities	977.59		2114.84
Current maturities of long-term debt	—		399.8
Other current liabilities	205.2		201.7
Other current liabilities	267.0		246.7
Total current liabilities	510.9		642.6
Total current liabilities	695.8		1,278.5
Long-term debt, including $1,900.0 and $1,700.0 from related parties, respectively	4,954.8		4,764.3
Long-term debt, including $1,513.5 from related parties	4,576.8		3,919.8
Asset retirement obligations	15.7		15.5
Asset retirement obligations	15.3		14.8
Other long-term liabilities	87.7		90.8
Other long-term liabilities	90.8		20.0
Deferred tax liability	44.7		44.5
Deferred tax liability	40.9		42.4
Fair value of derivative liabilities	13.4		6.8
Fair value of derivative liabilities	10.2		2.4
Redeemable non-controlling interest	—		5.2
Redeemable non-controlling interest	5.5		9.3
Partners’ equity:
Common unitholders (144,358,720 and 353,117,434 units issued and outstanding, respectively)	2,109.2		2,460.8
Common unitholders (144,358,720 units issued and outstanding)	1,465.6		1,681.2
Series B preferred unitholders (59,450,923 and 58,728,994 units issued and outstanding, respectively)	894.6		889.3
Series B preferred unitholders (59,748,549 and 59,599,550 units issued and outstanding, respectively)	895.3		895.1
Series C preferred unitholders (400,000 units outstanding)	401.1		395.1
General partner interest (1,594,974 equivalent units outstanding)	~~218~~215.62		~~231~~216.26
Accumulated other comprehensive loss	(1731.46)		(214.15)
Non-controlling interest	~~375~~424.43		~~309~~391.84
Total partners’ equity	3,~~981~~369.59		43,~~284~~564.19
Total liabilities and partners’ equity	$	98,~~416~~997.81	$	9,~~571~~134.36

See accompanying notes to consolidated financial statements.

Table of Contents

ENLINK MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

Consolidated Statements of Operations

(In millions, except per unit data)

	Three Months EndedSeptember 30,						Nine Months EndedSeptember 30,
	Three Months EndedMarch 31,
	2019		2018		2019		2018
	2020		2019
	(Unaudited)
Revenues:
Product sales	$	~~1,137~~892.29	$	1,~~832~~530.29	$	~~4,118.5~~	$	~~4,766.5~~
Product sales—related parties	—		10.2		—		41.0
Midstream services	244.0		246.5
Midstream services	263.3		241.5		762.5		476.1
Gain on derivative activity	19.2		1.8
Midstream services—related parties	—		35.8		—		377.2
Total revenues	1,156.1		1,779.2
Gain (loss) on derivative activity	7.5		(5.4)		16.2		(20.1)
Total revenues	1,408.0		2,114.3		4,897.2		5,640.7
Operating costs and expenses:
Cost of sales	~~999~~755.53		1,~~696~~363.64		~~3,663.0~~		~~4,403.7~~
Operating expenses	~~119~~100.27		114.75		~~351.6~~		~~337.3~~
General and administrative	3830.39		3938.26		~~108.8~~		~~94.5~~
(Gain) loss on disposition of assets	(3.0)		—		(2.9)		1.3
Gain on disposition of assets	(0.6)		—
Depreciation and amortization	~~157~~162.38		~~146~~152.71		~~463.1~~		~~430.1~~
Impairments	—168.4		~~24.6~~—		—		~~24.6~~
Loss on secured term loan receivable	—		—		52.9		—
Total operating costs and expenses	1,217.5		1,668.6
Total operating costs and expenses	1,311.3		2,021.8		4,636.5		5,291.5
Operating income (loss)	(61.4)		110.6
Operating income	96.7		92.5		260.7		349.2
Other income (expense):
Interest expense, net of interest income	(5655.6)		(4449.13)		~~(160.2)~~		~~(131.5)~~
Income from unconsolidated affiliates	4.0		4.3		14.0		11.7
Gain on extinguishment of debt	5.3		—
Other income (expense)	(0.2)		0.1		0.1		0.3
Income from unconsolidated affiliates	1.7		5.3
Total other expense	(5248.86)		(3944.70)		~~(146.1)~~		~~(119.5)~~
Income before non-controlling interest and income taxes	43.9		52.8		114.6		229.7
Income (loss) before non-controlling interest and income taxes	(110.0)		66.6
Income tax benefit (expense)	(0.3)		(0.9)		(0.5)		0.2
Income tax expense	(0.5)		(0.9)
Net income	43.6		51.9		114.1		229.9
Net income (loss)	(110.5)		65.7
Net income attributable to non-controlling interest	13.24		32.19		~~4.8~~		~~5.3~~
Net income attributable to ENLK	$	42.4	$	48.8	$	109.3	$	224.6
Net income (loss) attributable to ENLK	$	(113.9)	$	62.8

See accompanying notes to consolidated financial statements.

Table of Contents

ENLINK MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

Consolidated Statements of Comprehensive Income (Loss)

(In millions)

	Three Months EndedSeptember 30,						Nine Months EndedSeptember 30,
	Three Months EndedMarch 31,
	2019		2018		2019		2018
	2020		2019
	(Unaudited)
Net income	$	43.6	$	51.9	$	114.1	$	229.9
Net income (loss)	$	(110.5)	$	65.7
Loss on designated cash flow hedge	(117.81)		—		~~(15.3)~~		—
Comprehensive income	41.8		51.9		98.8		229.9
Comprehensive income (loss)	(127.6)		65.7
Comprehensive income attributable to non-controlling interest	13.24		32.19		~~4.8~~		~~5.3~~
Comprehensive income attributable to ENLK	$	40.6	$	48.8	$	94.0	$	224.6
Comprehensive income (loss) attributable to ENLK	$	(131.0)	$	62.8

See accompanying notes to consolidated financial statements.

Table of Contents

ENLINK MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

Consolidated Statements of Changes in Partners’ Equity

(In millions)

	Common Units					Series B Preferred Units				Series C Preferred Units					General Partner Interest						Accumulated Other Comprehensive Loss	Non-Controlling Interest	Total	Redeemable Non-~~controlling~~Controlling ~~interest~~Interest (Temporary Equity)
	$		Units	$		Units	$		Units	$		Units	$		$		$		$
	(Unaudited)
Balance, December 31, 2018	$	2,460.8	353.1	$	889.3	58.7	$	395.1	0.4	$	231.2	1.6	$	(2.1)	$	309.8	$	4,284.1	$	9.3
Balance, December 31, 2019	$	1,681.2	144.4	$	895.1	59.6	$	395.1	0.4	$	216.6	1.6	$	(14.5)	$	391.4	$	3,564.9	$	5.2
Adoption of ASC 842	0.3		—	—		—	—		—	—		—	—		—		0.3		—
Unit-based compensation	—		—	—		—	—		—	12.3		—	—		—		12.3		—
Balance, January 1, 2019	2,461.1		353.1	889.3		58.7	395.1		0.4	231.2		1.6	(2.1)		309.8		4,284.4		9.3
Distributions	(93.3)		—	(16.8)		0.1	—		—	—		—	—		(7.6)		(117.7)		(0.3)
Conversion of restricted units for common units, net of units withheld for taxes	(2.8)		0.5	—		—	—		—	—		—	—		—		(2.8)		—
Contributions from non-controlling interests	—		—	—		—	—		—	—		—	—		37.1		37.1		—
Unit-based compensation	1.4		—	—		—	—		—	12.1		—	—		—		13.5		—
Loss on designated cash flow hedge	—		—	—		—	—		—	—		—	(17.1)		—		(17.1)		—
Distributions	(139.4)		—	(16.5)		0.5	—		—	(15.6)		—	—		(6.3)		(177.8)		—
Redemption of non-controlling interest	—		—	—		—	—		—	—		—	—		—		—		(4.0)
Contributions from non-controlling interests	—		—	—		—	—		—	—		—	—		15.7		15.7		—
Fair value adjustment related to redeemable non-controlling interest	0.9		—	—		—	—		—	—		—	—		—		0.9		(0.9)
Fair value adjustment related to redeemable non-controlling interest	2.1		—	—		—	—		—	—		—	—		—		2.1		(2.1)
Net income (loss)	(123.2)		—	17.0		—	6.0		—	(13.7)		—	—		3.4		(110.5)		—
Issuance of common units to ENLC for acquisition of EOGP	—		55.8	—		—	—		—	—		—	—		—		—		—
Balance, March 31, 2020	$	1,465.6	144.4	$	895.3	59.7	$	401.1	0.4	$	215.2	1.6	$	(31.6)	$	424.3	$	3,369.9	$	—
Conversion of ENLK common units into ENLC units	—		(265.0)	—		—	—		—	—		—	—		—		—		—
Net income (loss)	47.5		—	18.6		—	6.0		—	(9.3)		—	—		2.9		65.7		—
Balance, March 31, 2019	2,369.9		144.4	891.4		59.2	401.1		0.4	218.4		1.6	(2.1)		322.1		4,200.8		7.2
Unit-based compensation	—		—	—		—	—		—	6.4		—	—		—		6.4		—
Distributions	(137.2)		—	(16.7)		0.1	(12.0)		—	—		—	—		(6.4)		(172.3)		—
Contributions from non-controlling interests	—		—	—		—	—		—	—		—	—		29.5		29.5		—
Loss on designated cash flow hedge	—		—	—		—	—		—	—		—	(13.5)		—		(13.5)		—
Fair value adjustment related to redeemable non-controlling interest	1.4		—	—		—	—		—	—		—	—		—		1.4		(1.4)
Net income (loss)	(13.8)		—	18.5		—	6.0		—	(6.6)		—	—		0.7		4.8		—
Balance, June 30, 2019	2,220.3		144.4	893.2		59.3	395.1		0.4	218.2		1.6	(15.6)		345.9		4,057.1		5.8
Unit-based compensation	—		—	—		—	—		—	11.1		—	—		—		11.1		—
Distributions	(139.8)		—	(17.1)		0.2	—		—	—		—	—		(5.0)		(161.9)		(0.3)
Contributions from non-controlling interests	—		—	—		—	—		—	—		—	—		33.4		33.4		—
Loss on designated cash flow hedge	—		—	—		—	—		—	—		—	(1.8)		—		(1.8)		—
Fair value adjustment related to redeemable non-controlling interest	0.1		—	—		—	—		—	—		—	—		—		0.1		(0.1)
Net income (loss)	28.6		—	18.5		—	6.0		—	(10.7)		—	—		1.1		43.5		0.1
Balance, September 30, 2019	$	2,109.2	144.4	$	894.6	59.5	$	401.1	0.4	$	218.6	1.6	$	(17.4)	$	375.4	$	3,981.5	$	5.5

See accompanying notes to consolidated financial statements.

Table of Contents

ENLINK MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

Consolidated Statements of Changes in Partners’ Equity (Continued)

(In millions)

	Common Units					Series B Preferred Units				Series C Preferred Units					General Partner Interest						Accumulated Other Comprehensive Loss	Non-Controlling Interest	Total	Redeemable Non-Controlling Interest (Temporary Equity)
	$		Units	$		Units	$		Units	$		Units	$		$		$		$
	(Unaudited)
Balance, December 31, 2017	$	3,108.6	349.7	$	864.1	57.1	$	395.1	0.4	$	206.6	1.6	$	(2.1)	$	233.2	$	4,805.5	$	4.6
Balance, December 31, 2018	$	2,460.8	353.1	$	889.3	58.7	$	395.1	0.4	$	231.2	1.6	$	(2.1)	$	309.8	$	4,284.1	$	9.3
Issuance of common units	0.9		0.1	—		—	—		—	—		—	—		—		0.9		—
Adoption of ASC 842	0.3		—	—		—	—		—	—		—	—		—		0.3		—
Conversion of restricted units for common units, net of units withheld for taxes	(2.7)		0.4	—		—	—		—	—		—	—		—		(2.7)		—
Balance, January 1, 2019	2,461.1		353.1	889.3		58.7	395.1		0.4	231.2		1.6	(2.1)		309.8		4,284.4		9.3
Unit-based compensation	4.4		—	—		—	—		—	4.4		—	—		—		8.8		—
Conversion of restricted units for common units, net of units withheld for taxes	(2.8)		0.5	—		—	—		—	—		—	—		—		(2.8)		—
Distributions	(137.6)		—	(16.0)		0.4	—		—	(15.4)		—	—		(10.0)		(179.0)		—
Unit-based compensation	1.4		—	—		—	—		—	12.1		—	—		—		13.5		—
Contributions from non-controlling interests	—		—	—		—	—		—	—		—	—		33.3		33.3		—
Distributions	(139.4)		—	(16.5)		0.5	—		—	(15.6)		—	—		(6.3)		(177.8)		—
Adjustment for acquisition of EOGP (Note 1)	2.8		—	—		—	—		—	—		—	—		(2.8)		—		—
Contributions from non-controlling interests	—		—	—		—	—		—	—		—	—		15.7		15.7		—
Net income	21.6		—	21.9		—	6.0		—	14.8		—	—		0.8		65.1		—
Fair value adjustment related to redeemable non-controlling interest	2.1		—	—		—	—		—	—		—	—		—		2.1		(2.1)
Balance, March 31, 2018	2,998.0		350.2	870.0		57.5	401.1		0.4	210.4		1.6	(2.1)		254.5		4,731.9		4.6
Issuance of common units to ENLC for acquisition of EOGP	—		55.8	—		—	—		—	—		—	—		—		—		—
Conversion of restricted units for common units, net of units withheld for taxes	(0.7)		0.1	—		—	—		—	—		—	—		—		(0.7)		—
Conversion of ENLK common units into ENLC units	—		(265.0)	—		—	—		—	—		—	—		—		—		—
Unit-based compensation	4.0		—	—		—	—		—	4.0		—	—		—		8.0		—
Net income (loss)	47.5		—	18.6		—	6.0		—	(9.3)		—	—		2.9		65.7		—
Distributions	(137.4)		—	(16.2)		0.4	(12.0)		—	(15.5)		—	—		(13.4)		(194.5)		—
Balance, March 31, 2019	$	2,369.9	144.4	$	891.4	59.2	$	401.1	0.4	$	218.4	1.6	$	(2.1)	$	322.1	$	4,200.8	$	7.2
Contributions from non-controlling interests	—		—	—		—	—		—	—		—	—		48.3		48.3		—
Adjustment for acquisition of EOGP (Note 1)	6.6		—	—		—	—		—	—		—	—		(6.6)		—		—
Net income	58.9		—	22.8		—	6.0		—	23.8		—	—		1.4		112.9		—
Balance, June 30, 2018	2,929.4		350.3	876.6		57.9	395.1		0.4	222.7		1.6	(2.1)		284.2		4,705.9		4.6
Issuance of common units	45.2		2.5	—		—	—		—	—		—	—		—		45.2		—
Conversion of restricted units for common units, net of units withheld for taxes	(2.2)		0.3	—		—	—		—	—		—	—		—		(2.2)		—
Unit-based compensation	8.0		—	—		—	—		—	7.3		—	—		—		15.3		—
Distributions	(138.0)		—	(16.3)		0.4	—		—	(15.4)		—	—		(14.2)		(183.9)		—
Contributions from non-controlling interests	—		—	—		—	—		—	—		—	—		40.4		40.4		—
Fair value adjustment related to redeemable non-controlling interest	(1.4)		—	—		—	—		—	—		—	—		—		(1.4)		1.4
Adjustment for acquisition of EOGP (Note 1)	11.1		—	—		—	—		—	—		—	—		(11.1)		—		—
Net income	5.2		—	24.3		—	6.0		—	13.3		—	—		2.9		51.7		0.2
Balance, September 30, 2018	$	2,857.3	353.1	$	884.6	58.3	$	401.1	0.4	$	227.9	1.6	$	(2.1)	$	302.2	$	4,671.0	$	6.2

See accompanying notes to consolidated financial statements.

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ENLINK MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

Consolidated Statements of Cash Flows

(In millions)

	Nine Months Ended September 30,
	Three Months EndedMarch 31,
	2019		2018
	2020		2019
	(Unaudited)
Cash flows from operating activities:
Net income	$	114.1	$	229.9
Net income (loss)	$	(110.5)	$	65.7
Adjustments to reconcile net income to net cash provided by operating activities:
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Impairments	—168.4		~~24.6~~—
Depreciation and amortization	~~463~~162.18		~~430~~152.1
Loss on secured term loan receivable	52.9		—
Non-cash unit-based compensation	8.8		10.9
Non-cash unit-based compensation	31.0		31.6
Gain on derivatives recognized in net income (loss)	(19.2)		(1.8)
(Gain) loss on derivatives recognized in net income	(16.2)		20.1
Cash settlements on derivatives	1.2		4.6
Cash settlements on derivatives	12.5		(4.3)
Gain on extinguishment of debt	(5.3)		—
Amortization of debt issue costs, net discount (premium) of notes	31.90		31.28
Distribution of earnings from unconsolidated affiliates	141.76		142.02
Income from unconsolidated affiliates	(141.07)		(115.73)
Non-cash revenue from contract restructuring	—		(45.5)
Other operating activities	(1.0)		(0.4)
Other operating activities	(6.5)		(2.2)
Changes in assets and liabilities:
Accounts receivable, accrued revenue, and other	~~331~~128.60		~~(292~~76.2)
Natural gas and NGLs inventory, prepaid expenses, and other	144.98		~~(92~~3.9)6
Accounts payable, accrued product purchases, and other accrued liabilities	(~~219~~200.29)		~~239~~(51.15)
Net cash provided by operating activities	~~769~~178.80		~~543~~258.81
Cash flows from investing activities:
Additions to property and equipment	(~~594~~112.50)		(~~639~~241.45)
Proceeds from sale of property	13.7		1.5
Other investing activities	(3.5)		0.5
Other investing activities	(2.2)		4.9
Net cash used in investing activities	(115.5)		(241.0)
Net cash used in investing activities	(583.0)		(633.0)
Cash flows from financing activities:
Proceeds from borrowings	~~3,593~~440.50		1,~~979~~368.04
Payments on borrowings	(~~3,330~~241.0)		(1,~~214~~320.0)
Payment of installment payable for EOGP acquisition	—		(250.0)
Debt financing costs	—		(5.6)
Debt financing costs	(10.0)		—
Distributions to non-controlling interests	(7.9)		(6.3)
Proceeds from issuance of common units	—		46.1
Contributions by non-controlling interests	37.1		15.7
Distributions to non-controlling interests	(18.0)		(37.6)
Distributions to Series B Preferred Units	(16.8)		(16.5)
Contributions by non-controlling interests, including contributions from affiliates of $48.6 for the nine months ended September 30, 2018	78.6		122.0
Distributions to common unitholders and to general partner	(93.3)		(155.0)
Distributions to Series B Preferred Units	(50.3)		(48.5)
Other financing activities	0.1		2.8
Distributions to Series C Preferred Units	(12.0)		(12.0)
Net cash provided by (used in) financing activities	118.2		(116.5)
Distributions to common unitholders and to general partner	(432.0)		(459.3)
Net increase (decrease) in cash and cash equivalents	180.7		(99.4)
Other financing activities	(4.4)		(3.7)
Cash and cash equivalents, beginning of period	77.4		99.5
Net cash provided by (used in) financing activities	(184.6)		122.0
Cash and cash equivalents, end of period	$	258.1	$	0.1
Net increase in cash and cash equivalents	2.2		32.8
Cash and cash equivalents, beginning of period	99.5		30.8
Cash and cash equivalents, end of period	$	101.7	$	63.6
Supplemental disclosures of cash flow information:
Cash paid for interest	$	~~127~~22.73	$	~~106~~13.39
Cash paid for income taxes	$	20.12	$	~~0.6~~—
Non-cash investing activities:
Non-cash accrual of property and equipment	$	242.68	$	139.35
Discounted secured term loan receivable from contract restructuring	$	—	$	47.7
Non-cash financing activities:
Redemption of non-controlling interest	$	(4.0)	$	—

See accompanying notes to consolidated financial statements.

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ENLINK MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements

~~September~~March 3031, ~~2019~~2020

(Unaudited)

(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~~, including the Operating Partnership and EOGP~~.

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.

Transfer of EOGP Interest

On January 31, 2019, ENLC transferred its 16.1% limited partner interest in EOGP to the Operating Partnership in exchange for 55,827,221 ENLK common units, resulting in the Operating Partnership owning 100% of the limited partner interests in EOGP. This acquisition has been accounted for as an acquisition under common control under ASC 805, Business Combinations, resulting in the retrospective adjustment of our prior results. The “Adjustment for acquisition of EOGP (Note 1)” presented in the consolidated statements of changes in partners’ equity for the period ended June 30, 2018 represents the adjustment due to the recast to offset distributions paid to ENLC and contributions received from ENLC for its related ownership in EOGP.

Simplification of the Corporate Structure

On October 21, 2018, ENLK, ENLC, the general partner of ENLK, the managing member of ENLC, and NOLA Merger Sub entered into the Merger Agreement pursuant to which, on January 25, 2019, NOLA Merger Sub merged with and into ENLK, with ENLK continuing as the surviving entity and as a subsidiary of ENLC. As a result of the Merger:

•Each issued and outstanding ENLK common unit (except for ENLK common units held by ENLC and its subsidiaries) was converted into 1.15 ENLC common units, which resulted in ENLC owning all of the remaining outstanding ENLK common units.

•Our general partner’s incentive distribution rights in ENLK were eliminated.

•The Series B Preferred Units continue to be issued and outstanding, except that certain terms of the Series B Preferred Units have been modified pursuant to an amended partnership agreement of ENLK. See “Note 7—Partners' Capital” for additional information regarding the modified terms of the Series B Preferred Units.

•ENLC issued to Enfield, the current holder of the Series B Preferred Units, for no additional consideration, ENLC Class C Common Units equal to the number of Series B Preferred Units held by Enfield immediately prior to the effective time of the Merger, in order to provide Enfield with certain voting rights with respect to ENLC. For each additional Series B Preferred Unit issued by ENLK in quarterly in-kind distributions, ENLC will issue an additional ENLC Class C Common Unit to the applicable holder of such Series B Preferred Unit. In addition, for each Series B Preferred Unit that is exchanged into an ENLC common unit, an ENLC Class C Common Unit will be canceled.

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Notes to Consolidated Financial Statements (Continued)

(Unaudited)

•The Series C Preferred Units and all of ENLK’s then-existing senior notes continue to be issued and outstanding following the Merger.

•Each unit-based award issued and outstanding immediately prior to the effective time of the Merger under the GP Plan has been converted into an award with respect to ENLC common units with substantially similar terms as were in effect immediately prior to the effective time.

•Each unit-based award with performance-based vesting conditions issued and outstanding immediately prior to the effective time of the Merger under the GP Plan and the 2014 Plan has been modified such that the performance metric for such award relates (on a weighted average basis) to (i) the combined performance of ENLC and ENLK for periods preceding the effective time of the Merger and (ii) the performance of ENLC for periods on and after the effective time of the Merger.

•ENLC assumed the outstanding debt under the Term Loan and ENLK became a guarantor thereof. See “Note 6—Long-Term Debt” for additional information regarding the Term Loan.

•We refinanced our existing revolving credit facilities at ENLK and ENLC. In connection with the Merger, ENLC entered into the Consolidated Credit Facility, with respect to which ENLK is a guarantor. See “Note 6—Long-Term Debt” for additional information regarding the Consolidated Credit Facility.

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~~East Texas and from our ~~south~~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~~West Texas and ~~central~~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 commodities purchased. While our transactions vary in form, the essential element of most of our transactions is the use of our assets to transport a product or provide a processed product to an end-user or marketer at the tailgate of the plant, pipeline, or barge, truck, or rail terminal.

1211

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Notes to Consolidated Financial Statements (Continued)

(Unaudited)

commodities purchased. While our transactions vary in form, the essential element of most of our transactions is the use of our assets to transport a product or provide a processed product to an end-user or marketer at the tailgate of the plant, pipeline, or barge, truck, or rail terminal.

(2) Significant Accounting Policies

a.Basis of Presentation

The accompanying consolidated financial statements ~~are~~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, ~~2018~~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 and nine months ended September 30, 2019, we had contractual commitments of $38.9 million and $113.6 million under our MVC contracts, respectively, and recorded $6.5 million and $14.2 million of revenue due to volume shortfalls, respectively. 12

MVC and Firm Transportation Commitments (1)
2019 (remaining)	$	58.9
2020	259.8
2021	108.1
2022	94.7
2023	85.7
Thereafter	237.0
Total	$	844.2

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ENLINK MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

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.

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ENLINK MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

c.Secured Term Loan Receivable

In late May 2019, White Star, the counterparty to our $58.0 million second lien secured term loan receivable, filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code. Under the original term loan agreement executed in May 2018, White Star was scheduled to make an installment payment of $19.5 million in April 2019. In November 2018 and again in February 2019, we amended the installment payment terms with the result that the single 2019 installment payment was split into two payments of $9.75 million in May 2019 and $10.75 million in October 2019. White Star defaulted on its May 2019 installment payment prior to filing for reorganization under Chapter 11 of the U.S. Bankruptcy Code. While the outcome of the bankruptcy proceeding is not yet finalized, we do not believe that it is probable that White Star will be able to repay the outstanding amounts owed to us under the second lien secured term loan. As a result, we have recorded a $52.9 million loss in our consolidated statement of operations for the nine months ended September 30, 2019, which represents a full write-down of the second lien secured term loan.

d.Accounting Standards to be Adopted in Future Periods

On August 29, 2018, the FASB issued ASU 2018-15, Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract (“ASU 2018-15”), which amends ASC 350-40, Internal-Use Software (“ASC 350-40”) to address a customer’s accounting for implementation costs incurred in a cloud computing arrangement that is a service contract. 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. We do not believe ASU 2018-15 will have a material impact on our financial statements, except 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 statement of operations, rather than “Depreciation and amortization.” We will adopt ASU 2018-15 prospectively effective January 1, 2020.

e.Adopted Accounting Standards

Effective January 1, ~~2019~~2020, we adopted ~~ASC~~ASU ~~842~~2018-15, ~~Leases,~~Customer’s ~~using~~Accounting ~~the~~for ~~modified~~Implementation ~~retrospective~~Costs ~~approach~~Incurred ~~whereby~~in wea ~~recognized~~Cloud ~~leases~~Computing onArrangement ~~our~~That ~~consolidated~~Is ~~balance~~a ~~sheet~~Service byContract ~~recording~~(Topic a350): ~~right~~Internal-ofUse Software. ASU 2018-~~use~~15 ~~asset~~aligns ~~and~~the ~~lease~~accounting ~~liability.~~for Wecosts ~~applied~~incurred ~~certain~~to ~~practical~~implement ~~expedients~~a ~~that~~cloud ~~were~~computing ~~allowed~~arrangement inthat ~~the~~is ~~adoption~~a ofservice ~~ASC~~arrangement ~~842,~~with ~~including~~the ~~not~~guidance ~~reassessing~~on ~~existing~~capitalizing ~~contracts~~costs ~~for~~associated ~~lease~~with ~~arrangements,~~developing ~~not~~or ~~reassessing~~obtaining ~~existing~~internal-use ~~lease~~software. ~~classification~~Specifically, ~~not~~the ~~recording~~ASU aamends ~~right~~ASC 350-~~of-use~~40 ~~asset~~to orinclude ~~lease~~in ~~liability~~its ~~for~~scope ~~leases~~implementation costs of ~~twelve~~a ~~months~~cloud orcomputing ~~less,~~arrangement ~~and~~that ~~not~~is ~~separating~~a ~~lease~~service contract and ~~non~~clarifies that a customer should apply ASC 350-~~lease~~40 ~~components~~to ofdetermine which implementation costs should be capitalized in a ~~lease~~cloud computing arrangement. Inthat ~~connection~~is ~~with~~considered ~~the~~a ~~adoption~~service ofcontract. ~~ASC~~For ~~842~~the inthree ~~January~~months ~~2019~~ended March 31, 2020, we ~~recorded~~did anot ~~lease~~capitalize ~~liability~~any ofcloud ~~$97~~computing costs.6 ~~million~~However, ato ~~right-of-use~~the ~~asset~~extent offuture ~~$75.3~~costs ~~million,~~incurred ~~and~~in a ~~reduction~~cloud ofcomputing ~~$22.6~~arrangement ~~million~~are incapitalizable, ~~other~~the ~~liabilities~~corresponding ~~previously~~amortization ~~recorded~~will ~~related~~be toincluded ~~lease~~in ~~incentives.~~“Operating ~~For~~expenses” ~~additional~~or ~~information~~“General ~~about~~and ~~our~~administrative” ~~adoption~~in ofthe ~~ASC~~consolidated ~~842~~statements of operations, ~~refer~~rather tothan “~~Note~~Depreciation ~~5—Leases~~and amortization.”

Effective January 1, 2020, we adopted ASU 2016-13, Financial Instruments—Credit Losses (3Topic 326). ~~Goodwill~~The updates in ASU 2016-13 provide financial statement users with more information about the expected credit losses on financial instruments and ~~Intangible~~other ~~Assets~~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.

~~Goodwill~~(3) Intangible Assets

~~During~~The ~~the~~following ~~third~~table ~~quarter~~represents ~~of 2019, we performed an interim impairment test due to a significant decline in ENLC’s unit price from the first quarter and downward revisions in~~ our ~~estimated~~change ~~future cash flows due to delays~~ in ~~development~~carrying ~~plans~~value ~~announced by certain~~ of ~~our~~intangible ~~major~~assets ~~customers.~~(in Wemillions): ~~determined that no impairments of goodwill were required as of September 30, 2019.~~

Intangible Assets


	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

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ENLINK MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

The following table represents our change in carrying value of intangible assets (in millions):

	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount
Nine Months Ended September 30, 2019
Customer relationships, beginning of period	$	1,795.8	$	(422.2)	$	1,373.6
Amortization expense	—		(92.8)		(92.8)
Customer relationships, end of period	$	1,795.8	$	(515.0)	$	1,280.8

The weighted average amortization period is 15.0 years. Amortization expense was $30.9 million for each of the three months ended September 30, 2019 and 2018, and $92.8 million and $92.6 million for the nine months ended September 30, 2019 and 2018, respectively.

The following table summarizes our estimated aggregate amortization expense for the next five years and thereafter (in millions):

2019 (remaining)	$	30.9
2020	123.7
2021	123.7
2022	123.7
2023	123.6
Thereafter	755.2
Total	$	1,280.8

(4) Related Party Transactions

a.Transactions with ENLC

Simplification of the Corporate Structure. On October 21, 2018, ENLK, ENLC, the general partner of ENLK, the managing member of ENLC, and NOLA Merger Sub entered into the Merger Agreement pursuant to which, on January 25, 2019, NOLA Merger Sub merged with and into ENLK, with ENLK continuing as the surviving entity and as a subsidiary of ENLC. See “Note 1—General” for more information on this transaction.

Transfer of EOGP Interest. On January 31, 2019, ENLC transferred its 16.1% limited partner interest in EOGP to the Operating Partnership in exchange for 55,827,221 ENLK common units, resulting in the Operating Partnership owning 100% of the limited partner interests in EOGP.

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 $814.28 million and $118.41 million atas ~~September~~of March 3031, ~~2019~~2020 and December 31, ~~2018~~2019, respectively.

b.Transactions with ~~Devon~~Cedar Cove JV

OnFor ~~July~~the ~~18,~~three ~~2018,~~months ~~subsidiaries~~ended ~~of Devon sold all of their equity interests in ENLK~~March 31, ~~ENLC,~~2020 and ~~the~~2019, ~~managing~~we ~~member~~recorded cost of ~~ENLC~~sales ~~to GIP for aggregate consideration~~ of $32.~~125~~9 ~~billion~~million and $8.1 ~~Accordingly~~million, ~~Devon is no longer an affiliate of ENLK or ENLC. The sale did not affect our commercial arrangements with Devon~~respectively, ~~except~~related ~~that Devon agreed~~ to ~~extend~~our ~~through~~purchase ~~2029~~of ~~certain~~residue ~~existing~~gas ~~fixed-fee gathering~~ and ~~processing~~NGLs ~~contracts~~from ~~related to~~ the ~~Bridgeport~~Cedar ~~plant~~Cove inJV ~~north~~subsequent ~~Texas~~to ~~and~~processing ~~the~~at ~~Cana~~its ~~plant~~Central in Oklahoma. ~~Prior~~processing tofacilities. ~~July 18~~Additionally, ~~2018,~~we ~~revenues~~had ~~from~~accounts ~~transactions~~payable ~~with~~balances ~~Devon are included in “Product sales—~~related ~~parties”~~to ortransactions ~~“Midstream~~with ~~services—related parties” in~~ the ~~consolidated~~Cedar ~~statement~~Cove JV of ~~operations~~$0.5 ~~Revenues~~million ~~from~~and ~~transactions~~$1.1 ~~with~~million ~~Devon~~at ~~after July 18~~March 31, ~~2018~~2020 ~~are~~and ~~included~~December 31, in2019, ~~“Product sales” or “Midstream services” in the consolidated statement of operations~~respectively.

For the three and nine months ended September 30, 2018, related party revenues from Devon accounted for 2.0% and 7.3%, respectively, of our revenues.

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Notes to Consolidated Financial Statements (Continued)

(Unaudited)

c.Transactions with Cedar Cove JV

For the three and nine months ended September 30, 2019, we recorded cost of sales of $4.1 million and $18.0 million, respectively, and for the three and nine months ended September 30, 2018, we recorded cost of sales of $11.3 million and $33.8 million, respectively, related to our purchase of residue gas and NGLs from the Cedar Cove JV subsequent to processing at our central Oklahoma processing facilities. We had no accounts receivable balances related to transactions with the Cedar Cove JV at September 30, 2019 and $0.7 million at December 31, 2018. Additionally, we had accounts payable balances related to transactions with the Cedar Cove JV of $3.6 million and $4.3 million at September 30, 2019 and December 31, 2018, respectively.

Management believes the foregoing transactions with related parties were executed on terms that are fair and reasonable to us. The amounts related to related party transactions are specified in the accompanying consolidated financial statements.

(5) Leases

Effective with the adoption of ASC 842 in January 2019, we evaluate new contracts at inception to determine if the contract conveys the right to control the use of an identified asset for a period of time in exchange for periodic payments. A lease exists if we obtain substantially all of the economic benefits of an asset, and we have the right to direct the use of that asset. When a lease exists, we record a right-of-use asset that represents our right to use the asset over the lease term and a lease liability that represents our obligation to make payments over the lease term. Lease liabilities are recorded at the sum of future lease payments discounted by the collateralized rate we could obtain to lease a similar asset over a similar period, and right-of-use assets are recorded equal to the corresponding lease liability, plus any prepaid or direct costs incurred to enter the lease, less the cost of any incentives received from the lessor. The majority of our leases are for the following types of assets:

•Office space. Our primary offices are in Dallas, Houston, and Midland, with smaller offices in other locations near our assets. Our office leases are long-term in nature and represent $61.3 million of our lease liability and $40.6 million of our right-of-use asset as of September 30, 2019. These office leases typically include variable lease costs related to utility expenses, which are determined based on our pro-rata share of the building expenses each month and expensed as incurred.

•Compression and other field equipment. We pay third parties to provide compressors or other field equipment for our assets. Under these agreements, a third party installs and operates compressor units based on specifications set by us to meet our compression needs at specific locations. While the third party determines which compressors to install and operates and maintains the units, we have the right to control the use of the compressors and are the sole economic beneficiary of the identified assets. These agreements are typically for an initial term of one to three years but will automatically renew from month to month until canceled by us or the lessor. Compression and other field equipment rentals represent $26.4 million of our lease liability and $26.3 million of our right-of-use asset as of September 30, 2019. Under certain agreements, we may incur variable lease costs related to incidental services provided by the equipment lessor, which are expensed as incurred.

•Office equipment. We rent office equipment for a monthly fee. These leases are typically for several years and represent $0.7 million of our lease liability and $0.7 million of our right-of-use asset as of September 30, 2019.

•Land and land easements. We make periodic payments to lease land or to have access to our assets. Land leases and easements are typically long-term to match the expected useful life of the corresponding asset and represent $15.1 million of our lease liability and $13.0 million of our right-of-use asset as of September 30, 2019.

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ENLINK MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

Lease balances are recorded on the consolidated balance sheets as follows (in millions):

	September 30, 2019
	March 31, 2020			December 31, 2019
Operating leases:
Other assets, net	$	8074.65		$	80.4
Other current liabilities	$	2117.36		$	21.1
Other long-term liabilities	$	8278.28		$	81.9
Other lease information
Weighted-average remaining lease term—Operating leases	1011.70 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 September 30,				Nine Months Ended September 30,
	Three Months EndedMarch 31,
	2019				2019
	2020		2019
Finance lease expense:
Amortization of right-of-use asset	$	~~2.2~~—	$	0.7	$	~~5.2~~
Interest on lease liability	0.1				0.1
Operating lease expense:
Long-term operating lease expense	76.24		6.3		~~21.8~~
Short-term lease expense	95.5		6.9		~~25.3~~
Variable lease expense	12.38		1.6		~~4.3~~
Total lease expense	$	2014.37	$	15.5	$	~~56.7~~

~~Other information about our leases is presented below (in millions):~~ 15

	Three Months Ended September 30,		Nine Months Ended September 30,
	2019		2019
Supplemental cash flow information:
Cash payments for finance leases included in cash flows from financing activities	$	0.4	$	1.2
Cash payments for operating leases included in cash flows from operating activities	$	7.2	$	22.6
Right-of-use assets obtained in exchange for operating lease liabilities	$	3.2	$	98.4

The following table summarizes the maturity of our lease liability as of September 30, 2019 (in millions):

	Total		2019 (remaining)		2020		2021		2022		2023		Thereafter
Undiscounted operating lease liability	$	142.7	$	6.7	$	23.5	$	17.1	$	10.2	$	9.0	$	76.2
Reduction due to present value	(39.2)		(1.3)		(4.5)		(3.8)		(3.4)		(3.1)		(23.1)
Operating lease liability	103.5		5.4		19.0		13.3		6.8		5.9		53.1
Total lease liability	$	103.5	$	5.4	$	19.0	$	13.3	$	6.8	$	5.9	$	53.1

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ENLINK MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

Other information about our leases is presented below (in millions):


	Three Months Ended March 31,
	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

(6) Long-Term Debt

As of ~~September~~March 3031, ~~2019~~2020 and December 31, ~~2018~~2019, long-term debt consisted of the following (in millions):

	September 30, 2019										December 31, 2018
	March 31, 2020										December 31, 2019
	Outstanding Principal		Premium (Discount)		Long-Term Debt		Outstanding Principal		Premium (Discount)		Long-Term Debt
Related party debt	$	1,~~513~~900.50	$	—	$	1,~~513~~900.50	$	—1,700.0	$	—	$	—1,700.0
Term Loan due 2021 (1)	—		—		—		850.0		—		850.0
4.40% Senior unsecured notes due 2024	545.0		1.4		546.4		550.0		1.5		551.5
2.70% Senior unsecured notes due 2019 (2)	—		—		—		400.0		—		400.0
4.15% Senior unsecured notes due 2025	747.5		(0.7)		746.8		750.0		(0.7)		749.3
4.40% Senior unsecured notes due 2024	550.0		1.6		551.6		550.0		1.8		551.8
4.85% Senior unsecured notes due 2026	497.0		(0.4)		496.6		500.0		(0.5)		499.5
4.15% Senior unsecured notes due 2025	750.0		(0.7)		749.3		750.0		(0.9)		749.1
4.85% Senior unsecured notes due 2026	500.0		(0.5)		499.5		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		(65.09)		444.01		450.0		(65.29)		~~443~~444.81
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,~~613~~989.5	$	(5.9)	4,~~607~~983.6		$	4,~~350~~800.0	$	(65.19)	4,~~343~~794.91
Debt issuance cost (3)					(30.8)						(24.3)
Debt issuance cost (1)					(28.8)						(29.8)
Less: Current maturities of long-term debt (2)					—						(399.8)
Long-term debt, net of unamortized issuance cost					$	4,954.8					$	4,764.3
Long-term debt, net of unamortized issuance cost					$	4,576.8					$	3,919.8

____________________________

(1)InNet ~~December~~of ~~2018,~~amortization ~~ENLK~~of ~~entered into an~~ $~~850~~11.09 million, ~~three-year unsecured Term Loan. Borrowings under the Term Loan bear interest based on Prime~~ and~~/or~~ ~~LIBOR plus an applicable margin~~$10. ~~The effective interest rate was 3.~~9% million at ~~December~~March 31, ~~2018.~~2020 Inand ~~connection with the closing of the Merger~~December 31, ~~the Term Loan was assumed by ENLC~~2019, ~~and we became a guarantor of the Term Loan~~respectively.

(2)The 2.70% senior unsecured notes matured on April 1, 2019. Therefore, the outstanding principal balance, net of discount and debt issuance costs, is classified as “Current maturities of long-term debt” on the consolidated balance sheet as of December 31, 2018.

(3)Net of amortization of $9.8 million and $15.3 million at September 30, 2019 and December 31, 2018, 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 ~~September~~March 3031, 2020 and December 31, 2019, $1~~,513~~.59 ~~million~~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.

~~Issuance and Repayment of Senior Unsecured Notes~~ 16

On April 9, 2019, ENLC issued $500.0 million in aggregate principal amount of ENLC’s 5.375% senior unsecured notes due June 1, 2029 (the “2029 Notes”) at a price to the public of 100% of their face value. Interest payments on the 2029 Notes are payable on June 1 and December 1 of each year, beginning December 1, 2019. The 2029 Notes are fully and unconditionally guaranteed by ENLK. Net proceeds of approximately $496.5 million were used to repay outstanding borrowings under the Consolidated Credit Facility, including borrowings incurred on April 1, 2019 to repay at maturity all of the $400.0 million outstanding aggregate principal amount of ENLK’s 2.70% senior unsecured notes due 2019, and for general limited liability company purposes.

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ENLINK MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

Consolidated Credit Facility

OnThe ~~December 11, 2018, ENLC entered into the~~ Consolidated Credit Facility, ~~which~~ permits ENLC to borrow up to $1.75 billion on a revolving credit basis and includes a $500.0 million letter of credit subfacility. The Consolidated Credit Facility became available for borrowings and letters of credit upon closing of the Merger. In addition, ENLK became a guarantor under the Consolidated Credit Facility upon the closing of the Merger. In the event that ENLC defaults on the Consolidated Credit Facility, ENLK will be liable for the entire outstanding balance ($~~275~~550.0 million as of ~~September~~March 3031, ~~2019~~2020), and 105% of the outstanding letters of credit under the Consolidated Credit Facility ($418.08 million as of ~~September 30~~March 31, ~~2019~~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 (~~the~~ LIBOR ~~Rate~~) 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 ~~September~~March 3031, ~~2019~~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 $~~275~~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. ~~On December 11, 2018, ENLK borrowed $850.0 million under the Term Loan and used the net proceeds to repay obligations outstanding under the ENLK Credit Facility.~~ 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 ~~immediately~~ becomes due, ~~and~~ 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 ~~September~~March 3031, ~~2019~~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.

19Borrowings 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

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ENLINK MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

Borrowings under the Term Loan bear interest at ENLC’s option at the Eurodollar Rate (the LIBOR Rate) 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 ~~September~~March 3031, ~~2019~~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.

20Senior Unsecured Notes Repurchases

~~Table~~For the three months ended March 31, 2020, we made aggregate payments of ~~Contents~~$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.

~~ENLINK~~(7) ~~MIDSTREAM~~Partners’ ~~PARTNERS,~~Capital ~~LP AND SUBSIDIARIES~~

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

(7) Partners' Capital

a.Series B Preferred Units

~~Prior~~Income tois ~~the~~allocated ~~closing~~to of the ~~Merger,~~ Series B Preferred ~~Unit~~Units ~~distributions were payable quarterly~~ in ~~cash at~~ an amount equal to ~~$0.28125 per Series B Preferred Unit (~~the ~~“Cash~~quarterly ~~Distribution Component”) plus an in-kind~~ distribution ~~equal~~with respect to the ~~greater~~period ofearned. (A) ~~0.0025~~summary ~~Series B Preferred Units per Series B Preferred Unit and (B) an amount equal to (i) the excess, if any,~~ of the distribution ~~that~~activity ~~would~~relating ~~have~~to ~~been payable had~~ the Series B Preferred Units ~~converted~~during ~~into ENLK common units over~~ the ~~Cash~~three ~~Distribution~~months ~~Component~~ended March 31, ~~divided~~2020 byand ~~(ii)~~2019 ~~the~~is ~~issue~~provided ~~price~~below: ~~of $15.00 (the “Issue Price”).~~

Following the closing of the Merger, and beginning with the quarter ended March 31, 2019, the holder of the Series B Preferred Units is entitled to quarterly cash distributions and distributions in-kind of additional Series B Preferred Units as described below. The quarterly in-kind distribution (the “Series B PIK Distribution”) equals the greater of (A) 0.0025 Series B Preferred Units per Series B Preferred Unit and (B) the number of Series B Preferred Units equal to the quotient of (x) the excess (if any) of (1) the distribution that would have been payable by ENLC had the Series B Preferred Units been exchanged for ENLC common units but applying a one-to-one exchange ratio (subject to certain adjustments) instead of the exchange ratio of 1.15 ENLC common units for each Series B Preferred Unit, subject to certain adjustments (the “Series B Exchange Ratio”), over (2) the Cash Distribution Component, divided by (y) the Issue Price. The quarterly cash distribution consists of the Cash Distribution Component plus an amount in cash that will be determined based on a comparison of the value (applying the Issue Price) of (i) the Series B PIK Distribution and (ii) the Series B Preferred Units that would have been distributed in the Series B PIK Distribution if such calculation applied the Series B Exchange Ratio instead of the one-to-one ratio (subject to certain adjustments).


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

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 nine months ended September 30, 2019 and 2018 is provided below:

Declaration period	Distribution paid as additional Series B Preferred Units	Cash Distribution (in millions)		Date paid/payable
2019
Fourth Quarter of 2018	425,785	$	16.5	February 13, 2019
First Quarter of 2019	147,887	$	16.7	May 14, 2019
Second Quarter of 2019	148,257	$	17.1	August 13, 2019
Third Quarter of 2019	148,627	$	17.1	November 13, 2019
2018
Fourth Quarter of 2017	413,658	$	16.0	February 13, 2018
First Quarter of 2018	416,657	$	16.2	May 14, 2018
Second Quarter of 2018	419,678	$	16.3	August 13, 2018
Third Quarter of 2018	422,720	$	16.4	November 13, 2018

b.Series C Preferred Units

~~Distributions~~There onwas ~~the~~no Series C Preferred Units accrue and are cumulative from the date of original issue and payable semi-annually in arrears on the 15th day of June and December of each year through and including December 15, 2022 and, thereafter, quarterly in arrears on the 15th day of March, June, September, and December of each year, in each case, if and when declared by our general partner out of legally available funds for such purpose. The initial distribution ~~rate~~activity ~~for~~relating ~~the Series C Preferred Units from and including the date of original issue~~ to, ~~but not including, December 15, 2022 is 6.0% per annum. On and after December 15, 2022, distributions on~~ the Series C Preferred Units ~~will~~during ~~accumulate for each distribution period at a percentage of~~ the ~~$1,000 liquidation preference per unit equal to an annual floating rate of the~~ three~~-month~~ ~~LIBOR~~months ~~plus~~ended aMarch 31, ~~spread~~2020 ofand 42019.~~11%. Income is allocated to the Series C Preferred Units in an amount equal to the earned distributions for the respective reporting period.~~

Following the Merger, the Series C Preferred Units remained issued and outstanding with the terms set forth above.

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ENLINK MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

c.Common Unit Distributions

~~Following~~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 ~~distributed~~no ~~$139~~longer have publicly held common units.8 ~~million~~ENLC owns all of our outstanding common units and ~~$277.0~~we ~~million~~make quarterly distributions to ENLC related to its ownership of our common units. ~~for~~For the three ~~and nine~~ months ended ~~September~~March 3031, ~~2019~~2020, ~~respectively~~we distributed $93.3 million to ENLC related to its ownership of our common units.

A summary of the distribution activity relating to the common units for periods prior to the Merger is provided below:

Declaration period	Distribution/unit		Date paid/payable
2019
Fourth Quarter of 2018	$	0.39	February 13, 2019
2018
Fourth Quarter of 2017	$	0.39	February 13, 2018
First Quarter of 2018	$	0.39	May 14, 2018
Second Quarter of 2018	$	0.39	August 13, 2018
Third Quarter of 2018	$	0.39	November 13, 2018

d.Allocation of ENLK Income

~~Prior~~The ~~to the closing of the Merger and for the three and nine months ended September 30, 2018,~~ net income ~~was~~(loss) allocated to our general partner inis anas ~~amount~~follows ~~equal to its incentive distribution rights. Prior to the closing of the Merger, we were required to pay our general partner incentive distributions~~ (in the amount of 13.0% of ENLK distributions in excess of $0.25 per unit, 23.0% of ENLK distributions in excess of $0.3125 per unit, and 48.0% of ENLK distributions in excess of $0.375 per unit. Our general partner was not entitled to incentive distributions with respect to (imillions) distributions on the Series B Preferred Units until such units converted into common units or (ii) the Series C Preferred Units. At the closing of the Merger, our general partner’s incentive distribution rights were eliminated. :

For the three and nine months ended September 30, 2018, our general partner’s share of net income consisted of incentive distribution rights to the extent earned, a deduction for unit-based compensation attributable to ENLC’s restricted units, and the percentage interest of our net income adjusted for ENLC’s unit-based compensation specifically allocated to our general partner. The net income allocated to our general partner is as follows (in millions):


	Three Months Ended March 31,
	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)

	Three Months EndedSeptember 30,						Nine Months EndedSeptember 30,
	2019		2018		2019		2018
Income allocation for incentive distributions	$	—	$	15.0	$	—	$	44.6
Unit-based compensation attributable to ENLC’s restricted and performance units	(11.1)		(7.3)		(29.6)		(15.7)
General partner share of net income	0.4		—		0.6		0.6
General partner interest in EOGP acquisition	—		5.6		2.4		22.4
General partner interest in net income (loss)	$	(10.7)	$	13.3	$	(26.6)	$	51.9

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ENLINK MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

(8) Investment in Unconsolidated Affiliates

As of ~~September~~March 3031, ~~2019~~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):

The following table shows the activity related to our investment in unconsolidated affiliates for the periods indicated (in millions):


	Three Months Ended March 31,
	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

	Three Months EndedSeptember 30,						Nine Months EndedSeptember 30,
	2019		2018		2019		2018
GCF
Distributions	$	5.1	$	5.3	$	14.7	$	16.4
Equity in income	$	4.4	$	4.6	$	15.3	$	14.0
Cedar Cove JV
Contributions	$	—	$	—	$	—	$	0.1
Distributions	$	0.3	$	—	$	0.8	$	0.3
Equity in loss	$	(0.4)	$	(0.3)	$	(1.3)	$	(2.3)
Total
Contributions	$	—	$	—	$	—	$	0.1
Distributions	$	5.4	$	5.3	$	15.5	$	16.7
Equity in income	$	4.0	$	4.3	$	14.0	$	11.7

The following table shows the balances related to our investment in unconsolidated affiliates as of March 31, 2020 and December 31, 2019 (in millions):

The following table shows the balances related to our investment in unconsolidated affiliates as of September 30, 2019 and December 31, 2018 (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

	September 30, 2019		December 31, 2018
GCF	$	42.5	$	41.9
Cedar Cove JV	36.1		38.2
Total investment in unconsolidated affiliates	$	78.6	$	80.1

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ENLINK MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

(9) Employee Incentive Plans

a.Long-Term Incentive Plans

~~Prior~~We toaccount ~~the~~for ~~Merger, ENLC and ENLK each had similar~~ unit-based compensation ~~payment~~in ~~plans~~accordance ~~for~~with ~~officers~~ASC ~~and~~718, ~~employees.~~which ~~ENLC~~requires ~~grants~~that compensation related to all unit-based awards ~~under~~be ~~the~~recognized ~~2014~~in ~~Plan,~~the ~~and~~consolidated ~~ENLK~~financial ~~granted~~statements. ~~unit~~Unit-based ~~awards~~compensation ~~under~~cost ~~the~~is GPvalued ~~Plan.~~at Asfair ofvalue at the ~~closing~~date of ~~the Merger~~grant, ~~(i)~~and ~~ENLC~~that ~~assumed~~grant ~~all~~date ~~obligations~~fair invalue ~~respect~~is ofrecognized ~~the~~as GPexpense ~~Plan~~over ~~and~~each ~~the~~award’s ~~outstanding~~requisite ~~awards~~service ~~granted~~period ~~thereunder~~with ~~(the~~a ~~“Legacy~~corresponding ~~ENLK~~increase ~~Awards”)~~to ~~and~~equity ~~(ii)~~or ~~the~~liability ~~Legacy ENLK Awards converted into ENLC unit-~~based ~~awards~~on ~~using~~ the ~~1.15~~terms ~~exchange~~of ~~ratio~~each ~~(as~~award ~~defined~~and in the ~~Merger~~appropriate ~~Agreement)~~accounting astreatment ~~the~~under ~~conversion~~ASC ~~rate~~718. InUnit-based ~~addition,~~compensation asassociated ofwith ~~the~~ENLC’s ~~closing~~unit-based ofcompensation ~~the~~plan ~~Merger~~awarded to directors, ~~the~~officers, ~~performance~~and ~~metric~~employees of ~~each~~our ~~Legacy~~general ~~ENLK~~partner ~~Award~~ and ~~each then outstanding award under~~ the ~~2014~~managing ~~Plan~~member ~~with~~of ~~performance-based~~ENLC ~~vesting~~is ~~conditions~~recorded ~~was~~by ~~modified~~ENLK assince ~~discussed~~ENLC inhas ~~(c)~~no ~~and~~substantial ~~(e)~~or ~~below.~~managed ~~Following~~operating ~~the~~activities ~~consummation~~other ofthan ~~the~~its ~~Merger,~~interests noin ~~additional awards will be granted under the GP Plan~~ENLK.

We account for unit-based compensation in accordance with ASC 718, Stock Compensation (“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 ENLC’s officers and employees is recorded by us since ENLC has no substantial or managed operating activities other than its interest in us.

Amounts recognized on the consolidated financial statements with respect to these plans are as follows (in millions):

	Three Months Ended September 30,						Nine Months Ended September 30,
	Three Months EndedMarch 31,
	2019		2018		2019		2018
	2020		2019
Cost of unit-based compensation charged to operating expense	$	2.12	$	50.23	$	~~4.5~~	$	~~9.5~~
Cost of unit-based compensation charged to general and administrative expense	106.06		1110.86		~~26.5~~		~~22.1~~
Total unit-based compensation expense	$	128.18	$	1710.09	$	~~31.0~~	$	~~31.6~~

~~b.EnLink Midstream Partners, LP Restricted Incentive Units~~19

ENLK restricted incentive units were valued at their fair value at the date of grant, which is equal to the market value of ENLK common units on such date. A summary of the restricted incentive unit activity for the nine months ended September 30, 2019 is provided below:

	Nine Months EndedSeptember 30, 2019
EnLink Midstream Partners, LP Restricted Incentive Units:	Number of Units	Weighted Average Grant-Date Fair Value
Non-vested, beginning of period	2,556,270	$	14.43
Vested (1)	(722,853)	10.02
Forfeited	(4,490)	11.93
Converted to ENLC (2)	(1,828,927)	16.11
Non-vested, end of period	—	$	—

____________________________

(1)Vested units included 249,201 units withheld for payroll taxes paid on behalf of employees.

(2)As a result of the Merger, the Legacy ENLK Awards converted into ENLC unit-based awards using the 1.15 exchange ratio (as defined in the Merger Agreement) as the conversion rate.

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ENLINK MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

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 and nine months ended September 30, 2019 and 2018 is provided below (in millions)b. ~~Since the Legacy ENLK Awards converted into~~ ENLC ~~unit-based~~Restricted ~~awards~~Incentive 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. Units

	Three Months Ended September 30,						Nine Months Ended September 30,
EnLink Midstream Partners, LP Restricted Incentive Units:	2019		2018		2019		2018
Aggregate intrinsic value of units vested	$	—	$	3.7	$	8.0	$	12.8
Fair value of units vested	$	—	$	2.8	$	7.2	$	16.1

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:

c.EnLink Midstream Partners, LP Performance Units


	Three Months Ended March 31, 2020
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

Prior to the Merger, our general partner granted performance awards under the GP Plan. The performance award agreements provided that the vesting of performance units (i.e., performance-based restricted incentive units) granted thereunder was dependent on the achievement of certain total shareholder return (“TSR”) performance goals relative to the TSR achievement of a peer group of companies (the “Peer Companies”) over the applicable performance period. The performance award agreements contemplated that the Peer Companies for an individual performance award (the “Subject Award”) were the companies comprising the AMZ, excluding ENLK and ENLC, on the grant date for the Subject Award. The performance units would vest based on the percentile ranking of the average of ENLK’s and ENLC’s TSR achievement (“EnLink TSR”) for the applicable performance period relative to the TSR achievement of the Peer Companies. As of the closing of the Merger, these performance-based Legacy ENLK Awards were modified, such that, the performance goal will, on a weighted average basis, (i) continue to relate to the EnLink TSR relative to the TSR performance of the Peer Companies in respect of periods preceding the effective time of the Merger; and (ii) relate solely to the TSR performance of ENLC relative to the TSR performance of such Peer Companies in respect of periods on and after the effective time of the Merger. 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 performance units ranges from zero to 200% of the performance units granted depending on the extent to which the related performance goals are achieved over the relevant performance period.

The fair value of each performance unit was estimated as of the date of grant using a Monte Carlo simulation with the following assumptions used for all performance unit grants made under the plan: (i) a risk-free interest rate based on United States Treasury rates as of the grant date; (ii) a volatility assumption based on the historical realized price volatility of ENLK’s common units and the designated Peer Companies’ securities; (iii) an estimated ranking of ENLK and ENLC among the designated Peer Companies; and (iv) the distribution yield. The fair value of the performance unit on the date of grant is expensed over a vesting period of approximately three years.

The following table presents a summary of the performance units:

	Nine Months EndedSeptember 30, 2019
EnLink Midstream Partners, LP Performance Units:	Number of Units	Weighted Average Grant-Date Fair Value
Non-vested, beginning of period	451,669	$	17.74
Vested (1)	(161,410)	10.54
Converted to ENLC (2)	(290,259)	28.31
Non-vested, end of period	—	$	—

____________________________

(1)~~Vested~~Restricted incentive units ~~included~~typically 62vest at the end of three years. In February 2020,~~403~~ ~~units~~ENLC ~~withheld~~granted ~~for~~1,144,842 ~~payroll~~restricted ~~taxes~~incentive ~~paid~~units onwith ~~behalf~~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)AsVested aunits ~~result~~included ~~of the Merger~~732,473 ~~the~~units ~~performance-based~~withheld ~~Legacy~~for ~~ENLK~~payroll ~~Awards~~taxes ~~converted~~paid ~~into~~on ~~ENLC~~behalf ~~unit-based~~of ~~performance awards using the 1~~employees.15 ~~exchange ratio (as defined in the Merger Agreement) as the conversion rate.~~

25A 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 March 31,
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.

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ENLINK MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

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 and nine months ended September 30, 2019 and 2018 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 September 30,						Nine Months Ended September 30,
EnLink Midstream Partners, LP Performance Units:	2019		2018		2019		2018
Aggregate intrinsic value of units vested	$	—	$	3.0	$	2.1	$	5.0
Fair value of units vested	$	—	$	3.6	$	1.7	$	7.7

d.EnLink Midstream, LLC Restricted Incentive Units

ENLC restricted incentive units are 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 nine months ended September 30, 2019 is provided below:

	Nine Months EndedSeptember 30, 2019
EnLink Midstream, LLC Restricted Incentive Units:	Number of Units		Weighted Average Grant-Date Fair Value
Non-vested, beginning of period	2,425,867		$	14.62
Granted (1)	1,875,490		11.39
Vested (1)(2)	(1,632,100)		11.55
Forfeited	(488,913)		14.39
Converted from ENLK (3)	2,103,266		14.01
Non-vested, end of period	4,283,610		$	14.10
Aggregate intrinsic value, end of period (in millions)	$	36.4

____________________________

(1)Restricted incentive units typically vest at the end of three years. In March 2019, ENLC granted 420,842 restricted incentive units with a fair value of $4.8 million to officers and certain employees as bonus payments for 2018, and these restricted incentive units vested immediately and are included in the restricted incentive units granted and vested line items.

(2)Vested units included 563,606 units withheld for payroll taxes paid on behalf of employees.

(3)Represents Legacy ENLK Awards that were converted into ENLC unit-based awards using the 1.15 exchange ratio (as defined in the Merger Agreement) as the conversion rate.

	Three Months Ended September 30,						Nine Months Ended September 30,
EnLink Midstream, LLC Restricted Incentive Units:	2019		2018		2019		2018
Aggregate intrinsic value of units vested	$	3.1	$	3.3	$	16.0	$	12.6
Fair value of units vested	$	5.8	$	2.6	$	18.9	$	16.1

As of September 30, 2019, there was $29.1 million of unrecognized compensation cost related to non-vested ENLC restricted incentive units. The cost is expected to be recognized over a weighted-average period of 1.8 years.

For restricted incentive unit awards granted after March 8, 2019 to certain officers and employees (the “grantee”), such awards (the “Subject Grants”) generally provide that, subject to the satisfaction of the conditions set forth in the agreement, the Subject Grants will vest on the third anniversary of the vesting commencement date (the “Regular Vesting Date”). The Subject Grants will be forfeited if the grantee’s employment or service with ENLC and its affiliates terminates prior to the Regular Vesting Date except that the Subject Grants will vest in full or on a pro-rated basis for certain terminations of employment or service prior to the Regular Vesting Date. For instance, the Subject Grants will vest on a pro-rated basis for any terminations of

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ENLINK MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

the grantee’s employment: (i) due to retirement, (ii) by ENLC or its affiliates without cause, or (iii) by the grantee for good reason (each, a “Covered Termination” and more particularly defined in the Subject Grants agreement) except that the Subject Grants will vest in full if the applicable Covered Termination is a “normal retirement” (as defined in the Subject Grants agreement) or the applicable Covered Termination occurs after a change of control (if any). The Subject Grants will vest in full if death or a qualifying disability occurs prior to the Regular Vesting Date.

e.EnLink Midstream, LLC’s 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 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.

Performance awards granted prior to March 8, 2019 provided that the vesting of performance units granted was dependent on the achievement of certain TSR performance goals relative to the TSR achievement of the Peer Companies over the applicable performance period. Prior to the Merger, vesting of the performance units was based on the percentile ranking of the EnLink TSR for the applicable performance period relative to the TSR achievement of the Peer Companies. As of the effective time of the Merger, these performance-based awards were modified, such that, the performance goal will, on a weighted average basis, (i) continue to relate to the EnLink TSR relative to the TSR performance of the Peer Companies in respect of periods preceding the effective time of the Merger; and (ii) relate solely to the TSR performance of ENLC relative to the TSR performance of such Peer Companies in respect of periods on and after the effective time of the Merger.

The following table presents a summary of the performance units:

	Nine Months EndedSeptember 30, 2019
	Three Months EndedMarch 31, 2020
EnLink Midstream, LLC Performance Units:	Number of Units		Weighted Average Grant-Date Fair Value
ENLC Performance Units:	Number of Units		Weighted Average Grant-Date Fair Value
Non-vested, beginning of period	~~418~~1,~~149~~317,856		$	1914.1522
Granted	~~931~~1,~~469~~161,986		137.0232
Vested (1)	(~~374~~160,~~745~~002)		2131.0813
Forfeited	(309,603)		15.28
Non-vested, end of period	2,319,840		$	9.60
Converted from ENLK (2)	333,798		25.84
Aggregate intrinsic value, end of period (in millions)	$	2.6
Non-vested, end of period	999,068		$	16.15
Aggregate intrinsic value, end of period (in millions)	$	8.5

____________________________

(1)Vested units included ~~146~~60,~~218~~920 units withheld for payroll taxes paid on behalf of employees.

~~(2)As~~A asummary ~~result~~ of the ~~Merger,~~performance ~~the~~units’ ~~performance-based~~aggregate ~~Legacy~~intrinsic ~~ENLK~~value ~~Awards~~(market ~~converted~~value ~~into~~at ~~ENLC~~vesting ~~performance-based~~date) ~~awards~~and ~~using~~fair ~~the~~value ~~1.15~~of ~~exchange~~units ~~ratio~~vested (asmarket ~~defined~~value inat ~~the~~date ~~Merger~~of ~~Agreement~~grant) asfor the ~~conversion~~three ~~rate~~months ended March 31, 2020 and 2019 is provided below (in millions).


	Three Months Ended March 31,
ENLC Performance Units:	2020		2019
Aggregate intrinsic value of units vested	$	0.9	$	1.8
Fair value of units vested	$	5.0	$	1.9

	Three Months Ended September 30,						Nine Months Ended September 30,
EnLink Midstream, LLC Performance Units:	2019		2018		2019		2018
Aggregate intrinsic value of units vested	$	1.6	$	2.8	$	3.4	$	4.7
Fair value of units vested	$	6.0	$	3.5	$	7.9	$	7.7

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.

AsThe offollowing ~~September 30,~~table ~~2019,~~presents ~~there~~a ~~was~~summary ~~$10.1 million~~ of ~~unrecognized~~the ~~compensation~~grant-date ~~cost~~fair ~~that~~value ~~related~~assumptions toby ~~non-vested ENLC~~ performance ~~units.~~unit ~~That~~grant ~~cost is expected to be recognized over a weighted-average period of 1.9 years.~~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 March 31,
ENLK Restricted Incentive Units:	2019
Aggregate intrinsic value of units vested	$	8.0
Fair value of units vested	$	7.2

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ENLINK MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

In connection with the GIP Transaction, certain outstanding performance unit agreements were modified to, among other things: (i) provide that the awards granted thereunder did not vest due to the closing of the GIP Transaction, and (ii) increase the minimum vesting of units from zero to 100% as described in our Current Report on Form 8-K filed with the Commission on July 23, 2018e.ENLK ~~The~~Performance modified performance units retained the original vesting schedules. As a result of the modifications, we will recognize an additional $2.1 million compensation cost over the life of these ENLC performance units. Units

InA ~~connection~~summary ~~with~~of the ~~Merger,~~performance ~~Legacy~~units’ ~~ENLK~~aggregate ~~Awards~~intrinsic ~~with~~value ~~“performance-based”~~(market value at vesting date) and ~~payment~~fair ~~conditions~~value ~~were~~of ~~modified~~units tovested ~~reflect~~(market value at date of grant) for the ~~Performance~~three ~~Metric~~months ~~Adjustment~~ended ~~(as~~March 31, ~~defined~~2019 inis ~~the~~provided ~~Merger~~below ~~Agreement~~(in millions). asSince ~~described~~the inLegacy ~~our~~ENLK ~~Current~~Awards ~~Report~~converted oninto ~~Form~~ENLC 8unit-Kbased ~~filed~~awards ~~with~~as ~~the~~a ~~Commission~~result onof ~~January~~the 29Merger, ~~2019.~~no ~~The~~additional ~~modified~~ performance units ~~retained~~will ~~the~~vest ~~original~~as ~~vesting~~ENLK ~~schedules.~~units Asunder athe ~~result~~GP ofPlan ~~the~~(such ~~modifications~~performance units, weas ~~will~~converted, ~~recognize~~are aneligible to vest as ENLC units) and no additional ~~$0.7~~expense ~~million~~will inbe ~~compensation~~recognized ~~costs~~after ~~over~~January ~~the~~25, ~~life~~2019 ofunder the ~~Legacy~~GP ~~ENLK Awards~~Plan.

2019 Performance Unit Awards


	Three Months Ended March 31,
ENLK Performance Units:	2019
Aggregate intrinsic value of units vested	$	2.1
Fair value of units vested	$	1.7

For performance awards granted after March 8, 2019 to the grantee, the vesting of performance units is dependent on (a) the grantee’s continued employment or service with ENLC or its affiliates for all relevant periods and (b) the TSR performance of ENLC (the “ENLC TSR”) and a performance goal based on cash flow (“Cash Flow”). At the time of grant, the Board of Directors of the managing member of ENLC (the “Board”) will determine the relative weighting of the two performance goals by including in the award agreement the number of units that will be eligible for vesting depending on the achievement of the TSR performance goals (the “Total TSR Units”) versus the achievement of the Cash Flow performance goals (the “Total CF Units”). These performance awards have four separate performance periods: (i) three performance periods are each of the first, second, and third calendar years that occur following the vesting commencement date of the performance awards and (ii) the fourth performance period is the cumulative three-year period from the vesting commencement date through the third anniversary thereof (the “Cumulative Performance Period”).

One-fourth of the Total TSR Units (the “Tranche TSR Units”) relates to each of the four performance periods described above. Following the end date of a given performance period, the Governance and Compensation Committee (the “Committee”) of the Board will measure and determine the ENLC TSR relative to the TSR performance of a designated group of peer companies (the “Designated Peer Companies”) to determine the Tranche TSR Units that are eligible to vest, subject to the grantee’s continued employment or service with ENLC or its affiliates through the end date of the Cumulative Performance Period. In short, the TSR for a given performance period is defined as (i)(A) the average closing price of a common equity security at the end of the relevant performance period minus (B) the average closing price of a common equity security at the beginning of the relevant performance period plus (C) reinvested dividends divided by (ii) the average closing price of a common equity security at the beginning of the relevant performance period.

The following table sets out the levels at which the Tranche TSR Units may vest (using linear interpolation) based on the ENLC TSR percentile ranking for the applicable performance period relative to the TSR achievement of the Designated Peer Companies:

Performance Level

Achieved ENLC TSRPosition Relative to Designated Peer Companies

Vesting percentageof the Tranche TSR Units

Below Threshold

Less than 25%

Threshold

Equal to 25%

50%

Target

Equal to 50%

100%

Maximum

Greater than or Equal to 75%

200%

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ENLINK MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

Approximately one-third of the Total CF Units (the “Tranche CF Units”) relates to each of the first three performance periods described above (i.e., the Cash Flow performance goal does not relate to the Cumulative Performance Period). The Board will establish the Cash Flow performance targets for purposes of the column in the table below titled “ENLC’s Achieved Cash Flow” for each performance period no later than March 31 of the year in which the relevant performance period begins. Following the end date of a given performance period, the Committee will measure and determine the Cash Flow performance of ENLC to determine the Tranche CF Units that are eligible to vest, subject to the grantee’s continued employment or service with ENLC or its affiliates through the end of the Cumulative Performance Period. In short, the Performance-Based Award Agreement defines Cash Flow for a given performance period as (A)(i) ENLC’s adjusted EBITDA minus (ii) interest expense, current taxes and other, maintenance capital expenditures, and preferred unit accrued distributions divided by (B) the time-weighted average number of ENLC’s common units outstanding during the relevant performance period. The following table sets out the levels at which the Tranche CF Units will be eligible to vest (using linear interpolation) based on the Cash Flow performance of ENLC for the performance period ending December 31, 2019:

Performance Level

ENLC’s Achieved Cash Flow

Vesting percentageof the Tranche CF Units

Below Threshold

Less than $1.43

Threshold

Equal to $1.43

50%

Target

Equal to $1.55

100%

Maximum

Greater than or Equal to $1.72

200%

The fair value of each performance unit is estimated as of the date of grant using a Monte Carlo simulation with the following assumptions used for all performance unit grants made under the plan: (i) a risk-free interest rate based on United States Treasury rates as of the grant date; (ii) a volatility assumption based on the historical realized price volatility of ENLC’s common units and the Designated Peer Companies’ or Peer Companies’ securities as applicable; (iii) an estimated ranking of ENLC (or for outstanding performance units granted prior to the Merger, ENLC and ENLK) among the Designated Peer Companies or Peer Companies, and (iv) the distribution yield. The fair value of the performance unit on the date of grant is expensed over a vesting period of approximately three years.

The following table presents a summary of the grant-date fair value assumptions by performance unit grant date:

EnLink Midstream, LLC Performance Units:	June 2019			March 2019
Grant-Date Fair Value	$	9.92		$	13.10
Beginning TSR price	$	9.84		$	10.92
Risk-free interest rate	1.72		%	2.42		%
Volatility factor	33.50		%	33.86		%
Distribution yield	11.5		%	9.7		%

(10) Derivatives

Interest Rate Swaps

WeIn ~~periodically~~April ~~enter~~2019, we entered into an ~~interest~~$850.0 million interest rate swap ~~swaps~~to ~~during~~manage the ~~debt~~interest ~~issuance~~rate ~~process~~risk toassociated ~~hedge~~with ~~variability~~our infloating-rate, ~~future long~~LIBOR-~~term~~based ~~debt~~borrowings. ~~interest~~Under ~~payments~~this ~~that~~arrangement, ~~may~~we ~~result~~pay ~~from~~a ~~changes~~fixed ~~in the benchmark~~ interest rate ~~(commonly~~of ~~the U~~2.S.28% ~~Treasury yield) prior to the debt being issued or to hedge variability~~ in ~~cash~~exchange ~~flows~~for onLIBOR-based ~~our~~ variable~~-rate~~ ~~debt. We designate~~ interest ~~rate~~through ~~swaps~~December as2021. ~~cash~~There ~~flow~~was ~~hedges~~no inineffectiveness ~~accordance~~related ~~with~~to ~~ASC~~this ~~815~~hedge.

InFor ~~April 2019, we entered into an $850.0 million interest rate swap to manage~~ the ~~interest~~three ~~rate~~months ~~risk~~ended ~~associated with our floating-rate~~March 31, ~~LIBOR-based borrowings. Under this arrangement~~2020, we ~~pay~~recorded ~~a fixed interest rate of 2~~$17.~~27825%~~1 inmillion ~~exchange~~into ~~for~~accumulated ~~LIBOR-based~~other ~~variable~~comprehensive ~~interest~~loss ~~through December 2021. Assets or liabilities~~ related to ~~this~~changes ~~interest rate swap contract are included~~ in ~~the~~ fair value of ~~derivative~~our assets and liabilities on the consolidated balance sheets, and the change in fair value of this contract is recorded net as gain or loss on designated cash flow hedges on the consolidated statements of comprehensive income. Monthly, upon settlement, we reclassify the gain or loss associated with the interest rate ~~swap into interest expense from accumulated other comprehensive income (loss)~~swaps. ~~There is no ineffectiveness related to this hedge.~~

29For 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.

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Notes to Consolidated Financial Statements (Continued)

(Unaudited)

In May 2017, we entered into an interest rate swap in connection with the issuance of our 2047 Notes. Upon settlement of the interest rate swap in May 2017, we recorded the associated $2.2 million settlement loss in accumulated comprehensive loss on the consolidated balance sheets. We will amortize the settlement loss into interest expense on the consolidated statements of operations over the term of the 2047 Notes. There was no ineffectiveness related to the hedge.

For the three and nine months ended September 30, 2019, we recorded $1.8 million and $15.3 million, respectively, into accumulated other comprehensive loss related to changes in fair value of our interest rate swaps.

For the three and nine months ended September 30, 2019, we realized a gain of $0.1 million and $0.4 million, respectively, related to the monthly settlement of our interest rate swaps and an immaterial amount of amortization, which we recorded into interest expense, net of interest income from accumulated other comprehensive loss. For the three and nine months ended September 30, 2018, we recorded an immaterial amount into interest expense, net of interest income from accumulated other comprehensive loss. We expect to recognize $5.3 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):

	September 30, 2019
	March 31, 2020		December 31, 2019
Fair value of derivative liabilities—current	$	(516.21)	$	(5.6)
Fair value of derivative liabilities—long-term	(1013.24)		(6.8)
Net fair value of derivatives	$	(15.4)
Net fair value of interest rate swaps	$	(29.5)	$	(12.4)

Commodity Swaps

The components of gain ~~(loss)~~ on derivative activity in the consolidated statements of operations related to commodity swaps are (in millions):

	Three Months Ended September 30,						Nine Months Ended September 30,
	Three Months EndedMarch 31,
	2019		2018		2019		2018
	2020		2019
Change in fair value of derivatives	$	(013.5)0	$	(02.80)	$	~~4.7~~	$	~~(14.8)~~
Realized gain (loss) on derivatives	8.0		(4.6)		11.5		(5.3)
Realized gain on derivatives	6.2		3.8
Gain (loss) on derivative activity	$	7.5	$	(5.4)	$	16.2	$	(20.1)
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):

	September 30, 2019		December 31, 2018
	March 31, 2020		December 31, 2019
Fair value of derivative assets—current	$	975.60	$	2812.69
Fair value of derivative assets—long-term	78.92		4.13
Fair value of derivative liabilities—current	(461.38)		(218.8)
Fair value of derivative liabilities—long-term	—		(2.4)
Net fair value of commodity swaps	$	21.4	$	8.4
Net fair value of derivatives	$	13.2	$	8.5

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Notes to Consolidated Financial Statements (Continued)

(Unaudited)

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 ~~September~~March 3031, ~~2019~~2020 (in millions). The remaining term of the contracts extend no later than December 2022.

September 30, 2019

March 31, 2020

Commodity

Instruments

Unit

Volume

Net Fair Value

NGL (short contracts)

Swaps

Gallons

(39155.78)

28.59

NGL (long contracts)

Swaps

Gallons

8.81

(0.63)

Natural gas (short contracts)

Swaps

MMBtu

(420.73)

0.25

Natural gas (long contracts)

Swaps

MMBtu

115.90

(0.15)

Crude and condensate (short contracts)

Swaps

MMbbls

(1213.02)

7(46.20)

Crude and condensate (long contracts)

Swaps

MMbbls

12.61

358.8

Total fair value of derivatives

13.2

Total fair value of commodity swaps

21.4

On all transactions where we are exposed to counterparty risk, we analyze the counterparty’s financial condition prior to entering into an agreement, establish limits, and monitor the appropriateness of these limits on an ongoing basis. We primarily deal with financial institutions when entering into financial derivatives on commodities. We have entered into Master ISDAs that allow for netting of swap contract receivables and payables in the event of default by either party. If our counterparties failed to perform under existing commodity swap contracts, the maximum loss on our gross receivable position of $1783.52 million as of ~~September~~March 3031, ~~2019~~2020 would be reduced to $1321.24 million due to the offsetting of gross fair value payables against gross fair value receivables as allowed by the ISDAs.

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Notes to Consolidated Financial Statements (Continued)

(Unaudited)

(11) Fair Value Measurements

Assets and liabilities measured at fair value on a recurring basis are summarized below (in millions):

	Level 2
	September 30, 2019		December 31, 2018
	March 31, 2020		December 31, 2019
Interest rate swaps (1)	$	(1529.45)	$	—(12.4)
Commodity swaps (2)	$	1321.24	$	8.54

____________________________

(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):

	September 30, 2019						December 31, 2018
	March 31, 2020						December 31, 2019
	CarryingValue		FairValue		CarryingValue		FairValue
Long-term debt (1)	$	4,~~576~~954.8	$	43,~~264~~021.36	$	4,~~319~~764.63	$	34,~~953~~444.62
Secured term loan receivable (2)	$	—	$	—	$	51.1	$	51.1

____________________________

(1)The carrying value of long-term debt ~~as of December 31, 2018 includes current maturities. The carrying value of long-term debt~~ is reduced by debt issuance costs of $3028.8 million and $2429.38 million atas ~~September~~of March 3031, ~~2019~~2020 and December 31, ~~2018~~2019, respectively. The respective fair values do not factor in debt issuance costs.

(2)In late May 2019, White Star, the counterparty to our $58.0 million second lien secured term loan receivable, filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code. We do not believe that it is probable that White Star will be able to repay the outstanding amounts owed to us under the second lien secured term loan. For additional information regarding this transaction, refer to “Note 2—Significant Accounting Policies.”

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.

AsThe offair ~~September 30,~~values ~~2019,~~of ~~ENLC~~all ~~had total borrowings under~~ senior unsecured notes ofas ~~$500.0 million maturing in 2029 with a fixed interest rate~~ of ~~5.375%. As of September~~March 3031, ~~2019,~~2020 ~~we had total borrowings under senior unsecured notes of $3.1 billion maturing between 2024~~ and ~~2047 with fixed interest rates ranging from 4.15% to 5.60%. As of~~ December 31, ~~2018, we had total borrowings under senior unsecured notes of $3.5 billion maturing between~~ 2019 ~~and~~were ~~2047~~based ~~with~~on ~~fixed~~Level ~~interest~~2 ~~rates~~inputs ~~ranging~~ from ~~2.70%~~third-party tomarket 5quotations.~~60%.~~

The fair values of all senior unsecured notes as of September 30, 2019 and December 31, 2018 were based on Level 2 inputs from third-party market quotations. The fair values of the secured term loan receivable were calculated using Level 2 inputs from third-party banks. 23

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Notes to Consolidated Financial Statements (Continued)

(Unaudited)

(12) Segment Information

Effective January 1, 2019, we changed our reportable operating segments to reflect how we currently make financial decisions and allocate resources. As of December 31, 2018, our reportable operating segments consisted of the following: (i) natural gas gathering, processing, transmission, and fractionation operations located in north Texas and the Permian Basin primarily in west Texas, (ii) natural gas pipelines, processing plants, storage facilities, NGL pipelines, and fractionation assets in Louisiana, (iii) natural gas gathering and processing operations located throughout Oklahoma, and (iv) crude rail, truck, pipeline, and barge facilities in west Texas, south Texas, Louisiana, Oklahoma, and ORV. Effective January 1, 2019, we are reporting financial performance in five segments: Permian, North Texas, Oklahoma, Louisiana, and Corporate. Crude and condensate operations are combined regionally with natural gas and NGL operations in the Oklahoma and Permian segments, and ORV operations are included in the Louisiana segment. We have recast the segment information for the three and nine months ended September 30, 2018 to conform to the current period presentation.

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~~West Texas and ~~eastern~~Eastern New Mexico and our crude operations in ~~south~~South Texas;

•North Texas Segment. The North Texas segment includes our natural gas gathering, processing, and transmission activities in ~~north~~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~~South Texas, our derivative activity, and our general corporate assets and expenses.

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Notes to Consolidated Financial Statements (Continued)

(Unaudited)

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 September 30, 2019
Three Months Ended March 31, 2020
Natural gas sales	$	2415.31	$	2220.21	$	5441.61	$	9281.06	$	—	$	~~193~~157.19
NGL sales	0.32		6.0.3		41.62		~~421~~373.07		—		~~431~~375.94
Crude oil and condensate sales	~~409~~285.40		—		2816.2		7458.64		—		~~512~~359.26
Product sales	~~434~~300.03		2820.24		8758.45		~~587~~513.67		—		~~1,137~~892.29
Natural gas sales—related parties	(0.1)		—		—		—		0.1		—
NGL sales—related parties	45.9		17.2		67.6		6.8		(137.6)		(0.1)
NGL sales—related parties	69.3		21.0		90.2		7.9		(188.4)		—
Crude oil and condensate sales—related parties	0.1		1.5		(0.2)		—		(1.3)		0.1
Crude oil and condensate sales—related parties	2.8		1.1		—		1.7		(5.6)		—
Product sales—related parties	46.0		18.7		67.4		6.8		(138.9)		—
Product sales—related parties	72.0		22.1		90.2		9.6		(193.9)		—
Gathering and transportation	16.3		45.9		56.3		11.7		—		130.2
Gathering and transportation	14.7		50.1		63.7		12.2		—		140.7
Processing	4.3		35.4		33.3		0.7		—		73.7
Processing	8.3		36.3		35.7		0.8		—		81.1
NGL services	—		—		—		19.6		—		19.6
NGL services	—		—		—		11.2		—		11.2
Crude services	4.2		—		4.3		10.6		—		19.1
Crude services	6.4		—		5.9		13.5		—		25.8
Other services	0.6		0.3		0.1		0.4		—		1.4
Other services	4.0		0.3		0.1		0.1		—		4.5
Midstream services	25.4		81.6		94.0		43.0		—		244.0
Midstream services	33.4		86.7		105.4		37.8		—		263.3
Crude services—related parties	—		—		0.1		—		(0.1)		—
NGL services—related parties	—		—		—		—		—		—
Midstream services—related parties	—		—		0.1		—		(0.1)		—
Crude services—related parties	—		—		0.2		—		(0.2)		—
Revenue from contracts with customers	371.7		120.7		220.0		563.5		(139.0)		1,136.9
Midstream services—related parties	—		—		0.2		—		(0.2)		—
Cost of sales	(313.9)		(27.0)		(93.7)		(459.7)		139.0		(755.3)
Revenue from contracts with customers	539.4		137.0		283.2		635.0		(194.1)		1,400.5
Operating expenses	(25.5)		(20.5)		(22.9)		(31.8)		—		(100.7)
Cost of sales	(474.2)		(41.4)		(148.4)		(529.6)		194.1		(999.5)
Gain on derivative activity	—		—		—		—		19.2		19.2
Operating expenses	(28.9)		(26.2)		(25.7)		(38.4)		—		(119.2)
Segment profit	$	32.3	$	73.2	$	103.4	$	72.0	$	19.2	$	300.1
Gain on derivative activity	—		—		—		—		7.5		7.5
Depreciation and amortization	$	(29.2)	$	(37.2)	$	(56.6)	$	(37.8)	$	(2.0)	$	(162.8)
Segment profit	$	36.3	$	69.4	$	109.1	$	67.0	$	7.5	$	289.3
Impairments	$	—	$	—	$	—	$	(168.4)	$	—	$	(168.4)
Depreciation and amortization	$	(31.6)	$	(35.4)	$	(51.1)	$	(37.3)	$	(1.9)	$	(157.3)
Capital expenditures	$	86.0	$	4.7	$	8.5	$	15.2	$	0.4	$	114.8
Goodwill	$	—	$	—	$	190.3	$	—	$	—	$	190.3
Capital expenditures	$	119.7	$	5.0	$	48.6	$	21.5	$	1.7	$	196.5

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Notes to Consolidated Financial Statements (Continued)

(Unaudited)

	Permian		North Texas		Oklahoma		Louisiana		Corporate		Totals
Three Months Ended September 30, 2018
Three Months Ended March 31, 2019
Natural gas sales	$	3936.61	$	2950.56	$	4161.96	$	~~129~~122.52	$	—	$	~~240~~270.5
NGL sales	(0.12)		169.83		~~12.~~8.9		~~839~~573.61		—		~~869~~591.31
Crude oil and condensate sales	~~636~~580.48		~~0.5~~—		1829.6		6658.98		—		~~722~~669.42
Product sales	676.1		46.8		73.3		1,036.0		—		1,832.2
Other	—		—		0.1		—		—		0.1
Natural gas sales—related parties	—		—		0.1		—		—		0.1
Product sales	616.7		59.9		100.2		754.1		—		1,530.9
NGL sales—related parties	~~138~~97.62		1528.25		~~192~~126.51		103.92		(~~347~~255.20)		~~10.0~~—
Crude oil and condensate sales—related parties	(04.5)0		01.50		~~(0.4)~~—		—		0.(5.0)		~~0.1~~—
Product sales—related parties	~~138~~101.12		1529.75		~~192~~126.21		103.92		(~~346~~260.70)		~~10.2~~—
Gathering and transportation	810.23		5763.6		4455.63		17.52		—		~~127~~146.94
Processing	67.57		3921.61		3734.1		0.89		—		8463.08
NGL services	—		—		—		11.97		—		11.97
Crude services	(15.1)2		—		04.90		1513.38		—		1523.10
Other services	2.1.5		0.32		—(0.3)		0.2		—		21.6
Midstream services	1524.7		9784.59		8293.61		4543.78		—		~~241~~246.5
Gathering and transportation—related parties	—		8.7		7.2		—		—		15.9
NGL services—related parties	—		—		—		(3.0)		3.0		—
Processing—related parties	—		10.1		3.3		—		—		13.4
Crude services—related parties	—		—		0.3		—		(0.3)		—
Crude services—related parties	6.3		—		0.1		—		—		6.4
Midstream services—related parties	—		—		0.3		(3.0)		2.7		—
Other services—related parties	—		0.1		—		—		—		0.1
Revenue from contracts with customers	742.6		174.3		319.7		798.1		(257.3)		1,777.4
Midstream services—related parties	6.3		18.9		10.6		—		—		35.8
Cost of sales	(676.2)		(73.7)		(184.2)		(686.6)		257.3		(1,363.4)
Revenue from contracts with customers	836.2		178.9		358.7		1,092.6		(346.7)		2,119.7
Operating expenses	(27.8)		(25.7)		(25.4)		(35.6)		—		(114.5)
Cost of sales	(775.3)		(56.0)		(228.2)		(983.8)		346.7		(1,696.6)
Gain on derivative activity	—		—		—		—		1.8		1.8
Operating expenses	(22.4)		(27.9)		(23.0)		(41.4)		—		(114.7)
Segment profit	$	38.6	$	74.9	$	110.1	$	75.9	$	1.8	$	301.3
Loss on derivative activity	—		—		—		—		(5.4)		(5.4)
Depreciation and amortization	$	(27.9)	$	(34.3)	$	(46.1)	$	(41.8)	$	(2.0)	$	(152.1)
Segment profit	$	38.5	$	95.0	$	107.5	$	67.4	$	(5.4)	$	303.0
Goodwill	$	—	$	—	$	190.3	$	—	$	—	$	190.3
Depreciation and amortization	$	(27.9)	$	(31.9)	$	(44.8)	$	(39.7)	$	(2.4)	$	(146.7)
Capital expenditures	$	95.9	$	4.3	$	108.2	$	41.0	$	1.6	$	251.0
Impairments	$	—	$	—	$	—	$	(24.6)	$	—	$	(24.6)
Goodwill	$	29.3	$	202.7	$	190.3	$	—	$	—	$	422.3
Capital expenditures	$	91.6	$	8.1	$	138.9	$	13.7	$	1.0	$	253.3

35The 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

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Notes to Consolidated Financial Statements (Continued)

(Unaudited)

	Permian		North Texas		Oklahoma		Louisiana		Corporate		Totals
Nine Months Ended September 30, 2019
Natural gas sales	$	59.4	$	104.7	$	176.5	$	316.8	$	—	$	657.4
NGL sales	0.9		24.0		17.8		1,492.9		—		1,535.6
Crude oil and condensate sales	1,622.2		—		86.4		216.9		—		1,925.5
Product sales	1,682.5		128.7		280.7		2,026.6		—		4,118.5
Natural gas sales—related parties	0.3		0.3		—		—		(0.6)		—
NGL sales—related parties	242.9		71.7		320.9		16.4		(651.9)		—
Crude oil and condensate sales—related parties	13.7		3.8		—		1.7		(19.2)		—
Product sales—related parties	256.9		75.8		320.9		18.1		(671.7)		—
Gathering and transportation	36.3		149.0		178.2		46.1		—		409.6
Processing	23.3		106.8		105.5		2.5		—		238.1
NGL services	—		—		—		32.9		—		32.9
Crude services	16.9		—		15.1		40.2		—		72.2
Other services	8.4		0.8		—		0.5		—		9.7
Midstream services	84.9		256.6		298.8		122.2		—		762.5
NGL services—related parties	—		—		—		(3.3)		3.3		—
Crude services—related parties	—		—		1.7		—		(1.7)		—
Midstream services—related parties	—		—		1.7		(3.3)		1.6		—
Revenue from contracts with customers	2,024.3		461.1		902.1		2,163.6		(670.1)		4,881.0
Cost of sales	(1,830.9)		(166.1)		(492.0)		(1,844.1)		670.1		(3,663.0)
Operating expenses	(85.1)		(77.7)		(77.2)		(111.6)		—		(351.6)
Gain on derivative activity	—		—		—		—		16.2		16.2
Segment profit	$	108.3	$	217.3	$	332.9	$	207.9	$	16.2	$	882.6
Depreciation and amortization	$	(89.6)	$	(106.6)	$	(144.8)	$	(116.0)	$	(6.1)	$	(463.1)
Goodwill	$	—	$	—	$	190.3	$	—	$	—	$	190.3
Capital expenditures	$	268.0	$	36.3	$	227.1	$	82.0	$	5.7	$	619.1

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

(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

(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

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ENLINK MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

	Permian		North Texas		Oklahoma		Louisiana		Corporate		Totals
Nine Months Ended September 30, 2018
Natural gas sales	$	110.8	$	98.1	$	127.9	$	377.2	$	—	$	714.0
NGL sales	0.9		16.8		18.3		2,075.9		—		2,111.9
Crude oil and condensate sales	1,725.1		0.5		63.8		151.2		—		1,940.6
Product sales	1,836.8		115.4		210.0		2,604.3		—		4,766.5
Natural gas sales—related parties	—		—		2.5		—		—		2.5
NGL sales—related parties	345.4		35.7		433.0		45.4		(822.1)		37.4
Crude oil and condensate sales—related parties	1.4		1.3		0.3		0.2		(2.1)		1.1
Product sales—related parties	346.8		37.0		435.8		45.6		(824.2)		41.0
Gathering and transportation	22.0		72.2		85.8		51.8		—		231.8
Processing	17.6		41.8		93.5		2.5		—		155.4
NGL services	—		—		—		38.8		—		38.8
Crude services	(1.0)		—		1.0		43.0		—		43.0
Other services	5.8		0.6		—		0.7		—		7.1
Midstream services	44.4		114.6		180.3		136.8		—		476.1
Gathering and transportation—related parties	—		122.7		80.6		—		—		203.3
Processing—related parties	—		108.5		48.5		—		—		157.0
Crude services—related parties	14.9		—		1.5		—		—		16.4
Other services—related parties	—		0.5		—		—		—		0.5
Midstream services—related parties	14.9		231.7		130.6		—		—		377.2
Revenue from contracts with customers	2,242.9		498.7		956.7		2,786.7		(824.2)		5,660.8
Cost of sales	(2,083.3)		(137.9)		(537.6)		(2,469.1)		824.2		(4,403.7)
Operating expenses	(70.9)		(84.7)		(64.5)		(117.2)		—		(337.3)
Loss on derivative activity	—		—		—		—		(20.1)		(20.1)
Segment profit	$	88.7	$	276.1	$	354.6	$	200.4	$	(20.1)	$	899.7
Depreciation and amortization	$	(82.0)	$	(94.8)	$	(133.3)	$	(113.0)	$	(7.0)	$	(430.1)
Impairments	$	—	$	—	$	—	$	(24.6)	$	—	$	(24.6)
Goodwill	$	29.3	$	202.7	$	190.3	$	—	$	—	$	422.3
Capital expenditures	$	208.0	$	16.1	$	382.8	$	42.5	$	3.3	$	652.7

and financial results, and those of others in our industry, have been adversely affected and will likely continue to be adversely affected until the markets for these commodities recover and producers elect to expand their production activities. For example, since mid-March, we have experienced reduced volumes gathered, processed, fractionated, and transported on our assets as a result of reduced production from the regions that supply our systems. We cannot predict the full impact that COVID-19 or the significant disruption and volatility currently being experienced in the oil and natural gas markets will have on our business, liquidity, financial condition, results of operations, or cash flows (including our ability to make distributions to our unitholders) at this time, due to numerous uncertainties. The ultimate impacts will depend on future developments, including, among others, the ultimate geographic spread of the virus, the consequences of governmental and other measures designed to prevent the spread of the virus, the development of effective treatments, the duration of the outbreak and the governmental measures designed to contain the virus, actions taken by members of OPEC+ and other foreign, oil-exporting countries, actions taken by governmental authorities, customers, suppliers, and other third parties, workforce availability, the availability of oil storage capacity, and the timing and extent to which normal economic and operating conditions resume.

~~The following table reconciles the segment profits reported above to the operating income as reported on the consolidated statements of operations (in millions):~~ 28

	Three Months Ended September 30,						Nine Months Ended September 30,
	2019		2018		2019		2018
Segment profit	$	289.3	$	303.0	$	882.6	$	899.7
General and administrative expenses	(38.3)		(39.2)		(108.8)		(94.5)
Gain (loss) on disposition of assets	3.0		—		2.9		(1.3)
Depreciation and amortization	(157.3)		(146.7)		(463.1)		(430.1)
Impairments	—		(24.6)		—		(24.6)
Loss on secured term loan receivable	—		—		(52.9)		—
Operating income	$	96.7	$	92.5	$	260.7	$	349.2

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ENLINK MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

The table below represents information about segment assets as of September 30, 2019 and December 31, 2018 (in millions):

Segment Identifiable Assets:	September 30, 2019		December 31, 2018
Permian	$	2,239.4	$	2,096.8
North Texas	1,191.2		1,308.2
Oklahoma	3,262.9		3,209.5
Louisiana	2,570.8		2,734.5
Corporate	152.5		222.3
Total identifiable assets	$	9,416.8	$	9,571.3

(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:	September 30, 2019		December 31, 2018
Natural gas and NGLs inventory	$	49.8	$	41.3
Secured term loan receivable from contract restructuring, net of discount of $1.1 at December 31, 2018 (1)	—		19.4
Prepaid expenses and other	17.7		12.1
Natural gas and NGLs inventory, prepaid expenses, and other	$	67.5	$	72.8

____________________________

(1)In late May 2019, White Star, the counterparty to our $58.0 million second lien secured term loan receivable, filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code. We do not believe that it is probable that White Star will be able to repay the outstanding amounts owed to us under the second lien secured term loan. For additional information regarding this transaction, refer to “Note 2—Significant Accounting Policies.”

Other current liabilities:	September 30, 2019		December 31, 2018
Accrued interest	$	57.8	$	37.3
Accrued wages and benefits, including taxes	22.8		37.2
Accrued ad valorem taxes	34.8		28.1
Capital expenditure accruals	74.8		50.6
Onerous performance obligations	—		9.0
Short-term lease liability	21.3		1.5
Suspense producer payments	16.8		34.6
Operating expense accruals	9.2		10.2
Other	29.5		38.2
Other current liabilities	$	267.0	$	246.7

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Please read the following discussion of our financial condition and results of operations in conjunction with the financial statements and notes thereto included elsewhere in this report. In addition, please refer to the Definitions page set forth in this report prior to Part I—Financial Information.

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~~, including the Operating Partnership and EOGP~~.

Overview

We are a Delaware limited partnership formed on July 12, 2002. 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 midstream energy asset network includes approximately 12,000 miles of pipelines, 21 natural gas processing plants with approximately 5.3 Bcf/d of processing capacity, seven fractionators with approximately ~~280~~290,000 Bbls/d of fractionation capacity, barge and rail terminals, product storage facilities, purchasing and marketing capabilities, brine disposal wells, a crude oil trucking fleet, and equity investments in certain joint ventures. We manage and report our activities primarily according to the nature of activity and geography. We have five reportable segments:

•North Texas Segment. The North Texas segment includes our natural gas gathering, processing, and transmission activities in ~~north~~North Texas;

We manage our operations by focusing on gross operating margin because our business is generally to gather, process, transport, or market natural gas, NGLs, crude oil, and condensate using our assets for a fee. We 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 commodity purchase. While our transactions vary in form, the essential element of most of our transactions is the use of our assets to transport a product or provide a processed product to an end-user or marketer at the tailgate of the plant, pipeline, or barge, truck, or rail terminal. We define gross operating margin as operating revenue minus cost of sales. Gross operating margin is a non-GAAP financial measure and is explained in greater detail under “Non-GAAP Financial Measures” below. Approximately 9089% of our gross operating margin was derived from fee-based contractual arrangements with minimal direct commodity price exposure for the ~~nine~~three months ended ~~September~~March 3031, ~~2019~~2020. We reflect revenue as “Product sales” and “Midstream services” on the consolidated statements of operations.

Devon is one of our primary customers. For the three ~~and nine~~ months ended ~~September~~March 3031, 2020 and 2019, approximately 3133.84% and 30.20% of our gross operating margin, respectively, was attributable to commercial contracts with Devon. ~~For the three and~~

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nine months ended September 30, 2018, approximately 38.5% and 38.3% of our gross operating margin, respectively, was attributable to commercial contracts with Devon.

Our revenues and gross operating margins are generated from eight primary sources:

•gathering and transporting natural gas, NGLs, and crude oil on the pipeline systems we own;

•processing natural gas at our processing plants;

•fractionating and marketing recovered NGLs;

•providing compression services;

•providing crude oil and condensate transportation and terminal services;

•providing condensate stabilization services;

•providing brine disposal services; and

•providing natural gas, crude oil, and NGL storage.

We gather, transport, or store gas owned by others under fee-only contract arrangements based either on the volume of gas gathered, transported, or stored or, for firm transportation arrangements, a stated monthly fee for a specified monthly quantity with an additional fee based on actual volumes. We also buy natural gas from producers or shippers at a market index less a fee-based deduction subtracted from the purchase price of the natural gas. We then gather or transport the natural gas and sell the natural gas at a market index, thereby earning a margin through the fee-based deduction. We attempt to execute substantially all purchases and sales concurrently, or we enter into a future delivery obligation, thereby establishing the basis for the fee we will receive for each natural gas transaction. We are also party to certain long-term gas sales commitments that we satisfy through supplies purchased under long-term gas purchase agreements. When we enter into those arrangements, our sales obligations generally match our purchase obligations. However, over time, the supplies that we have under contract may decline due to reduced drilling or other causes, and we may be required to satisfy the sales obligations by buying additional gas at prices that may exceed the prices received under the sales commitments. In our purchase/sale transactions, the resale price is generally based on the same index at which the gas was purchased.

We typically buy mixed NGLs from our suppliers to our gas processing plants at a fixed discount to market indices for the component NGLs with a deduction for our fractionation fee. We subsequently sell the fractionated NGL products based on the same index-based prices. To a lesser extent, we transport and fractionate or store NGLs owned by others for a fee based on the volume of NGLs transported and fractionated or stored. The operating results of our NGL fractionation business are largely dependent upon the volume of mixed NGLs fractionated and the level of fractionation fees charged. With our fractionation business, we also have the opportunity for product upgrades for each of the discrete NGL products. We realize higher gross operating margins from product upgrades during periods with higher NGL prices.

We gather or transport crude oil and condensate owned by others by rail, truck, pipeline, and barge facilities under fee-only contract arrangements based on volumes gathered or transported. We also buy crude oil and condensate on our own gathering systems, third-party systems, and trucked from producers at a market index less a stated transportation deduction. We then transport and resell the crude oil and condensate through a process of basis and fixed price trades. We execute substantially all purchases and sales concurrently, thereby establishing the net margin we will receive for each crude oil and condensate transaction.

We realize gross operating margins from our gathering and processing services primarily through different contractual arrangements: processing margin (“margin”) contracts, POL contracts, POP contracts, fixed-fee component contracts, or a combination of these contractual arrangements. “See Item 3. Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk” for a detailed description of these contractual arrangements. Under any of these gathering and processing arrangements, we may earn a fee for the services performed, or we may buy and resell the gas and/or NGLs as part of the processing arrangement and realize a net margin as our fee. Under margin contract arrangements, our gross operating margins are higher during periods of high NGL prices relative to natural gas prices. Gross operating margin results under POL contracts are impacted only by the value of the liquids produced with margins higher during periods of higher liquids prices. Gross operating margin results under POP contracts are impacted only by the value of the natural gas and liquids produced with margins higher during periods of higher natural gas and liquids prices. Under fixed-fee based contracts, our gross operating margins are driven by throughput volume.

Operating expenses are costs directly associated with the operations of a particular asset. Among the most significant of these costs are those associated with direct labor and supervision, property insurance, property taxes, repair and maintenance expenses, contract services, and utilities. These costs are normally fairly stable across broad volume ranges and therefore do not normally increase or decrease significantly in the short term with increases or decreases in the volume of gas, liquids, crude oil, and condensate moved through or by our assets.

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~~General~~Recent ~~and~~Developments ~~administrative~~Affecting ~~expenses~~Industry ~~are~~Conditions ~~dictated by the terms of our partnership agreement. These expenses include the costs of employee, officer,~~ and director compensation and benefits properly allocable to us, fees, services, and other transaction costs related to acquisitions, and all other expenses necessary or appropriate to the conduct of business and allocable to us. Our partnership agreement provides that our general partner determines the expenses that are allocable to us in any reasonable manner determined by our general partner in its sole discretion. Subsequent to the Merger, ENLK no longer allocates general and administrative expenses to ENLC. Business

~~Recent~~On ~~Developments~~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 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 1, 2020, and the ensuing expiration thereof. 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.

~~Lobo~~As ~~Natural~~a ~~Gas~~result ~~Gathering~~of the supply/demand imbalance, reduced commodity prices, limited storage capacity, and ~~Processing~~an ~~Facilities~~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. InThis ~~early~~reduction ~~April~~in ~~2019~~production has been most acute for crude oil production, webut ~~completed~~because ~~construction~~condensate production and a significant portion of gas and NGL production depends on, or is a ~~100~~byproduct ~~MMcf/d~~of, ~~expansion~~the toproduction of crude oil, the curtailment of crude oil drilling and production affects the production of these other commodities. As a result of these decreases in producer activity, our ~~Lobo~~business ~~III~~and ~~cryogenic~~financial ~~gas~~results, ~~processing~~and ~~plant~~those of others in our industry, ~~bringing~~have been adversely affected and will likely continue to be adversely affected until the ~~total~~markets ~~operational~~for ~~processing~~these ~~capacity~~commodities atrecover and producers elect to expand their production activities. For example, since mid-March, we have experienced reduced volumes gathered, processed, fractionated, and transported on our ~~Lobo~~assets ~~facilities~~as a result of reduced production from the regions that supply our systems. Our first priority in our response to ~~375~~this ~~MMcf/d~~crisis has been the health and safety of our employees and those of our customers and other business counterparties. We have implemented preventative measures and developed a response plan to minimize unnecessary risk of exposure and prevent infection, while supporting our customers’ operations. We have a crisis management team for health, safety and environmental matters and personnel issues, and we have established a cross-functional COVID-19 response team to address various impacts of the situation, as they have been developing. We also have modified certain business practices (including discontinuing all non-essential business travel, implementing a temporary work-from-home policy for employees who can execute their work remotely, and encouraging employees to adhere to local and regional social distancing recommendations) to support efforts to reduce the spread of COVID-19 and to conform to government restrictions and best practices encouraged by the Centers for Disease Control and Prevention, the World Health Organization, and other governmental and regulatory authorities. We also have promoted heightened awareness and vigilance, hygiene, and implementation of more stringent cleaning protocols across our facilities and operations.

~~Cajun~~There is considerable uncertainty regarding the extent to which COVID-~~Sibon~~19 ~~Pipeline.~~will Incontinue ~~April~~to ~~2019,~~spread weand ~~completed~~the extent and duration of governmental and other measures implemented to try to slow the ~~expansion~~spread of ~~our~~the ~~Cajun~~virus, such as large-~~Sibon~~scale ~~NGL~~travel ~~pipeline~~bans ~~capacity~~and restrictions, ~~which~~border ~~connects~~closures, quarantines, shelter-in-place orders, and business and government shutdowns. As a result, there is significant uncertainty regarding how long the ~~Mont~~market ~~Belvieu~~dislocations ~~NGL~~will ~~hub~~continue and how significantly and how long they will continue to ~~our~~affect ~~fractionation~~us. ~~facilities~~We expect to see continued volatility in ~~Louisiana.~~crude ~~This~~oil, iscondensate, natural gas, and NGL prices for the ~~third~~foreseeable ~~phase~~future, ofwhich may, over the long term, adversely impact our ~~Cajun-Sibon~~business. ~~system~~A ~~referred~~sustained significant decline in oil and natural gas exploration and production activities and related reduced demand for our services by our customers, whether due to asdecreases ~~Cajun~~in ~~Sibon~~consumer ~~III~~demand or reduction in the prices for oil, ~~which~~condensate ~~increases~~natural ~~throughput~~gas ~~capacity~~and ~~from~~NGLs ~~130~~or otherwise,~~000~~ ~~bbls/d~~would tohave ~~185~~a material adverse effect on our business,~~000~~ ~~bbls/d~~liquidity, financial condition, results of operations, and cash flows (including our ability to make distributions to our unitholders).

~~Avenger~~As ~~Crude~~of ~~Oil~~the ~~Gathering~~date ~~System.~~of ~~Avenger~~this isreport, aour ~~crude~~efforts ~~oil~~to ~~gathering~~respond ~~system~~to inthe challenges presented by the ~~northern~~conditions ~~Delaware~~described ~~Basin~~above and isminimize ~~supported~~the byimpacts ato ~~long-term~~our ~~contract~~business ~~with~~have ~~Devon~~yielded onresults. ~~dedicated~~Our ~~acreage~~systems, inpipelines, ~~their~~and ~~Todd~~facilities have remained operational. We have also moved quickly and ~~Potato~~decisively ~~Basin~~to ~~development~~implement ~~areas~~strategies into ~~Eddy~~reduce costs, increase operational efficiencies, and ~~Lea~~lower ~~counties~~our capital spending. As we previously announced, we intend to reduce our capital expenditures in ~~New~~2020, ~~Mexico~~including both growth and maintenance capital expenditures, to between $190 million and $250 million, a 65% reduction from 2019 total capital spending. We ~~commenced~~have ~~initial~~also ~~operations~~reduced oncosts ~~Avenger~~across ~~during~~our ~~the~~platform ~~third~~and ~~quarter~~we ofintend ~~2018~~to reduce our general and ~~began~~administrative and operational expenses by $100 million for the full-~~service~~year ~~operations~~2020 versus the twelve months ended December 31, 2019. In addition, we maintain our previously announced plan to fully self-fund all capital expenditures during 2020 with internally generated cash flows, and have no plans to access the ~~second~~capital ~~quarter~~markets during 2020. Also, as of ~~2019~~March 31, 2020, we had approximately $258 million of cash on our balance sheet and have drawn only approximately $550 million on our $1. 75 billion ENLC Credit Facility. We

Central Oklahoma Plants. In June 2019, we commenced operations on our Thunderbird Plant, which expands our central Oklahoma gas processing capacity by an additional 200 MMcf/d, bringing our total processing capacity at our central Oklahoma facilities to 1.2 Bcf/d. 31

Riptide Processing Plant. In September 2019, we completed construction of a 65 MMcf/d expansion to our Riptide processing plant in the Midland Basin, bringing the total operational processing capacity at the plant to 165 MMcf/d.

Delaware Basin Processing Plant. In August 2019, we commenced construction of our Tiger Plant, which will expand our Delaware Basin processing capacity by an additional 200 MMcf/d. We expect the plant to be operational in the second half of 2020. This processing plant is owned by the Delaware Basin JV.

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have not requested any funding under any federal or other governmental programs to support our operations, and we do not expect to utilize any such funding. We are continuing to address concerns to protect the health and safety of our employees and those of our customers and other business counterparties, and this includes changes to comply with health-related guidelines as they are modified and supplemented.

We cannot predict the full impact that COVID-19 or the significant disruption and volatility currently being experienced in the oil and natural gas markets will have on our business, liquidity, financial condition, results of operations, and cash flows (including our ability to make distributions to unitholders) at this time due to numerous uncertainties. The ultimate impacts will depend on future developments, including, among others, the ultimate geographic spread of the virus, the consequences of governmental and other measures designed to prevent the spread of the virus, the development of effective treatments, the duration of the outbreak, and the governmental measures designed to contain the virus, actions taken by members of OPEC+ and other foreign, oil-exporting countries, actions taken by governmental authorities, customers, suppliers, and other third parties, workforce availability, the availability of oil storage capacity, and the timing and extent to which normal economic and operating conditions resume.

We have revised our forecasts and as a result have recorded impairments of property and equipment during the three months ended March 31, 2020. We will continue to monitor the market environment and will evaluate whether additional triggering events would indicate possible impairments of property and equipment and intangible assets.

For additional discussion regarding risks associated with the COVID-19 pandemic, see Part II, Item 1A “Risk Factors” in this report.

Other Recent Developments

Riptide Processing Plant. In March 2020, we completed construction of a 55 MMcf/d expansion to our Riptide processing plant in the Midland Basin, bringing the total operational processing capacity at the plant to 220 MMcf/d.

Non-GAAP Financial Measures

Gross Operating Margin

We define gross operating margin as revenues less cost of sales. We present gross operating margin by segment in “Results of Operations.” We disclose gross operating margin in addition to total revenue because it is the primary performance measure used by our management. We believe gross operating margin is an important measure because, in general, our business is to gather, process, transport, or market natural gas, NGLs, condensate, and crude oil for a fee or to purchase and resell natural gas, NGLs, condensate, and crude oil for a margin. Operating expense is a separate measure used by our management to evaluate operating performance of field operations. Direct labor and supervision, property insurance, property taxes, repair and maintenance, utilities, and contract services comprise the most significant portion of our operating expenses. We do not deduct operating expenses from total revenue in calculating gross operating margin because these expenses are largely independent of the volumes we transport or process and fluctuate depending on the activities performed during a specific period. The GAAP measure most directly comparable to gross operating margin is operating income (loss). Gross operating margin should not be considered an alternative to, or more meaningful than, operating income (loss) as determined in accordance with GAAP. Gross operating margin has important limitations because it excludes all operating costs that affect operating income (loss) except cost of sales. Our gross operating margin may not be comparable to similarly- titled measures of other companies because other entities may not calculate these amounts in the same manner.

~~The following table provides a reconciliation of operating income to gross operating margin (in millions):~~32

	Three Months EndedSeptember 30,						Nine Months EndedSeptember 30,
	2019		2018		2019		2018
Operating income	$	96.7	$	92.5	$	260.7	$	349.2
Add:
Operating expenses	119.2		114.7		351.6		337.3
General and administrative expenses	38.3		39.2		108.8		94.5
(Gain) loss on disposition of assets	(3.0)		—		(2.9)		1.3
Depreciation and amortization	157.3		146.7		463.1		430.1
Impairments	—		24.6		—		24.6
Loss on secured term loan receivable	—		—		52.9		—
Gross operating margin	$	408.5	$	417.7	$	1,234.2	$	1,237.0

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The following table provides a reconciliation of operating income (loss) to gross operating margin (in millions):


	Three Months Ended March 31,
	2020		2019
Operating income (loss)	$	(61.4)	$	110.6

Add:
Operating expenses	100.7		114.5
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		—


Gross operating margin	$	400.8	$	415.8

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Results of Operations

The table below sets forth certain financial and operating data for the periods indicated. We manage our operations by focusing on gross operating margin, which we define as revenue less cost of sales as reflected in the table below (in millions, except volumes):

Three Months EndedSeptember 30,

Nine Months EndedSeptember 30,

Three Months EndedMarch 31,

2019

2018

2019

2018

2020

2019

Permian Segment

Revenues

~~539~~371.47

~~836~~742.26

~~2,024.3~~

~~2,242.9~~

Cost of sales

(~~474~~313.29)

(~~775~~676.32)

~~(1,830.9)~~

~~(2,083.3)~~

Total gross operating margin

6557.28

6066.94

~~193.4~~

~~159.6~~

North Texas Segment

Revenues

~~137~~120.07

~~178~~174.93

~~461.1~~

~~498.7~~

Cost of sales

(4127.40)

(5673.07)

~~(166.1)~~

~~(137.9)~~

Total gross operating margin

9593.67

~~122~~100.96

~~295.0~~

~~360.8~~

Oklahoma Segment

Revenues

~~283~~220.20

~~358~~319.7

~~902.1~~

~~956.7~~

Cost of sales

(~~148~~93.47)

(~~228~~184.2)

~~(492.0)~~

~~(537.6)~~

Total gross operating margin

~~134~~126.83

~~130~~135.5

~~410.1~~

~~419.1~~

Louisiana Segment

Revenues

~~635~~563.05

~~1,092~~798.61

~~2,163.6~~

~~2,786.7~~

Cost of sales

(~~529~~459.67)

(~~983~~686.86)

~~(1,844.1)~~

~~(2,469.1)~~

Total gross operating margin

~~105~~103.48

~~108~~111.85

~~319.5~~

~~317.6~~

Corporate Segment

Revenues

(~~186~~119.68)

(~~352~~255.15)

~~(653.9)~~

~~(844.3)~~

Cost of sales

~~194~~139.10

~~346~~257.73

~~670.1~~

~~824.2~~

Total gross operating margin

719.52

(51.4)8

~~16.2~~

~~(20.1)~~

Total

Revenues

1,~~408~~156.01

21,~~114~~779.32

~~4,897.2~~

~~5,640.7~~

Cost of sales

(~~999~~755.53)

(1,~~696~~363.64)

~~(3,663.0)~~

~~(4,403.7)~~

Total gross operating margin

~~408~~400.58

~~417~~415.78

~~1,234.2~~

~~1,237.0~~

Midstream Volumes:

Permian Segment

Gathering and Transportation (MMBtu/d)

~~751~~831,~~400~~100

~~557~~657,~~100~~500

~~695,300~~

~~498,000~~

Processing (MMBtu/d)

~~798~~861,~~200~~700

~~566~~712,~~200~~000

~~745,100~~

~~512,900~~

Crude Oil Handling (Bbls/d)

~~112~~133,~~900~~400

~~131~~147,~~700~~400

~~135,000~~

~~119,900~~

North Texas Segment

Gathering and Transportation (MMBtu/d)

1,~~644~~577,~~300~~700

1,~~710~~683,~~200~~100

~~1,658,000~~

~~1,741,100~~

Processing (MMBtu/d)

~~760~~699,700

~~744~~729,~~600~~800

~~753,600~~

~~750,200~~

Oklahoma Segment

Gathering and Transportation (MMBtu/d)

1,~~351~~220,~~800~~900

1,~~259~~244,~~700~~400

~~1,304,100~~

~~1,181,800~~

Processing (MMBtu/d)

1,~~323~~154,~~100~~400

1,~~239~~231,~~000~~600

~~1,284,800~~

~~1,170,300~~

Crude Oil Handling (Bbls/d)

5936,600

1729,~~400~~200

~~47,600~~

~~12,900~~

Louisiana Segment

Gathering and Transportation (MMBtu/d)

2,~~078~~043,~~500~~200

2,~~273~~070,~~700~~500

~~2,025,000~~

~~2,197,100~~

Processing (MMBtu/d)

~~385~~169,~~500~~600

~~429~~468,~~200~~000

~~396,600~~

~~422,200~~

Crude Oil Handling (Bbls/d)

2117,~~200~~400

1715,~~200~~000

~~18,800~~

~~14,800~~

NGL Fractionation (Gals/d)

78,~~240~~184,100

6,~~545~~973,~~100~~800

~~7,231,400~~

~~6,457,000~~

Brine Disposal (Bbls/d)

21,~~500~~700

3,~~300~~500

~~3,100~~

~~3,200~~

4334

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Three Months Ended ~~September~~March 3031, ~~2019~~2020 Compared to Three Months Ended ~~September~~March 3031, ~~2018~~2019

Gross Operating Margin. Gross operating margin was $~~408~~400.5 8 million for the three months ended ~~September~~March 3031, ~~2019~~2020 compared to $~~417~~415.78 million for the three months ended ~~September~~March 3031, ~~2018~~2019, a decrease of $915.20 million, or 23.26%, due to the following:

•Permian Segment. Gross operating margin in the Permian segment ~~increased~~decreased $48.36 million, ~~which~~resulting ~~was~~from ~~primarily~~(i) ~~due to~~ a $97.56 million ~~increase~~decrease in gross operating margin ~~due to higher volumes~~ from our Permian ~~gas~~crude assets ~~related~~with ~~to continued development by our customers, as~~ a ~~result of~~ $~~5.2 million from our Delaware Basin assets and $4.~~3 ~~million from our Midland Basin assets~~.8 ~~These increases were partially offset by a $5.5~~ million decrease ~~from~~due ~~our~~to ~~Permian~~declines in crude ~~assets,~~oil ~~which~~prices ~~was~~and ~~attributable to a~~ $23.18 million ~~decrease~~of inthat ~~gross~~decrease ~~operating margin~~ due to ~~lower crude oil handling volumes and~~ the expiration of an MVC related to aour ~~transportation~~South ~~services~~Texas ~~agreement~~assets ~~with~~in ~~Devon~~July ~~during the third quarter of~~ 2019, and (ii) a $31.40 million decrease in gross operating margin ~~associated~~from ~~with~~ our ~~physical~~Permian ~~crude~~gas ~~marketing~~assets ~~arrangements.~~due ~~We manage our exposure~~ to ~~crude~~a ~~price~~$2.3 ~~fluctuations~~million decrease in ~~our~~gross ~~physical~~operating ~~crude~~margin ~~marketing~~related ~~arrangements~~to ~~through various derivative arrangements. The timing of~~ our ~~realization~~Midland ofBasin ~~the~~assets ~~gains~~offset orby ~~losses~~a ~~from~~$1.3 ~~these~~million ~~crude~~increase ~~derivative arrangements may not occur~~ in ~~the~~gross ~~same~~operating ~~period~~margin asrelated ~~the~~to ~~corresponding physical crude marketing transaction, and all associated gains and losses from the derivative arrangements are reflected in~~ our ~~Corporate~~Delaware ~~segment~~Basin assets.

•North Texas Segment. Gross operating margin in the North Texas segment decreased $276.39 million ~~primarily due to the January 1~~, ~~2019~~which ~~expiration~~was ofprimarily ~~Devon’s~~due ~~obligations related~~ to ~~MVCs on our North Texas assets and~~ volume declines ~~due~~resulting tofrom limited new drilling. ~~Shortfall~~in ~~revenue from~~ the ~~Devon-related MVCs was $22~~region.1 ~~million for the three months ended September 30, 2018.~~

•Oklahoma Segment. Gross operating margin in the Oklahoma segment ~~increased~~decreased $49.32 million~~, which was primarily due to higher volumes from our Oklahoma crude assets~~. Gross operating margin ~~from~~contributed by our Oklahoma gas assets decreased by $310.01 million, ~~between~~which ~~periods~~was aspartially ~~increases~~due into ~~gross~~lower ~~operating~~volumes ~~margin~~ from ~~higher~~our ~~volumes~~existing ~~were~~customers, and was partially offset by ~~the~~a ~~negative~~$0.9 ~~impact~~million ofincrease ~~NGL~~in ~~and~~gross ~~gas~~operating ~~price~~margin ~~declines~~contributed ~~under~~by our Oklahoma ~~processing~~crude ~~contracts with fixed recovery provisions~~assets.

•Louisiana Segment. Gross operating margin in the Louisiana segment decreased $37.47 million., ~~Gross~~resulting ~~operating margin~~ from ~~our~~(i) ~~NGL~~a ~~transmission and fractionation assets increased by~~ $94.0 million, ~~which~~decrease ~~was~~in ~~primarily~~gross ~~due~~operating tomargin ~~higher~~from ~~volumes~~our ~~that~~Louisiana ~~resulted~~gas ~~from~~plants ~~the~~due ~~completion~~to oflower ~~the~~processing ~~Cajun-Sibon~~margins ~~pipeline~~and ~~expansion~~volumes inattributable ~~April~~to ~~2019.~~a ~~The~~less ~~increase~~favorable ~~was~~processing ~~offset~~environment, byand (ii) a $123.47 million decrease ~~from~~in ~~our~~gross ~~Louisiana gas business. Gross~~ operating margin from our Louisiana gas transmission assets ~~decreased $6.0 million~~ due to the expiration of certain firm transportation contracts and decreased volumes. ~~Gross~~While gross operating margin ~~from~~related to our ~~Louisiana~~ORV ~~gas~~crude ~~plants~~assets decreased $61.48 million, primarily due to lower ~~processing~~volumes, ~~margins~~this decrease was partially offset by an increase of $1.8 million in gross operating margin from our NGL transmission and ~~volumes~~fractionation ~~attributable~~assets, which was primarily due to ahigher ~~less~~volumes ~~favorable~~that ~~processing~~resulted ~~environment~~from ~~during~~the completion of the ~~three~~Cajun-Sibon ~~months~~pipeline ~~ended~~expansion ~~September~~in ~~30,~~April 2019.

44•Corporate Segment. Gross operating margin in the Corporate segment increased $17.4 million, which was primarily due to the changes in fair value of our commodity swaps between the periods as summarized below (in millions):


	Three Months Ended March 31,
	2020		2019
Realized swaps:
Crude swaps	$	(0.6)	$	3.3
NGL swaps	5.2		1.9
Gas swaps	1.6		(1.4)
Realized gain on derivatives	6.2		3.8

Unrealized swaps:
Crude swaps	6.2		(0.4)
NGL swaps	—		(3.5)
Gas swaps	6.8		1.9
Change in fair value of derivatives	13.0		(2.0)

Gain on derivative activity	$	19.2	$	1.8

Certain gathering and processing agreements provide for quarterly or annual MVCs, including MVCs from Devon. Under these agreements, our customers agree to ship and/or process a minimum volume of commodity on our systems over an agreed time period. If a customer 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 commodity volumes and the MVC for that period. Some of these agreements also contain make-up right provisions that allow a customer to utilize gathering or processing fees in

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~~•Corporate~~excess ~~Segment.~~of ~~Gross~~the ~~operating~~MVC ~~margin~~ in ~~the~~subsequent ~~Corporate~~periods ~~segment~~to ~~increased~~offset ~~$12.9~~shortfall ~~million,~~amounts ~~which~~in ~~was~~previous ~~primarily~~periods. ~~due~~We torecord ~~the~~revenue ~~changes~~under inMVC ~~fair~~contracts ~~value~~during periods of ~~our~~shortfall ~~commodity~~when ~~swaps~~it ~~between~~is known that the ~~periods~~customer ascannot, ~~summarized~~or ~~below~~will (not, make up the deficiency in ~~millions):~~subsequent periods.

	Three Months Ended September 30,
	2019		2018
Realized swaps:
Crude swaps	$	5.5	$	0.9
NGL swaps	1.8		(4.0)
Gas swaps	0.7		(1.5)
Realized gain (loss) on derivatives	8.0		(4.6)
Unrealized swaps:
Crude swaps	(0.4)		1.3
NGL swaps	(0.4)		(2.0)
Gas swaps	0.3		(0.1)
Change in fair value of derivatives	(0.5)		(0.8)
Gain (loss) on derivative activity	$	7.5	$	(5.4)

Certain gathering and processing agreements provide for quarterly or annual MVCs, including MVCs from Devon. Under these agreements, our customers agree to ship and/or process a minimum volume of commodity on our systems over an agreed time period. If a customer 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 commodity volumes and the MVC for that period. Some of these agreements also contain make-up right provisions that allow a customer 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.

Revenue recorded for the shortfall between actual production volumes and the MVC is as follows (in millions):

	Permian		North Texas		Oklahoma		Total
	Three Months EndedMarch 31,
Three Months Ended
	2020				2019
September 30, 2019
Permian Segment	$	2.0			$	3.8
Midstream services	$	1.7	$	—	$	4.8	$	6.5
Oklahoma Segment	9.8				—
Total	$	111.78	$	—	$	43.8	$	~~6.5~~
September 30, 2018
Midstream services	$	2.1	$	17.7	$	—	$	19.8
Midstream services—related parties	0.6		4.4		—		5.0
Total	$	2.7	$	22.1	$	—	$	24.8

On January 1, 2019, certain MVCs related to gathering and processing agreements with Devon for operations in the North Texas and Oklahoma segments expired. These MVCs generated $22.1 million in shortfall revenue for the three months ended September 30, 2018. Additionally, an MVC related to a transportation services agreement with Devon for operations in the Permian segment expired on July 31, 2019. This MVC generated $1.7 million and $2.7 million in shortfall revenue for the three months ended September 30, 2019 and 2018, respectively. Our MVC revenue in the Oklahoma segment is generated from a gathering and processing arrangement with Devon which expires in 2030, with the MVC provision under the agreement expiring in December 2020.

45Operating Expenses. Operating expenses were $100.7 million for the three months ended March 31, 2020 compared to $114.5 million for the three months ended March 31, 2019, a decrease of $13.8 million, or 12.1%. The primary contributors to the total decrease by segment were as follows (in millions):


	Three Months Ended March 31,						Change
	2020		2019		$		%
Permian Segment	$	25.5	$	27.8	$	(2.3)	(8.3)	%
North Texas Segment	20.5		25.7		(5.2)		(20.2)	%
Oklahoma Segment	22.9		25.4		(2.5)		(9.8)	%
Louisiana Segment	31.8		35.6		(3.8)		(10.7)	%
Total	$	100.7	$	114.5	$	(13.8)	(12.1)	%

•Permian Segment. Operating expenses in the Permian segment decreased $2.3 million primarily due to reductions in materials and supplies expenses.

•North Texas Segment. Operating expenses in the North Texas segment decreased $5.2 million primarily due to reductions in materials and supplies expenses, construction fees and services, and vehicle rentals.

•Oklahoma Segment. Operating expenses in the Oklahoma segment decreased $2.5 million primarily due to reductions in compressor operations and maintenance, materials and supplies expenses, construction fees and services, and vehicle rentals.

•Louisiana Segment. Operating expenses in the Louisiana segment decreased $3.8 million primarily due to reductions in labor and benefits costs, materials and supplies expenses, construction fees and services, and vehicle rentals.

Operating expenses for the three months ended March 31, 2020 included $3.3 million of severance costs related to a reduction in workforce.

General and Administrative Expenses. General and administrative expenses were $30.9 million for the three months ended March 31, 2020 compared to $38.6 million for the three months ended March 31, 2019, a decrease of $7.7 million, or 19.9%. The primary contributors to the decrease were as follows:

•Unit-based compensation expense decreased $4.0 million, which was primarily due to larger awards and lower forfeitures during the first quarter of 2019 as compared to the first quarter of 2020.

•Transaction costs decreased $1.7 million, which was primarily due to higher transaction costs related to the Merger that were incurred during the first quarter of 2019.

•Benefits and payroll taxes decreased $1.2 million, which was primarily due to a reduction in costs related to employee benefits.

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~~Operating~~General ~~Expenses.~~and ~~Operating~~administrative expenses ~~were $119.2 million~~ for the three months ended ~~September 30~~March 31, ~~2019~~2020 ~~compared~~included to $~~114~~2.76 million ~~for the three months ended September 30, 2018, an increase~~ of ~~$4.5~~severance ~~million,~~costs orrelated ~~3.9%. The primary contributors~~ to ~~the~~a ~~total~~reduction ~~increase by segment were as follows (~~in ~~millions):~~ workforce.

	Three Months EndedSeptember 30,						Change
	2019		2018		$		%
Permian Segment	$	28.9	$	22.4	$	6.5	29.0	%
North Texas Segment	26.2		27.9		(1.7)		(6.1)	%
Oklahoma Segment	25.7		23.0		2.7		11.7	%
Louisiana Segment	38.4		41.4		(3.0)		(7.2)	%
Total	$	119.2	$	114.7	$	4.5	3.9	%

Depreciation and Amortization. Depreciation and amortization was $162.8 million for the three months ended March 31, 2020 compared to $152.1 million for the three months ended March 31, 2019, an increase of $10.7 million, or 7.0%. This increase was primarily due to accelerated depreciation in the North Texas and Oklahoma segments on certain non-core assets based on changes in their estimated useful lives and new assets placed into service in key growth areas, including the Thunderbird Plant, the expansion of the Lobo III cryogenic gas processing plant, the Cajun-Sibon NGL pipeline, Avenger, the Black Coyote crude oil gathering system, and well connections in Oklahoma. These increases were partially offset by retirements of certain non-core assets in the Louisiana segment during the first quarter of 2019.

~~•Permian Segment~~Impairments. ~~Operating~~For ~~expenses~~the inthree ~~the~~months ~~Permian~~ended ~~segment~~March 31, ~~increased~~2020, we recognized a $6168.50 million ~~primarily~~impairment ~~due~~on property and equipment related to ~~expanded~~a ~~operations~~portion ~~with~~of ~~increases~~our inLouisiana ~~utilities,~~reporting ~~materials~~segment ~~and~~because ~~supplies~~the ~~expenses,~~carrying ~~construction~~amounts ~~fees~~were ~~and~~not ~~services~~recoverable based on our expected future cash flows. Additionally, ~~and~~we adrecorded ~~valorem~~a ~~taxes~~$0.4 million impairment related to certain cancelled projects. See “Item 1. Financial Statements—Note 2” for additional information on our property and equipment impairments.

~~•North~~Gain ~~Texas~~on ~~Segment~~Extinguishment of Debt. ~~Operating~~We ~~expenses~~recognized ina ~~the~~gain ~~North~~on ~~Texas~~extinguishment ~~segment~~of ~~decreased~~debt of $15.73 million ~~primarily~~for the three months ended March 31, 2020 due to ~~reduced~~repurchases ~~compression~~of the 2024, 2025, and ~~treater~~2026 ~~rental~~Notes ~~costs~~in open market transactions. See “Item 1. Financial Statements—Note 6” for additional information.

~~•Oklahoma~~Interest ~~Segment~~Expense. ~~Operating~~Interest ~~expenses~~expense inwas $55.6 million for the ~~Oklahoma~~three ~~segment~~months ~~increased~~ended March 31, 2020 compared to $249.73 million ~~primarily~~for ~~due~~the tothree ~~expanded~~months ~~operations~~ended ~~with~~March 31, ~~increases~~2019, inan ~~compressor~~increase ~~rentals~~of $6.3 million, ~~compression~~or ~~operations~~12.8%. ~~and~~Interest ~~maintenance,~~expense ~~and~~consisted ~~labor~~of ~~and~~the ~~benefits~~following ~~costs.~~(in millions):

•Louisiana Segment. Operating expenses in the Louisiana segment decreased $3.0 million primarily due to reduced compression rental expense and lower ad valorem taxes.


	Three Months Ended March 31,
	2020		2019
Senior Notes	$	37.4	$	40.0
Related party debt	17.1		11.0

Capitalized interest	(1.2)		(2.0)
Amortization of debt issue costs and net discounts (premiums)	1.0		1.8

Other	1.3		(1.5)
Total	$	55.6	$	49.3

Depreciation and Amortization. Depreciation and amortization was $157.3 million for the three months ended September 30, 2019 compared to $146.7 million for the three months ended September 30, 2018, an increase of $10.6 million, or 7.2%. This increase was primarily due to additional depreciation of $6.8 million attributable to new assets placed in service in key growth areas, primarily related to the completion of the Thunderbird Plant, the expansion of the Lobo III cryogenic gas processing plant, further expansion of Avenger, and additional well connections in Oklahoma.

Impairments. For the three months ended September 30, 2018, we recognized impairments of property and equipment of $24.6 million related to certain non-core pipeline assets because the carrying values were no longer recoverable.

Interest Expense. Interest expense was $56.6 million for the three months ended September 30, 2019 compared to $44.1 million for the three months ended September 30, 2018, an increase of $12.5 million, or 28.3%. Interest expense consisted of the following (in millions):

	Three Months EndedSeptember 30,
	2019		2018
Senior Notes	$	37.3	$	40.0
ENLK Credit Facility	—		6.9
Related party debt	18.7		—
Capitalized interest	(0.3)		(2.3)
Amortization of debt issue costs and net discounts (premiums)	1.1		0.8
Other	(0.2)		(1.3)
Total	$	56.6	$	44.1

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Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018

Gross Operating Margin. Gross operating margin was $1,234.2 million for the nine months ended September 30, 2019 compared to $1,237.0 million for the nine months ended September 30, 2018, a decrease of $2.8 million, or 0.2%, due to the following:

•Permian Segment. Gross operating margin in the Permian segment increased $33.8 million, which was primarily due to a $34.8 million increase in gross operating margin due to higher volumes on our Permian gas assets from continued development by our customers, including $20.0 million from our Delaware Basin assets, and $14.8 million from our Midland Basin assets. This increase was slightly offset by a $1.3 million decrease in gross operating margin from our Permian crude assets, which was due to a $3.9 million increase in gross operating margin from our Midland and Delaware Basins crude assets, offset by a $5.2 million decrease in gross operating margin from our south Texas assets due to an MVC expiration in July 2019 and decreased crude activity during 2019.

•North Texas Segment. Gross operating margin in the North Texas segment decreased $65.8 million, which was primarily due to the January 1, 2019 expiration of Devon’s obligations related to MVCs on our North Texas assets and normal volume declines due to limited new drilling. Shortfall revenue from the Devon-related MVCs was $61.1 million for the nine months ended September 30, 2018.

•Oklahoma Segment. Gross operating margin in the Oklahoma segment decreased $9.0 million. Gross operating margin from our Oklahoma assets increased $36.1 million, which was primarily due to higher volumes from continued development by our customers, with $18.6 million contributed by our Oklahoma gas assets and $17.5 million contributed by our Oklahoma crude assets. This increase in gross operating margin was offset by the recognition of $45.5 million in gross operating margin from a contract restructuring with White Star during the nine months ended September 30, 2018.

•Louisiana Segment. Gross operating margin in the Louisiana segment increased $1.9 million. Gross operating margin from our NGL assets increased by $17.4 million primarily due to higher volumes with the completion of the Cajun-Sibon pipeline expansion in April 2019. Our ORV crude assets contributed an increase of $4.3 million primarily due to higher volumes. These increases were partially offset by a decrease of $19.2 million from our Louisiana gas business, primarily due to a $11.2 million decrease from our Louisiana gas plants due to a less favorable processing environment during the nine months ended September 30, 2019 and an $8.0 million decrease from our Louisiana gas transportation assets due to the expiration of certain firm transportation contracts and decreased volumes during the same period.

•Corporate Segment. Gross operating margin in the Corporate segment increased $36.3 million, which was primarily due to the changes in fair value of our commodity swaps between the periods as summarized below (in millions):

	Nine Months EndedSeptember 30,
	2019		2018
Realized swaps:
Crude swaps	$	6.4	$	0.8
NGL swaps	7.4		(6.7)
Gas swaps	(2.3)		0.6
Realized gain (loss) on derivatives	11.5		(5.3)
Unrealized swaps:
Crude swaps	4.1		(6.5)
NGL swaps	(2.7)		(5.1)
Gas swaps	3.3		(3.2)
Change in fair value of derivatives	4.7		(14.8)
Gain (loss) on derivative activity	$	16.2	$	(20.1)

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Revenue recorded for the shortfall between actual production volumes and the MVC is as follows (in millions):

	Permian		North Texas		Oklahoma		Total
Nine Months Ended
September 30, 2019
Midstream services	$	9.4	$	—	$	4.8	$	14.2
Total	$	9.4	$	—	$	4.8	$	14.2
September 30, 2018
Midstream Services (1)	$	2.1	$	17.8	$	52.7	$	72.6
Midstream services—related parties	6.3		43.3		1.2		50.8
Total	$	8.4	$	61.1	$	53.9	$	123.4

____________________________

(1)We restructured a natural gas gathering and processing contract with White Star that contained MVCs. As a result, we recognized $45.5 million of midstream services revenue in the Oklahoma segment for the nine months ended September 30, 2018.

On January 1, 2019, certain MVCs related to gathering and processing agreements with Devon for operations in the North Texas and Oklahoma segments expired. These MVCs generated $62.3 million in shortfall revenue for the nine months ended September 30, 2018. Additionally, an MVC related to a transportation services agreement with Devon for operations in the Permian segment expired on July 31, 2019. This MVC generated $9.4 million and $8.4 million in shortfall revenue for the nine months ended September 30, 2019 and 2018, respectively. Our MVC revenue in the Oklahoma segment is generated from a gathering and processing arrangement with Devon which expires in 2030, with the MVC provision under the agreement expiring in December 2020.

Operating Expenses. Operating expenses were $351.6 million for the nine months ended September 30, 2019 compared to $337.3 million for the nine months ended September 30, 2018, an increase of $14.3 million, or 4.2%. The primary contributors to the increase by segment were as follows (in millions):

	Nine Months EndedSeptember 30,						Change
	2019		2018		$		%
Permian Segment	$	85.1	$	70.9	$	14.2	20.0	%
North Texas Segment	77.7		84.7		(7.0)		(8.3)	%
Oklahoma Segment	77.2		64.5		12.7		19.7	%
Louisiana Segment	111.6		117.2		(5.6)		(4.8)	%
Total	$	351.6	$	337.3	$	14.3	4.2	%

•Permian Segment. Operating expenses in the Permian segment increased $14.2 million primarily due to expanded operations and higher utilities expense, bulk purchases of materials and supplies, construction fees and services, and compressor rentals.

•North Texas Segment. Operating expenses in the North Texas segment decreased $7.0 million primarily due to decreased compressor rentals, compressor overhauls, and labor and benefits costs.

•Oklahoma Segment. Operating expenses in the Oklahoma segment increased $12.7 million primarily due to expanded operations with increases in utilities, equipment rentals, compression operations and maintenance, and labor and benefits costs.

•Louisiana Segment. Operating expenses in the Louisiana segment decreased $5.6 million primarily due to reduced materials and supplies expenses, labor and benefits costs, and compression rentals partially offset by increased equipment rental and utility costs.

General and Administrative Expenses. General and administrative expenses were $108.8 million for the nine months ended September 30, 2019 compared to $94.5 million for the nine months ended September 30, 2018, an increase of $14.3 million, or 15.1%. The primary contributors to the increase were as follows:

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•Transaction costs increased $0.9 million, which was primarily due to costs incurred related to the Merger, which closed during the first quarter of 2019.

•Unit-based compensation expense increased $4.4 million, which was primarily due to increased bonus expense and accelerated vesting related to an executive departure in the third quarter of 2019. This increase was partially offset by accelerated vesting related to the GIP Transaction and an organizational realignment in the third quarter of 2018.

•Fees and services expense increased $3.8 million, which was primarily due to increased software consulting and legal fees.

•Salaries and wages expense increased $1.2 million, which was primarily due to severance expense for an executive departure in the third quarter of 2019.

Depreciation and Amortization. Depreciation and amortization was $463.1 million for the nine months ended September 30, 2019 compared to $430.1 million for the nine months ended September 30, 2018, an increase of $33.0 million, or 7.7%. This increase was primarily due to increased depreciation of $19.0 million attributable to new assets placed in service in key growth areas, primarily related to the completion of the Thunderbird Plant, the expansion of the Lobo III cryogenic gas processing plant, the Cajun-Sibon NGL pipeline, Avenger, the Black Coyote crude oil gathering system, and well connections in Oklahoma. Additionally, depreciation increased by $16.2 million primarily due to retirements and reductions in our estimated useful lives of certain assets primarily located in the Texas and Louisiana segments. These increases were partially offset by a $7.8 million decrease due to a reduction in depreciation resulting from an impairment of the carrying value of certain non-core crude pipeline assets during 2018.

Impairments. For the nine months ended September 30, 2018, we recognized impairments of property and equipment of $24.6 million related to certain non-core pipeline assets because the carrying values were no longer recoverable.

Loss on secured term loan receivable. We have recorded a $52.9 million loss in our consolidated statement of operations for the nine months ended September 30, 2019 related to the write-off of the secured term loan receivable. For additional information regarding this transaction, refer to “Item 1. Financial Statements—Note 2.”

Interest Expense. Interest expense was $160.2 million for the nine months ended September 30, 2019 compared to $131.5 million for the nine months ended September 30, 2018, an increase of $28.7 million, or 21.8%. Interest expense consisted of the following (in millions):

	Nine Months EndedSeptember 30,
	2019		2018
Senior Notes	$	114.6	$	120.0
ENLK Credit Facility	0.3		15.2
Related party debt	48.0		—
Capitalized interest	(4.1)		(5.1)
Amortization of debt issue costs and net discounts (premiums)	3.9		3.2
Secured term loan receivable adjustment	(2.2)		—
Other	(0.3)		(1.8)
Total	$	160.2	$	131.5

Income (Loss) from Unconsolidated Affiliate Investments. Income from unconsolidated affiliate investments was $14.0 million for the nine months ended September 30, 2019 compared to $11.7 million for the nine months ended September 30, 2018, an increase of $2.3 million. The increase was primarily attributable to additional income of $1.3 million from our GCF investment as a result of higher fractionation revenues and lower operating expenses and additional income of $1.0 million from our Cedar Cove JV.

Critical Accounting Policies

Information regarding our critical accounting policies is included in Item 7 of our Annual Report on Form 10-K for the year ended December 31, ~~2018~~2019, except ~~for our critical accounting policy on leases, which changed~~ as adescribed ~~result of the adoption of ASC 842 on January 1, 2019~~below. ~~See “Item 1. Financial Statements—Note 5” for information on our leases accounting policy.~~

49Property and Equipment

During March 2020, we determined that a sustained decline in our unit price and weakness in the overall energy sector, driven by low commodity prices and lower consumer demand due to the COVID-19 pandemic, caused a change in circumstances warranting an interim impairment test. 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.

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Liquidity and Capital Resources

Cash Flows from Operating Activities. Net cash provided by operating activities was $~~769~~178.80 million for the ~~nine~~three months ended ~~September~~March 3031, ~~2019~~2020 compared to $~~543~~258.81 million for the ~~nine~~three months ended ~~September~~March 3031, ~~2018~~2019. Operating cash flows and changes in working capital for comparative periods were as follows (in millions):

	Nine Months Ended September 30,
	Three Months EndedMarch 31,
	2019		2018
	2020		2019
Operating cash flows before working capital	$	~~655~~206.51	$	~~689~~229.8
Changes in working capital	~~114~~(28.31)		~~(146~~28.0)3

Operating cash flows before changes in working capital decreased $3423.37 million for the ~~nine~~three months ended ~~September~~March 3031, ~~2019~~2020 compared to the ~~nine~~three months ended ~~September~~March 3031, ~~2018~~2019. The primary contributors to the decrease in operating cash flows were as follows:

•~~General~~Gross ~~and~~operating ~~administrative~~margin, ~~expenses~~ excluding ~~unit~~non-~~based~~cash ~~compensation~~commodity ~~increased~~swap activity, decreased $935.8 ~~million~~ ~~primarily due to higher transaction costs related to the Merger in January 2019~~million. ~~For more information, see “Results of Operations.”~~

•~~Operating~~Interest ~~expenses~~expense, excluding ~~unit-based~~amortization ~~compensation~~of ~~increased~~debt ~~$19.3~~issue ~~million~~costs ~~primarily~~and ~~due~~net todiscounts ~~expanded~~(premium) ~~operations.~~of ~~For more information~~notes, ~~see~~increased ~~“Results~~$7.1 ~~of Operations~~million.”

~~•Interest~~These ~~expense,~~changes ~~excluding~~to ~~amortization~~operating ofcash ~~debt~~flows ~~issue~~were ~~costs~~offset ~~and~~by ~~net~~the ~~discounts, increased $28.0 million.~~following:

~~These~~•General ~~decreases to operating cash flows were partially offset by a $23.2 million increase in gross operating margin, excluding unrealized gains~~ and ~~losses~~administrative onexpenses ~~derivative activity and~~ excluding ~~non~~unit-~~cash~~based ~~revenue~~compensation ~~recognized~~decreased ~~from the restructuring of a contract~~$3. ~~The changes in working capital for the nine months ended September~~7 ~~30,~~million ~~2019 compared to the nine months ended September 30, 2018 were~~ primarily due to ~~fluctuations~~higher intransaction ~~trade~~costs ~~receivable~~related ~~and payable balances due~~ to ~~timing~~the ofMerger ~~collection and payments, changes~~ in ~~inventory~~January ~~balances~~2019. ~~attributable~~For tomore ~~normal operating fluctuations~~information, ~~and~~see ~~fluctuations~~“Results ~~in accrued revenue and accrued cost~~ of ~~sales~~Operations. ”

~~Cash~~•Operating ~~Flows~~expenses ~~from~~excluding ~~Investing~~unit-based ~~Activities.~~compensation ~~Net~~decreased ~~cash used in investing activities was~~ $~~583~~15.07 million ~~for~~primarily ~~the~~due ~~nine~~to ~~months~~a ~~ended~~reduction ~~September 30,~~in ~~2019, compared to $633~~operations.0 ~~million~~For ~~for~~more ~~the nine months ended September 30~~information, ~~2018.~~see ~~Our~~“Results ~~primary~~of ~~investing cash flows were as follows (in millions):~~ Operations.”

	Nine Months Ended September 30,
	2019		2018
Growth capital expenditures	$	(560.0)	$	(608.8)
Maintenance capital expenditures	(34.5)		(30.6)
Proceeds from sale of property	13.7		1.5

The changes in working capital for the three months ended March 31, 2020 compared to the three months ended March 31, 2019 were primarily due to fluctuations in trade receivable and payable balances due to timing of collection and payments, changes in inventory balances attributable to normal operating fluctuations, and fluctuations in accrued revenue and accrued cost of sales.

~~Growth~~Cash ~~capital~~Flows ~~expenditures~~from ~~decreased~~Investing Activities. Net cash used in investing activities was $48115.85 million for the ~~nine~~three months ended ~~September~~March 3031, ~~2019~~2020, compared to $241.0 million for the ~~nine~~three months ended ~~September~~March 3031, ~~2018~~2019. ~~The~~Investing ~~decrease~~cash ~~was~~flows are primarily ~~due~~related to ~~lower overall growth~~ capital expenditures. ~~due~~Capital toexpenditures ~~the~~decreased ~~completion~~from of$241.5 ~~Avenger~~million ~~and~~for the ~~Lobo~~three ~~III~~months ~~gas~~ended ~~processing plant in the Delaware Basin in 2018~~March 31, ~~compared~~2019 to ~~the~~$112.0 ~~capital~~million ~~expenditures~~for ~~in 2019 related to~~ the ~~Lobo~~three ~~III~~months ~~cryogenic~~ended ~~gas processing plant expansion~~March 31, ~~the~~2020. ~~Thunderbird~~The ~~Plant,~~decrease ~~the~~was ~~expansion~~primarily ofdue ~~the~~to ~~Cajun-Sibon~~reduced ~~NGL~~capital ~~pipeline,~~spending ~~and~~plans ~~the~~for ~~expansion of the Riptide processing plant~~2020.

~~Proceeds from the sale of assets increased $12.2 million for the nine months ended September 30, 2019, primarily due to the sale of certain non-core assets during 2019.~~38

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Cash Flows from Financing Activities. Net cash ~~used~~provided inby financing activities was $~~184~~118.62 million for the ~~nine~~three months ended ~~September~~March 3031, ~~2019~~2020 and net cash ~~provided~~used byin financing activities was $~~122~~116.05 million for the ~~nine~~three months ended ~~September~~March 3031, ~~2018~~2019. Our primary financing activities consisted of the following (in millions):

	Nine Months Ended September 30,
	Three Months EndedMarch 31,
	2019		2018
	2020		2019
Net borrowings on the ENLK Credit Facility	$	—	$	765.0
Net borrowings on related party debt (1)	$	199.0	$	48.4
Net borrowings on related party debt	663.5		—
Contributions by non-controlling interests (2)	37.1		15.7
Net repayments on the 2019 unsecured senior notes	(400.0)		—
Distributions to non-controlling interests (3)	(7.9)		(6.3)
Proceeds from issuance of common units	—		46.1
Distributions to common units (4)	(93.3)		(139.4)
Contributions by non-controlling interests (1)	78.6		122.0
Distributions to general partner interest (including incentive distribution rights) (5)	—		(15.6)
Payment of installment payable for EOGP acquisition	—		(250.0)
Distributions to Series B Preferred Unitholders (6)	(16.8)		(16.5)
Distributions to common units	(416.4)		(413.0)
Distributions to general partner interest (including incentive distribution rights) (2)	(15.6)		(46.3)
Distributions to non-controlling interests	(18.0)		(37.6)
Distributions to Series B Preferred Units	(50.3)		(48.5)
Distributions to Series C Preferred Units	(12.0)		(12.0)

____________________________

(1)~~Represents~~Related ~~contributions~~party ~~from~~debt ~~NGP~~includes toborrowings under the ~~Delaware~~Consolidated ~~Basin~~Credit JVFacility, ofthe ~~$78.6~~Term ~~million~~Loan, and ~~$73~~ENLC’s 5.~~6 million~~375% ~~for~~senior ~~the~~unsecured ~~nine~~notes ~~months~~due ~~ended~~2029 ~~September~~to ~~30,~~fund ~~2019~~the operations and ~~2018,~~growth ~~respectively,~~capital ~~and~~expenditures ~~$48.6~~of ~~million~~ENLK ~~from~~through ~~ENLC~~a torelated ~~EOGP~~party ~~for~~arrangement ~~the~~with ~~nine~~ENLC. ~~months~~See ~~ended~~“Item ~~September~~1. ~~30,~~Financial ~~2018~~Statements—Note 6” for additional information.

(2)AtRepresents ~~the~~contributions ~~closing~~from ofNGP to the ~~Merger,~~Delaware ~~our~~Basin ~~general partner’s incentive distribution rights were eliminated~~JV.

~~For~~(3)Represents ~~the~~distributions ~~nine~~to ~~months~~NGP ~~ended~~for ~~September 30,~~its ~~2018,~~ownership wein ~~sold~~the anDelaware ~~aggregate~~Basin ofJV, ~~2.6~~distributions ~~million~~to ~~ENLK~~Marathon ~~common~~Petroleum ~~units~~Corporation ~~under~~for anits ~~equity~~ownership ~~distribution~~in ~~agreement~~the Ascension JV, ~~generating~~and ~~proceeds~~distributions ofto ~~$46.1~~other ~~million.~~minor non-controlling interests.

~~For~~(4)Subsequent to the ~~nine~~closing ~~months~~of ~~ended~~the ~~September 30~~Merger, ~~2019,~~we ~~distributions~~no tolonger have publicly held common units. ~~include~~ENLC ~~$139.4~~owns ~~million~~all ~~related~~of toour ~~ENLK~~outstanding common units ~~prior to the Merger,~~ and ~~$277.0~~we ~~million~~make ~~was~~quarterly ~~distributed~~distributions to ENLC ~~subsequent~~related to ~~the~~its ~~Merger~~ownership of our common units.

~~Distributions~~(5)At tothe ~~non-controlling~~closing ~~interests~~of ~~included distributions to NGP for its ownership in~~ the ~~Delaware~~Merger, ~~Basin~~our JVgeneral ~~and~~partner’s ~~distributions~~incentive todistribution ~~Marathon~~rights ~~Petroleum~~were ~~Corporation for its ownership in the Ascension JV~~eliminated.

~~Subsequent to the closing of the Merger, ENLK no longer has publicly held common units.~~ (6)See “Item 1. Financial Statements—Note 7” for information on distributions to holders of the Series B Preferred Units and Series C Preferred Units.

Capital Requirements. We ~~consider~~expect ~~a number of factors in determining whether~~ our ~~capital~~remaining ~~expenditures~~2020 ~~are growth~~ capital expenditures, orincluding ~~maintenance~~ capital ~~expenditures.~~contributions ~~Growth~~to ~~capital~~our ~~expenditures~~unconsolidated ~~generally~~affiliate ~~include~~investments, ~~capital~~to ~~expenditures~~be ~~made~~approximately ~~for~~$100 ~~acquisitions~~million orto ~~capital~~$160 ~~improvements~~million, ~~that~~which weis ~~expect~~net ~~will~~of ~~increase~~approximately ~~our~~$10 ~~asset~~million ~~base,~~to ~~operating~~$40 ~~income,~~million orfrom ~~operating~~our ~~capacity~~joint ~~over~~venture ~~the long-term~~partners. ~~Examples~~Our ofprimary ~~growth~~ capital ~~expenditures~~projects ~~include~~for the ~~acquisition~~remainder of ~~assets~~2020 ~~and~~include the construction ~~or development~~ of ~~additional~~the ~~pipeline,~~Tiger ~~storage,~~Plant ~~well connections, gathering, or processing assets,~~ in ~~each case, to~~ the ~~extent~~Delaware ~~such~~Basin ~~capital~~and ~~expenditures~~continued ~~are~~development ~~expected~~of ~~to expand~~ our ~~asset~~existing ~~base,~~systems. ~~operating~~See ~~capacity,~~“Recent orDevelopments” ~~our~~for ~~operating~~further ~~income~~details.

~~Maintenance~~We ~~capital~~expect ~~expenditures~~to ~~include~~fund capital expenditures ~~made~~from tooperating ~~replace~~cash ~~partially~~flows orand ~~fully~~capital ~~depreciated~~contributions ~~assets~~by injoint ~~order~~venture topartners ~~maintain~~that relate to the ~~existing~~non-controlling ~~operating~~interest ~~capacity~~share of ~~the~~our ~~assets~~consolidated ~~and~~entities. toIn ~~extend~~2020, ~~their~~it ~~useful~~is ~~lives.~~possible ~~Examples~~that not all of ~~maintenance~~our ~~capital~~planned ~~expenditures~~projects ~~are~~will ~~expenditures~~be tocommenced ~~refurbish~~or ~~and~~completed. ~~replace~~Our ~~pipelines,~~ability ~~gathering~~to ~~assets,~~pay ~~well~~distributions ~~connections~~to our unitholders, ~~compression~~to ~~assets~~fund planned capital expenditures, and ~~processing~~to ~~assets~~make upacquisitions towill ~~their~~depend ~~original~~upon our future operating ~~capacity~~performance, orwhich towill ~~maintain~~be ~~pipeline~~affected ~~and~~by ~~equipment~~prevailing ~~reliability~~economic conditions in the industry, ~~integrity~~financial, business, and ~~safety~~other ~~and~~factors, tosome ~~address~~of ~~environmental~~which ~~laws~~are ~~and~~beyond ~~regulations~~our control.

WeOff-Balance ~~expect~~Sheet our remaining 2019 growth capital expenditures, including capital contributions to our unconsolidated affiliate investments, to be approximately $120 million to $200 million, net of $31 million to $51 million which we expect to come from our joint venture partnersArrangements. We ~~expect~~had ~~our~~no ~~remaining~~off-balance ~~2019~~sheet ~~maintenance~~arrangements ~~capital~~as ~~expenditures to be approximately $10 million to $20 million. Our primary capital projects for the remainder~~ of ~~2019 include the ongoing construction of the Tiger Plant in the Delaware Basin~~March 31, ~~and continued development of our existing systems~~2020. ~~See “Recent Developments” for further details.~~

We expect to fund growth capital expenditures from the proceeds of borrowings under the Consolidated Credit Facility, operating cash flows, and proceeds from other debt and equity sources, including capital contributions by joint venture partners that relate to the non-controlling interest share of our consolidated entities. We expect to fund our maintenance capital expenditures from operating cash flows. In 2019, it is possible that not all of our planned projects will be commenced or 39

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~~completed.~~Total ~~Our~~Contractual ~~ability~~Cash toObligations. ~~pay~~A ~~distributions~~summary toof our ~~unitholders,~~total tocontractual ~~fund~~cash ~~planned~~obligations ~~capital~~as ~~expenditures,~~of ~~and to make acquisitions will depend upon our future operating performance~~March 31, ~~which~~2020 ~~will~~is beas ~~affected~~follows ~~by prevailing economic conditions~~ (in ~~the industry, financial, business, and other factors, some of which are beyond our control.~~millions):

Off-Balance Sheet Arrangements. No off-balance sheet arrangements existed as of September 30, 2019.


	Payments Due by Period
	Total		Remainder 2020		2021		2022		2023		2024		Thereafter
Long-term debt obligations	$	3,089.5	$	—	$	—	$	—	$	—	$	545.0	$	2,544.5
Related party debt	1,900.0		—		850.0		—		—		550.0		500.0
Interest payable on fixed long-term debt obligations	2,499.7		163.6		175.6		175.6		175.6		163.6		1,645.7

Operating lease obligations	133.9		16.3		17.0		12.2		10.2		9.5		68.7
Purchase obligations	18.5		18.5		—		—		—		—		—
Pipeline and trucking capacity and deficiency agreements (1)	196.0		29.5		37.7		31.8		28.1		33.0		35.9
Inactive easement commitment (2)	10.0		—		—		10.0		—

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