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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 ~~March~~June 3130, 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 ~~April~~July 30, 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	2930
3.	Quantitative and Qualitative Disclosures About Market Risk	4144
4.	Controls and Procedures	4447
	PART II—OTHER INFORMATION
1.	Legal Proceedings	4548
1A.	Risk Factors	4548
6.	Exhibits	4648

Table of Contents

DEFINITIONS

The following terms as defined are used in this document:

Defined Term						Definition
/d						Per day.
2014 Plan						ENLC’s 2014 Long-Term Incentive Plan.
ASC						The FASB Accounting Standards Codification.
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.
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.
ENLC						EnLink Midstream, LLC.
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 became a wholly-owned subsidiary 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.
GP Plan						Our general partner’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.
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, LLC (previously a wholly-owned subsidiary of ENLC) 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, LLC (previously a wholly-owned subsidiary of ENLC prior to the Merger) related to the Merger.
MMbbls						Million barrels.
MMbtu						Million British thermal units.
MMcf						Million cubic feet.
MVC						Minimum volume commitment.
NGL						Natural gas liquid.

Table of Contents

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.
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 Oklahoma.
Tiger Plant						A gas processing plant that is under construction in the Delaware Basin and is owned by the Delaware Basin JV.

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)

	March 31, 2020		December 31, 2019
	June 30, 2020		December 31, 2019
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	~~258~~52.10	$	77.4
Accounts receivable:
Trade, net of allowance for bad debt of $0.6 and $0.5, respectively	34.2		36.2
Trade, net of allowance for bad debt of $0.5 and $0.5, respectively	82.0		36.2
Accrued revenue and other	~~337~~304.47		460.1
Related party	1422.81		18.1
Fair value of derivative assets	759.09		12.9
Other current assets	1758.84		56.9
Total current assets	~~737~~529.31		661.6
Property and equipment, net of accumulated depreciation of $3,545.2 and $3,418.6, respectively	6,896.3		7,081.3
Property and equipment, net of accumulated depreciation of $3,654.7 and $3,418.6, respectively	6,828.7		7,081.3
Intangible assets, net of accumulated amortization of $576.8 and $545.9, respectively	1,219.0		1,249.9
Intangible assets, net of accumulated amortization of $607.1 and $545.9, respectively	1,187.1		1,249.9
Investment in unconsolidated affiliates	4342.01		43.1
Fair value of derivative assets	85.28		4.3
Other assets, net	9388.3		94.4
Total assets	$	8,~~997~~681.1	$	9,134.6
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable and drafts payable	$	5149.24	$	70.6
Accounts payable to related party	0.54		1.1
Accrued gas, NGLs, condensate, and crude oil purchases	~~176~~188.18		354.8
Fair value of derivative liabilities	7731.93		14.4
Other current liabilities	~~205~~156.27		201.7
Total current liabilities	~~510~~426.96		642.6
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 $1,748.7 and $1,700.0 from related parties, respectively	4,749.0		4,764.3
Asset retirement obligations	15.79		15.5
Other long-term liabilities	8784.78		90.8
Deferred tax liability	4445.73		44.5
Fair value of derivative liabilities	139.4		6.8
Redeemable non-controlling interest	—		5.2
Partners’ equity:
Common unitholders (144,358,720 units issued and outstanding)	1,~~465~~440.6		1,681.2
Series B preferred unitholders (59,748,549 and 59,599,550 units issued and outstanding, respectively)	895.3		895.1
Series B preferred unitholders (59,897,920 and 59,599,550 units issued and outstanding, respectively)	895.7		895.1
Series C preferred unitholders (400,000 units outstanding)	~~401~~395.1		395.1
General partner interest (1,594,974 equivalent units outstanding)	215.24		216.6
Accumulated other comprehensive loss	(3129.6)		(14.5)
Non-controlling interest	~~424~~432.39		391.4
Total partners’ equity	3,~~369~~350.91		3,564.9
Total liabilities and partners’ equity	$	8,~~997~~681.1	$	9,134.6

See accompanying notes to consolidated financial statements.

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ENLINK MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

Consolidated Statements of Operations

(In millions, except per unit data)

	Three Months EndedMarch 31,
	Three Months EndedJune 30,						Six Months EndedJune 30,
	2020		2019		2020		2019
	(Unaudited)
Revenues:
Product sales	$	~~892~~532.96	$	1,~~530~~450.94	$	1,425.5	$	2,981.3
Midstream services	~~244~~234.07		~~246~~252.57		478.7		499.2
Gain on derivative activity	19.2		1.8
Gain (loss) on derivative activity	(22.4)		6.9		(3.2)		8.7
Total revenues	~~1,156~~744.19		1,~~779~~710.20		1,901.0		3,489.2
Operating costs and expenses:
Cost of sales	~~755~~397.37		1,~~363~~300.41		1,153.0		2,663.5
Operating expenses	~~100~~88.71		~~114~~117.59		188.8		232.4
General and administrative	3023.94		3831.69		54.3		70.5
Gain on disposition of assets	(0.6)		—
Loss on disposition of assets	5.2		0.1		4.6		0.1
Depreciation and amortization	~~162~~158.82		~~152~~153.17		321.0		305.8
Impairments	~~168~~1.45		—		169.9		—
Total operating costs and expenses	1,217.5		1,668.6
Loss on secured term loan receivable	—		52.9		—		52.9
Operating income (loss)	(61.4)		110.6
Total operating costs and expenses	674.1		1,656.6		1,891.6		3,325.2
Operating income	70.8		53.4		9.4		164.0
Other income (expense):
Interest expense, net of interest income	(55.62)		(4954.3)		(110.8)		(103.6)
Gain on extinguishment of debt	526.37		—		32.0		—
Income from unconsolidated affiliates	1.7		5.3
Income (loss) from unconsolidated affiliates	(0.7)		4.7		1.0		10.0
Total other expense	(48.6)		(44.0)
Other income	—		0.3		—		0.3
Income (loss) before non-controlling interest and income taxes	(110.0)		66.6
Total other expense	(29.2)		(49.3)		(77.8)		(93.3)
Income tax expense	(0.5)		(0.9)
Income (loss) before non-controlling interest and income taxes	41.6		4.1		(68.4)		70.7
Net income (loss)	(110.5)		65.7
Income tax benefit (expense)	(1.0)		0.7		(1.5)		(0.2)
Net income attributable to non-controlling interest	3.4		2.9
Net income (loss)	40.6		4.8		(69.9)		70.5
Net income (loss) attributable to ENLK	$	(113.9)	$	62.8
Net income attributable to non-controlling interest	2.5		0.7		5.9		3.6
Net income (loss) attributable to ENLK	$	38.1	$	4.1	$	(75.8)	$	66.9

See accompanying notes to consolidated financial statements.

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ENLINK MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

Consolidated Statements of Comprehensive Income (Loss)

(In millions)

	Three Months EndedMarch 31,
	Three Months EndedJune 30,						Six Months EndedJune 30,
	2020		2019		2020		2019
	(Unaudited)
Net income (loss)	$	~~(110~~40.5)6	$	654.78	$	(69.9)	$	70.5
Loss on designated cash flow hedge	(17.1)		—
Gain (loss) on designated cash flow hedge	2.0		(13.5)		(15.1)		(13.5)
Comprehensive income (loss)	~~(127~~42.6)		65(8.7)		(85.0)		57.0
Comprehensive income attributable to non-controlling interest	32.45		20.97		5.9		3.6
Comprehensive income (loss) attributable to ENLK	$	~~(131~~40.0)1	$	62(9.84)	$	(90.9)	$	53.4

See accompanying notes to consolidated financial statements.

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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 Interest (Temporary Equity)
	$		Units	$		Units	$		Units	$		Units	$		$		$		$
	(Unaudited)
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
Unit-based compensation	—		—	—		—	—		—	12.3		—	—		—		12.3		—
Distributions	(93.3)		—	(16.8)		0.1	—		—	—		—	—		(7.6)		(117.7)		(0.3)
Contributions from non-controlling interests	—		—	—		—	—		—	—		—	—		37.1		37.1		—
Loss on designated cash flow hedge	—		—	—		—	—		—	—		—	(17.1)		—		(17.1)		—
Redemption of non-controlling interest	—		—	—		—	—		—	—		—	—		—		—		(4.0)
Fair value adjustment related to redeemable non-controlling interest	0.9		—	—		—	—		—	—		—	—		—		0.9		(0.9)
Net income (loss)	(123.2)		—	17.0		—	6.0		—	(13.7)		—	—		3.4		(110.5)		—
Balance, March 31, 2020	$1,465.6	~~1,465.6~~	144.4	$895.3	~~895.3~~	59.7	$401.1	~~401.1~~	0.4	$215.2	~~215.2~~	1.6	$(31.6)	~~(31.6)~~	$424.3	~~424.3~~	$3,369.9	~~3,369.9~~	$—	—
Unit-based compensation	—		—	—		—	—		—	6.8		—	—		—		6.8		—
Distributions	(46.5)		—	(16.8)		0.2	(12.0)		—	—		—	—		(7.1)		(82.4)		—
Contributions from non-controlling interests	—		—	—		—	—		—	—		—	—		13.2		13.2		—
Gain on designated cash flow hedge	—		—	—		—	—		—	—		—	2.0		—		2.0		—
Net income (loss)	21.5		—	17.2		—	6.0		—	(6.6)		—	—		2.5		40.6		—
Balance, June 30, 2020	$	1,440.6	144.4	$	895.7	59.9	$	395.1	0.4	$	215.4	1.6	$	(29.6)	$	432.9	$	3,350.1	$	—

See accompanying notes to consolidated financial statements.

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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, 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
Adoption of ASC 842	0.3		—	—		—	—		—	—		—	—		—		0.3		—
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
Conversion of restricted units for common units, net of units withheld for taxes	(2.8)		0.5	—		—	—		—	—		—	—		—		(2.8)		—
Unit-based compensation	1.4		—	—		—	—		—	12.1		—	—		—		13.5		—
Distributions	(139.4)		—	(16.5)		0.5	—		—	(15.6)		—	—		(6.3)		(177.8)		—
Contributions from non-controlling interests	—		—	—		—	—		—	—		—	—		15.7		15.7		—
Fair value adjustment related to redeemable non-controlling interest	2.1		—	—		—	—		—	—		—	—		—		2.1		(2.1)
Issuance of common units to ENLC for acquisition of EOGP	—		55.8	—		—	—		—	—		—	—		—		—		—
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	~~2,369.9~~	144.4	$891.4	~~891.4~~	59.2	$401.1	~~401.1~~	0.4	$218.4	~~218.4~~	1.6	$(2.1)	~~(2.1)~~	$322.1	~~322.1~~	$4,200.8	~~4,200.8~~	$7.2	~~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

See accompanying notes to consolidated financial statements.

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ENLINK MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

Consolidated Statements of Cash Flows

(In millions)

	Three Months EndedMarch 31,
	Six Months EndedJune 30,
	2020		2019
	(Unaudited)
Cash flows from operating activities:
Net income (loss)	$	(~~110~~69.59)	$	6570.75
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Impairments	~~168~~169.49		—
Depreciation and amortization	~~162~~321.80		~~152~~305.18
Non-cash unit-based compensation	8.8		10.9
Loss on secured term loan receivable	—		52.9
Gain on derivatives recognized in net income (loss)	(19.2)		(1.8)
Non-cash unit-based compensation	16.2		18.9
Cash settlements on derivatives	1.2		4.6
(Gain) loss on derivatives recognized in net income (loss)	3.2		(8.7)
Gain on extinguishment of debt	(5.3)		—
Cash settlements on derivatives	2.8		4.9
Amortization of debt issue costs, net discount (premium) of notes	1.0		1.8
Gain on extinguishment of debt	(32.0)		—
Distribution of earnings from unconsolidated affiliates	1.6		2.2
Amortization of debt issue costs, net discount (premium) of notes	2.2		2.9
Income from unconsolidated affiliates	(1.7)		(5.3)
Distribution of earnings from unconsolidated affiliates	1.2		9.7
Other operating activities	(1.0)		(0.4)
Income from unconsolidated affiliates	(1.0)		(10.0)
Other operating activities	4.9		(4.2)
Changes in assets and liabilities:
Accounts receivable, accrued revenue, and other	~~128~~105.07		76259.27
Natural gas and NGLs inventory, prepaid expenses, and other	~~44.~~8.6		3(7.68)
Accounts payable, accrued product purchases, and other accrued liabilities	(~~200~~220.93)		(51179.50)
Net cash provided by operating activities	~~178~~312.05		~~258~~515.16
Cash flows from investing activities:
Additions to property and equipment	(~~112~~203.06)		(~~241~~428.54)
Other investing activities	(31.5)6		01.5
Net cash used in investing activities	(~~115~~202.50)		(~~241~~426.09)
Cash flows from financing activities:
Proceeds from borrowings	~~440~~490.0		13,~~368~~058.45
Payments on borrowings	(~~241~~476.0)		(12,~~320~~870.0)
Debt financing costs	—		(59.67)
Distributions to non-controlling interests	(715.90)		(612.37)
Contributions by non-controlling interests	3750.13		1545.72
Distributions to Series B Preferred Units	(1633.86)		(1633.52)
Distributions to common unitholders and to general partner	(93.3)		(155.0)
Distributions to Series C Preferred Units	(12.0)		(12.0)
Other financing activities	0.1		2.8
Distributions to common unitholders and to general partner	(139.8)		(292.2)
Net cash provided by (used in) financing activities	118.2		(116.5)
Other financing activities	0.2		(3.6)
Net increase (decrease) in cash and cash equivalents	180.7		(99.4)
Net cash used in financing activities	(135.9)		(129.7)
Net decrease in cash and cash equivalents	(25.4)		(41.0)
Cash and cash equivalents, beginning of period	77.4		99.5
Cash and cash equivalents, end of period	$	~~258~~52.10	$	058.15
Supplemental disclosures of cash flow information:
Cash paid for interest	$	22106.36	$	13103.94
Cash paid for income taxes	$	0.2	$	—1.2
Non-cash investing activities:
Non-cash accrual of property and equipment	$	2(19.86)	$	9.(5.8)
Right-of-use assets obtained in exchange for operating lease liabilities	$	4.8	$	95.2
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

~~March~~June 3130, 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.

Please read the notes to the consolidated financial statements in conjunction with the Definitions page set forth in this report prior to Part I—Financial Information.

a.Organization of Business

ENLK is a Delaware limited partnership formed in 2002. Our business activities are conducted through the Operating Partnership and the subsidiaries of the Operating Partnership.

EnLink Midstream GP, LLC, a Delaware limited liability company, is our general partner. Our general partner manages our operations and activities. Our general partner is a direct, wholly-owned subsidiary of ENLC. ENLC’s units are traded on the New York Stock Exchange under the symbol “ENLC.” ENLC’s managing member is a wholly-owned subsidiary of GIP.

b.Nature of Business

We primarily focus on providing midstream energy services, including:

•gathering, compressing, treating, processing, transporting, storing, and selling natural gas;

•fractionating, transporting, storing, and selling NGLs; and

•gathering, transporting, stabilizing, storing, trans-loading, and selling crude oil and condensate, in addition to brine disposal services.

Our natural gas business includes connecting the wells of producers in our market areas to our gathering systems. Our gathering systems consist of networks of pipelines that collect natural gas from points at or near producing wells and transport it to our processing plants or to larger pipelines for further transmission. We operate processing plants that remove NGLs from the natural gas stream that is transported to the processing plants by our own gathering systems or by third-party pipelines. In conjunction with our gathering and processing business, we may purchase natural gas and NGLs from producers and other supply sources and sell that natural gas or NGLs to utilities, industrial consumers, marketers, and pipelines. Our transmission pipelines receive natural gas from our gathering systems and from third-party gathering and transmission systems and deliver natural gas to industrial end-users, utilities, and other pipelines.

Our fractionators separate NGLs into separate purity products, including ethane, propane, iso-butane, normal butane, and natural gasoline. Our fractionators receive NGLs primarily through our transmission lines that transport NGLs from East Texas and from our South Louisiana processing plants. Our fractionators also have the capability to receive NGLs by truck or rail terminals. We also have agreements pursuant to which third parties transport NGLs from our West Texas and Central Oklahoma operations to our NGL transmission lines that then transport the NGLs to our fractionators. In addition, we have NGL storage capacity to provide storage for customers.

Our crude oil and condensate business includes the gathering and transmission of crude oil and condensate via pipelines, barges, rail, and trucks, in addition to condensate stabilization and brine disposal. We also purchase crude oil and condensate from producers and other supply sources and sell that crude oil and condensate through our terminal facilities to various markets.

Across our businesses, we primarily earn our fees through various fee-based contractual arrangements, which include stated fee-only contract arrangements or arrangements with fee-based components where we purchase and resell commodities in connection with providing the related service and earn a net margin as our fee. We earn our net margin under our purchase and resell contract arrangements primarily as a result of stated service-related fees that are deducted from the price of the

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ENLINK MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

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.

c.Current Market Environment

As a result of the supply/demand imbalance, reduced commodity prices, and an uncertain timeline for recovery, oil and natural gas producers, including many of our customers, have curtailed their current drilling and production activity, including in some cases by shutting-in production, as well as reducing their plans for future drilling and production activity. As a result of these decreases in producer activity, we have experienced reduced volumes gathered, processed, fractionated, and transported on our assets in some of the regions that supply our systems.

There is considerable uncertainty regarding how long COVID-19 will persist and affect economic conditions and the extent and duration of changes in consumer behavior, such as the reluctance to travel, as well as governmental and other measures implemented to try to slow the spread of the virus, such as large-scale travel bans and restrictions, border closures, quarantines, shelter-in-place orders, and business and government shutdowns. As a result, there is significant uncertainty regarding how long the market dislocations will continue and how significantly and how long they will continue to affect us. We expect to see continued volatility in crude oil, condensate, natural gas, and NGL prices for the foreseeable future, which may, over the long term, adversely impact our business. A 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 decreases in consumer demand or reduction in the prices for oil, condensate natural gas and NGLs or otherwise, would have a material adverse effect on our business, liquidity, financial condition, results of operations, and cash flows (including our ability to make distributions to our unitholders).

(2) Significant Accounting Policies

a.Basis of Presentation

The accompanying consolidated financial statements have been prepared in accordance with the instructions to Form 10-Q, are unaudited, and do not include all the information and disclosures required by GAAP for complete financial statements. All adjustments that, in the opinion of management, are necessary for a fair presentation of the results of operations for the interim periods have been made and are of a recurring nature unless otherwise disclosed herein. The results of operations for such interim periods are not necessarily indicative of results of operations for a full year. These consolidated financial statements should be read in conjunction with the consolidated financial statements and accompanying notes included in our Annual Report on Form 10-K for the year ended December 31, 2019. Certain reclassifications were made to the financial statements for the prior period to conform to current period presentation. The effect of these reclassifications had no impact on previously reported partners’ equity or net income (loss). All significant intercompany balances and transactions have been eliminated in consolidation.

b.Revenue Recognition

Minimum Volume Commitments and Firm Transportation Contracts

Certain of our gathering and processing agreements provide for quarterly or annual MVCs. Under these agreements, our customers or suppliers agree to ship and/or process a minimum volume of product on our systems over an agreed time period. If a customer or supplier under such an agreement fails to meet its MVC for a specified period, the customer is obligated to pay a contractually-determined fee based upon the shortfall between actual product volumes and the MVC for that period. Some of these agreements also contain make-up right provisions that allow a customer or supplier to utilize gathering or processing fees in excess of the MVC in subsequent periods to offset shortfall amounts in previous periods. We record revenue under MVC contracts during periods of shortfall when it is known that the customer cannot, or will not, make up the deficiency in subsequent periods. Deficiency fee revenue is included in midstream services revenue.

For our firm transportation contracts, we transport commodities owned by others for a stated monthly fee for a specified monthly quantity with an additional fee based on actual volumes. We include transportation fees from firm transportation contracts in our midstream services revenue.

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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 provisionsb.Revenue ~~All~~Recognition 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

Minimum Volume Commitments and Firm Transportation Contracts

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 six months ended June 30, 2020, we had contractual commitments of $41.4 million and $83.2 million under our MVC contracts, respectively, and recorded $13.4 million and $25.2 million of revenue due to volume shortfalls, respectively.


MVC and Firm Transportation Commitments (in millions) (1)
2020 (remaining)	$	126.9
2021	115.1
2022	99.8
2023	90.5
2024	77.0
Thereafter	143.3
Total	$	652.6

____________________________

(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~~June 3130, 2020, we recognized a $1.5 million impairment on property and equipment related to cancelled projects. For the six months ended June 30, 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~~, weand ~~recorded~~ a $01.49 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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Notes to Consolidated Financial Statements (Continued)

(Unaudited)

d.Redeemable Non-Controlling Interest

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 June 30, 2020, but we have not yet agreed to a redemption value with the non-controlling interest holder.

e.Adopted Accounting Standards

Effective January 1, 2020, we adopted ASU 2018-15, Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract (Topic 350): Internal-Use Software. ASU 2018-15 aligns the accounting for costs incurred to implement a cloud computing arrangement that is a service arrangement with the guidance on capitalizing costs associated with developing or obtaining internal-use software. Specifically, the ASU amends ASC 350-40 to include in its scope implementation costs of a cloud computing arrangement that is a service contract and clarifies that a customer should apply ASC 350-40 to determine which implementation costs should be capitalized in a cloud computing arrangement that is considered a service contract. For the three and six months ended ~~March~~June 3130, 2020, we did not capitalize any cloud computing costs. However, to the extent future costs incurred in a cloud computing arrangement are capitalizable, the corresponding amortization will be included in “Operating expenses” or “General and administrative” in the consolidated statements of operations, rather than “Depreciation and amortization.”

Effective January 1, 2020, we adopted ASU 2016-13, Financial Instruments—Credit Losses (Topic 326). The updates in ASU 2016-13 provide financial statement users with more information about the expected credit losses on financial instruments and other commitments to extend credit held by a reporting entity at each reporting date. Following the adoption of ASU 2016-13, we record an allowance for doubtful accounts based on our expectation of future losses. Because our receivables are typically paid within 30 days, and because we closely monitor the credit-worthiness of all our counterparties, adopting ASU 2016-13 did not have a material effect on our financial statements. However, in the event we foresee further or sustained deterioration in the current market environment, or other factors indicating an increased likelihood of defaults by our customers, we may recognize additional losses.

(3) Intangible Assets

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

	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount
Three Months Ended March 31, 2020
Six Months Ended June 30, 2020
Customer relationships, beginning of period	$	1,795.8	$	(545.9)	$	1,249.9
Amortization expense	—		(3061.98)		(3061.98)
Customer relationships, end of period	$	1,795.8	$	(576.8)	$	1,219.0
Retirements (1)	(1.6)		0.6		(1.0)
Customer relationships, end of period	$	1,794.2	$	(607.1)	$	1,187.1

~~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~~(1)Intangible ~~weighted~~assets ~~average~~retired ~~amortization~~as ~~period~~a isresult ~~15.0 years. Amortization expense was $30.9 million for each~~ of the ~~three~~disposition ~~months~~of ~~ended~~certain ~~March 31,~~non-core ~~2020 and 2019, respectively~~assets.

~~The~~Intangible ~~following~~assets ~~table~~associated ~~summarizes~~with ~~our~~customer ~~estimated~~relationships ~~aggregate~~are ~~amortization~~amortized ~~expense~~on ~~for~~a straight-line basis over the ~~next~~expected ~~five~~period ~~years~~of ~~and~~benefits ~~thereafter~~of ~~(in~~the ~~millions):~~ customer relationships, which range from 10 to 20 years.

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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Notes to Consolidated Financial Statements (Continued)

(Unaudited)

The weighted average amortization period is 15.0 years. Amortization expense was $30.9 million and $31.0 million for the three months ended June 30, 2020 and 2019, respectively, and $61.8 million and $61.9 million for the six months ended June 30, 2020 and 2019, respectively.

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


2020 (remaining)	$	61.7
2021	123.4
2022	123.4
2023	123.4
2024	123.4
Thereafter	631.8

Total	$	1,187.1

(4) Related Party Transactions

a.Transactions with ENLC

Related Party Debt. Related party debt includes borrowings under the Consolidated Credit Facility, the Term Loan, and ENLC’s 5.375% senior unsecured notes to fund the operations and growth capital expenditures of ENLK through a related party arrangement with ENLC. See “Note 65—Long-Term Debt” for more information on this arrangement.

We had accounts receivable balances related to transactions with ENLC of $1422.81 million and $18.1 million as of ~~March~~June 3130, 2020 and December 31, 2019, respectively.

b.Transactions with Cedar Cove JV

For the three and six months ended ~~March~~June 3130, 2020, we recorded cost of sales of $1.3 million and $4.2 million, respectively, and for the three and six months ended June 30, 2019, we recorded cost of sales of $25.98 million and $813.19 million, respectively, related to our purchase of residue gas and NGLs from the Cedar Cove JV subsequent to processing at its Central Oklahoma processing facilities. Additionally, we had accounts payable balances related to transactions with the Cedar Cove JV of $0.54 million and $1.1 million at ~~March~~June 3130, 2020 and December 31, 2019, 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~~included in the accompanying consolidated financial statements.

(5) Leases

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

	March 31, 2020			December 31, 2019
Operating leases:
Other assets, net	$	74.5		$	80.4
Other current liabilities	$	17.6		$	21.1
Other long-term liabilities	$	78.8		$	81.9
Other lease information
Weighted-average remaining lease term—Operating leases	11.0 years			10.6 years
Weighted-average discount rate—Operating leases	5.2		%	5.1		%

Certain of our lease agreements have options to extend the lease for a certain period after the expiration of the initial term. We recognize the cost of a lease over the expected total term of the lease, including optional renewal periods that we can reasonably expect to exercise. We do not have material obligations whereby we guarantee a residual value on assets we lease, nor do our lease agreements impose restrictions or covenants that could affect our ability to make distributions.

Lease expense is recognized on the consolidated statements of operations as “Operating expenses” and “General and administrative” depending on the nature of the leased asset. The components of total lease expense are as follows (in millions):

	Three Months EndedMarch 31,
	2020		2019
Finance lease expense:
Amortization of right-of-use asset	$	—	$	0.7
Operating lease expense:
Long-term operating lease expense	6.4		6.3
Short-term lease expense	5.5		6.9
Variable lease expense	2.8		1.6
Total lease expense	$	14.7	$	15.5

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(Unaudited)

~~Other information about our leases is presented below~~ (~~in millions~~5): Long-Term Debt

	Three Months EndedMarch 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

As of June 30, 2020 and December 31, 2019, long-term debt consisted of the following (in millions):

The following table summarizes the maturity of our lease liability as of March 31, 2020 (in millions):


	June 30, 2020										December 31, 2019
	Outstanding Principal		Premium (Discount)		Long-Term Debt		Outstanding Principal		Premium (Discount)		Long-Term Debt
Related party debt	$	1,748.7	$	—	$	1,748.7	$	1,700.0	$	—	$	1,700.0

4.40% Senior unsecured notes due 2024	521.8		1.2		523.0		550.0		1.5		551.5
4.15% Senior unsecured notes due 2025	720.8		(0.6)		720.2		750.0		(0.7)		749.3
4.85% Senior unsecured notes due 2026	491.0		(0.4)		490.6		500.0		(0.5)		499.5
5.60% Senior unsecured notes due 2044	350.0		(0.2)		349.8		350.0		(0.2)		349.8
5.05% Senior unsecured notes due 2045	450.0		(5.8)		444.2		450.0		(5.9)		444.1
5.45% Senior unsecured notes due 2047	500.0		(0.1)		499.9		500.0		(0.1)		499.9
Debt classified as long-term, including current maturities of long-term debt	$	4,782.3	$	(5.9)	4,776.4		$	4,800.0	$	(5.9)	4,794.1
Debt issuance cost (1)					(27.4)						(29.8)

Long-term debt, net of unamortized issuance cost					$	4,749.0					$	4,764.3

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

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

____________________________

(1)Net of amortization of $1112.96 million and $10.9 million at ~~March~~June 3130, 2020 and December 31, 2019, respectively.

Related Party Debt

Related party debt includes borrowings under the Consolidated Credit Facility, the Term Loan, and ENLC’s 5.375% senior unsecured notes to fund the operations and growth capital expenditures of ENLK through a related party arrangement with ENLC. Interest charged to ENLK for borrowings made through the related party arrangement will be the same as interest charged to ENLC on borrowings under the Consolidated Credit Facility, the Term Loan, and ENLC’s 5.375% senior unsecured notes. As of ~~March~~June 3130, 2020 and December 31, 2019, $1.~~9 billion and $1.~~7 billion, ~~respectively,~~ of related party debt is included in “Long-term debt” in the consolidated balance sheet related to these borrowings.

The indebtedness under ENLC's 5.375% senior unsecured notes due June 1, 2029, the Consolidated Credit Facility, and the Term Loan was incurred by ENLC but is guaranteed by ENLK. Therefore, the covenants in the agreements governing such indebtedness described below affect balances owed by ENLK on the related party debt.

Consolidated Credit Facility

The Consolidated Credit Facility permits ENLC to borrow up to $1.75 billion on a revolving credit basis and includes a $500.0 million letter of credit subfacility. The Consolidated Credit Facility became available for borrowings and letters of credit upon closing of the Merger. In addition, ENLK became a guarantor under the Consolidated Credit Facility upon the closing of the Merger. In the event that ENLC defaults on the Consolidated Credit Facility, ENLK will be liable for the entire outstanding balance ($400.0 million as of June 30, 2020), and 105% of the outstanding letters of credit under the Consolidated Credit Facility ($23.0 million as of June 30, 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

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Notes to Consolidated Financial Statements (Continued)

(Unaudited)

~~Consolidated~~increase ~~Credit~~the ~~Facility~~ 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.

The Consolidated Credit Facility permits ENLC to borrow up to $1.75 billion on a revolving credit basis and includes a $500.0 million letter of credit subfacility. The Consolidated Credit Facility became available for borrowings and letters of credit upon closing of the Merger. In addition, ENLK became a guarantor under the Consolidated Credit Facility upon the closing of the Merger. In the event that ENLC defaults on the Consolidated Credit Facility, ENLK will be liable for the entire outstanding balance ($550.0 million as of March 31, 2020), and 105% of the outstanding letters of credit under the Consolidated Credit Facility ($18.8 million as of March 31, 2020). The obligations under the Consolidated Credit Facility are unsecured.

Borrowings under the Consolidated Credit Facility bear interest at ENLC’s option at the Eurodollar Rate (LIBOR) plus an applicable margin (ranging from 1.125% to 2.00%) or the Base Rate (the highest of the Federal Funds Rate plus 0.50%, the 30-day Eurodollar Rate plus 1.0% or the administrative agent’s prime rate) plus an applicable margin (ranging from 0.125% to 1.00%). The applicable margins vary depending on ENLC’s debt rating. Upon breach by ENLC of certain covenants governing the Consolidated Credit Facility, amounts outstanding under the Consolidated Credit Facility, if any, may become due and payable immediately.

At ~~March~~June 3130, 2020, ENLC was in compliance with and expects to be in compliance with the financial covenants of the Consolidated Credit Facility for at least the next twelve months. Accordingly, we do not expect to make payments related to our guarantee of the $~~550~~400.0 million outstanding on the Consolidated Credit Facility.

Term Loan

On December 11, 2018, ENLK entered into the Term Loan with Bank of America, N.A., as Administrative Agent, Bank of Montreal and Royal Bank of Canada, as Co-Syndication Agents, Citibank, N.A. and Wells Fargo Bank, National Association, as Co-Documentation Agents, and the lenders party thereto. Upon the closing of the Merger, ENLC assumed ENLK’s obligations under the Term Loan, and ENLK became a guarantor of the Term Loan. In the event that ENLC defaults on the Term Loan and the outstanding balance becomes due, ENLK will be liable for any amount owed on the Term Loan not paid by ENLC. The outstanding balance of the Term Loan was $850.0 million as of ~~March~~June 3130, 2020. The obligations under the Term Loan are unsecured.

The Term Loan will mature on December 10, 2021. The Term Loan contains certain financial, operational, and legal covenants. The financial covenants are tested on a quarterly basis, based on the rolling four-quarter period that ends on the last day of each fiscal quarter. The financial covenants include (i) maintaining a ratio of consolidated EBITDA (as defined in the Term Loan, which term includes projected EBITDA from certain capital expansion projects) to consolidated interest charges of no less than 2.5 to 1.0 at all times prior to the occurrence of an investment grade event (as defined in the Term Loan) and (ii) maintaining a ratio of consolidated indebtedness to consolidated EBITDA of no more than 5.0 to 1.0. If ENLC consummates one or more acquisitions in which the aggregate purchase price is $50.0 million or more, ENLC can elect to increase the maximum allowed ratio of consolidated indebtedness to consolidated EBITDA to 5.5 to 1.0 for the quarter in which the acquisition occurs and the three subsequent quarters.

Borrowings under the Term Loan bear interest at ENLC’s option at LIBOR plus an applicable margin (ranging from 1.0% to 1.75%) or the Base Rate (the highest of the Federal Funds Rate plus 0.5%, the 30-day Eurodollar Rate plus 1.0% or the administrative agent’s prime rate) plus an applicable margin (ranging from 0.0% to 0.75%). The applicable margins vary depending on ENLC’s debt rating. Upon breach by ENLC of certain covenants included in the Term Loan, amounts outstanding under the Term Loan may become due and payable immediately.

At June 30, 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.

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Notes to Consolidated Financial Statements (Continued)

(Unaudited)

depending on ENLC’s debt rating. Upon breach by ENLC of certain covenants included in the Term Loan, amounts outstanding under the Term Loan may become due and payable immediately.

At March 31, 2020, ENLC was in compliance with and expects to be in compliance with the financial covenants of the Term Loan for at least the next twelve months. Accordingly, we do not expect to make payments related to our guarantee of the $850.0 million outstanding on the Term Loan.

Senior Unsecured Notes Repurchases

For the three and six months ended ~~March~~June 3130, 2020, we and ENLC made aggregate payments ~~of $5.2 million~~ to partially repurchase ~~$10.5 million of~~ the 2024, 2025, 2026, and ~~2026~~2029 Notes in open market transactions,. ~~which~~Activity ~~resulted~~related into athe ~~$5.3~~partial ~~million~~repurchases ~~gain~~of onour ~~extinguishment~~outstanding debt consisted of ~~debt.~~the following (in millions):

(7) Partners’ Capital


	Three Months Ended June 30, 2020		Six Months Ended June 30, 2020
Debt repurchased	$	57.2	$	67.7
Aggregate payments	(30.8)		(36.0)
Net discount on repurchased debt	(0.3)		(0.3)
Accrued interest on repurchased debt	0.6		0.6
Gain on extinguishment of debt	$	26.7	$	32.0

(6) Partners’ Capital

a.Series B Preferred Units

Income is allocated to the Series B Preferred Units in an amount equal to the quarterly distribution with respect to the period earned. A summary of the distribution activity relating to the Series B Preferred Units during the ~~three~~six months ended ~~March~~June 3130, 2020 and 2019 is provided below:

Declaration period	Distribution paid as additional Series B Preferred Units	Cash Distribution (in millions)		Date paid/payable
2020
Fourth Quarter of 2019	148,999	$	16.8	February 13, 2020
First Quarter of 2020	149,371	$	16.8	May 13, 2020
Second Quarter of 2020	149,745	$	16.8	August 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
Second Quarter of 2019	148,257	$	17.1	August 13, 2019

b.Series C Preferred Units

~~There~~We ~~was~~distributed no$12.0 million ~~distribution activity relating~~ to ~~the~~holders of Series C Preferred Units during the three and six months ended ~~March~~June 3130, 2020 and 2019, respectively.

c.Common Unit Distributions

On February 13, 2019, we paid $0.39 per ENLK common unit related to the fourth quarter of 2018. Subsequent to the closing of the Merger, we no longer have publicly held common units. ENLC owns all of our outstanding common units and we make quarterly distributions to ENLC related to its ownership of our common units. ~~For the three months ended March 31, 2020, we distributed $93.3 million to ENLC related to its ownership of our common units.~~

d.Allocation of ENLK Income

The net income (loss) allocated to our general partner is as follows (in millions):

	Three Months EndedMarch 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)

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Notes to Consolidated Financial Statements (Continued)

(Unaudited)

~~(8)~~d.Allocation ~~Investment~~of inENLK ~~Unconsolidated Affiliates~~ Income

~~As of March 31, 2020, our unconsolidated investments consisted of a 38.75% ownership in GCF and a 30% ownership in the Cedar Cove JV.~~ The ~~following~~net ~~table~~income ~~shows~~(loss) ~~the~~allocated ~~activity related~~ to our ~~investment~~general inpartner ~~unconsolidated~~is ~~affiliates~~as ~~for~~follows ~~the periods indicated~~ (in millions):

	Three Months EndedMarch 31,
	Three Months EndedJune 30,						Six Months EndedJune 30,
	2020		2019		2020		2019
GCF
Unit-based compensation attributable to ENLC’s restricted and performance units	$	(6.8)	$	(6.4)	$	(19.1)	$	(18.5)
Distributions	$	1.6	$	2.2
General partner share of net income (loss)	0.2		(0.2)		(1.2)		0.2
Equity in income	$	1.8	$	5.7
General partner interest in EOGP acquisition	—		—		—		2.4
Cedar Cove JV
General partner interest in net income (loss)	$	(6.6)	$	(6.6)	$	(20.3)	$	(15.9)
Distributions	$	0.2	$	0.3
Equity in loss	$	(0.1)	$	(0.4)
Total
Distributions	$	1.8	$	2.5
Equity in income	$	1.7	$	5.3

~~The~~(7) ~~following~~Investment ~~table shows the balances related to our investment~~ in ~~unconsolidated~~Unconsolidated ~~affiliates~~Affiliates ~~as of March 31, 2020 and December 31, 2019 (in millions):~~

	March 31, 2020		December 31, 2019
GCF	$	39.4	$	39.2
Cedar Cove JV	3.6		3.9
Total investment in unconsolidated affiliates	$	43.0	$	43.1

As of June 30, 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):

(9) Employee Incentive Plans


	Three Months Ended June 30,						Six Months Ended June 30,
	2020		2019		2020		2019
GCF

Distributions	$	—	$	7.4	$	1.6	$	9.6
Equity in income	$	0.3	$	5.2	$	2.1	$	10.9

Cedar Cove JV

Distributions	$	0.2	$	0.2	$	0.4	$	0.5
Equity in loss	$	(1.0)	$	(0.5)	$	(1.1)	$	(0.9)

Total

Distributions	$	0.2	$	7.6	$	2.0	$	10.1
Equity in income (loss)	$	(0.7)	$	4.7	$	1.0	$	10.0

The following table shows the balances related to our investment in unconsolidated affiliates as of June 30, 2020 and December 31, 2019 (in millions):


	June 30, 2020		December 31, 2019
GCF	$	39.7	$	39.2
Cedar Cove JV	2.4		3.9
Total investment in unconsolidated affiliates	$	42.1	$	43.1

(8) Employee Incentive Plans

a.Long-Term Incentive Plans

We account for unit-based compensation in accordance with ASC 718, which requires that compensation related to all unit-based awards be recognized in the consolidated financial statements. Unit-based compensation cost is valued at fair value at the date of grant, and that grant date fair value is recognized as expense over each award’s requisite service period with a corresponding increase to equity or liability based on the terms of each award and the appropriate accounting treatment under ASC 718. Unit-based compensation associated with ENLC’s unit-based compensation plan awarded to directors, officers, and employees of our general partner and the managing member of ENLC is recorded by ENLK since ENLC has no substantial or managed operating activities other than its interests in ENLK.

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

	Three Months EndedMarch 31,
	2020		2019
Cost of unit-based compensation charged to operating expense	$	2.2	$	0.3
Cost of unit-based compensation charged to general and administrative expense	6.6		10.6
Total unit-based compensation expense	$	8.8	$	10.9

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Notes to Consolidated Financial Statements (Continued)

(Unaudited)

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


	Three Months Ended June 30,						Six Months Ended June 30,
	2020		2019		2020		2019
Cost of unit-based compensation charged to operating expense	$	2.0	$	2.1	$	4.2	$	2.4
Cost of unit-based compensation charged to general and administrative expense	5.4		5.9		12.0		16.5
Total unit-based compensation expense	$	7.4	$	8.0	$	16.2	$	18.9

b.ENLC Restricted Incentive Units

ENLC restricted incentive units were valued at their fair value at the date of grant, which is equal to the market value of ENLC common units on such date. A summary of the restricted incentive unit activity for the ~~three~~six months ended ~~March~~June 3130, 2020 is provided below:

	Three Months EndedMarch 31, 2020
	Six Months EndedJune 30, 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~~673,~~493~~848		5.6655
Vested (1)(2)	(12,~~978~~413,~~817~~687)		910.5635
Forfeited	(53478,~~105~~304)		118.3439
Non-vested, end of period	65,~~586~~845,~~176~~462		$	9.5011
Aggregate intrinsic value, end of period (in millions)	$	714.23

____________________________

(1)Restricted incentive units typically vest at the end of three years. In February 2020, ENLC granted 1,144,842 restricted incentive units with a fair value of $5.2 million to officers and certain employees as bonus payments for 2019, and these restricted incentive units vested immediately and are included in the restricted incentive units granted and vested line items.

(2)Vested units included ~~732~~851,~~473~~940 units withheld for payroll taxes paid on behalf of employees.

A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for the three and six months ended ~~March~~June 3130, 2020 and 2019 is provided below (in millions):

	Three Months EndedMarch 31,
	Three Months EndedJune 30,						Six Months EndedJune 30,
ENLC Restricted Incentive Units:	2020		2019		2020		2019
Aggregate intrinsic value of units vested	$	100.18	$	120.45	$	10.9	$	12.9
Fair value of units vested	$	186.91	$	120.65	$	25.0	$	13.1

As of ~~March~~June 3130, 2020, there was $3729.34 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 1.98 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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Notes to Consolidated Financial Statements (Continued)

(Unaudited)

The following table presents a summary of the performance units:

	Three Months EndedMarch 31, 2020
	Six Months EndedJune 30, 2020
ENLC Performance Units:	Number of Units		Weighted Average Grant-Date Fair Value
Non-vested, beginning of period	1,317,856		$	14.22
Granted	1,161,986		7.32
Vested (1)	(~~160~~178,~~002~~403)		3130.1356
Non-vested, end of period	2,319,840		$	9.60
Forfeited	(37,646)		11.81
Aggregate intrinsic value, end of period (in millions)	$	2.6
Non-vested, end of period	2,263,793		$	9.43
Aggregate intrinsic value, end of period (in millions)	$	5.5

____________________________

(1)Vested units included 6067,~~920~~775 units withheld for payroll taxes paid on behalf of employees.

A summary of the performance units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for the three and six months ended ~~March~~June 3130, 2020 and 2019 is provided below (in millions).

	Three Months EndedMarch 31,
	Three Months EndedJune 30,						Six Months EndedJune 30,
ENLC Performance Units:	2020		2019		2020		2019
Aggregate intrinsic value of units vested	$	~~0.9~~—	$	~~1.8~~—	$	0.9	$	1.8
Fair value of units vested	$	5.0.5	$	~~1.9~~—	$	5.5	$	1.9

As of ~~March~~June 3130, 2020, there was $1614.85 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 1.87 years.

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


ENLC Performance Units:	January 2020			March 2020
Grant-Date Fair Value	$	7.69		$	1.13
Beginning TSR price	$	6.13		$	1.25
Risk-free interest rate	1.62		%	0.42		%
Volatility factor	37.00		%	51.00		%

d.ENLK Restricted Incentive Units

A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for the ~~three~~six months ended ~~March~~June 3130, 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 EndedMarch 31,
			Six Months EndedJune 30,
ENLK Restricted Incentive Units:	~~2019~~		2019
Aggregate intrinsic value of units vested	$	~~8.0~~	$	8.0
Fair value of units vested	$	~~7.2~~	$	7.2

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ENLINK MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

e.ENLK Performance Units

A summary of the performance units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for the ~~three~~six months ended ~~March~~June 3130, 2019 is provided below (in millions). Since the Legacy ENLK Awards converted into ENLC unit-based awards as a result of the Merger, no additional performance units will vest as ENLK units under the GP Plan (such performance units, as converted, are eligible to vest as ENLC units) and no additional expense will be recognized after January 25, 2019 under the GP Plan.

			Three Months EndedMarch 31,
	Six Months EndedJune 30,
ENLK Performance Units:	2019		~~2019~~
Aggregate intrinsic value of units vested	$	2.1	$	~~2.1~~
Fair value of units vested	$	1.7	$	~~1.7~~

(109) Derivatives

Interest Rate Swaps

In April 2019, we entered into an $850.0 million interest rate swap to manage the interest rate risk associated with our floating-rate, LIBOR-based borrowings. Under this arrangement, we pay a fixed interest rate of 2.28% in exchange for LIBOR-based variable interest through December 2021. There was no ineffectiveness related to this hedge.

~~For~~The ~~the~~gain ~~three~~(loss) ~~months~~on ~~ended~~designated ~~March 31,~~cash ~~2020,~~flow wehedge ~~recorded $17.1 million into accumulated other comprehensive loss~~ related to changes in the fair value of our interest rate swaps. were as follows (in millions):

For the three months ended March 31, 2020, we realized a loss of $1.3 million related to the monthly settlements of our interest rate swaps, which we recorded into interest expense, net of interest income from accumulated other comprehensive loss. We expect to recognize an additional $16.3 million of interest expense out of accumulated other comprehensive loss over the next twelve months.


	Three Months Ended June 30,						Six Months Ended June 30,
	2020		2019		2020		2019
Gain (loss) on designated cash flow hedge	$	2.0	$	(13.5)	$	(15.1)	$	(13.5)

The interest expense, recognized from accumulated other comprehensive loss from the monthly settlement of our interest rate swaps, included in our consolidated income statement were as follows (in millions):


	Three Months Ended June 30,						Six Months Ended June 30,
	2020		2019		2020		2019
Interest expense (income)	$	3.7	$	(0.3)	$	5.0	$	(0.3)

We expect to recognize an additional $18.4 million of interest expense out of accumulated other comprehensive loss over the next twelve months.

The fair value of our interest rate swaps included in our consolidated balance sheets were as follows (in millions):

	March 31, 2020		December 31, 2019
	June 30, 2020		December 31, 2019
Fair value of derivative liabilities—current	$	(1618.13)	$	(5.6)
Fair value of derivative liabilities—long-term	(139.43)		(6.8)
Net fair value of interest rate swaps	$	(2927.56)	$	(12.4)

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ENLINK MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

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 EndedMarch 31,
	Three Months EndedJune 30,						Six Months EndedJune 30,
	2020		2019		2020		2019
Change in fair value of derivatives	$	13(18.08)	$	(27.0)2	$	(5.8)	$	5.2
Realized gain on derivatives	6.2		3.8
Realized gain (loss) on derivatives	(3.6)		(0.3)		2.6		3.5
Gain on derivative activity	$	19.2	$	1.8
Gain (loss) on derivative activity	$	(22.4)	$	6.9	$	(3.2)	$	8.7

The fair value of derivative assets and liabilities related to commodity swaps are as follows (in millions):

	March 31, 2020		December 31, 2019
	June 30, 2020		December 31, 2019
Fair value of derivative assets—current	$	759.09	$	12.9
Fair value of derivative assets—long-term	85.28		4.3
Fair value of derivative liabilities—current	(6113.80)		(8.8)
Net fair value of commodity swaps	$	21.4	$	8.4
Fair value of derivative liabilities—long-term	(0.1)		—
Net fair value of commodity swaps	$	2.6	$	8.4

22Set 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 June 30, 2020 (in millions). The remaining term of the contracts extend no later than December 2022.

June 30, 2020

Commodity

Instruments

Unit

Volume

Net Fair Value

NGL (short contracts)

Swaps

Gallons

(172.5)

(5.7)

NGL (long contracts)

Swaps

Gallons

3.4

(0.1)

Natural gas (short contracts)

Swaps

MMBtu

(21.6)

(0.2)

Natural gas (long contracts)

Swaps

MMBtu

15.9

(0.6)

Crude and condensate (short contracts)

Swaps

MMbbls

(10.7)

7.2

Crude and condensate (long contracts)

Swaps

MMbbls

0.6

2.0

Total fair value of commodity swaps

2.6

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 $15.7 million as of June 30, 2020 would be reduced to $8.1 million due to the offsetting of gross fair value payables against gross fair value receivables as allowed by the ISDAs.

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ENLINK MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

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 March 31, 2020 (~~in millions~~10). ~~The~~Fair ~~remaining~~Value ~~term~~Measurements ~~of the contracts extend no later than December 2022.~~

March 31, 2020

Commodity

Instruments

Unit

Volume

Net Fair Value

NGL (short contracts)

Swaps

Gallons

(155.8)

8.9

NGL (long contracts)

Swaps

Gallons

8.1

(0.3)

Natural gas (short contracts)

Swaps

MMBtu

(20.3)

0.5

Natural gas (long contracts)

Swaps

MMBtu

15.0

(0.5)

Crude and condensate (short contracts)

Swaps

MMbbls

(13.2)

(46.0)

Crude and condensate (long contracts)

Swaps

MMbbls

2.1

58.8

Total fair value of commodity swaps

21.4

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 $83.2 million as of March 31, 2020 would be reduced to $21.4 million due to the offsetting of gross fair value payables against gross fair value receivables as allowed by the ISDAs.

(11) Fair Value Measurements

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

	Level 2
	March 31, 2020		December 31, 2019
	June 30, 2020		December 31, 2019
Interest rate swaps (1)	$	(2927.56)	$	(12.4)
Commodity swaps (2)	$	212.46	$	8.4

____________________________

(1)The fair values of the interest rate swaps are estimated based on the difference between expected cash flows calculated at the contracted interest rates and the expected cash flows using observable benchmarks for the variable interest rates.

(2)The fair values of commodity swaps represent the amount at which the instruments could be exchanged in a current arms-length transaction adjusted for our credit risk and/or the counterparty credit risk as required under ASC 820.

Fair Value of Financial Instruments

The estimated fair value of our financial instruments has been determined using available market information and valuation methodologies. Considerable judgment is required to develop the estimates of fair value; thus, the estimates provided below are not necessarily indicative of the amount we could realize upon the sale or refinancing of such financial instruments (in millions):

March 31, 2020

December 31, 2019

June 30, 2020

December 31, 2019

CarryingValue

FairValue

CarryingValue

FairValue

Long-term debt (1)

4,~~954~~749.80

3,~~021~~791.61

4,764.3

4,444.2

____________________________

(1)The carrying value of long-term debt is reduced by debt issuance costs of $2827.84 million and $29.8 million as of ~~March~~June 3130, 2020 and December 31, 2019, respectively. The respective fair values do not factor in debt issuance costs.

The carrying amounts of our cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the short-term maturities of these assets and liabilities.

The fair values of all senior unsecured notes as of ~~March~~June 3130, 2020 and December 31, 2019 were based on Level 2 inputs from third-party market quotations.

23(11) Segment Information

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ENLINK MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

(12) Segment Information

Identification of the majority of our operating segments is based principally upon geographic regions served:

•Permian Segment. The Permian segment includes our natural gas gathering, processing, and transmission activities and our crude oil operations in the Midland and Delaware Basins in West Texas and Eastern New Mexico and our crude operations in South Texas;

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

•Oklahoma Segment. The Oklahoma segment includes our natural gas gathering, processing, and transmission activities, and our crude oil operations in the Cana-Woodford, Arkoma-Woodford, northern Oklahoma Woodford, STACK, and CNOW shale areas;

•Louisiana Segment. The Louisiana segment includes our natural gas pipelines, natural gas processing plants, storage facilities, fractionation facilities, and NGL assets located in Louisiana and our crude oil operations in ORV; and

•Corporate Segment. The Corporate segment includes our unconsolidated affiliate investments in the Cedar Cove JV in Oklahoma, our ownership interest in GCF in South Texas, our derivative activity, and our general corporate assets and expenses.

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ENLINK MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

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 March 31, 2020
Three Months Ended June 30, 2020
Natural gas sales	$	1532.14	$	2014.16	$	4128.18	$	8168.6	$	—	$	~~157~~144.94
NGL sales	(0.21)		~~0.3~~—		10.25		~~373~~280.79		—		~~375~~281.43
Crude oil and condensate sales	~~285~~87.0		—		165.20		5814.49		—		~~359~~106.69
Product sales	~~300~~119.3		2014.46		5834.53		~~513~~364.74		—		~~892~~532.96
NGL sales—related parties	4559.95		1713.29		6756.60		63.82		(~~137~~132.65)		(0.1)
Crude oil and condensate sales—related parties	~~0.1~~—		10.54		(0.2)1		—		(10.36)		(0.1)
Product sales—related parties	4659.05		1814.73		6756.41		63.82		(~~138~~133.91)		—
Gathering and transportation	1613.31		4544.92		5652.35		11.75		—		~~130~~121.23
Processing	47.35		3533.40		3332.31		0.76		—		73.72
NGL services	—		—0.1		—		1918.6		—		1918.67
Crude services	45.20		—		4.36		1011.60		—		1920.16
Other services	0.62		0.32		0.1		0.4		—		10.49
Midstream services	25.48		8177.65		9489.03		4342.01		—		~~244~~234.07
Crude services—related parties	—		—		0.1		—		(0.1)		—
Midstream services—related parties	—		—		0.1		—		(0.1)		—
Revenue from contracts with customers	~~371~~204.76		~~120~~106.74		~~220~~179.08		~~563~~409.57		(~~139~~133.02)		~~1,136~~767.93
Cost of sales	(~~313~~138.94)		(2718.09)		(9361.71)		(~~459~~312.75)		~~139~~133.02		(~~755~~397.37)
Operating expenses	(2522.57)		(2018.5)		(2219.94)		(3127.85)		—		(~~100~~88.71)
Gain on derivative activity	—		—		—		—		19.2		19.2
Loss on derivative activity	—		—		—		—		(22.4)		(22.4)
Segment profit	$	32.3	$	73.2	$	103.4	$	72.0	$	19.2	$	300.1
Segment profit (loss)	$	43.5	$	69.0	$	99.3	$	69.7	$	(22.4)	$	259.1
Depreciation and amortization	$	(2931.20)	$	(3736.24)	$	(5654.61)	$	(3734.86)	$	(2.01)	$	(~~162~~158.82)
Impairments	$	—	$	—	$	—	$	(~~168~~1.45)	$	—	$	(~~168~~1.45)
Capital expenditures	$	8646.09	$	43.70	$	83.50	$	15.26	$	0.47	$	~~114~~69.82

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ENLINK MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

	Permian		North Texas		Oklahoma		Louisiana		Corporate		Totals
Three Months Ended March 31, 2019
Three Months Ended June 30, 2019
Natural gas sales	$	~~36.~~(1.0)	$	5031.69	$	6160.63	$	~~122~~102.26	$	—	$	~~270~~193.58
NGL sales	(0.2)8		98.37		84.93		~~573~~498.18		—		~~591~~512.16
Crude oil and condensate sales	~~580~~632.80		—		2928.6		5883.85		—		~~669~~744.21
Other	—		—		(0.1)		—		—		(0.1)
Product sales	~~616~~631.78		5940.96		~~100~~93.21		~~754~~684.19		—		1,~~530~~450.94
NGL sales—related parties	97.2		28.5		126.1		3.2		(255.0)		—
Natural gas sales—related parties	0.4		0.3		—		—		(0.7)		—
Crude oil and condensate sales—related parties	4.0		1.0		—		—		(5.0)		—
NGL sales—related parties	76.4		22.2		104.6		5.3		(208.5)		—
Product sales—related parties	101.2		29.5		126.1		3.2		(260.0)		—
Crude oil and condensate sales—related parties	6.9		1.7		—		—		(8.6)		—
Gathering and transportation	10.3		63.6		55.3		17.2		—		146.4
Product sales—related parties	83.7		24.2		104.6		5.3		(217.8)		—
Processing	7.7		21.1		34.1		0.9		—		63.8
Gathering and transportation	11.3		49.0		59.2		16.7		—		136.2
NGL services	—		—		—		11.7		—		11.7
Processing	7.3		35.7		35.7		0.8		—		79.5
Crude services	5.2		—		4.0		13.8		—		23.0
NGL services	—		—		—		10.0		—		10.0
Other services	1.5		0.2		(0.3)		0.2		—		1.6
Crude services	5.3		—		5.2		12.9		—		23.4
Midstream services	24.7		84.9		93.1		43.8		—		246.5
Other services	2.9		0.3		0.2		0.2		—		3.6
NGL services—related parties	—		—		—		(3.0)		3.0		—
Midstream services	26.8		85.0		100.3		40.6		—		252.7
Crude services—related parties	—		—		0.3		—		(0.3)		—
NGL services—related parties	—		—		—		(0.3)		0.3		—
Midstream services—related parties	—		—		0.3		(3.0)		2.7		—
Crude services—related parties	—		—		1.2		—		(1.2)		—
Revenue from contracts with customers	742.6		174.3		319.7		798.1		(257.3)		1,777.4
Midstream services—related parties	—		—		1.2		(0.3)		(0.9)		—
Cost of sales	(676.2)		(73.7)		(184.2)		(686.6)		257.3		(1,363.4)
Revenue from contracts with customers	742.3		149.8		299.2		730.5		(218.7)		1,703.1
Operating expenses	(27.8)		(25.7)		(25.4)		(35.6)		—		(114.5)
Cost of sales	(680.5)		(51.0)		(159.4)		(627.9)		218.7		(1,300.1)
Gain on derivative activity	—		—		—		—		1.8		1.8
Operating expenses	(28.4)		(25.8)		(26.1)		(37.6)		—		(117.9)
Segment profit	$	38.6	$	74.9	$	110.1	$	75.9	$	1.8	$	301.3
Gain on derivative activity	—		—		—		—		6.9		6.9
Depreciation and amortization	$	(27.9)	$	(34.3)	$	(46.1)	$	(41.8)	$	(2.0)	$	(152.1)
Segment profit	$	33.4	$	73.0	$	113.7	$	65.0	$	6.9	$	292.0
Depreciation and amortization	$	(30.1)	$	(36.9)	$	(47.6)	$	(36.9)	$	(2.2)	$	(153.7)
Goodwill	$	—	$	—	$	190.3	$	—	$	—	$	190.3
Capital expenditures	$	9552.94	$	427.30	$	~~108~~70.23	$	4119.05	$	12.64	$	~~251~~171.06

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

	Three Months Ended March 31,
	2020		2019
Segment profit	$	300.1	$	301.3
General and administrative expenses	(30.9)		(38.6)
Gain on disposition of assets	0.6		—
Depreciation and amortization	(162.8)		(152.1)
Impairments	(168.4)		—
Operating income (loss)	$	(61.4)	$	110.6

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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 March 31, 2020 and December 31, 2019 (in millions):


	Permian		North Texas		Oklahoma		Louisiana		Corporate		Totals
Six Months Ended June 30, 2020
Natural gas sales	$	47.5	$	34.7	$	69.9	$	150.2	$	—	$	302.3
NGL sales	0.1		0.3		1.7		654.6		—		656.7
Crude oil and condensate sales	372.0		—		21.2		73.3		—		466.5

Product sales	419.6		35.0		92.8		878.1		—		1,425.5

NGL sales—related parties	105.4		31.1		123.6		10.0		(270.1)		—
Crude oil and condensate sales—related parties	0.1		1.9		(0.1)		—		(1.9)		—
Product sales—related parties	105.5		33.0		123.5		10.0		(272.0)		—
Gathering and transportation	29.4		90.1		108.8		23.2		—		251.5
Processing	11.8		68.4		65.4		1.3		—		146.9
NGL services	—		0.1		—		38.2		—		38.3
Crude services	9.2		—		8.9		21.6		—		39.7
Other services	0.8		0.5		0.2		0.8		—		2.3
Midstream services	51.2		159.1		183.3		85.1		—		478.7



Crude services—related parties	—		—		0.2		—		(0.2)		—

Midstream services—related parties	—		—		0.2		—		(0.2)		—
Revenue from contracts with customers	576.3		227.1		399.8		973.2		(272.2)		1,904.2
Cost of sales	(452.3)		(45.9)		(154.8)		(772.2)		272.2		(1,153.0)
Operating expenses	(48.2)		(39.0)		(42.3)		(59.3)		—		(188.8)
Loss on derivative activity	—		—		—		—		(3.2)		(3.2)
Segment profit (loss)	$	75.8	$	142.2	$	202.7	$	141.7	$	(3.2)	$	559.2
Depreciation and amortization	$	(60.2)	$	(73.6)	$	(110.7)	$	(72.4)	$	(4.1)	$	(321.0)
Impairments	$	—	$	—	$	—	$	(169.9)	$	—	$	(169.9)

Capital expenditures	$	132.9	$	7.7	$	11.5	$	30.8	$	1.1	$	184.0

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)

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.


	Permian		North Texas		Oklahoma		Louisiana		Corporate		Totals
Six Months Ended June 30, 2019
Natural gas sales	$	35.1	$	82.5	$	121.9	$	224.8	$	—	$	464.3
NGL sales	0.6		18.0		13.2		1,071.9		—		1,103.7
Crude oil and condensate sales	1,212.8		—		58.2		142.3		—		1,413.3

Product sales	1,248.5		100.5		193.3		1,439.0		—		2,981.3
Natural gas sales—related parties	0.4		0.3		—		—		(0.7)		—
NGL sales—related parties	173.6		50.7		230.7		8.5		(463.5)		—
Crude oil and condensate sales—related parties	10.9		2.7		—		—		(13.6)		—
Product sales—related parties	184.9		53.7		230.7		8.5		(477.8)		—
Gathering and transportation	21.6		112.6		114.5		33.9		—		282.6
Processing	15.0		56.8		69.8		1.7		—		143.3
NGL services	—		—		—		21.7		—		21.7
Crude services	10.5		—		9.2		26.7		—		46.4
Other services	4.4		0.5		(0.1)		0.4		—		5.2
Midstream services	51.5		169.9		193.4		84.4		—		499.2


NGL services—related parties	—		—		—		(3.3)		3.3		—
Crude services—related parties	—		—		1.5		—		(1.5)		—

Midstream services—related parties	—		—		1.5		(3.3)		1.8		—
Revenue from contracts with customers	1,484.9		324.1		618.9		1,528.6		(476.0)		3,480.5
Cost of sales	(1,356.7)		(124.7)		(343.6)		(1,314.5)		476.0		(2,663.5)
Operating expenses	(56.2)		(51.5)		(51.5)		(73.2)		—		(232.4)
Gain on derivative activity	—		—		—		—		8.7		8.7
Segment profit	$	72.0	$	147.9	$	223.8	$	140.9	$	8.7	$	593.3
Depreciation and amortization	$	(58.0)	$	(71.2)	$	(93.7)	$	(78.7)	$	(4.2)	$	(305.8)

Goodwill	$	—	$	—	$	190.3	$	—	$	—	$	190.3
Capital expenditures	$	148.3	$	31.3	$	178.5	$	60.5	$	4.0	$	422.6

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


	Three Months Ended June 30,						Six Months Ended June 30,
	2020		2019		2020		2019
Segment profit	$	259.1	$	292.0	$	559.2	$	593.3
General and administrative expenses	(23.4)		(31.9)		(54.3)		(70.5)
Loss on disposition of assets	(5.2)		(0.1)		(4.6)		(0.1)
Depreciation and amortization	(158.2)		(153.7)		(321.0)		(305.8)
Impairments	(1.5)		—		(169.9)		—
Loss on secured term loan receivable	—		(52.9)		—		(52.9)

Operating income	$	70.8	$	53.4	$	9.4	$	164.0

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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 June 30, 2020 and December 31, 2019 (in millions):


Segment Identifiable Assets:	June 30, 2020		December 31, 2019
Permian	$	2,268.5	$	2,281.1
North Texas	1,061.7		1,135.8
Oklahoma	2,934.4		3,035.0
Louisiana	2,273.7		2,562.0
Corporate	142.8		120.7
Total identifiable assets	$	8,681.1	$	9,134.6

(12) 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:	June 30, 2020		December 31, 2019
Natural gas and NGLs inventory	$	39.7	$	43.4

Prepaid expenses and other	18.7		13.5
Other current assets	$	58.4	$	56.9


Other current liabilities:	June 30, 2020		December 31, 2019
Accrued interest	$	32.0	$	32.6
Accrued wages and benefits, including taxes	15.8		31.5
Accrued ad valorem taxes	23.0		28.5
Capital expenditure accruals	20.6		42.4
Retention liability	11.0		8.7
Short-term lease liability	16.0		21.1
Suspense producer payments	12.1		13.8
Operating expense accruals	9.2		10.8
Other	17.0		12.3
Other current liabilities	$	156.7	$	201.7

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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.

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 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 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 8994% of our gross operating margin was derived from fee-based contractual arrangements with minimal direct commodity price exposure for the ~~three~~six months ended ~~March~~June 3130, 2020. We reflect revenue as “Product sales” and “Midstream services” on the consolidated statements of operations.

~~Devon~~The isfollowing ~~one~~customers individually represented greater than 10% of our ~~primary~~consolidated ~~customers~~revenues. ~~For~~These ~~the~~customers ~~three~~represent ~~months~~a ~~ended~~significant ~~March 31,~~percentage ~~2020~~of ~~and 2019~~revenues, ~~approximately 33.4%~~ and ~~30.0%~~the loss of ~~our~~the ~~gross~~customer ~~operating~~would ~~margin,~~have ~~respectively,~~a ~~was~~material ~~attributable~~adverse toimpact ~~commercial~~on ~~contracts~~our ~~with~~results ~~Devon.~~

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of operations because the revenues and gross operating margin received from transactions with these customers is material to us. No other customers represented greater than 10% of our consolidated revenues.


	Three Months Ended June 30,						Six Months Ended June 30,
	2020		2019		2020		2019
Devon	17.7	%	(1)		15.0	%	(1)
Dow Hydrocarbons and Resources LLC	13.5	%	10.1	%	12.3	%	10.4	%
Marathon Petroleum Corporation	10.3	%	15.2	%	14.8	%	14.7	%

____________________________

(1)Consolidated revenues for Devon did not exceed 10% of our consolidated revenues for the three and six months ended June 30, 2019.

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. 31

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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.

Recent Developments Affecting Industry Conditions and Our Business

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 now reached ~~more~~every ~~than~~region ~~200~~of ~~countries~~the globe and has resulted in widespread adverse impacts on the global economy, on the energy industry as a whole and on 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~~and ~~example,~~especially ~~global~~crude ~~demand for~~ oil ~~has dropped by nearly one-third since mid-February~~. ~~The~~While ~~decline~~reductions in global demand ~~has~~for ~~been~~natural ~~met~~gas ~~with~~and aNGLs ~~decline~~were innever ~~the~~as ~~market~~severe ~~price~~as for ~~these commodities, particularly for~~ crude oil, and ~~especially following~~ the ~~announcement~~demand byfor ~~Saudi Arabia of a significant increase in its maximum~~ crude oil ~~production~~has ~~capacity,~~recovered asfrom ~~well~~the assteepest ~~the~~drops ~~announcement~~in byApril ~~Russia~~and ~~that~~May, ~~previously~~global ~~agreed~~demand ~~upon~~for ~~oil~~energy ~~production~~is ~~cuts~~still ~~between~~reduced ~~members~~as of ~~OPEC+~~the ~~would~~date ~~expire~~of onthis ~~April~~report 1,from ~~2020,~~levels ~~and~~before the ~~ensuing~~pandemic ~~expiration~~in ~~thereof~~mid-February. OnThe ~~April~~decline ~~12,~~in ~~2020~~demand, ~~members~~coupled with the failure of OPEC+ ~~agreed~~ to ~~certain~~quickly ~~production~~agree ~~cuts;~~on ~~however,~~oil ~~these~~production cuts, ~~are~~resulted ~~not~~in ~~expected~~a todecline bein ~~enough~~the tomarket ~~offset~~price ~~near-term~~for ~~demand~~these ~~loss~~commodities, ~~attributable~~most toseverely ~~the~~for ~~COVID-19~~crude ~~pandemic~~oil. InAlthough ~~addition,~~OPEC+ ~~crude~~agreed ~~oil~~to ~~stockpiles~~production ~~and~~cuts ~~the~~in ~~decision~~April, ofextended ~~end~~these ~~users,~~cuts ~~such~~through ~~as refineries~~July, ~~not~~and toare ~~take~~expected ato ~~normal~~continue ~~level~~the ofproduction ~~crude~~cuts ~~oil~~beyond ~~shipments~~July, ~~has~~although ~~led~~at to a ~~severe~~more ~~and~~moderate ~~growing~~level, ~~shortage~~and ofalthough ~~storage~~United ~~capacity~~States ~~for~~ oil ~~and~~producers ~~significantly~~have ~~higher~~also ~~costs~~curtailed ~~for~~their ~~available~~drilling ~~storage.~~programs, Inthese ~~the~~cuts ~~case~~have ofnot ~~the~~been ~~oil~~enough ~~markets,~~to ~~both~~fully ~~the~~offset ~~decline~~demand inloss ~~demand~~attributable ~~and~~to ~~storage~~the ~~concerns~~COVID-19 ~~have~~pandemic ~~caused~~and ~~the~~market ~~price~~prices ofremain ~~oil~~lower tothan ~~reach~~prior ~~historic~~to ~~lows.~~the pandemic.

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 many of our customers, have ~~sharply~~ curtailed their current drilling and production activity, asincluding ~~well~~in assome ~~their~~cases ~~plans~~by ~~for future drilling and production activity. This reduction~~ shutting-in production ~~has been most acute for crude oil production~~, ~~but~~as ~~because~~well ~~condensate~~as ~~production~~reducing ~~and~~their aplans ~~significant~~for ~~portion~~future ~~of gas and NGL production depends on, or is a byproduct of, the production of crude oil, the curtailment of crude oil~~ drilling and production ~~affects the production of these other commodities~~activity. As a result of these decreases in producer activity, our business 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 asin asome ~~result~~ of ~~reduced production from~~ the regions that supply our systems. Our first priority in our response to this 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.

~~There~~Since isthe ~~considerable~~outbreak ~~uncertainty~~began, ~~regarding~~our ~~the~~first ~~extent~~priority tohas ~~which~~been ~~COVID-19~~the ~~will~~health ~~continue~~and tosafety ~~spread~~of ~~and~~our ~~the~~employees ~~extent~~ and ~~duration~~those of ~~governmental~~our customers and other ~~measures~~business counterparties. We have implemented topreventative ~~try~~measures and developed a response plan to ~~slow~~minimize ~~the~~unnecessary ~~spread~~risk of ~~the~~exposure ~~virus~~and prevent infection, ~~such~~while assupporting ~~large-scale~~our ~~travel~~customers’ ~~bans~~operations. ~~and~~We ~~restrictions,~~have ~~border~~a ~~closures,~~crisis ~~quarantines,~~management ~~shelter-in-place~~team ~~orders~~for health, safety and ~~business~~environmental matters and ~~government~~personnel ~~shutdowns.~~issues, Asand we have established a ~~result,~~cross-functional ~~there~~COVID-19 isresponse ~~significant~~team ~~uncertainty~~to ~~regarding~~address ~~how~~various ~~long~~impacts of the ~~market~~situation, ~~dislocations~~as ~~will~~they ~~continue~~have ~~and~~been ~~how~~developing. ~~significantly~~We ~~and~~also ~~how~~have ~~long~~modified ~~they~~certain ~~will~~business ~~continue~~practices to(including ~~affect~~discontinuing ~~us.~~all Wenon-essential ~~expect~~business totravel, ~~see~~implementing ~~continued~~a ~~volatility~~temporary inwork-from-home ~~crude~~policy ~~oil,~~for ~~condensate,~~employees ~~natural~~who ~~gas~~can execute their work remotely, and ~~NGL~~encouraging ~~prices~~employees ~~for~~to ~~the~~adhere ~~foreseeable~~to ~~future,~~local ~~which~~and ~~may,~~regional ~~over~~social ~~the~~distancing ~~long~~recommendations) ~~term,~~to ~~adversely~~support ~~impact~~efforts ~~our~~to ~~business.~~reduce Athe ~~sustained~~spread ~~significant~~of ~~decline~~COVID-19 inand ~~oil~~to ~~and~~conform ~~natural~~to ~~gas~~government ~~exploration~~restrictions and ~~production~~best ~~activities~~practices ~~and~~encouraged ~~related~~by ~~reduced~~the ~~demand~~Centers for ~~our~~Disease ~~services~~Control byand ~~our customers~~Prevention, ~~whether~~the ~~due~~World toHealth ~~decreases~~Organization, inand ~~consumer~~other ~~demand~~governmental orand ~~reduction~~regulatory inauthorities. ~~the~~We ~~prices~~also ~~for~~have ~~oil,~~promoted ~~condensate~~heightened ~~natural~~awareness ~~gas~~ and ~~NGLs~~vigilance, ~~or otherwise~~hygiene, ~~would~~and ~~have~~implementation aof ~~material~~more ~~adverse~~stringent ~~effect~~cleaning onprotocols across our ~~business,~~facilities ~~liquidity,~~and ~~financial~~operations. ~~condition,~~We ~~results~~continue ofto ~~operations,~~evaluate and ~~cash~~adjust ~~flows~~these ~~(including~~preventative ~~our~~measures, ~~ability~~response toplans ~~make~~and ~~distributions~~business topractices ~~our~~with ~~unitholders).~~the evolving impacts of COVID-19.

AsThere ofis ~~the~~considerable ~~date~~uncertainty ofregarding ~~this~~how ~~report,~~long ~~our~~COVID-19 ~~efforts~~will topersist ~~respond~~and toaffect economic conditions and the ~~challenges~~extent ~~presented~~and byduration ~~the~~of ~~conditions~~changes ~~described~~in ~~above~~consumer ~~and~~behavior, ~~minimize~~such as the ~~impacts~~reluctance to ~~our~~travel, ~~business~~as ~~have~~well ~~yielded~~as ~~results.~~governmental ~~Our~~and ~~systems,~~other ~~pipelines,~~measures ~~and~~implemented ~~facilities~~to ~~have~~try ~~remained~~to ~~operational.~~slow Wethe ~~have~~spread ~~also~~of ~~moved~~the ~~quickly~~virus, ~~and~~such ~~decisively~~as tolarge-scale ~~implement~~travel ~~strategies~~bans toand ~~reduce~~restrictions, ~~costs~~border closures, ~~increase~~quarantines, ~~operational~~shelter-in-place ~~efficiencies~~orders, and ~~lower~~business ~~our~~and ~~capital~~government ~~spending~~shutdowns. As wea ~~previously announced~~result, wethere ~~intend~~is tosignificant ~~reduce~~uncertainty ~~our~~regarding ~~capital~~how ~~expenditures~~long inthe ~~2020,~~market ~~including~~dislocations ~~both~~will ~~growth~~continue and ~~maintenance~~how ~~capital~~significantly ~~expenditures, to between $190 million~~ and ~~$250~~how ~~million,~~long athey ~~65%~~will ~~reduction~~continue ~~from~~to ~~2019~~affect ~~total capital spending~~us. We ~~have~~expect ~~also~~to ~~reduced~~see ~~costs~~continued ~~across~~volatility ~~our~~in ~~platform~~crude ~~and~~oil, wecondensate, ~~intend~~natural togas, ~~reduce~~and ~~our~~NGL ~~general~~prices ~~and~~for ~~administrative~~the ~~and~~foreseeable ~~operational~~future, ~~expenses~~which bymay, ~~$100~~over ~~million~~the ~~for~~long ~~the~~term, ~~full-year~~adversely ~~2020~~impact ~~versus~~our ~~the~~business. ~~twelve~~A ~~months~~sustained ~~ended~~significant ~~December~~decline ~~31,~~in ~~2019.~~oil Inand ~~addition,~~natural wegas ~~maintain~~exploration ~~our~~and ~~previously~~production ~~announced~~activities ~~plan~~and torelated ~~fully~~reduced ~~self-fund~~demand ~~all~~for ~~capital~~our ~~expenditures~~services ~~during~~by ~~2020~~our ~~with~~customers, ~~internally~~whether ~~generated~~due ~~cash~~to ~~flows,~~decreases ~~and~~in ~~have~~consumer nodemand ~~plans~~or toreduction ~~access~~in the ~~capital~~prices ~~markets~~for ~~during~~oil, ~~2020.~~condensate ~~Also,~~natural asgas ofand ~~March~~NGLs ~~31,~~or ~~2020~~otherwise, wewould ~~had~~have ~~approximately~~a ~~$258~~material ~~million~~adverse ofeffect ~~cash~~ on our ~~balance~~business, ~~sheet~~liquidity, ~~and~~financial ~~have~~condition, ~~drawn~~results ~~only~~of ~~approximately~~operations, ~~$550~~and ~~million~~cash onflows (including our ~~$1.75~~ability ~~billion~~to ~~ENLC~~make ~~Credit~~distributions ~~Facility.~~to Weour unitholders).

31As of the date of this report, our efforts to respond to the challenges presented by the conditions described above and minimize the impacts to our business have yielded results. Our systems, pipelines, and facilities have remained operational. We

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have also moved quickly and decisively, and we continue to adapt and respond promptly, to implement strategies to reduce costs, increase operational efficiencies, and lower our capital spending. As we previously announced, we intend to reduce our capital expenditures in 2020, including both growth and maintenance capital expenditures, to between $190 million and $250 million, a 65% reduction from 2019 total capital spending. We have also reduced costs across our platform and we intend to reduce our general and administrative and operational expenses by $120 million for the full-year 2020 versus the twelve months ended December 31, 2019. Also, as of June 30, 2020, we had approximately $52 million of cash on our balance sheet and have drawn only approximately $400 million on the $1.75 billion Consolidated Credit Facility. We 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~~duration ~~spread~~and persistence of the ~~virus~~outbreak, the ~~consequences~~effect of ~~governmental~~the outbreak on economic, social and other ~~measures~~aspects ~~designed~~of toeveryday ~~prevent~~life, the ~~spread~~consequences of ~~the~~governmental ~~virus,~~and ~~the~~other ~~development~~measures ofdesigned ~~effective~~to ~~treatments,~~prevent the ~~duration~~spread of the ~~outbreak~~virus, ~~and~~ the ~~governmental~~development ~~measures~~and ~~designed~~timing toof ~~contain~~effective ~~the~~treatments ~~virus~~and vaccines, 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, social and operating conditions resume.

WeFor ~~have~~additional ~~revised~~discussion ~~our~~regarding ~~forecasts~~risks ~~and~~associated aswith ~~a result have recorded impairments of property and equipment during~~ the ~~three~~COVID-19 ~~months~~pandemic, ~~ended~~see ~~March~~Part 31II, ~~2020.~~Item We1A ~~will~~“Risk ~~continue~~Factors” toin ~~monitor~~our ~~the~~Quarterly ~~market~~Report ~~environment~~on ~~and~~Form ~~will~~10-Q ~~evaluate~~for ~~whether~~the ~~additional~~quarter ~~triggering~~ended ~~events~~March ~~would~~31, ~~indicate possible impairments of property and equipment and intangible assets~~2020.

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.

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~~third ~~half~~quarter of 2020. This processing plant is owned by the Delaware Basin JV.

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.

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

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


	Three Months Ended June 30,						Six Months Ended June 30,
	2020		2019		2020		2019
Operating income	$	70.8	$	53.4	$	9.4	$	164.0

Add:
Operating expenses	88.1		117.9		188.8		232.4
General and administrative expenses	23.4		31.9		54.3		70.5
Loss on disposition of assets	5.2		0.1		4.6		0.1
Depreciation and amortization	158.2		153.7		321.0		305.8
Impairments	1.5		—		169.9		—
Loss on secured term loan receivable	—		52.9		—		52.9

Gross operating margin	$	347.2	$	409.9	$	748.0	$	825.7

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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 EndedMarch 31,
	Three Months EndedJune 30,						Six Months EndedJune 30,
	2020		2019		2020		2019
Permian Segment
Revenues	$	~~371~~204.76	$	742.63	$	576.3	$	1,484.9
Cost of sales	(~~313~~138.94)		(~~676~~680.25)		(452.3)		(1,356.7)
Total gross operating margin	$	5766.82	$	6661.48	$	124.0	$	128.2
North Texas Segment
Revenues	$	~~120~~106.74	$	~~174~~149.38	$	227.1	$	324.1
Cost of sales	(2718.09)		(7351.70)		(45.9)		(124.7)
Total gross operating margin	$	9387.75	$	~~100~~98.68	$	181.2	$	199.4
Oklahoma Segment
Revenues	$	~~220~~179.08	$	~~319~~299.72	$	399.8	$	618.9
Cost of sales	(9361.71)		(~~184~~159.24)		(154.8)		(343.6)
Total gross operating margin	$	~~126~~118.37	$	~~135~~139.58	$	245.0	$	275.3
Louisiana Segment
Revenues	$	~~563~~409.57	$	~~798~~730.15	$	973.2	$	1,528.6
Cost of sales	(~~459~~312.75)		(~~686~~627.69)		(772.2)		(1,314.5)
Total gross operating margin	$	~~103~~97.82	$	~~111~~102.56	$	201.0	$	214.1
Corporate Segment
Revenues	$	(~~119~~155.86)	$	(~~255~~211.58)	$	(275.4)	$	(467.3)
Cost of sales	~~139~~133.02		~~257~~218.37		272.2		476.0
Total gross operating margin	$	19(22.24)	$	16.89	$	(3.2)	$	8.7
Total
Revenues	$	~~1,156~~744.19	$	1,~~779~~710.20	$	1,901.0	$	3,489.2
Cost of sales	(~~755~~397.37)		(1,~~363~~300.41)		(1,153.0)		(2,663.5)
Total gross operating margin	$	~~400~~347.82	$	~~415~~409.89	$	748.0	$	825.7
Midstream Volumes:
Permian Segment
Gathering and Transportation (MMBtu/d)	~~831~~871,~~100~~500		~~657~~676,~~500~~000		851,300		666,800
Processing (MMBtu/d)	~~861~~896,~~700~~100		~~712~~724,~~000~~100		878,900		718,100
Crude Oil Handling (Bbls/d)	~~133~~112,~~400~~300		~~147~~145,~~400~~100		122,900		146,200
North Texas Segment
Gathering and Transportation (MMBtu/d)	1,~~577~~485,~~700~~900		1,~~683~~646,~~100~~900		1,531,800		1,664,900
Processing (MMBtu/d)	~~699~~670,~~700~~600		~~729~~770,~~800~~100		685,200		750,100
Oklahoma Segment
Gathering and Transportation (MMBtu/d)	1,~~220~~092,~~900~~600		1,~~244~~314,~~400~~900		1,156,800		1,279,800
Processing (MMBtu/d)	1,~~154~~082,~~400~~100		1,~~231~~298,~~600~~800		1,118,300		1,265,400
Crude Oil Handling (Bbls/d)	3630,~~600~~000		2953,~~200~~800		33,300		41,600
Louisiana Segment
Gathering and Transportation (MMBtu/d)	21,~~043~~873,~~200~~600		21,~~070~~925,~~500~~900		1,958,400		1,997,800
Processing (MMBtu/d)	~~169~~197,~~600~~200		~~468~~337,~~000~~100		183,400		402,200
Crude Oil Handling (Bbls/d)	1715,~~400~~700		1520,000		16,600		17,500
NGL Fractionation (Gals/d)	87,~~184~~344,~~100~~800		67,~~973~~477,~~800~~400		7,764,500		7,227,000
Brine Disposal (Bbls/d)	1,~~700~~400		3,~~500~~400		1,600		3,400

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Three Months Ended ~~March~~June 3130, 2020 Compared to Three Months Ended ~~March~~June 3130, 2019

Gross Operating Margin. Gross operating margin was $~~400~~347.82 million for the three months ended ~~March~~June 3130, 2020 compared to $~~415~~409.89 million for the three months ended ~~March~~June 3130, 2019, a decrease of $1562.07 million, or 315.63%, due to the following:

•Permian Segment. Gross operating margin in the Permian segment ~~decreased~~increased $84.64 million, resulting from (i) a $72.65 million ~~decrease~~increase in gross operating margin from our Permian crude assets ~~with~~primarily aattributable ~~$3.8 million decrease due~~ to ~~declines~~volume growth in ~~crude~~our ~~oil~~Delaware ~~prices~~Basin ~~and~~assets, ~~$3.8~~which ~~million~~was ofpartially ~~that~~offset ~~decrease~~by ~~due to~~ the expiration of an MVC related to our South Texas assets in July 2019, and (ii) a $1.09 million ~~decrease~~increase in gross operating margin from our Permian gas assets ~~due~~primarily toattributable ~~a $2.3 million decrease in gross operating margin related~~ to ~~our~~volume ~~Midland Basin assets offset by a $1~~growth.3 ~~million increase in gross operating margin related to our Delaware Basin assets.~~

•North Texas Segment. Gross operating margin in the North Texas segment decreased $611.93 million, which was primarily due to volume declines resulting from limited new drilling in the region.

•Oklahoma Segment. Gross operating margin in the Oklahoma segment decreased $921.~~2 million. Gross operating margin contributed by our Oklahoma gas assets decreased $10.~~1 million, ~~which~~primarily ~~was partially~~ due to lower volumes from ~~our~~well ~~existing~~shut-ins ~~customers,~~from ~~and was partially offset by a $0.9 million increase in gross operating margin contributed by~~ our ~~Oklahoma crude assets~~customers.

•Louisiana Segment. Gross operating margin in the Louisiana segment decreased $75.74 million, resulting from (i) a $4.0 million decrease in gross operating margin from our Louisiana gas plants due to lower processing margins and volumes attributable to a less favorable processing environment, and (ii) a $3.7 million decrease in gross operating margin from our Louisiana gas transmission assets due to the expiration of certain firm transportation contracts and decreased volumes. While gross operating margin related to our ORV crude assets decreased $1.8 million, primarily due to lower volumes, this decrease was partially offset by an increase of $1.8 million in gross operating margin from our NGL transmission and fractionation assets, which was primarily due to higher volumes that resulted from the completion of the Cajun-Sibon pipeline expansion in April 2019. :

•~~Corporate~~A ~~Segment~~$4.7 ~~Gross~~million ~~operating~~decrease ~~margin~~from inour ~~the~~Louisiana ~~Corporate~~gas ~~segment~~assets ~~increased~~due ~~$17.4~~to ~~million,~~lower ~~which~~processing ~~was~~margins ~~primarily~~and ~~due~~volumes attributable to ~~the~~a ~~changes~~less infavorable ~~fair~~processing ~~value~~environment, ofthe ~~our~~expiration ~~commodity~~of ~~swaps~~certain ~~between~~firm ~~the~~transportation ~~periods~~contracts, asand ~~summarized~~decreased ~~below (in millions):~~volumes.

	Three Months EndedMarch 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

•A $4.3 million decrease from our ORV crude assets primarily due to lower volumes.

~~Certain~~•A ~~gathering~~$3.6 ~~and~~million ~~processing~~increase ~~agreements provide for quarterly or annual MVCs, including MVCs~~ from ~~Devon. Under these agreements,~~ our ~~customers~~NGL ~~agree~~transmission ~~to ship~~ and~~/or~~ ~~process~~fractionation ~~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~~assets, ~~the~~which ~~customer~~was isprimarily ~~obligated~~due to ~~pay~~ a ~~contractually~~settlement ~~determined~~payment ~~fee~~received ~~based~~as ~~upon~~ the ~~shortfall~~result ~~between actual commodity volumes and the MVC for that period. Some~~ of ~~these agreements also contain make-up right provisions that allow~~ a ~~customer~~contract ~~to utilize gathering or processing fees in~~ dispute.

35•Corporate Segment. Gross operating margin in the Corporate segment decreased $29.3 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 June 30,
	2020		2019
Realized swaps:
Crude swaps	$	(2.4)	$	(2.5)
NGL swaps	(0.4)		3.7
Gas swaps	(0.8)		(1.5)
Realized loss on derivatives	(3.6)		(0.3)

Unrealized swaps:
Crude swaps	(3.6)		4.9
NGL swaps	(14.4)		1.3
Gas swaps	(0.8)		1.0
Change in fair value of derivatives	(18.8)		7.2

Gain (loss) on derivatives	$	(22.4)	$	6.9

Certain gathering and processing agreements provide for quarterly or annual MVCs. 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.

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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):

	Three Months EndedMarch 31,
	Three Months EndedJune 30,
	2020		2019
Permian Segment	$	2(1.07)	$	3.89
Oklahoma Segment	915.81		—
Total	$	1113.84	$	3.89

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 $~~100~~88.71 million for the three months ended ~~March~~June 3130, 2020 compared to $~~114~~117.59 million for the three months ended ~~March~~June 3130, 2019, a decrease of $1329.8 million, or 1225.13%. The primary contributors to the total decrease by segment were as follows (in millions):

	Three Months EndedMarch 31,						Change
	Three Months EndedJune 30,						Change
	2020		2019		$		%
Permian Segment	$	2522.57	$	2728.84	$	(25.37)	(820.31)	%
North Texas Segment	2018.5		25.78		(57.23)		(2028.23)	%
Oklahoma Segment	2219.94		2526.41		(26.57)		(925.87)	%
Louisiana Segment	3127.85		3537.6		(310.81)		(1026.79)	%
Total	$	~~100~~88.71	$	~~114~~117.59	$	(1329.8)	(1225.13)	%

•Permian Segment. Operating expenses in the Permian segment decreased $25.37 million primarily due to decreased labor and benefits expense as a result of a reduction in workforce in April 2020 and reductions in ~~materials~~construction fees and ~~supplies~~services, ~~expenses~~and sales and use tax.

•North Texas Segment. Operating expenses in the North Texas segment decreased $57.23 million primarily due to ~~reductions~~decreased labor and benefits expense as a result of a reduction in ~~materials~~workforce in April 2020 and ~~supplies~~reductions ~~expenses~~in operations and maintenance, ~~construction~~ad ~~fees~~valorem tax, sales and ~~services~~use tax, and ~~vehicle~~compressor rentals.

•Oklahoma Segment. Operating expenses in the Oklahoma segment decreased $26.57 million primarily due to ~~reductions~~decreased labor and benefits expense as a result of a reduction in ~~compressor~~workforce ~~operations~~in April 2020 and ~~maintenance,~~reductions in materials and supplies ~~expenses~~expense, operations and maintenance, construction fees and services, and ~~vehicle~~compressor and treater rentals.

•Louisiana Segment. Operating expenses in the Louisiana segment decreased $310.81 million primarily due to ~~reductions~~decreased in labor and benefits ~~costs,~~expense as a result of a reduction in workforce in April 2020 and reductions in materials and supplies ~~expenses~~expense, utilities, construction fees and services, ad valorem tax, and vehicle ~~rentals~~expenses.

~~Operating~~General and Administrative Expenses. General and administrative expenses were $23.4 million for the three months ended ~~March 31~~June 30, 2020 ~~included~~compared to $331.39 million offor ~~severance~~the ~~costs~~three ~~related~~months toended June 30, 2019, a ~~reduction~~decrease inof ~~workforce~~$8.5 million, or 26.6%. The primary contributors to the decrease were as follows:

~~General~~•Labor ~~and~~costs ~~Administrative Expenses. General~~ and ~~administrative~~unit-based ~~expenses~~compensation ~~were~~costs decreased $303.98 million, ~~for~~which ~~the~~was ~~three~~primarily ~~months~~due ~~ended March 31, 2020 compared~~ to ~~$38.6 million for the three months ended March 31, 2019,~~ a ~~decrease~~reduction ofin ~~$7.7~~workforce ~~million,~~in orApril 192020.~~9%. The primary contributors to the decrease were as follows:~~

•~~Unit-based~~Expenses ~~compensation~~related ~~expense~~to ~~decreased~~fees ~~$4.0~~and ~~million~~services, ~~which~~travel, ~~was~~rents ~~primarily~~and ~~due~~leases, toand ~~larger~~insurance ~~awards~~decreased ~~and~~$3.2 ~~lower~~million ~~forfeitures~~primarily ~~during~~due ~~the~~to ~~first~~general ~~quarter~~cost ofsaving ~~2019~~initiatives asand ~~compared~~decreased toactivity ~~the~~as ~~first~~a ~~quarter~~result of ~~2020~~COVID-19.

~~•Transaction~~Depreciation ~~costs~~and ~~decreased~~Amortization. Depreciation and amortization was $1158.2 million for the three months ended June 30, 2020 compared to $153.7 million for the three months ended June 30, ~~which~~2019, an increase of $4.5 million, or 2.9%. This increase was primarily due to ~~higher~~new ~~transaction~~assets ~~costs~~placed ~~related~~in toservice in the ~~Merger~~Permian, ~~that~~Oklahoma, and Louisiana segments, as well as accelerated depreciation on certain non-core assets. These increases were ~~incurred~~partially ~~during~~offset by the impairment of Louisiana segment assets in the first quarter of 2020 and the conclusion of a finance lease in the North Texas segment in 2019.

~~•Benefits and payroll taxes decreased $1.2 million, which was primarily due to a reduction in costs related to employee benefits.~~ 37

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~~General~~Impairments. ~~and~~For ~~administrative expenses for~~ the three months ended ~~March 31~~June 30, 2020, ~~included~~we recognized a $21.65 million ofimpairment ~~severance~~on ~~costs~~property and equipment related to acancelled ~~reduction~~projects. inSee ~~workforce~~“Item 1. Financial Statements—Note 2” for additional information on our property and equipment impairments.

~~Depreciation~~Gain ~~and~~on ~~Amortization.~~Extinguishment ~~Depreciation~~of ~~and amortization was $162~~Debt.8 ~~million~~We ~~for~~recognized ~~the~~a ~~three~~gain ~~months~~on ~~ended~~extinguishment ~~March 31,~~of ~~2020~~debt ~~compared~~of to $~~152~~26.17 million for the three months ended ~~March~~June 3130, ~~2019,~~2020 ~~an increase of $10.7 million, or 7.0%. This increase was primarily~~ due to ~~accelerated~~repurchases 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~~2024, ~~the Cajun-Sibon NGL pipeline~~2025, ~~Avenger~~2026, ~~the Black Coyote crude oil gathering system,~~ and ~~well~~2029 ~~connections~~Notes in ~~Oklahoma.~~open ~~These~~market ~~increases~~transactions. ~~were~~See ~~partially~~“Item ~~offset~~1. byFinancial ~~retirements~~Statements—Note of5” ~~certain~~for ~~non-core~~additional ~~assets in the Louisiana segment during the first quarter of 2019~~information.

~~Impairments~~Interest Expense. ~~For~~Interest expense was $55.2 million for the three months ended ~~March~~June 3130, 2020, wecompared ~~recognized~~to a $~~168~~54.03 million ~~impairment~~for ~~on property and equipment related to a portion of our Louisiana reporting segment because~~ the ~~carrying~~three ~~amounts~~months ~~were~~ended ~~not~~June 30, ~~recoverable based on our expected future cash flows. Additionally~~2019, wean ~~recorded~~increase aof $0.49 million, ~~impairment~~or ~~related to certain cancelled projects. See “Item~~ 1.7%. ~~Financial~~Interest ~~Statements—Note~~expense 2”consisted ~~for~~of ~~additional~~the ~~information~~following on(in ~~our~~millions): ~~property and equipment impairments.~~

Gain on Extinguishment of Debt. We recognized a gain on extinguishment of debt of $5.3 million for the three months ended March 31, 2020 due to repurchases of the 2024, 2025, and 2026 Notes in open market transactions. See “Item 1. Financial Statements—Note 6” for additional information.


	Three Months Ended June 30,
	2020		2019
Senior Notes	$	36.5	$	37.3
Related party debt	15.1		18.3

Capitalized interest	(1.3)		(1.8)
Amortization of debt issue costs and net discounts (premiums)	1.2		1.0

Interest rate swap	3.7		(0.3)
Other	—		(0.2)
Total	$	55.2	$	54.3

~~Interest~~Income ~~Expense~~(Loss) from Unconsolidated Affiliate Investments. ~~Interest~~Loss ~~expense~~from unconsolidated affiliate investments was $550.67 million for the three months ended ~~March~~June 3130, 2020 compared to income of $494.37 million for the three months ended ~~March~~June 3130, 2019, ana ~~increase~~decrease of $65.34 million,. orThe 12decrease was primarily attributable to a reduction of income of $4.~~8%.~~9 ~~Interest~~million ~~expense~~from ~~consisted~~our GCF investment as a result of ~~the~~lower ~~following~~fractionation ~~(in~~revenues ~~millions):~~and lower operating expenses and a reduction of income of $0.5 million from our Cedar Cove JV.

	Three Months EndedMarch 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

Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019

Gross Operating Margin. Gross operating margin was $748.0 million for the six months ended June 30, 2020 compared to $825.7 million for the six months ended June 30, 2019, a decrease of $77.7 million, or 9.4%, due to the following:

•Permian Segment. Gross operating margin in the Permian segment decreased $4.2 million, resulting from:

•An $11.6 million decrease due to the expiration of an MVC related to our South Texas assets in July 2019.

•A $3.7 million increase due to volume growth in our Midland Basin crude assets.

•A $2.9 million increase due to volume growth in our Delaware Basin crude assets.

•A $1.9 million decrease related to our Midland Basin gas assets.

•A $2.7 million increase related to our Delaware Basin gas assets.

•North Texas Segment. Gross operating margin in the North Texas segment decreased $18.2 million, which was primarily due to volume declines resulting from limited new drilling in the region.

•Oklahoma Segment. Gross operating margin in the Oklahoma segment decreased $30.3 million. Gross operating margin contributed by our Oklahoma gas assets decreased $31.2 million, which was partially due to lower volumes from our existing customers, and was partially offset by a $0.9 million increase in gross operating margin contributed by our Oklahoma crude assets.

•Louisiana Segment. Gross operating margin in the Louisiana segment decreased $13.1 million, resulting from:

•A $12.4 million decrease from our Louisiana gas assets due to lower processing margins and volumes attributable to a less favorable processing environment, the expiration of certain firm transportation contracts, and decreased volumes.

•A $6.1 million decrease from our ORV crude assets primarily due to lower volumes.

•A $5.4 million increase from our NGL transmission and fractionation assets, which was primarily due to higher volumes that resulted from the completion of the Cajun-Sibon pipeline expansion in April 2019 and a settlement payment received as the result of a contract dispute.

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•Corporate Segment. Gross operating margin in the Corporate segment decreased $11.9 million, which was primarily due to the changes in fair value of our commodity swaps between the periods as summarized below (in millions):


	Six Months Ended June 30,
	2020		2019
Realized swaps:
Crude swaps	$	(3.0)	$	0.8
NGL swaps	6.3		5.6
Gas swaps	(0.7)		(2.9)
Realized gain on derivatives	2.6		3.5

Unrealized swaps:
Crude swaps	2.5		4.5
NGL swaps	(7.0)		(2.3)
Gas swaps	(1.3)		3.0
Change in fair value of derivatives	(5.8)		5.2

Gain (loss) on derivatives	$	(3.2)	$	8.7

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


	Six Months Ended June 30,
	2020		2019
Permian	$	0.3	$	7.7
Oklahoma	24.9		—
Total	$	25.2	$	7.7

Operating Expenses. Operating expenses were $188.8 million for the six months ended June 30, 2020 compared to $232.4 million for the six months ended June 30, 2019, a decrease of $43.6 million, or 18.8%. The primary contributors to the decrease by segment were as follows (in millions):


	Six Months Ended June 30,						Change
	2020		2019		$		%
Permian Segment	$	48.2	$	56.2	$	(8.0)	(14.2)	%
North Texas Segment	39.0		51.5		(12.5)		(24.3)	%
Oklahoma Segment	42.3		51.5		(9.2)		(17.9)	%
Louisiana Segment	59.3		73.2		(13.9)		(19.0)	%
Total	$	188.8	$	232.4	$	(43.6)	(18.8)	%

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•Permian Segment. Operating expenses in the Permian segment decreased $8.0 million primarily due to decreased labor and benefits expense as a result of a reduction in workforce in April 2020 and reductions in materials and supplies expense, construction fees and services, sales and use tax, and vehicle expenses.

•North Texas Segment. Operating expenses in the North Texas segment decreased $12.5 million primarily due to decreased labor and benefits expense as a result of a reduction in workforce in April 2020 and reductions in materials and supplies expense, operations and maintenance, construction fees and services, ad valorem tax, sales and use tax, and treater and compressor rentals.

•Oklahoma Segment. Operating expenses in the Oklahoma segment decreased $9.2 million primarily due to decreased labor and benefits expense as a result of a reduction in workforce in April 2020 and reductions in materials and supplies expense, construction fees and services, operations and maintenance, utilities, ad valorem tax, and treater rentals.

•Louisiana Segment. Operating expenses in the Louisiana segment decreased $13.9 million primarily due to decreased labor and benefits expense as a result of a reduction in workforce in April 2020 and reductions in materials and supplies expense, construction fees and services, ad valorem tax, and vehicle expenses.

General and Administrative Expenses. General and administrative expenses were $54.3 million for the six months ended June 30, 2020 compared to $70.5 million for the six months ended June 30, 2019, a decrease of $16.2 million, or 23.0%. The primary contributors to the decrease were as follows:

•Labor costs and unit-based compensation decreased $8.6 million due to a reduction in workforce and lower bonus accrual.

•Transaction costs decreased $2.1 million, which was primarily due to costs incurred related to the Merger, which closed during the first quarter of 2019.

•Fees and services expense, rents and leases, and insurance expenses decreased $1.4 million, which was primarily due to general cost saving initiatives.

Depreciation and Amortization. Depreciation and amortization was $321.0 million for the six months ended June 30, 2020 compared to $305.8 million for the six months ended June 30, 2019, an increase of $15.2 million, or 5.0%. This increase was primarily due to new assets placed in service in the Oklahoma segment, as well as accelerated depreciation on certain non-core assets. These increases were partially offset by the impairment of Louisiana segment assets in the first quarter of 2020 and the conclusion of a finance lease in the North Texas segment in 2019.

Impairments. For the six months ended June 30, 2020, we recognized impairment expense related to property and equipment. For the six months ended June 30, 2019, we did not recognize an impairment expense. See “Item 1. Financial Statements—Note 2” for additional information on our property and equipment impairments. Impairment expense is composed of the following amounts (in millions):


	Six Months Ended June 30,
	2020
Property impairment	$	168.0
Cancelled projects	1.9
Total	$	169.9

Gain on Extinguishment of Debt. We recognized a gain on extinguishment of debt of $32.0 million for the six months ended June 30, 2020 due to repurchases of the 2024, 2025, 2026, and 2029 Notes in open market transactions. See “Item 1. Financial Statements—Note 5” for additional information.

Loss on secured term loan receivable. We recorded a $52.9 million loss in our consolidated statement of operations for the six months ended June 30, 2019 related to the write-off of the secured term loan receivable.

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Interest Expense. Interest expense was $110.8 million for the six months ended June 30, 2020 compared to $103.6 million for the six months ended June 30, 2019, an increase of $7.2 million, or 6.9%. Interest expense consisted of the following (in millions):


	Six Months Ended June 30,
	2020		2019
Senior Notes	$	73.9	$	77.3
Related party debt	32.2		29.3
Capitalized interest	(2.5)		(3.8)
Amortization of debt issue costs and net discounts (premiums)	2.2		2.8
Interest rate swap	5.0		(0.3)
Other	—		(1.7)

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