enlc-20200930

Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

Form 10-Q

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

For the quarterly period ended September 30, 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 October 29, 2020, the Registrant had 144,358,720 common units outstanding, all of which were held by our affiliate, EnLink Midstream, LLC.

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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	30

3.	Quantitative and Qualitative Disclosures About Market Risk	45

4.	Controls and Procedures	48

	PART II—OTHER INFORMATION

1.	Legal Proceedings	49

1A.	Risk Factors	49

5.	Other Information	49



6.	Exhibits	50

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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.

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.”


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.



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.


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.

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.
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.

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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.

Tiger Plant						A gas processing plant in the Delaware Basin owned by the Delaware Basin JV.

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PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

ENLINK MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

Consolidated Balance Sheets

(In millions, except unit data)


	September 30, 2020		December 31, 2019
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	78.9	$	77.4
Accounts receivable:
Trade, net of allowance for bad debt of $0.5 and $0.5, respectively	58.3		36.2
Accrued revenue and other	352.9		460.1
Related party	16.0		18.1
Fair value of derivative assets	9.6		12.9
Other current assets	81.7		56.9
Total current assets	597.4		661.6
Property and equipment, net of accumulated depreciation of $3,775.9 and $3,418.6, respectively	6,742.0		7,081.3
Intangible assets, net of accumulated amortization of $638.0 and $545.9, respectively	1,156.2		1,249.9
Investment in unconsolidated affiliates	41.9		43.1
Fair value of derivative assets	5.4		4.3
Other assets, net	87.3		94.4
Total assets	$	8,630.2	$	9,134.6
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable and drafts payable	$	54.4	$	70.6
Accounts payable to related party	0.9		1.1
Accrued gas, NGLs, condensate, and crude oil purchases	214.8		354.8
Fair value of derivative liabilities	33.1		14.4

Other current liabilities	188.8		201.7
Total current liabilities	492.0		642.6
Long-term debt, including $1,648.7 and $1,700.0 from related parties, respectively	4,650.0		4,764.3
Asset retirement obligations	16.1		15.5
Other long-term liabilities	83.5		90.8
Deferred tax liability	45.2		44.5
Fair value of derivative liabilities	4.5		6.8

Redeemable non-controlling interest	—		5.2

Partners’ equity:
Common unitholders (144,358,720 units issued and outstanding)	1,419.2		1,681.2
Series B preferred unitholders (60,047,665 and 59,599,550 units issued and outstanding, respectively)	896.1		895.1
Series C preferred unitholders (400,000 units outstanding)	401.1		395.1
General partner interest (1,594,974 equivalent units outstanding)	215.7		216.6
Accumulated other comprehensive loss	(24.9)		(14.5)
Non-controlling interest	431.7		391.4
Total partners’ equity	3,338.9		3,564.9
Total liabilities and partners’ equity	$	8,630.2	$	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 Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
	(Unaudited)
Revenues:
Product sales	$	696.1	$	1,137.2	$	2,121.6	$	4,118.5

Midstream services	237.5		263.3		716.2		762.5

Gain (loss) on derivative activity	(5.1)		7.5		(8.3)		16.2
Total revenues	928.5		1,408.0		2,829.5		4,897.2
Operating costs and expenses:
Cost of sales	549.5		999.5		1,702.5		3,663.0
Operating expenses	94.3		119.2		283.1		351.6
General and administrative	25.6		38.3		79.9		108.8
(Gain) loss on disposition of assets	(1.8)		(3.0)		2.8		(2.9)
Depreciation and amortization	160.3		157.3		481.3		463.1
Impairments	—		—		169.9		—
Loss on secured term loan receivable	—		—		—		52.9

Total operating costs and expenses	827.9		1,311.3		2,719.5		4,636.5
Operating income	100.6		96.7		110.0		260.7
Other income (expense):
Interest expense, net of interest income	(55.5)		(56.6)		(166.3)		(160.2)
Gain on extinguishment of debt	—		—		32.0		—
Income (loss) from unconsolidated affiliates	(0.2)		4.0		0.8		14.0
Other income (expense)	0.4		(0.2)		0.4		0.1
Total other expense	(55.3)		(52.8)		(133.1)		(146.1)
Income (loss) before non-controlling interest and income taxes	45.3		43.9		(23.1)		114.6
Income tax expense	(0.3)		(0.3)		(1.8)		(0.5)
Net income (loss)	45.0		43.6		(24.9)		114.1
Net income attributable to non-controlling interest	3.4		1.2		9.3		4.8
Net income (loss) attributable to ENLK	$	41.6	$	42.4	$	(34.2)	$	109.3

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 Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
	(Unaudited)
Net income (loss)	$	45.0	$	43.6	$	(24.9)	$	114.1
Gain (loss) on designated cash flow hedge	4.7		(1.8)		(10.4)		(15.3)
Comprehensive income (loss)	49.7		41.8		(35.3)		98.8
Comprehensive income attributable to non-controlling interest	3.4		1.2		9.3		4.8
Comprehensive income (loss) attributable to ENLK	$	46.3	$	40.6	$	(44.6)	$	94.0

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		144.4	895.3		59.7	401.1		0.4	215.2		1.6	(31.6)		424.3		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		—
Unit-based compensation	—		—	—		—	—		—	7.2		—	—		—		7.2		—
Distributions	(46.4)		—	(16.8)		0.1	—		—	—		—	—		(6.5)		(69.7)		(0.3)
Contributions from non-controlling interests	—		—	—		—	—		—	—		—	—		1.9		1.9		—
Gain on designated cash flow hedge	—		—	—		—	—		—	—		—	4.7		—		4.7		—

Fair value adjustment related to redeemable non-controlling interest	(0.3)		—	—		—	—		—	—		—	—		—		(0.3)		0.3
Net income (loss)	25.3		—	17.2		—	6.0		—	(6.9)		—	—		3.4		45.0		—
Balance, September 30, 2020	$	1,419.2	144.4	$	896.1	60.0	$	401.1	0.4	$	215.7	1.6	$	(24.9)	$	431.7	$	3,338.9	$	—

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		144.4	891.4		59.2	401.1		0.4	218.4		1.6	(2.1)		322.1		4,200.8		7.2

Unit-based compensation	—		—	—		—	—		—	6.4		—	—		—		6.4		—
Distributions	(137.2)		—	(16.7)		0.1	(12.0)		—	—		—	—		(6.4)		(172.3)		—
Contributions from non-controlling interests	—		—	—		—	—		—	—		—	—		29.5		29.5		—
Loss on designated cash flow hedge	—		—	—		—	—		—	—		—	(13.5)		—		(13.5)		—
Fair value adjustment related to redeemable non-controlling interest	1.4		—	—		—	—		—	—		—	—		—		1.4		(1.4)
Net income (loss)	(13.8)		—	18.5		—	6.0		—	(6.6)		—	—		0.7		4.8		—


Balance, June 30, 2019	2,220.3		144.4	893.2		59.3	395.1		0.4	218.2		1.6	(15.6)		345.9		4,057.1		5.8
Unit-based compensation	—		—	—		—	—		—	11.1		—	—		—		11.1		—
Distributions	(139.8)		—	(17.1)		0.2	—		—	—		—	—		(5.0)		(161.9)		(0.3)
Contributions from non-controlling interests	—		—	—		—	—		—	—		—	—		33.4		33.4		—
Loss on designated cash flow hedge	—		—	—		—	—		—	—		—	(1.8)		—		(1.8)		—
Fair value adjustment related to redeemable non-controlling interest	0.1		—	—		—	—		—	—		—	—		—		0.1		(0.1)
Net income (loss)	28.6		—	18.5		—	6.0		—	(10.7)		—	—		1.1		43.5		0.1
Balance, September 30, 2019	$	2,109.2	144.4	$	894.6	59.5	$	401.1	0.4	$	218.6	1.6	$	(17.4)	$	375.4	$	3,981.5	$	5.5

See accompanying notes to consolidated financial statements.

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ENLINK MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

Consolidated Statements of Cash Flows

(In millions)


	Nine Months Ended September 30,
	2020		2019
	(Unaudited)
Cash flows from operating activities:
Net income (loss)	$	(24.9)	$	114.1
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Impairments	169.9		—
Depreciation and amortization	481.3		463.1

Loss on secured term loan receivable	—		52.9
Non-cash unit-based compensation	24.6		31.0

(Gain) loss on derivatives recognized in net income (loss)	8.3		(16.2)
Cash settlements on derivatives	(1.0)		12.5
Gain on extinguishment of debt	(32.0)		—
Amortization of debt issue costs, net discount (premium) of notes	3.1		3.9

Distribution of earnings from unconsolidated affiliates	1.6		14.7
Income from unconsolidated affiliates	(0.8)		(14.0)

Other operating activities	2.9		(6.5)
Changes in assets and liabilities:
Accounts receivable, accrued revenue, and other	87.4		331.6
Natural gas and NGLs inventory, prepaid expenses, and other	(13.6)		1.9
Accounts payable, accrued product purchases, and other accrued liabilities	(150.4)		(219.2)
Net cash provided by operating activities	556.4		769.8
Cash flows from investing activities:
Additions to property and equipment	(254.4)		(594.5)
Proceeds from sale of property	7.2		13.7


Other investing activities	(3.5)		(2.2)
Net cash used in investing activities	(250.7)		(583.0)
Cash flows from financing activities:
Proceeds from borrowings	690.0		3,593.5
Payments on borrowings	(776.0)		(3,330.0)

Debt financing costs	—		(10.0)


Distributions to non-controlling interests	(21.8)		(18.0)
Contributions by non-controlling interests	52.2		78.6
Distributions to Series B Preferred Units	(50.4)		(50.3)
Distributions to Series C Preferred Units	(12.0)		(12.0)
Distributions to common unitholders and to general partner	(186.2)		(432.0)
Other financing activities	—		(4.4)
Net cash used in financing activities	(304.2)		(184.6)
Net increase in cash and cash equivalents	1.5		2.2
Cash and cash equivalents, beginning of period	77.4		99.5
Cash and cash equivalents, end of period	$	78.9	$	101.7

Supplemental disclosures of cash flow information:
Cash paid for interest	$	125.7	$	127.7
Cash paid for income taxes	$	1.1	$	2.1
Non-cash investing activities:
Non-cash accrual of property and equipment	$	(27.2)	$	24.6
Right-of-use assets obtained in exchange for operating lease liabilities	$	9.1	$	98.4
Non-cash financing activities:
Redemption of non-controlling interest	$	(4.0)	$	—

See accompanying notes to consolidated financial statements.

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ENLINK MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements

September 30, 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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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

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 every region of 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 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 reduction in global demand for energy, volatility in the market prices for these commodities, and a significant and persistent reduction in the market price of crude oil. As a result of the demand destruction, reduced commodity prices, and an uncertain timeline for full recovery, many oil and natural gas producers, including some of our customers, have curtailed their current drilling and production activity and reduced or slowed down their plans for future drilling and production activity. As a result of these decreases in producer activity, we experienced reduced volumes gathered, processed, fractionated, and transported on our assets in some of the regions that supply our systems during portions of the first and second quarters, although volumes have since been restored nearly to pre-pandemic levels.

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 whether 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 that exist as of the date of this report will be extended or new measures will be reinstated. As a result, there is significant uncertainty regarding whether market dislocations will continue or increase and how significantly and how long they may 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.

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b.Revenue Recognition

Minimum Volume Commitments and Firm Transportation Contracts

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

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

The following table summarizes the contractually committed fees that we expect to recognize in our consolidated statements of operations, in either revenue or reductions to cost of sales, from MVC and firm transportation contractual provisions. All amounts in the table below are determined using the contractually-stated MVC or firm transportation volumes specified for each period multiplied by the relevant deficiency or reservation fee. Actual amounts could differ due to the timing of revenue recognition or reductions to cost of sales resulting from make-up right provisions included in our agreements, as well as due to nonpayment or nonperformance by our customers. These fees do not represent the shortfall amounts we expect to collect under our MVC contracts, as we generally do not expect volume shortfalls to equal the full amount of the contractual MVCs during these periods. For example, for the three and nine months ended September 30, 2020, we had contractual commitments of $44.8 million and $128.0 million under our MVC contracts, respectively, and recorded $14.0 million and $39.2 million of revenue due to volume shortfalls, respectively.


MVC and Firm Transportation Commitments (in millions) (1)
2020 (remaining)	$	65.3
2021	119.7
2022	102.1
2023	91.5
2024	77.4
Thereafter	144.9
Total	$	600.9

____________________________

(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 nine months ended September 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, and a $1.9 million impairment related to certain cancelled projects. For the three months ended September 30, 2020, we did not recognize any impairment related to property and equipment.

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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, the 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 included in “Other current liabilities” on the consolidated balance sheet as of September 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 nine months ended September 30, 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
Nine Months Ended September 30, 2020
Customer relationships, beginning of period	$	1,795.8	$	(545.9)	$	1,249.9

Amortization expense	—		(92.7)		(92.7)
Retirements (1)	(1.6)		0.6		(1.0)
Customer relationships, end of period	$	1,794.2	$	(638.0)	$	1,156.2

____________________________

(1) Intangible assets retired as a result of the disposition of certain non-core assets.

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 10 to 20 years.

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The weighted average amortization period is 15.0 years. Amortization expense was $30.9 million for each of the three months ended September 30, 2020 and 2019, and $92.7 million and $92.8 million for the nine months ended September 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)	$	30.8
2021	123.4
2022	123.4
2023	123.4
2024	123.4
Thereafter	631.8

Total	$	1,156.2

(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 5—Long-Term Debt” for more information on this arrangement.

We had accounts receivable balances related to transactions with ENLC of $16.0 million and $18.1 million as of September 30, 2020 and December 31, 2019, respectively.

b.Transactions with Cedar Cove JV

For the three and nine months ended September 30, 2020, we recorded cost of sales of $2.0 million and $6.2 million, respectively, and for the three and nine months ended September 30, 2019, we recorded cost of sales of $4.1 million and $18.0 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 $0.9 million and $1.1 million at September 30, 2020 and December 31, 2019, respectively.

c.Transactions with GIP

For the three and nine months ended September 30, 2020, we recorded general and administrative expenses of $0.2 million related to personnel secondment services provided by GIP. We did not record any expenses related to transactions with GIP for the three and nine months ended September 30, 2019.

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 included in the accompanying consolidated financial statements.

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(5) Long-Term Debt

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


	September 30, 2020						December 31, 2019
	Outstanding Principal		Premium (Discount)		Long-Term Debt		Outstanding Principal		Premium (Discount)		Long-Term Debt
Related party debt	$	1,648.7	$	—	$	1,648.7	$	1,700.0	$	—	$	1,700.0

4.40% Senior unsecured notes due 2024	521.8		1.1		522.9		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		(5.7)		444.3		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	$	4,682.3	$	(5.9)	4,676.4		$	4,800.0	$	(5.9)	4,794.1
Debt issuance cost (1)					(26.4)						(29.8)

Long-term debt, net of unamortized issuance cost					$	4,650.0					$	4,764.3

____________________________

(1)Net of amortization of $13.7 million and $10.9 million at September 30, 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 September 30, 2020 and December 31, 2019, $1.6 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 ($300.0 million as of September 30, 2020), and 105% of the outstanding letters of credit under the Consolidated Credit Facility ($19.3 million as of September 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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increase the maximum allowed ratio of consolidated indebtedness to consolidated EBITDA to 5.5 to 1.0 for the quarter in which the acquisition occurs and the three subsequent quarters.

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

At September 30, 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 $300.0 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 September 30, 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 September 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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Senior Unsecured Notes Repurchases

For the nine months ended September 30, 2020, we and ENLC made aggregate payments to partially repurchase the 2024, 2025, 2026, and 2029 Notes in open market transactions. We and ENLC did not make any payments to repurchase senior notes during the three months ended September 30, 2020. Activity related to the partial repurchases of our outstanding debt consisted of the following (in millions):


	Nine Months Ended September 30, 2020
Debt repurchased	$	67.7
Aggregate payments	(36.0)
Net discount on repurchased debt	(0.3)
Accrued interest on repurchased debt	0.6
Gain on extinguishment of debt	$	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 nine months ended September 30, 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
Third Quarter of 2020	150,119	$	16.9	November 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
Third Quarter of 2019	148,627	$	17.1	November 13, 2019

b.Series C Preferred Units

We distributed $12.0 million to holders of Series C Preferred Units during the nine months ended September 30, 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.

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d.Allocation of ENLK Income

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Unit-based compensation attributable to ENLC’s restricted and performance units	$	(7.2)	$	(11.1)	$	(26.3)	$	(29.6)
General partner share of net income (loss)	0.3		0.4		(0.9)		0.6
General partner interest in EOGP acquisition	—		—		—		2.4
General partner interest in net income (loss)	$	(6.9)	$	(10.7)	$	(27.2)	$	(26.6)

(7) Investment in Unconsolidated Affiliates

As of September 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):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
GCF

Distributions	$	—	$	5.1	$	1.6	$	14.7
Equity in income	$	0.4	$	4.4	$	2.5	$	15.3

Cedar Cove JV

Distributions	$	—	$	0.3	$	0.4	$	0.8
Equity in loss	$	(0.6)	$	(0.4)	$	(1.7)	$	(1.3)

Total

Distributions	$	—	$	5.4	$	2.0	$	15.5
Equity in income (loss)	$	(0.2)	$	4.0	$	0.8	$	14.0

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


	September 30, 2020		December 31, 2019
GCF	$	40.1	$	39.2
Cedar Cove JV	1.8		3.9
Total investment in unconsolidated affiliates	$	41.9	$	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.

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Cost of unit-based compensation charged to operating expense	$	2.0	$	2.1	$	6.2	$	4.5
Cost of unit-based compensation charged to general and administrative expense	6.4		10.0		18.4		26.5
Total unit-based compensation expense	$	8.4	$	12.1	$	24.6	$	31.0

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 nine months ended September 30, 2020 is provided below:


	Nine Months Ended September 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)	4,873,848		5.42
Vested (1)(2)	(2,839,869)		10.93
Forfeited	(661,623)		8.28
Non-vested, end of period	5,435,961		$	8.50
Aggregate intrinsic value, end of period (in millions)	$	12.8

____________________________

(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 1,009,546 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 nine months ended September 30, 2020 and 2019 is provided below (in millions):


	Three Months Ended September 30,				Nine Months Ended September 30,
ENLC Restricted Incentive Units:	2020		2019		2020		2019
Aggregate intrinsic value of units vested	$	1.0	$	3.1	$	11.9	$	16.0
Fair value of units vested	$	6.0	$	5.8	$	31.0	$	18.9

As of September 30, 2020, there was $23.3 million of unrecognized compensation cost related to non-vested ENLC restricted incentive units. This cost is expected to be recognized over a weighted-average period of 1.6 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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The following table presents a summary of the performance units:


	Nine Months Ended September 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	1,361,986		6.63
Vested (1)	(181,647)		30.31
Forfeited	(166,211)		11.01
Non-vested, end of period	2,331,984		$	8.76
Aggregate intrinsic value, end of period (in millions)	$	5.5

____________________________

(1)Vested units included 69,052 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 nine months ended September 30, 2020 and 2019 is provided below (in millions).


	Three Months Ended September 30,				Nine Months Ended September 30,
ENLC Performance Units:	2020		2019		2020		2019
Aggregate intrinsic value of units vested	$	—	$	1.6	$	0.9	$	3.4
Fair value of units vested	$	—	$	6.0	$	5.5	$	7.9

As of September 30, 2020, there was $12.3 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 1.5 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			July 2020
Grant-Date Fair Value	$	7.69		$	1.13		$	2.33
Beginning TSR price	$	6.13		$	1.25		$	2.52
Risk-free interest rate	1.62		%	0.42		%	0.17		%
Volatility factor	37.00		%	51.00		%	67.00		%

(9) Derivatives

Interest Rate Swaps

In April 2019, we entered into an $850.0 million interest rate swap with ENLC 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.

The gain (loss) on designated cash flow hedge related to changes in the fair value of our interest rate swaps were as follows (in millions):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Gain (loss) on designated cash flow hedge	$	4.7	$	(1.8)	$	(10.4)	$	(15.3)

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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 September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Interest expense (income)	$	4.6	$	(0.1)	$	9.6	$	(0.4)

We expect to recognize an additional $18.6 million of interest expense out of accumulated other comprehensive loss over the next twelve months.

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


	September 30, 2020		December 31, 2019


Fair value of derivative liabilities—current	$	(18.5)	$	(5.6)
Fair value of derivative liabilities—long-term	(4.5)		(6.8)
Net fair value of interest rate swaps	$	(23.0)	$	(12.4)

Commodity Swaps

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Change in fair value of derivatives	$	(2.2)	$	(0.5)	$	(8.0)	$	4.7
Realized gain (loss) on derivatives	(2.9)		8.0		(0.3)		11.5
Gain (loss) on derivative activity	$	(5.1)	$	7.5	$	(8.3)	$	16.2

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


	September 30, 2020		December 31, 2019
Fair value of derivative assets—current	$	9.6	$	12.9
Fair value of derivative assets—long-term	5.4		4.3
Fair value of derivative liabilities—current	(14.6)		(8.8)

Net fair value of commodity swaps	$	0.4	$	8.4

Set forth below are the summarized notional volumes and fair values of all instruments related to commodity swaps that we held for price risk management purposes and the related physical offsets at September 30, 2020 (in millions). The remaining term of the contracts extend no later than December 2022.

September 30, 2020

Commodity

Instruments

Unit

Volume

Net Fair Value

NGL (short contracts)

Swaps

Gallons

(161.6)

(8.5)

NGL (long contracts)

Swaps

Gallons

1.9

—

Natural gas (short contracts)

Swaps

MMBtu

(18.1)

(2.3)

Natural gas (long contracts)

Swaps

MMBtu

11.3

0.5

Crude and condensate (short contracts)

Swaps

MMbbls

(9.5)

8.5

Crude and condensate (long contracts)

Swaps

MMbbls

0.6

2.2

Total fair value of commodity swaps

0.4

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

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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 $15.0 million as of September 30, 2020 would be reduced to $9.1 million due to the offsetting of gross fair value payables against gross fair value receivables as allowed by the ISDAs.

(10) Fair Value Measurements

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


	Level 2
	September 30, 2020		December 31, 2019
Interest rate swaps (1)	$	(23.0)	$	(12.4)
Commodity swaps (2)	$	0.4	$	8.4

____________________________

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

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

Fair Value of Financial Instruments

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


	September 30, 2020				December 31, 2019
	Carrying Value		Fair Value		Carrying Value		Fair Value
Long-term debt (1)	$	4,650.0	$	3,892.8	$	4,764.3	$	4,444.2

____________________________

(1)The carrying value of long-term debt is reduced by debt issuance costs of $26.4 million and $29.8 million as of September 30, 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 September 30, 2020 and December 31, 2019 were based on Level 2 inputs from third-party market quotations.

(11) 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;

•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;

•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;

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

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

We evaluate the performance of our operating segments based on segment profits. Summarized financial information for our reportable segments is shown in the following tables (in millions):


	Permian		Louisiana		Oklahoma		North Texas		Corporate		Totals
Three Months Ended September 30, 2020
Natural gas sales	$	46.5	$	76.4	$	40.1	$	16.0	$	—	$	179.0
NGL sales	0.1		402.3		1.2		—		—		403.6
Crude oil and condensate sales	82.6		21.7		9.2		—		—		113.5

Product sales	129.2		500.4		50.5		16.0		—		696.1

NGL sales—related parties	95.6		3.3		85.4		21.4		(205.7)		—
Crude oil and condensate sales—related parties	—		—		—		0.7		(0.7)		—
Product sales—related parties	95.6		3.3		85.4		22.1		(206.4)		—
Gathering and transportation	17.9		10.7		56.7		43.4		—		128.7
Processing	8.0		0.3		32.4		33.3		—		74.0
NGL services	—		14.2		—		—		—		14.2
Crude services	3.8		12.2		3.7		—		—		19.7
Other services	0.2		0.4		0.1		0.2		—		0.9
Midstream services	29.9		37.8		92.9		76.9		—		237.5



Crude services—related parties	—		—		0.1		—		(0.1)		—

Midstream services—related parties	—		—		0.1		—		(0.1)		—
Revenue from contracts with customers	254.7		541.5		228.9		115.0		(206.5)		933.6
Cost of sales	(185.4)		(441.4)		(101.0)		(28.2)		206.5		(549.5)
Operating expenses	(22.9)		(31.1)		(20.1)		(20.2)		—		(94.3)
Loss on derivative activity	—		—		—		—		(5.1)		(5.1)
Segment profit (loss)	$	46.4	$	69.0	$	107.8	$	66.6	$	(5.1)	$	284.7
Depreciation and amortization	$	(31.9)	$	(36.9)	$	(53.0)	$	(36.8)	$	(1.7)	$	(160.3)


Capital expenditures	$	28.5	$	8.5	$	2.6	$	3.0	$	0.6	$	43.2

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	Permian		Louisiana		Oklahoma		North Texas		Corporate		Totals
Three Months Ended September 30, 2019
Natural gas sales	$	24.3	$	92.0	$	54.6	$	22.2	$	—	$	193.1
NGL sales	0.3		421.0		4.6		6.0		—		431.9
Crude oil and condensate sales	409.4		74.6		28.2		—		—		512.2

Product sales	434.0		587.6		87.4		28.2		—		1,137.2
Natural gas sales—related parties	(0.1)		—		—		—		0.1		—
NGL sales—related parties	69.3		7.9		90.2		21.0		(188.4)		—
Crude oil and condensate sales—related parties	2.8		1.7		—		1.1		(5.6)		—
Product sales—related parties	72.0		9.6		90.2		22.1		(193.9)		—
Gathering and transportation	14.7		12.2		63.7		50.1		—		140.7
Processing	8.3		0.8		35.7		36.3		—		81.1
NGL services	—		11.2		—		—		—		11.2
Crude services	6.4		13.5		5.9		—		—		25.8
Other services	4.0		0.1		0.1		0.3		—		4.5
Midstream services	33.4		37.8		105.4		86.7		—		263.3



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

Midstream services—related parties	—		—		0.2		—		(0.2)		—
Revenue from contracts with customers	539.4		635.0		283.2		137.0		(194.1)		1,400.5
Cost of sales	(474.2)		(529.6)		(148.4)		(41.4)		194.1		(999.5)
Operating expenses	(28.9)		(38.4)		(25.7)		(26.2)		—		(119.2)
Gain on derivative activity	—		—		—		—		7.5		7.5
Segment profit	$	36.3	$	67.0	$	109.1	$	69.4	$	7.5	$	289.3
Depreciation and amortization	$	(31.6)	$	(37.3)	$	(51.1)	$	(35.4)	$	(1.9)	$	(157.3)

Goodwill	$	—	$	—	$	190.3	$	—	$	—	$	190.3
Capital expenditures	$	119.7	$	21.5	$	48.6	$	5.0	$	1.7	$	196.5

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(Unaudited)


	Permian		Louisiana		Oklahoma		North Texas		Corporate		Totals
Nine Months Ended September 30, 2020
Natural gas sales	$	94.0	$	226.6	$	110.0	$	50.7	$	—	$	481.3
NGL sales	0.2		1,056.9		2.9		0.3		—		1,060.3
Crude oil and condensate sales	454.6		95.0		30.4		—		—		580.0

Product sales	548.8		1,378.5		143.3		51.0		—		2,121.6

NGL sales—related parties	201.0		13.3		209.0		52.5		(475.8)		—
Crude oil and condensate sales—related parties	0.1		—		(0.1)		2.6		(2.6)		—
Product sales—related parties	201.1		13.3		208.9		55.1		(478.4)		—
Gathering and transportation	47.3		33.9		165.5		133.5		—		380.2
Processing	19.8		1.6		97.8		101.7		—		220.9
NGL services	—		52.4		—		0.1		—		52.5
Crude services	13.0		33.8		12.6		—		—		59.4
Other services	1.0		1.2		0.3		0.7		—		3.2
Midstream services	81.1		122.9		276.2		236.0		—		716.2



Crude services—related parties	—		—		0.3		—		(0.3)		—

Midstream services—related parties	—		—		0.3		—		(0.3)		—
Revenue from contracts with customers	831.0		1,514.7		628.7		342.1		(478.7)		2,837.8
Cost of sales	(637.7)		(1,213.6)		(255.8)		(74.1)		478.7		(1,702.5)
Operating expenses	(71.1)		(90.4)		(62.4)		(59.2)		—		(283.1)
Loss on derivative activity	—		—		—		—		(8.3)		(8.3)
Segment profit (loss)	$	122.2	$	210.7	$	310.5	$	208.8	$	(8.3)	$	843.9
Depreciation and amortization	$	(92.1)	$	(109.3)	$	(163.7)	$	(110.4)	$	(5.8)	$	(481.3)
Impairments	$	—	$	(169.9)	$	—	$	—	$	—	$	(169.9)

Capital expenditures	$	161.4	$	39.3	$	14.1	$	10.7	$	1.7	$	227.2

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(Unaudited)


	Permian		Louisiana		Oklahoma		North Texas		Corporate		Totals
Nine Months Ended September 30, 2019
Natural gas sales	$	59.4	$	316.8	$	176.5	$	104.7	$	—	$	657.4
NGL sales	0.9		1,492.9		17.8		24.0		—		1,535.6
Crude oil and condensate sales	1,622.2		216.9		86.4		—		—		1,925.5

Product sales	1,682.5		2,026.6		280.7		128.7		—		4,118.5
Natural gas sales—related parties	0.3		—		—		0.3		(0.6)		—
NGL sales—related parties	242.9		16.4		320.9		71.7		(651.9)		—
Crude oil and condensate sales—related parties	13.7		1.7		—		3.8		(19.2)		—
Product sales—related parties	256.9		18.1		320.9		75.8		(671.7)		—
Gathering and transportation	36.3		46.1		178.2		149.0		—		409.6
Processing	23.3		2.5		105.5		106.8		—		238.1
NGL services	—		32.9		—		—		—		32.9
Crude services	16.9		40.2		15.1		—		—		72.2
Other services	8.4		0.5		—		0.8		—		9.7
Midstream services	84.9		122.2		298.8		256.6		—		762.5


NGL services—related parties	—		(3.3)		—		—		3.3		—
Crude services—related parties	—		—		1.7		—		(1.7)		—

Midstream services—related parties	—		(3.3)		1.7		—		1.6		—
Revenue from contracts with customers	2,024.3		2,163.6		902.1		461.1		(670.1)		4,881.0
Cost of sales	(1,830.9)		(1,844.1)		(492.0)		(166.1)		670.1		(3,663.0)
Operating expenses	(85.1)		(111.6)		(77.2)		(77.7)		—		(351.6)
Gain on derivative activity	—		—		—		—		16.2		16.2
Segment profit	$	108.3	$	207.9	$	332.9	$	217.3	$	16.2	$	882.6
Depreciation and amortization	$	(89.6)	$	(116.0)	$	(144.8)	$	(106.6)	$	(6.1)	$	(463.1)

Goodwill	$	—	$	—	$	190.3	$	—	$	—	$	190.3
Capital expenditures	$	268.0	$	82.0	$	227.1	$	36.3	$	5.7	$	619.1

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 September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Segment profit	$	284.7	$	289.3	$	843.9	$	882.6
General and administrative expenses	(25.6)		(38.3)		(79.9)		(108.8)
Gain (loss) on disposition of assets	1.8		3.0		(2.8)		2.9
Depreciation and amortization	(160.3)		(157.3)		(481.3)		(463.1)
Impairments	—		—		(169.9)		—
Loss on secured term loan receivable	—		—		—		(52.9)

Operating income	$	100.6	$	96.7	$	110.0	$	260.7

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(Unaudited)

The table below represents information about segment assets as of September 30, 2020 and December 31, 2019 (in millions):


Segment Identifiable Assets:	September 30, 2020		December 31, 2019
Permian	$	2,245.3	$	2,281.1
Louisiana	2,278.9		2,562.0
Oklahoma	2,889.1		3,035.0
North Texas	1,031.2		1,135.8
Corporate	185.7		120.7
Total identifiable assets	$	8,630.2	$	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:	September 30, 2020		December 31, 2019
Natural gas and NGLs inventory	$	63.9	$	43.4

Prepaid expenses and other	17.8		13.5
Other current assets	$	81.7	$	56.9


Other current liabilities:	September 30, 2020		December 31, 2019
Accrued interest	$	56.7	$	32.6
Accrued wages and benefits, including taxes	18.3		31.5
Accrued ad valorem taxes	33.9		28.5
Capital expenditure accruals	12.1		42.4
Retainage liability	11.8		8.7
Short-term lease liability	17.1		21.1
Suspense producer payments	10.3		13.8
Operating expense accruals	10.5		10.8
Other	18.1		12.3
Other current liabilities	$	188.8	$	201.7

(13) Subsequent Events

Accounts Receivable Securitization Facility. On October 21, 2020 (the “Closing Date”), EnLink Midstream Funding, LLC, a bankruptcy-remote special purpose entity (the “SPV”) that is our indirect subsidiary, entered into a three-year committed accounts receivable securitization facility (the “AR Facility”) of up to $250 million with PNC Bank, National Association, as administrative agent (the “Administrative Agent”) and lender, and PNC Capital Markets, LLC (“PNCCM”), as structuring agent.

In connection with the AR Facility, certain of our subsidiaries, as originators (the “Originators”), have sold and contributed, and will continue to sell or contribute, pursuant to a Sale and Contribution Agreement, dated as of the Closing Date (the “Sale and Contribution Agreement”), all of their accounts receivable and certain related assets (collectively, the “Receivables”) to the SPV, a separate legal subsidiary of ENLK whose sole business consists of the purchase, or acceptance through capital contributions, of the Receivables and whose assets are not available to satisfy creditors of ENLK, the Originators, or any other subsidiary of ENLK or ENLC.

The SPV financed its acquisition of the Receivables, and will finance its ongoing purchase of the Receivables, in part by obtaining secured loans from the lenders party to the Receivables Financing Agreement, dated as of the Closing Date (the “RFA”), among the SPV, EnLink Midstream Operating, LP, as initial servicer (the “Servicer”), the Administrative Agent, the lenders party thereto, and PNCCM. The amount available for borrowings at any one time under the RFA is limited to a borrowing base amount calculated based on the outstanding balance of eligible Receivables, subject to certain reserves,

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concentration limits, and other limitations. Borrowings under the RFA bear interest based on LIBOR or LMIR (each as defined in the RFA), in each case subject to a minimum floor of 37.5 basis points, plus a drawn fee initially in the amount of 162.5 bps. The drawn fee varies based on ENLC’s credit rating, and the SPV also pays a fee on the undrawn committed amount of the RFA. Interest and fees payable by the SPV under the RFA are due monthly.

The SPV pledged its ownership interest in the Receivables as collateral security for all amounts outstanding under the RFA, and the Servicer will perform administrative and collection services relating to the Receivables on behalf of the SPV for a fee.

The RFA is scheduled to terminate on October 20, 2023, unless extended in accordance with its terms or earlier terminated, at which time no further advances will be available and the obligations thereunder repaid in full by no later than (i) the date that is ninety (90) days following such date or (ii) such earlier date on which the loans under the RFA become due and payable.

The purchase price for the sale of the Receivables by an Originator to the SPV consisted of, and will continue to consist of, a combination of (i) equity contributions in the SPV from its direct parent, (ii) cash available to the SPV from loans under the RFA and from collections on previously sold Receivables, and (iii) to the extent that the SPV does not have funds available to pay the purchase price in cash, through an increase in the principal amount of a subordinated intercompany loan deemed made by such Originator to the SPV.

ENLC guaranteed the respective obligations of the Originators and the Servicer under the Sale and Contribution Agreement and the RFA, as applicable, pursuant to a Performance Guaranty dated as of the Closing Date. However, neither ENLC nor any of its subsidiaries guarantees the SPV’s borrowings under the RFA or the collectability of the Receivables. However, neither ENLC nor any of its or ENLK’s subsidiaries guarantees the SPV’s borrowings under the RFA or the collectability of the Receivables.

As of the Closing Date there were $225 million of borrowings by the SPV under the RFA. ENLC used the cash proceeds from the sale of the Receivables to the SPV to repay borrowings under its revolving credit facility.

Sale of Victoria Express Pipeline. On October 22, 2020, we completed the sale of the Victoria Express Pipeline and its related terminals and storage assets located in the Eagle Ford Shale in South Texas for approximately $20 million. We expect to recognize a loss of approximately $8 million on the sale.

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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 11,800 miles of pipelines, 22 natural gas processing plants with approximately 5.5 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; and

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 95% of our gross operating margin was derived from fee-based contractual arrangements with minimal direct commodity price exposure for the nine months ended September 30, 2020. We reflect revenue as “Product sales” and “Midstream services” on the consolidated statements of operations.

The following customers individually represented greater than 10% of our consolidated revenues. These customers represent a significant percentage of revenues, and the loss of the customer would have a material adverse impact on our results

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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 September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Devon	14.2	%	11.7	%	14.7	%	10.0	%
Dow Hydrocarbons and Resources LLC	15.2	%	(1)		13.2	%	10.0	%
Marathon Petroleum Corporation	(1)		12.4	%	12.7	%	14.0	%

____________________________

(1)Consolidated revenues for these customers did not exceed 10% of our consolidated revenues for the applicable reporting period.

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

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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.

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.

Recent Developments Affecting Industry Conditions and Our Business

Since the outbreak began, our first priority has been the health and safety of our employees and those of our customers and other business counterparties. In March, we implemented preventative measures and developed a response plan to minimize unnecessary risk of exposure and prevent infection, while supporting our customers’ operations, and we continue to follow these plans. We maintain a crisis management team for health, safety and environmental matters and personnel issues and a cross-functional COVID-19 response team to address various impacts of the situation, as they develop. We also continue to follow modified business practices (including discontinuing non-essential business travel, implementing staggered work-from-home policies for employees who can execute their work remotely in order to reduce office density, 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. We continue to evaluate and adjust these preventative measures, response plans and business practices with the evolving impacts of COVID-19.

As 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 throughout the period. We 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

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full-year 2020 versus the twelve months ended December 31, 2019. Also, as of September 30, 2020, we had $78.9 million of cash on our balance sheet and have drawn only $300.0 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 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 duration and persistence of the outbreak, the effect of the outbreak on economic, social and other aspects of everyday life, the consequences of governmental and other measures designed to prevent the spread of the virus, the development and timing of effective treatments 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, and the timing and extent to which normal economic, social and operating conditions resume.

For additional discussion regarding risks associated with the COVID-19 pandemic, see Part II, Item 1A “Risk Factors” in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020.

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 2020, we completed the construction of our Tiger Plant, which expanded our Delaware Basin processing capacity by an additional 200 MMcf/d. 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 to gross operating margin (in millions):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Operating income	$	100.6	$	96.7	$	110.0	$	260.7

Add:
Operating expenses	94.3		119.2		283.1		351.6
General and administrative expenses	25.6		38.3		79.9		108.8
(Gain) loss on disposition of assets	(1.8)		(3.0)		2.8		(2.9)
Depreciation and amortization	160.3		157.3		481.3		463.1
Impairments	—		—		169.9		—
Loss on secured term loan receivable	—		—		—		52.9

Gross operating margin	$	379.0	$	408.5	$	1,127.0	$	1,234.2

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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 Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Permian Segment
Revenues	$	254.7	$	539.4	$	831.0	$	2,024.3
Cost of sales	(185.4)		(474.2)		(637.7)		(1,830.9)
Total gross operating margin	$	69.3	$	65.2	$	193.3	$	193.4
Louisiana Segment
Revenues	$	541.5	$	635.0	$	1,514.7	$	2,163.6
Cost of sales	(441.4)		(529.6)		(1,213.6)		(1,844.1)
Total gross operating margin	$	100.1	$	105.4	$	301.1	$	319.5
Oklahoma Segment
Revenues	$	228.9	$	283.2	$	628.7	$	902.1
Cost of sales	(101.0)		(148.4)		(255.8)		(492.0)
Total gross operating margin	$	127.9	$	134.8	$	372.9	$	410.1
North Texas Segment
Revenues	$	115.0	$	137.0	$	342.1	$	461.1
Cost of sales	(28.2)		(41.4)		(74.1)		(166.1)
Total gross operating margin	$	86.8	$	95.6	$	268.0	$	295.0
Corporate Segment
Revenues	$	(211.6)	$	(186.6)	$	(487.0)	$	(653.9)
Cost of sales	206.5		194.1		478.7		670.1
Total gross operating margin	$	(5.1)	$	7.5	$	(8.3)	$	16.2
Total
Revenues	$	928.5	$	1,408.0	$	2,829.5	$	4,897.2
Cost of sales	(549.5)		(999.5)		(1,702.5)		(3,663.0)
Total gross operating margin	$	379.0	$	408.5	$	1,127.0	$	1,234.2

Midstream Volumes:
Permian Segment
Gathering and Transportation (MMBtu/d)	923,400		751,400		875,200		695,300
Processing (MMBtu/d)	929,900		798,200		895,800		745,100
Crude Oil Handling (Bbls/d)	99,100		112,900		115,000		135,000
Louisiana Segment
Gathering and Transportation (MMBtu/d)	1,961,100		2,078,500		1,959,600		2,025,000

Crude Oil Handling (Bbls/d)	15,700		21,200		16,300		18,800
NGL Fractionation (Gals/d)	7,462,600		7,240,100		7,665,700		7,231,400
Brine Disposal (Bbls/d)	1,100		2,500		1,400		3,100
Oklahoma Segment
Gathering and Transportation (MMBtu/d)	1,113,900		1,351,800		1,142,800		1,304,100
Processing (MMBtu/d)	1,125,600		1,323,100		1,120,800		1,284,800
Crude Oil Handling (Bbls/d)	25,600		59,600		30,800		47,600
North Texas Segment
Gathering and Transportation (MMBtu/d)	1,450,900		1,644,300		1,505,100		1,658,000
Processing (MMBtu/d)	669,000		760,700		679,800		753,600

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Three Months Ended September 30, 2020 Compared to Three Months Ended September 30, 2019

Gross Operating Margin. Gross operating margin was $379.0 million for the three months ended September 30, 2020 compared to $408.5 million for the three months ended September 30, 2019, a decrease of $29.5 million, or 7.2%, due to the following:

•Permian Segment. Gross operating margin in the Permian segment increased $4.1 million, resulting from:

•A $2.7 million decrease on our South Texas assets primarily due to the expiration of an MVC provision in July 2019.

•A $3.4 million decrease due to volume declines on our Midland Basin crude assets.

•A $1.3 million increase due to volume growth in our Delaware Basin crude assets.

•A $6.0 million increase related to volume growth from additional well connects on our Midland Basin gas assets.

•A $2.9 million increase related to volume growth from additional well connects on our Delaware Basin gas assets.

•Louisiana Segment. Gross operating margin in the Louisiana segment decreased $5.3 million, resulting from:

•A $7.0 million decrease from our ORV crude assets primarily due to lower volumes.

•A $1.7 million increase from our NGL transmission and fractionation assets primarily due to higher volumes.

•Oklahoma Segment. Gross operating margin in the Oklahoma segment decreased $6.9 million, resulting from:

•A $3.8 million decrease due to volume decline in our Oklahoma crude assets primarily due to lower volumes from our existing customers.

•A $3.1 million decrease due to volume decline in our Oklahoma gas assets primarily due to lower volumes from our existing customers.

•North Texas Segment. Gross operating margin in the North Texas segment decreased $8.8 million, which was primarily due to volume declines resulting from limited new drilling in the region.

•Corporate Segment. Gross operating margin in the Corporate segment decreased $12.6 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 September 30,
	2020		2019
Realized swaps:
Crude swaps	$	0.2	$	5.5
NGL swaps	(3.4)		1.8
Gas swaps	0.3		0.7
Realized gain (loss) on derivatives	(2.9)		8.0

Unrealized swaps:
Crude swaps	1.4		(0.4)
NGL swaps	(2.5)		(0.4)
Gas swaps	(1.1)		0.3
Change in fair value of derivatives	(2.2)		(0.5)

Gain (loss) on derivatives	$	(5.1)	$	7.5

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agreements also contain make-up right provisions that allow a customer to utilize gathering or processing fees in excess of the MVC in subsequent periods to offset shortfall amounts in previous periods. We record revenue under MVC contracts during periods of shortfall when it is known that the customer cannot, or will not, make up the deficiency in subsequent periods.

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


	Three Months Ended September 30,
	2020		2019
Permian Segment	$	0.3	$	1.7
Oklahoma Segment	13.7		4.8
Total	$	14.0	$	6.5

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 $94.3 million for the three months ended September 30, 2020 compared to $119.2 million for the three months ended September 30, 2019, a decrease of $24.9 million, or 20.9%. The primary contributors to the total decrease by segment were as follows (in millions):


	Three Months Ended September 30,				Change
	2020		2019		$		%
Permian Segment	$	22.9	$	28.9	$	(6.0)	(20.8)	%
Louisiana Segment	31.1		38.4		(7.3)		(19.0)	%
Oklahoma Segment	20.1		25.7		(5.6)		(21.8)	%
North Texas Segment	20.2		26.2		(6.0)		(22.9)	%
Total	$	94.3	$	119.2	$	(24.9)	(20.9)	%

•Permian Segment. Operating expenses in the Permian segment decreased $6.0 million primarily due to decreased labor and benefits expense as a result of reductions in workforce and reductions in construction fees and services.

•Louisiana Segment. Operating expenses in the Louisiana segment decreased $7.3 million primarily due to decreased labor and benefits expense as a result of reductions in workforce and reductions in materials and supplies expense, construction fees and services, and vehicle expenses.

•Oklahoma Segment. Operating expenses in the Oklahoma segment decreased $5.6 million primarily due to decreased labor and benefits expense as a result of reductions in workforce and reductions in construction fees and services and compressor rentals.

•North Texas Segment. Operating expenses in the North Texas segment decreased $6.0 million primarily due to decreased labor and benefits expense as a result of reductions in workforce and reductions in materials and supplies expense, compression operations and maintenance, and compressor rentals.

General and Administrative Expenses. General and administrative expenses were $25.6 million for the three months ended September 30, 2020 compared to $38.3 million for the three months ended September 30, 2019, a decrease of $12.7 million, or 33.2%. The primary contributors to the decrease were as follows:

•Labor costs and unit-based compensation costs decreased $10.8 million, which was primarily due to reductions in workforce.

•Expenses related to fees and services, travel, rents and leases, and insurance decreased $1.7 million primarily due to general cost saving initiatives and decreased activity as a result of COVID-19.

Depreciation and Amortization. Depreciation and amortization was $160.3 million for the three months ended September 30, 2020 compared to $157.3 million for the three months ended September 30, 2019, an increase of $3.0 million, or 1.9%. This increase was primarily due to new assets placed in service in the Permian, Oklahoma, and Louisiana segments, as well as a change in the estimated useful lives of certain non-core assets in the North Texas and Oklahoma segments. These

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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.

Gain (loss) on disposition of assets. For the three months ended September 30, 2020, we recognized a gain on the sale of assets of $1.8 million compared to a gain of $3.0 million for the three months ended September 30, 2019. The $1.8 million gain was primarily related to the sale of non-core assets in North Texas.

Interest Expense. Interest expense was $55.5 million for the three months ended September 30, 2020 compared to $56.6 million for the three months ended September 30, 2019, a decrease of $1.1 million, or 1.9%. Interest expense consisted of the following (in millions):


	Three Months Ended September 30,
	2020		2019
Senior Notes	$	36.5	$	37.3
Related party debt	13.8		18.7
Capitalized interest	(0.6)		(0.3)
Amortization of debt issue costs and net discounts (premiums)	0.9		1.1
Interest rate swap - realized	4.6		(0.1)
Other	0.3		(0.1)
Total	$	55.5	$	56.6

Income (Loss) from Unconsolidated Affiliate Investments. Loss from unconsolidated affiliate investments was $0.2 million for the three months ended September 30, 2020 compared to income of $4.0 million for the three months ended September 30, 2019, a decrease of $4.2 million. The decrease was primarily attributable to a reduction of income of $4.0 million from our GCF investment as a result of lower fractionation revenues and lower operating expenses and a reduction of income of $0.2 million from our Cedar Cove JV.

Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019

Gross Operating Margin. Gross operating margin was $1,127.0 million for the nine months ended September 30, 2020 compared to $1,234.2 million for the nine months ended September 30, 2019, a decrease of $107.2 million, or 8.7%, due to the following:

•Permian Segment. Gross operating margin in the Permian segment decreased $0.1 million, primarily driven by:

•A $14.3 million decrease on our South Texas assets primarily due to the expiration of an MVC provision in July 2019.

•A $4.2 million increase due to volume growth in our Delaware Basin crude assets.

•A $4.1 million increase related to volume growth from additional well connects on our Midland Basin gas assets.

•A $5.6 million increase related to volume growth from additional well connects on our Delaware Basin gas assets.

•Louisiana Segment. Gross operating margin in the Louisiana segment decreased $18.4 million, resulting from:

•A $12.4 million decrease from our Louisiana gas assets due to the expiration of certain firm transportation contracts, and decreased gathering and transportation volumes.

•A $13.1 million decrease from our ORV crude assets primarily due to lower volumes.

•A $7.1 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 in the amount of $5.5 million.

•Oklahoma Segment. Gross operating margin in the Oklahoma segment decreased $37.2 million, resulting from:

•A $2.9 million decrease due to volume decline in our Oklahoma crude assets primarily due to lower volumes from our existing customers..

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•A $34.3 million decrease due to volume decline in our Oklahoma gas assets primarily due to lower volumes from our existing customers.

•North Texas Segment. Gross operating margin in the North Texas segment decreased $27.0 million, which was primarily due to volume declines resulting from limited new drilling in the region.

•Corporate Segment. Gross operating margin in the Corporate segment decreased $24.5 million, which was primarily due to the changes in fair value of our commodity swaps between the periods as summarized below (in millions):


	Nine Months Ended September 30,
	2020		2019
Realized swaps:
Crude swaps	$	(2.8)	$	6.4
NGL swaps	2.9		7.4
Gas swaps	(0.4)		(2.3)
Realized gain (loss) on derivatives	(0.3)		11.5

Unrealized swaps:
Crude swaps	3.9		4.1
NGL swaps	(9.5)		(2.7)
Gas swaps	(2.4)		3.3
Change in fair value of derivatives	(8.0)		4.7

Gain (loss) on derivatives	$	(8.3)	$	16.2

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.

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


	Nine Months Ended September 30,
	2020		2019
Permian	$	0.6	$	9.4
Oklahoma	38.6		4.8
Total	$	39.2	$	14.2

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Operating Expenses. Operating expenses were $283.1 million for the nine months ended September 30, 2020 compared to $351.6 million for the nine months ended September 30, 2019, a decrease of $68.5 million, or 19.5%. The primary contributors to the decrease by segment were as follows (in millions):


	Nine Months Ended September 30,				Change
	2020		2019		$		%
Permian Segment	$	71.1	$	85.1	$	(14.0)	(16.5)	%
Louisiana Segment	90.4		111.6		(21.2)		(19.0)	%
Oklahoma Segment	62.4		77.2		(14.8)		(19.2)	%
North Texas Segment	59.2		77.7		(18.5)		(23.8)	%
Total	$	283.1	$	351.6	$	(68.5)	(19.5)	%

•Permian Segment. Operating expenses in the Permian segment decreased $14.0 million primarily due to decreased labor and benefits expense as a result of reductions in workforce and reductions in materials and supplies expense, construction fees and services, vehicle expenses, and sales and use tax.

•Louisiana Segment. Operating expenses in the Louisiana segment decreased $21.2 million primarily due to decreased labor and benefits expense as a result of reductions in workforce and reductions in materials and supplies expense, construction fees and services, compressor rentals, and vehicle expenses.

•Oklahoma Segment. Operating expenses in the Oklahoma segment decreased $14.8 million primarily due to decreased labor and benefits expense as a result of reductions in workforce and reductions in materials and supplies expense, construction fees and services, compressor rentals, and vehicle expenses.

•North Texas Segment. Operating expenses in the North Texas segment decreased $18.5 million primarily due to decreased labor and benefits expense as a result of reductions in workforce and reductions in materials and supplies expense, operations and maintenance, fees and services, sales and use tax, ad valorem taxes, and compressor rentals.

General and Administrative Expenses. General and administrative expenses were $79.9 million for the nine months ended September 30, 2020 compared to $108.8 million for the nine months ended September 30, 2019, a decrease of $28.9 million, or 26.6%. The primary contributors to the decrease were as follows:

•Labor costs and unit-based compensation decreased $19.4 million due to reductions in workforce and lower bonus accrual.

•Expenses related to fees and services, travel, rents and leases, and insurance decreased $6.1 million, which was primarily due to general cost saving initiatives.

•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.

Depreciation and Amortization. Depreciation and amortization was $481.3 million for the nine months ended September 30, 2020 compared to $463.1 million for the nine months ended September 30, 2019, an increase of $18.2 million, or 3.9%. This increase was primarily due to new assets placed in service in the Permian and Oklahoma segments, as well as a change in the estimated useful lives of certain non-core assets in the North Texas and Oklahoma segments. 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.

Gain (loss) on disposition of assets. For the nine months ended September 30, 2020, we recognized a loss on the sale of assets of $2.8 million compared to a gain of $2.9 million for the nine months ended September 30, 2019. The $2.8 million loss was primarily related to the sale of non-core Permian assets, partially offset by the sale of certain non-core assets in North Texas.

Impairments. For the nine months ended September 30, 2020, we recognized impairment expense related to property and equipment. For the nine months ended September 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):

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	Nine Months Ended September 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 nine months ended September 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 nine months ended September 30, 2019 related to the write-off of the secured term loan receivable.

Interest Expense. Interest expense was $166.3 million for the nine months ended September 30, 2020 compared to $160.2 million for the nine months ended September 30, 2019, an increase of $6.1 million, or 3.8%. Interest expense consisted of the following (in millions):


	Nine Months Ended September 30,
	2020		2019
Senior Notes	$	110.4	$	114.6
ENLK Credit Facility	—		0.3
Related party debt	46.0		48.0
Capitalized interest	(3.1)		(4.1)
Amortization of debt issue costs and net discounts (premiums)	3.1		3.9
Interest rate swap - realized	9.6		(0.4)
Other	0.3		(2.1)
Total	$	166.3	$	160.2

Income (Loss) from Unconsolidated Affiliate Investments. Income from unconsolidated affiliate investments was $0.8 million for the nine months ended September 30, 2020 compared to $14.0 million for the nine months ended September 30, 2019, a decrease of $13.2 million. The decrease was primarily attributable to a reduction of income of $12.8 million from our GCF investment as a result of lower fractionation revenues and lower operating expenses and a reduction of income of $0.4 million from our Cedar Cove JV.

Critical Accounting Policies

Information regarding our critical accounting policies is included in Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2019, except as described below.

Property and Equipment

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.

During March 2020, we determined that a sustained decline in our unit price and weakness in the overall energy sector, driven by low commodity prices and lower consumer demand due to the COVID-19 pandemic, caused a change in circumstances warranting an interim impairment test. For the nine months ended September 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, and a $1.9 million impairment related to certain

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cancelled projects. For the three months ended September 30, 2020, we did not recognize any impairment related to property and equipment.

In the current worldwide economic and commodity price environment and to the extent conditions further deteriorate, we may identify additional triggering events that may require future evaluations of the recoverability of the carrying value of our long-lived assets and investments, which could result in further impairment charges. See “Item 1. Financial Statements—Note 1” for additional information.

Liquidity and Capital Resources

Cash Flows from Operating Activities. Net cash provided by operating activities was $556.4 million for the nine months ended September 30, 2020 compared to $769.8 million for the nine months ended September 30, 2019. Operating cash flows and changes in working capital for comparative periods were as follows (in millions):


	Nine Months Ended September 30,
	2020		2019
Operating cash flows before working capital	$	633.0	$	655.5
Changes in working capital	(76.6)		114.3

Operating cash flows before changes in working capital decreased $22.5 million for the nine months ended September 30, 2020 compared to the nine months ended September 30, 2019. The primary contributors to the decrease in operating cash flows were as follows:

•Gross operating margin, excluding non-cash commodity swap activity, decreased $96.2 million.

•Distribution of earnings from unconsolidated affiliates decreased $13.1 million.

•Interest expense, excluding amortization of debt issue costs and net discounts (premium) of notes, increased $6.9 million.

These changes to operating cash flows were offset by the following:

•Operating expenses excluding unit-based compensation decreased $70.3 million primarily due to reductions in workforce. For more information, see “Results of Operations.”

•General and administrative expenses excluding unit-based compensation decreased $20.9 million primarily due to a reduction in costs across our platform and reductions in workforce. For more information, see “Results of Operations.”

The changes in working capital for the nine months ended September 30, 2020 compared to the nine months ended September 30, 2019 were primarily due to fluctuations in trade receivable and payable balances due to timing of collection and payments, changes in inventory balances attributable to normal operating fluctuations, and fluctuations in accrued revenue and accrued cost of sales.

Cash Flows from Investing Activities. Net cash used in investing activities was $250.7 million for the nine months ended September 30, 2020, compared to $583.0 million for the nine months ended September 30, 2019. Investing cash flows are primarily related to capital expenditures, which decreased from $594.5 million for the nine months ended September 30, 2019 to $254.4 million for the nine months ended September 30, 2020. The decrease was primarily due to reduced capital spending plans for 2020. Additionally, proceeds from the sale of assets decreased from $13.7 million for the nine months ended September 30, 2019 to $7.2 million for the nine months ended September 30, 2020 related to the sale of non-core assets for each period.

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Cash Flows from Financing Activities. Net cash used in financing activities was $304.2 million for the nine months ended September 30, 2020 compared to $184.6 million for the nine months ended September 30, 2019. Our primary financing activities consisted of the following (in millions):


	Nine Months Ended September 30,
	2020		2019
Net borrowings on related party debt (1)	$	(50.8)	$	588.5
Net repurchases on senior unsecured notes	(35.2)		—
Net repayments of the 2019 unsecured senior notes	—		(400.0)
Contributions by non-controlling interests (2)	52.2		78.6
Distributions to non-controlling interests (3)	(21.8)		(18.0)
Distributions to common units (4)	(186.2)		(276.6)
Distributions to general partner interest (including incentive distribution rights) (5)	—		(15.6)
Distributions to Series B Preferred Unitholders (6)	(50.4)		(50.3)
Distributions to Series C Preferred Unitholders (6)	(12.0)		(12.0)

____________________________

(1)Related party debt includes borrowings under the Consolidated Credit Facility, the Term Loan, and ENLC’s 5.375% senior unsecured notes due 2029 to fund the operations and growth capital expenditures of ENLK through a related party arrangement with ENLC. See “Item 1. Financial Statements—Note 5” for additional information.

(2)Represents contributions from NGP to the Delaware Basin JV.

(3)Represents distributions to NGP for its ownership in the Delaware Basin JV, distributions to Marathon Petroleum Corporation for its ownership in the Ascension JV, and distributions to other minor non-controlling interests.

(4)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.

(5)At the closing of the Merger, our general partner’s incentive distribution rights were eliminated.

(6)See “Item 1. Financial Statements—Note 6” for information on distributions to holders of the Series B Preferred Units and Series C Preferred Units.

Capital Requirements. We expect our remaining 2020 capital expenditures, including capital contributions to our unconsolidated affiliate investments, to be approximately $15 million to $55 million, which is net of approximately $5 million to $15 million from our joint venture partners. Our primary capital projects for the remainder of 2020 relate to the continued development of our existing systems through well connects and other small projects.

We expect to fund capital expenditures from operating cash flows and capital contributions by joint venture partners that relate to the non-controlling interest share of our consolidated entities. In 2020, it is possible that not all of our planned projects will be commenced or completed. Our ability to pay distributions to our unitholders, to fund planned capital expenditures, and to make acquisitions will depend upon our future operating performance, which will be affected by prevailing economic conditions in the industry, financial, business, and other factors, some of which are beyond our control.

Off-Balance Sheet Arrangements. We had no off-balance sheet arrangements as of September 30, 2020.

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Total Contractual Cash Obligations. A summary of our total contractual cash obligations as of September 30, 2020 is as follows (in millions):


	Payments Due by Period
	Total		Remainder 2020		2021		2022		2023		2024		Thereafter
Long-term debt obligations	$	3,033.6	$	—	$	—	$	—	$	—	$	521.8	$	2,511.8
Related party debt	1,648.7		—		850.0		—		—		300.0		498.7
Interest payable on fixed long-term debt obligations	2,399.8		74.6		173.1		173.1		173.1		161.6		1,644.3

Operating lease obligations	126.8		5.5		19.4		13.4		10.2		9.5		68.8
Purchase obligations	4.1		4.1		—		—		—		—		—
Pipeline and trucking capacity and deficiency agreements (1)	184.4		14.5		41.0		31.8		28.1		33.0		36.0
Inactive easement commitment (2)	10.0		—		—		10.0		—		—		—
Total contractual obligations	$	7,407.4	$	98.7	$	1,083.5	$	228.3	$	211.4	$	1,025.9	$	4,759.6

____________________________

(1) Consists of pipeline capacity payments for firm transportation and deficiency agreements.

(2) Amounts related to inactive easements paid as utilized by us with balance due in 2022 if not utilized.

The above table does not include any physical or financial contract purchase commitments for natural gas and NGLs due to the nature of both the price and volume components of such purchases, which vary on a daily or monthly basis. Additionally, we do not have contractual commitments for fixed price and/or fixed quantities of any material amount that is not already disclosed in the table above.

The interest payable under the related party debt related to the Consolidated Credit Facility and the Term Loan are not reflected in the above table because such amounts depend on the outstanding balances and interest rates of the Consolidated Credit Facility and the Term Loan, which vary from time to time.

Our contractual cash obligations for the remainder of 2020 are expected to be funded from cash flows generated from our operations.

Indebtedness

We have a related party debt arrangement with ENLC to fund the operations and growth capital expenditures of ENLK. Interest charged to ENLK for borrowings made through the related party arrangement is substantially the same as interest charged to ENLC on borrowings from third party lenders. 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 in “Item 1. Financial Statements—Note 5” affect balances owed by ENLK on the related party debt. As of September 30, 2020, we had $1.6 billion in outstanding borrowings under the related party debt arrangement, of which $1.15 billion was related to the Consolidated Credit Facility and the Term Loan and $498.7 million was related to ENLC’s 5.375% unsecured senior notes due 2029.

In addition, as of September 30, 2020, we have $3.0 billion in aggregate principal amount of outstanding unsecured senior notes maturing from 2024 to 2047.

See “Item 1. Financial Statements—Note 5” and “Item 1. Financial Statements—Note 13” for more information on our outstanding debt instruments.

Recent Accounting Pronouncements

See “Item 1. Financial Statements—Note 2” for more information on recently issued and adopted accounting pronouncements.

Disclosure Regarding Forward-Looking Statements

This Quarterly Report on Form 10-Q contains forward-looking statements within the meaning of the federal securities laws. Although these statements reflect the current views, assumptions and expectations of our management, the matters addressed herein involve certain assumptions, risks and uncertainties that could cause actual activities, performance, outcomes

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and results to differ materially from those indicated herein. Therefore, you should not rely on any of these forward-looking statements. All statements, other than statements of historical fact, included in this Quarterly Report constitute forward-looking statements, including, but not limited to, statements identified by the words “forecast,” “may,” “believe,” “will,” “should,” “plan,” “predict,” “anticipate,” “intend,” “estimate,” “expect,” “continue,” and similar expressions. Such forward-looking statements include, but are not limited to, statements about when additional capacity will be operational, timing for completion of construction or expansion projects, results in certain basins, profitability, financial or leverage metrics, future cost savings or operational initiatives, our future capital structure and credit ratings, objectives, strategies, expectations, and intentions, the impact of the COVID-19 pandemic on us and our financial results and operations, and other statements that are not historical facts. Factors that could result in such differences or otherwise materially affect our financial condition, results of operation, or cash flows, include, without limitation, (a) the impact of the ongoing coronavirus (COVID-19) outbreak on our business, financial condition, and results of operation, (b) potential conflicts of interest of GIP with us and the potential for GIP to favor GIP’s own interests to the detriment of our unitholders, (c) GIP’s ability to compete with us and the fact that it is not required to offer us the opportunity to acquire additional assets or businesses, (d) a default under GIP’s credit facility could result in a change in control of us and a default under ENLC’s Consolidated Credit Facility and Term Loan, (e) the dependence on Devon for a substantial portion of the natural gas and crude that we gather, process, and transport, (f) developments that materially and adversely affect Devon or other customers, (g) adverse developments in the midstream business that may reduce our ability to make distributions, (h) competition for crude oil, condensate, natural gas, and NGL supplies and any decrease in the availability of such commodities, (i) decreases in the volumes that we gather, process, fractionate, or transport, (j) construction risks in our major development projects, (k) our ability to receive or renew required permits and other approvals, (l) increased federal, state, and local legislation, and regulatory initiatives, as well as government reviews relating to hydraulic fracturing resulting in increased costs and reductions or delays in natural gas production by our customers, (m) climate change legislation and regulatory initiatives resulting in increased operating costs and reduced demand for the natural gas and NGL services we provide, (n) changes in the availability and cost of capital, including as a result of a change in our credit rating, (o) volatile prices and market demand for crude oil, condensate, natural gas, and NGLs that are beyond our control, (p) our debt levels could limit our flexibility and adversely affect our financial health or limit our flexibility to obtain financing and to pursue other business opportunities, (q) operating hazards, natural disasters, weather-related issues or delays, casualty losses, and other matters beyond our control, (r) reductions in demand for NGL products by the petrochemical, refining, or other industries or by the fuel markets, (s) impairments to goodwill, long-lived assets and equity method investments, and (t) the effects of existing and future laws and governmental regulations, including environmental and climate change requirements and other uncertainties. In addition to the specific uncertainties, factors, and risks discussed above and elsewhere in this Quarterly Report on Form 10-Q, the risk factors set forth in Part I, “Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2019 and in Part II, “Item 1A. Risk Factors” of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020 may affect our performance and results of operations. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may differ materially from those in the forward-looking statements. We disclaim any intention or obligation to update or review any forward-looking statements or information, whether as a result of new information, future events, or otherwise.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

Market risk is the risk of loss arising from adverse changes in market rates and prices. Our primary market risk is the risk related to changes in the prices of natural gas, NGLs, condensate, and crude oil. In addition, we are also exposed to the risk of changes in interest rates on floating rate debt.

Comprehensive financial reform legislation was signed into law by the President on July 21, 2010. The legislation calls for the CFTC to regulate certain markets for derivative products, including OTC derivatives. The CFTC has issued several relevant regulations, and other rulemakings are pending at the CFTC, the product of which would be rules that implement the mandates in the legislation to cause significant portions of derivatives markets to clear through clearinghouses. While some of these rules have been finalized, some have not, and, as a result, the final form and timing of the implementation of the regulatory regime affecting commodity derivatives remains uncertain.

In particular, on October 18, 2011, the CFTC adopted final rules under the Dodd-Frank Act establishing position limits for certain energy commodity futures and options contracts and economically equivalent swaps, futures and options. The position limit levels set the maximum amount of covered contracts that a trader may own or control separately or in combination, net long or short. The final rules also contained limited exemptions from position limits which would be phased in over time for certain bona fide hedging transactions and positions. The CFTC’s original position limits rule was challenged in court by two industry associations and was vacated and remanded by a federal district court. The CFTC proposed new rules in January 2020 (withdrawing previously proposed rules from November 2013 and December 2016) that would place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. The CFTC sought comment on the position limits rules as reproposed and revised, but the new rules have not yet been issued in final form, and the impact of any final provisions on us is uncertain at this time.

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The legislation and potential new regulations may also require counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. The legislation and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures and to generate sufficient cash flow to pay quarterly distributions at current levels or at all. Our revenues could be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material, adverse effect on us, our financial condition, and our results of operations.

Commodity Price Risk

We are subject to risks due to fluctuations in commodity prices. Approximately 95% of our gross operating margin for the nine months ended September 30, 2020 was generated from arrangements with fee-based structures with minimal direct commodity price exposure. Our exposure to these commodity price fluctuations is primarily in the gas processing component of our business. We currently process gas under four main types of contractual arrangements (or a combination of these types of contractual arrangements) as summarized below.

1.Fee-based contracts. Under fee-based contracts, we earn our fees through (1) stated fixed-fee arrangements in which we are paid a fixed fee per unit of volume processed or (2) arrangements where we purchase and resell commodities in connection with providing the related processing service and earn a net margin through a fee-like deduction subtracted from the purchase price of the commodities.

2.Processing margin contracts. Under these contracts, we pay the producer for the full amount of inlet gas to the plant, and we make a margin based on the difference between the value of liquids recovered from the processed natural gas as compared to the value of the natural gas volumes lost and the cost of fuel used in processing. The shrink and fuel losses are referred to as plant thermal reduction, or PTR. Our margins from these contracts are high during periods of high liquids prices relative to natural gas prices and can be negative during periods of high natural gas prices relative to liquids prices. However, we mitigate our risk of processing natural gas when margins are negative primarily through our ability to bypass processing when it is not profitable for us or by contracts that revert to a minimum fee for processing if the natural gas must be processed to meet pipeline quality specifications. For the nine months ended September 30, 2020, less than 1% of our gross operating margin was generated from processing margin contracts.

3.POL contracts. Under these contracts, we receive a fee in the form of a percentage of the liquids recovered, and the producer bears all the cost of the natural gas shrink. Therefore, our margins from these contracts are greater during periods of high liquids prices. Our margins from processing cannot become negative under POL contracts, but they do decline during periods of low liquids prices.

4.POP contracts. Under these contracts, we receive a fee in the form of a portion of the proceeds of the sale of natural gas and liquids. Therefore, our margins from these contracts are greater during periods of high natural gas and liquids prices. Our margins from processing cannot become negative under POP contracts, but they do decline during periods of low natural gas and liquids prices.

For the nine months ended September 30, 2020, approximately 5% of our gross operating margin was generated from POL or POP contracts.

Our primary commodity risk management objective is to reduce volatility in our cash flows. We maintain a risk management committee, including members of senior management, which oversees all hedging activity. We enter into hedges for natural gas, crude and condensate, and NGLs using OTC derivative financial instruments with only certain well-capitalized counterparties which have been approved in accordance with our commodity risk management policy.

We have hedged our exposure to fluctuations in prices for natural gas, NGLs, and crude oil volumes produced for our account. We have tailored our hedges to generally match the product composition and the delivery points to those of our physical equity volumes. The hedges cover specific products based upon our expected equity composition.

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The following table sets forth certain information related to derivative instruments outstanding at September 30, 2020 mitigating the risks associated with the gas processing and fractionation components of our business. The relevant payment index price for liquids is the monthly average of the daily closing price for deliveries of commodities into Mont Belvieu, Texas as reported by Oil Price Information Service. The relevant index price for natural gas is Henry Hub Gas Daily as defined by the pricing dates in the swap contracts.

Period

Underlying

Notional Volume

We Pay

We Receive (1)

Net Fair Value
Asset/(Liability)
(In millions)

October 2020 - May 2021

Ethane

1,971 (MBbls)

$0.2031/gal

Index

(2.3)

October 2020 - July 2021

Propane

1,273 (MBbls)

Index

$0.5083/gal

(3.2)

October 2020 - July 2021

Normal butane

447 (MBbls)

Index

$0.5921/gal

(1.3)

October 2020 - January 2021

Natural gasoline

202 (MBbls)

Index

$0.8779/gal

(1.7)

October 2020 - October 2021

Natural gas

80,632 (MMBtu/d)

Index

$2.3700/MMBtu

(1.8)

October 2020 - January 2021

Crude and condensate

1,030 (MBbls)

Index

$40.41/Bbl

0.4

October 2020 - December 2022

Crude and condensate

9,062 (MBbls)

$1.824/Bbl

Index (2)

10.3

0.4

____________________________

(1)Weighted average.

(2)Represents the WTI Houston and WTI Midland differential.

Another price risk we face is the risk of mismatching volumes of gas bought or sold on a monthly price versus volumes bought or sold on a daily price. We enter each month with a balanced book of natural gas bought and sold on the same basis. However, it is normal to experience fluctuations in the volumes of natural gas bought or sold under either basis, which leaves us with short or long positions that must be covered. We use financial swaps to mitigate the exposure at the time it is created to maintain a balanced position.

The use of financial instruments may expose us to the risk of financial loss in certain circumstances, including instances when (1) sales volumes are less than expected requiring market purchases to meet commitments or (2) counterparties fail to purchase the contracted quantities of natural gas or otherwise fail to perform. To the extent that we engage in hedging activities, we may be prevented from realizing the benefits of favorable price changes in the physical market. However, we are similarly insulated against unfavorable changes in such prices.

As of September 30, 2020, outstanding natural gas swap agreements, NGL swap agreements, swing swap agreements, storage swap agreements, and other derivative instruments had a net fair value asset of $0.4 million. The aggregate effect of a hypothetical 10% change, increase or decrease, in gas, crude and condensate, and NGL prices would result in a change of approximately $9.3 million in the net fair value of these contracts as of September 30, 2020.

Interest Rate Risk

We are exposed to interest rate risk on the Consolidated Credit Facility and the Term Loan through the related party debt arrangement with ENLC. At September 30, 2020, we had $1,648.7 million in outstanding borrowings under the related party debt arrangement, of which $1,150.0 million was related to the Consolidated Credit Facility and the Term Loan. In April 2019, we entered into $850.0 million of interest rate swaps to reduce the variability of cash outflows associated with interest payments related to our long-term debt with variable interest rates. These swaps have been designated as cash flow hedges. See “Item 1. Financial Statements—Note 9” for more information on our outstanding derivatives. A 1.0% increase or decrease in interest rates would change our annualized interest expense by approximately $11.5 million for the Consolidated Credit Facility and the Term Loan. This change in interest expense would be partially offset by an $8.5 million change related to our open interest rate swap hedge.

We are not exposed to changes in interest rates with respect to our senior unsecured notes due in 2024, 2025, 2026, 2044, 2045, or 2047 or our related party debt balance related to ENLC’s senior unsecured notes due in 2029 as these are fixed-rate obligations. As of September 30, 2020, the estimated fair value of our senior unsecured notes and ENLC’s senior unsecured notes was approximately $2,339.2 million and $403.6 million, respectively, based on the market prices of the market prices of our and ENLC's publicly traded debt at September 30, 2020. Market risk is estimated as the potential decrease in fair value of our long-term debt resulting from a hypothetical increase of 1.0% in interest rates. Such an increase in interest rates would result in an approximate $166.6 million decrease in fair value of the senior unsecured notes at September 30, 2020. See “Item 1. Financial Statements—Note 5” for more information on our outstanding indebtedness.

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Item 4. Controls and Procedures

a.Evaluation of Disclosure Controls and Procedures

We carried out an evaluation, under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer of our general partner, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report pursuant to Exchange Act Rules 13a-15 and 15d-15. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of the period covered by this report (September 30, 2020), our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time period specified in the applicable rules and forms, and that such information is accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosure.

b.Changes in Internal Control Over Financial Reporting

There has been no change in our internal control over financial reporting that occurred in the three months ended September 30, 2020 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II—OTHER INFORMATION

Item 1. Legal Proceedings

We are involved in various litigation and administrative proceedings arising in the normal course of business. In the opinion of management, any liabilities that may result from these claims would not individually or in the aggregate have a material adverse effect on our financial position, results of operations, or cash flows.

Item 1A. Risk Factors

Information about risk factors does not differ materially from that set forth in Part I, “Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2019, as supplemented by Part II, “Item 1A. Risk Factors” of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020.

Item 5. Other Information

Disclosure Pursuant to Item 5.02 of Form 8-K – Departure of Directors or Certain Officers; Election of Directors; Appointment of Certain Officers; Compensatory Arrangements of Certain Officers.

On November 3, 2020, J. Philipp Rossbach, the Partnership’s current Chief Accounting Officer, was named as the Partnership’s principal accounting officer. Mr. Rossbach will replace Pablo G. Mercado as the principal accounting officer of ENLK. Mr. Mercado will continue to serve as ENLK’s Chief Financial Officer and principal financial officer.

Mr. Rossbach, 39, has served as Chief Accounting Officer of the Partnership since April 2020. Previously, Mr. Rossbach served in other accounting roles with the Partnership, including as Corporate Controller from March 2016 to March 2020, as Director – Operations Accounting from August 2014 to February 2016, and as Manager – General Accounting from 2013. Mr. Rossbach will continue working under his existing compensation arrangements.

Also on November 3, 2020, the Operating Partnership amended and restated the existing Change in Control Agreement (the “CIC Agreement”) with each of its named executive officers other than the Chairman and Chief Executive Officer to increase the change in control benefit multiplier from two times the change in control benefit to two and a half times the change in control benefit. The change in control benefit in the CIC Agreement consists of (A) the officer’s then-current base salary and (B) any target bonus for the year that includes the date of termination. The change in control benefit multiplier in the CIC Agreement with the Partnership’s Chairman and Chief Executive Officer remains unchanged at three times the change in control benefit.

For more information on the terms of the CIC Agreement, see ENLK’s Annual Report on Form 10-K for the fiscal year ended December 31, 2019, filed with the Securities and Exchange Commission on February 26, 2020.

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Item 6. Exhibits

The exhibits filed as part of this report are as follows (exhibits incorporated by reference are set forth with the name of the registrant, the type of report and registration number or last date of the period for which it was filed, and the exhibit number in such filing):


Number		Description

3.1	—	Certificate of Limited Partnership of EnLink Midstream Partners, LP (incorporated by reference to Exhibit 3.1 to our Registration Statement on Form S-1, file No. 333-97779).
3.2	—	Certificate of Amendment to the Certificate of Limited Partnership of EnLink Midstream Partners, LP (incorporated by reference to Exhibit 3.2 to our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2012, filed with the Commission on August 7, 2012, file No. 000-50067).
3.3	—	Second Amendment to the Certificate of Limited Partnership of EnLink Midstream Partners, LP (incorporated by reference to Exhibit 3.3 to our Current Report on Form 8-K dated March 6, 2014, filed with the Commission on March 11, 2014, file No. 001-36340).
3.4	—	Third Amendment to the Certificate of Limited Partnership of EnLink Midstream Partners, LP (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K dated June 16, 2017, filed with the Commission on June 19, 2017, file No. 001-36340).
3.5	—	Tenth Amended and Restated Agreement of Limited Partnership of EnLink Midstream Partners, LP, dated as of January 25, 2019 (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K dated January 25, 2019, filed with the Commission on January 29, 2019, file No. 001-36340).
3.6	—	Certificate of Formation of EnLink Midstream GP, LLC (incorporated by reference to Exhibit 3.7 to our Registration Statement on Form S-1, file No. 333-97779).
3.7	—	Certificate of Amendment to the Certificate of Formation of EnLink Midstream GP, LLC (incorporated by reference to Exhibit 3.12 to our Registration Statement on Form S-3, file No. 333-194465).
3.8	—	Fourth Amended and Restated Limited Liability Company Agreement of EnLink Midstream GP, LLC, dated as of July 18, 2018 (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K dated July 17, 2018, filed with the Commission on July 23, 2018, file No. 001-36340).





10.1	—	Sale and Contribution Agreement, dated as of October 21, 2020, by and among EnLink Midstream Funding, LLC, EnLink Midstream Operating, LP, and the originators from time to time party thereto (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K dated October 21, 2020, filed with the Commission on October 22, 2020, file No. 001-36340).
10.2	—	Receivables Financing Agreement, dated as of October 21, 2020, by and among EnLink Midstream Funding, LLC, as borrower, EnLink Midstream Operating, LP, as initial servicer, PNC Bank, National Association, as administrative agent and lender, the lenders party thereto, and PNC Capital Markets, LLC, as structuring agent (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K dated October 21, 2020, filed with the Commission on October 22, 2020, file No. 001-36340).

10.3 ‡*	—	Form of EnLink Midstream Operating, LP Amended and Restated Change in Control Agreement.
31.1 *	—	Certification of the Principal Executive Officer.
31.2 *	—	Certification of the Principal Financial Officer.
32.1 *	—	Certification of the Principal Executive Officer and Principal Financial Officer pursuant to 18 U.S.C. Section 1350.
101 *	—	The following financial information from EnLink Midstream Partners, LP's Quarterly Report on Form 10-Q for the quarter ended September 30, 2020, formatted in iXBRL (Inline eXtensible Business Reporting Language): (i) Consolidated Balance Sheets as of September 30, 2020 and December 31, 2019, (ii) Consolidated Statements of Operations for the three and nine months ended September 30, 2020 and 2019, (iii) Consolidated Statements of Changes in Partners’ Equity for the three months ended September 30, 2020 and 2019, June 30, 2020 and 2019, and March 31, 2020 and 2019, (iv) Consolidated Statements of Cash Flows for the nine months ended September 30, 2020 and 2019, and (v) the Notes to Consolidated Financial Statements.
104 *	—	Cover Page Interactive Data File (formatted as Inline iXBRL and included in Exhibit 101).

____________________________

* Filed herewith.

‡ As required by Item 15(a)(3), this Exhibit is identified as a compensatory benefit plan or arrangement.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


	EnLink Midstream Partners, LP

	By:	EnLink Midstream GP, LLC,
		its general partner

	By:	/s/ J. PHILIPP ROSSBACH
		J. Philipp Rossbach
		Chief Accounting Officer
		(Principal Accounting Officer)
November 5, 2020