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, 2021~~March 31, 2022

☐ 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: 001-36336

ENLINK MIDSTREAM, LLC

(Exact name of registrant as specified in its charter)


Delaware		46-4108528
(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

Common Units Representing Limited Liability Company Interests

ENLC

The New York Stock Exchange

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 ☒ 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 ☒ 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~~April 28, ~~2021,~~2022, the Registrant had ~~487,957,616~~483,011,794 common units outstanding.

Table of Contents

TABLE OF CONTENTS

Table of Contents

DEFINITIONS

The following terms as defined are used in this document:


Defined Term						Definition
/d						Per day.
2014 Plan						ENLC’s 2014 Long-Term Incentive Plan.
Adjusted gross margin						Revenue less cost of sales, exclusive of operating expenses and depreciation and ~~amortization related to our operating segments.~~amortization. Adjusted gross 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.
AR Facility						An accounts receivable securitization facility of up to $350 million entered into by EnLink Midstream Funding, LLC, a bankruptcy-remote special purpose entity and our indirect subsidiary, with PNC Bank, National Association, as administrative agent and lender, and PNC Capital Markets, LLC, as structuring agent and sustainability agent. The AR Facility is scheduled to terminate on September 24, 2024, unless extended or earlier terminated in accordance with its terms.
ASC						The ~~FASB~~Financial Accounting Standards Board Accounting Standards Codification.
ASC 718						ASC 718, Compensation—Stock Compensation.
ASC 820						ASC 820, Fair Value Measurements.



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.
~~Bbls~~ Bbl						~~Barrels.~~Barrel.
Bcf						Billion cubic feet.
Beginning TSR Price						The beginning total shareholder return (“TSR”) price, which is the closing ~~share~~unit price of ENLC on the grant date of the performance award agreement or the previous trading day if the grant date was not a trading day, is one of the assumptions used to calculate the grant-date fair value of performance award agreements.
CCS						Carbon capture, transportation, and sequestration.
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.
CO2						Carbon dioxide.
Commission						U.S. Securities and Exchange Commission.
Consolidated Credit Facility						A $1.75 billion unsecured revolving credit facility entered into by ENLC that matures on January 25, 2024, which includes a $500.0 million letter of credit subfacility. The Consolidated Credit Facility was available upon closing of the Merger and is guaranteed by ENLK.
Delaware Basin						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 processing plant located in the Delaware Basin in Texas.
~~Devon~~						~~Devon Energy Corporation.~~
ENLC						EnLink Midstream, LLC.
ENLC Class C Common Units						A class of non-economic ENLC common units issued immediately prior to the Merger equal to the number of Series B Preferred Units held immediately prior to the effective time of the Merger, in order to provide certain voting rights to holders of the Series B Preferred Units with respect to ENLC.
ENLK						EnLink Midstream Partners, LP or, when applicable, EnLink Midstream Partners, LP together with its consolidated subsidiaries. Also referred to as the “Partnership.”
~~FASB~~Exchange Act						~~Financial Accounting Standards Board.~~The Securities Exchange Act of 1934, as amended.
GAAP						Generally accepted accounting principles in the United States of America.
Gal						~~Gallons.~~Gallon.
GCF						Gulf Coast Fractionators, which owns an NGL fractionator in Mont Belvieu, Texas. ENLK owns 38.75% of GCF. The GCF assets have been temporarily idled to reduce operating expenses. We expect these assets to resume operations when there is a sustained need for additional fractionation capacity in Mont Belvieu.
General Partner						EnLink Midstream GP, LLC, the general partner of ENLK.

Table of Contents


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.
ISDAs						International Swaps and Derivatives Association Agreements.
LIBOR						U.S. Dollar London Interbank Offered Rate.
Managing Member						EnLink Midstream Manager, LLC, the managing member of ENLC.
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.
Midland Basin						A large sedimentary basin in West Texas.

~~Table of Contents~~


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.
Permian Basin						A large sedimentary basin that includes the Midland and Delaware ~~Basins.~~Basins primarily in West Texas and New Mexico.
POL contracts						Percentage-of-liquids contracts.
POP contracts						Percentage-of-proceeds contracts.
Series B Preferred ~~Units~~Unit						ENLK’s Series B Cumulative Convertible Preferred ~~Units.~~Unit.
Series C Preferred ~~Units~~Unit						ENLK’s Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred ~~Units.~~Unit.
STACK						Sooner Trend Anadarko Basin Canadian and Kingfisher Counties in Oklahoma.
Term Loan						A term loan originally in the amount of $850.0 million 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.~~guaranteed. The Term Loan ~~matures on December 10, 2021.~~was paid at maturity.

Table of Contents

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Consolidated Balance Sheets

(In millions, except unit data)


		September 30, 2021		December 31, 2020			March 31, 2022		December 31, 2021
		(Unaudited)					(Unaudited)
ASSETS	ASSETS					ASSETS
Current assets:	Current assets:					Current assets:
Cash and cash equivalents	Cash and cash equivalents	$	36.1	$	39.6	Cash and cash equivalents	$	68.7	$	26.2
Accounts receivable:	Accounts receivable:					Accounts receivable:
Trade, net of allowance for bad debt of $0.3 and $0.5, respectively		88.5		80.6
Trade, net of allowance for bad debt of $0.3 and $0.3, respectively						Trade, net of allowance for bad debt of $0.3 and $0.3, respectively	70.4		94.9
Accrued revenue and other	Accrued revenue and other	636.6		447.5		Accrued revenue and other	857.9		693.3

Fair value of derivative assets	Fair value of derivative assets	75.3		25.0		Fair value of derivative assets	68.1		22.4
Other current assets	Other current assets	156.2		58.7		Other current assets	112.7		83.6
Total current assets	Total current assets	992.7		651.4		Total current assets	1,177.8		920.4
Property and equipment, net of accumulated depreciation of $4,215.7 and $3,863.0, respectively		6,425.1		6,652.1
Intangible assets, net of accumulated amortization of $763.2 and $668.8, respectively		1,081.6		1,125.4
Property and equipment, net of accumulated depreciation of $4,450.6 and $4,332.0, respectively						Property and equipment, net of accumulated depreciation of $4,450.6 and $4,332.0, respectively	6,321.8		6,388.3
Intangible assets, net of accumulated amortization of $827.9 and $795.1, respectively						Intangible assets, net of accumulated amortization of $827.9 and $795.1, respectively	1,016.9		1,049.7

Investment in unconsolidated affiliates	Investment in unconsolidated affiliates	29.0		41.6		Investment in unconsolidated affiliates	27.3		28.0
Fair value of derivative assets	Fair value of derivative assets	2.2		4.9		Fair value of derivative assets	0.1		0.2
Other assets, net	Other assets, net	95.9		75.5		Other assets, net	96.3		96.6
Total assets	Total assets	$	8,626.5	$	8,550.9	Total assets	$	8,640.2	$	8,483.2
LIABILITIES AND MEMBERS’ EQUITY	LIABILITIES AND MEMBERS’ EQUITY					LIABILITIES AND MEMBERS’ EQUITY
Current liabilities:	Current liabilities:					Current liabilities:
Accounts payable and drafts payable	Accounts payable and drafts payable	$	103.5	$	60.5	Accounts payable and drafts payable	$	131.7	$	139.6

Accrued gas, NGLs, condensate, and crude oil purchases (1)	Accrued gas, NGLs, condensate, and crude oil purchases (1)	529.8		291.5		Accrued gas, NGLs, condensate, and crude oil purchases (1)	740.0		521.5
Fair value of derivative liabilities	Fair value of derivative liabilities	110.9		37.1		Fair value of derivative liabilities	97.2		34.9
Current maturities of long-term debt		150.0		349.8
Other current liabilities	Other current liabilities	215.9		149.1		Other current liabilities	215.4		202.9
Total current liabilities	Total current liabilities	1,110.1		888.0		Total current liabilities	1,184.3		898.9
Long-term debt		4,242.6		4,244.0
Long-term debt, net of unamortized issuance cost						Long-term debt, net of unamortized issuance cost	4,315.0		4,363.7

Other long-term liabilities	Other long-term liabilities	92.1		94.8		Other long-term liabilities	94.0		93.9
Deferred tax liability, net	Deferred tax liability, net	124.2		108.6		Deferred tax liability, net	140.5		137.5
Fair value of derivative liabilities	Fair value of derivative liabilities	2.3		2.5		Fair value of derivative liabilities	0.6		2.2

Members’ equity:	Members’ equity:					Members’ equity:
Members’ equity (487,951,939 and 489,381,149 units issued and outstanding, respectively)		1,338.8		1,508.8
Members’ equity (483,364,767 and 484,277,258 units issued and outstanding, respectively)						Members’ equity (483,364,767 and 484,277,258 units issued and outstanding, respectively)	1,291.5		1,325.8
Accumulated other comprehensive loss	Accumulated other comprehensive loss	(4.2)		(15.3)		Accumulated other comprehensive loss	(1.3)		(1.4)
Non-controlling interest	Non-controlling interest	1,720.6		1,719.5		Non-controlling interest	1,615.6		1,662.6
Total members’ equity	Total members’ equity	3,055.2		3,213.0		Total members’ equity	2,905.8		2,987.0
Commitments and contingencies (Note 15)		0		0
Commitments and contingencies (Note 14)						Commitments and contingencies (Note 14)	0		0
Total liabilities and members’ equity	Total liabilities and members’ equity	$	8,626.5	$	8,550.9	Total liabilities and members’ equity	$	8,640.2	$	8,483.2

____________________________

(1)Includes related party accounts payable balances of ~~$1.9~~$5.8 million and ~~$1.0~~$1.6 million at ~~September 30, 2021~~March 31, 2022 and December 31, ~~2020,~~2021, respectively.

See accompanying notes to consolidated financial statements.

Table of Contents

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Consolidated Statements of Operations

(In millions, except per unit data)


		Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended March 31,
		2021		2020		2021		2020			2022		2021
		(Unaudited)									(Unaudited)
Revenues:	Revenues:									Revenues:
Product sales	Product sales	$	1,610.2	$	696.1	$	3,968.7	$	2,121.6	Product sales	$	2,043.9	$	1,122.9

Midstream services	Midstream services	211.0		237.5		629.2		716.2		Midstream services	215.0		208.9

Loss on derivative activity	Loss on derivative activity	(33.6)		(5.1)		(155.2)		(8.3)		Loss on derivative activity	(31.2)		(83.4)
Total revenues	Total revenues	1,787.6		928.5		4,442.7		2,829.5		Total revenues	2,227.7		1,248.4
Operating costs and expenses:	Operating costs and expenses:									Operating costs and expenses:
Cost of sales, exclusive of operating expenses and depreciation and amortization ~~(2)~~(1)	Cost of sales, exclusive of operating expenses and depreciation and amortization ~~(2)~~(1)	1,400.8		549.5		3,390.6		1,702.5		Cost of sales, exclusive of operating expenses and depreciation and amortization ~~(2)~~(1)	1,794.5		934.7
Operating expenses	Operating expenses	106.9		94.3		260.0		283.1		Operating expenses	120.9		56.3
Depreciation and amortization	Depreciation and amortization	153.0		160.3		455.9		481.3		Depreciation and amortization	152.9		151.0
Impairments		—		—		—		354.5
(Gain) loss on disposition of assets		(0.4)		(1.8)		(0.7)		2.8

Loss on disposition of assets										Loss on disposition of assets	5.1		—
General and administrative	General and administrative	28.2		25.7		80.3		79.6		General and administrative	29.0		26.0

Total operating costs and expenses	Total operating costs and expenses	1,688.5		828.0		4,186.1		2,903.8		Total operating costs and expenses	2,102.4		1,168.0
Operating income (loss)		99.1		100.5		256.6		(74.3)
Operating income										Operating income	125.3		80.4
Other income (expense):	Other income (expense):									Other income (expense):
Interest expense, net of interest income	Interest expense, net of interest income	(60.1)		(55.5)		(180.1)		(166.3)		Interest expense, net of interest income	(55.1)		(60.0)
Gain on extinguishment of debt		—		—		—		32.0
Income (loss) from unconsolidated affiliates		(2.3)		(0.2)		(9.9)		0.8
Other income		—		0.4		0.1		0.4

Loss from unconsolidated affiliate investments										Loss from unconsolidated affiliate investments	(1.1)		(6.3)
Other income (expense)										Other income (expense)	0.1		(0.1)
Total other expense	Total other expense	(62.4)		(55.3)		(189.9)		(133.1)		Total other expense	(56.1)		(66.4)
Income (loss) before non-controlling interest and income taxes		36.7		45.2		66.7		(207.4)
Income tax benefit (expense)		(4.4)		(6.0)		(12.4)		16.0
Net income (loss)		32.3		39.2		54.3		(191.4)
Income before non-controlling interest and income taxes										Income before non-controlling interest and income taxes	69.2		14.0
Income tax expense										Income tax expense	(3.2)		(1.4)
Net income										Net income	66.0		12.6
Net income attributable to non-controlling interest	Net income attributable to non-controlling interest	30.4		26.6		86.7		78.7		Net income attributable to non-controlling interest	30.8		25.3
Net income (loss) attributable to ENLC	Net income (loss) attributable to ENLC	$	1.9	$	12.6	$	(32.4)	$	(270.1)	Net income (loss) attributable to ENLC	$	35.2	$	(12.7)
Net income (loss) attributable to ENLC per unit:	Net income (loss) attributable to ENLC per unit:									Net income (loss) attributable to ENLC per unit:
Basic common unit	Basic common unit	$	—	$	0.03	$	(0.07)	$	(0.55)	Basic common unit	$	0.07	$	(0.03)
Diluted common unit	Diluted common unit	$	—	$	0.03	$	(0.07)	$	(0.55)	Diluted common unit	$	0.07	$	(0.03)

____________________________

(1)Includes related party cost of sales of ~~$4.9~~$10.6 million and ~~$2.0~~$3.2 million for the three months ended ~~September 30,~~March 31, 2022 and 2021, and 2020, respectively, and excludes all operating expenses as well as depreciation and amortization related to our operating segments of $150.8 million and $158.6 million for the three months ended September 30, 2021 and 2020, respectively.

~~(2)~~

Includes related party cost of sales of $11.7 million and $6.2 million for the nine months ended September 30, 2021 and 2020, respectively, and excludes all operating expenses as well as depreciation and amortization related to our operating segments of $449.9 million and $475.5 million for the nine months ended September 30, 2021 and 2020, respectively.

See accompanying notes to consolidated financial statements.

Table of Contents

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Consolidated Statements of Comprehensive Income ~~(Loss)~~

(In millions)
Three Months Ended
September 30, Nine Months Ended
September 30,
2021 2020 2021 2020
(Unaudited)
Net income (loss) $ 32.3 $ 39.2 $ 54.3 $ (191.4)
Unrealized gain (loss) on designated cash flow hedge (1) 3.8 3.6 11.1 (8.0)
Comprehensive income (loss) 36.1 42.8 65.4 (199.4)
Comprehensive income attributable to non-controlling interest 30.4 26.6 86.7 78.7
Comprehensive income (loss) attributable to ENLC $ 5.7 $ 16.2 $ (21.3) $ (278.1)


	Three Months Ended March 31,
	2022		2021
	(Unaudited)
Net income	$	66.0	$	12.6
Unrealized gain on designated cash flow hedge (1)	0.1		3.6
Comprehensive income	66.1		16.2
Comprehensive income attributable to non-controlling interest	30.8		25.3
Comprehensive income (loss) attributable to ENLC	$	35.3	$	(9.1)

____________________________

(1)Includes ~~a tax expense of $1.2 million and a~~ tax expense of $1.1 million for the three months ended ~~September 30, 2021 and 2020, respectively, and a tax expense of $3.4 million and a tax benefit of $2.4 million for the nine months ended September 30, 2021 and 2020, respectively.~~

March 31, 2021.

See accompanying notes to consolidated financial statements.

Table of Contents

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Consolidated Statements of Changes in Members’ Equity

(In millions)

Common Units Accumulated Other Comprehensive Loss Non-Controlling Interest Total Redeemable Non-controlling interest (Temporary Equity)
$ Units $ $ $ $
(Unaudited)
Balance, December 31, 2020 $ 1,508.8 489.4 $ (15.3) $ 1,719.5 $ 3,213.0 $ —
Conversion of restricted units for common units, net of units withheld for taxes (1.2) 0.7 — — (1.2) —
Unit-based compensation 6.5 — — — 6.5 —
Contributions from non-controlling interests — — — 0.9 0.9 —
Distributions (47.1) — — (25.8) (72.9) (0.2)
Unrealized gain on designated cash flow hedge (1) — — 3.6 — 3.6 —
Fair value adjustment related to redeemable non-controlling interest (0.1) — — — (0.1) 0.2
Net income (loss) (12.7) — — 25.3 12.6 —
Balance, March 31, 2021 1,454.2 490.1 (11.7) 1,719.9 3,162.4 —
Conversion of restricted units for common units, net of units withheld for taxes (0.2) 0.1 — — (0.2) —
Unit-based compensation 6.4 — — — 6.4 —
Contributions from non-controlling interests — — — 1.0 1.0 —
Distributions (46.7) — — (36.0) (82.7) —
Unrealized gain on designated cash flow hedge (2) — — 3.7 — 3.7 —
Common units repurchased (2.0) (0.3) — — (2.0) —
Net income (loss) (21.6) — — 31.0 9.4 —
Balance, June 30, 2021 1,390.1 489.9 (8.0) 1,715.9 3,098.0 —
Conversion of restricted units for common units, net of units withheld for taxes (0.5) 0.2 — — (0.5) —
Unit-based compensation 6.4 — — — 6.4 —
Contributions from non-controlling interests — — — 0.5 0.5 —
Distributions (46.6) — — (26.2) (72.8) —
Unrealized gain on designated cash flow hedge (3) — — 3.8 — 3.8 —
Common units repurchased (12.5) (2.1) — — (12.5) —
Net income 1.9 — — 30.4 32.3 —
Balance, September 30, 2021 $ 1,338.8 488.0 $ (4.2) $ 1,720.6 $ 3,055.2 $ —

~~____________________________~~


	Common Units			Accumulated Other Comprehensive Loss		Non-Controlling Interest		Total
	$		Units	$		$		$
	(Unaudited)
Balance, December 31, 2021	$	1,325.8	484.3	$	(1.4)	$	1,662.6	$	2,987.0
Conversion of restricted units for common units, net of units withheld for taxes	(4.2)		1.2	—		—		(4.2)
Unit-based compensation	8.1		—	—		—		8.1
Contributions from non-controlling interests	—		—	—		7.3		7.3
Distributions	(56.4)		—	—		(34.6)		(91.0)
Unrealized gain on designated cash flow hedge	—		—	0.1		—		0.1
Redemption of Series B Preferred Units	—		—	—		(50.5)		(50.5)
Common units repurchased	(17.0)		(2.1)	—		—		(17.0)
Net income	35.2		—	—		30.8		66.0
Balance, March 31, 2022	$	1,291.5	483.4	$	(1.3)	$	1,615.6	$	2,905.8

~~(1)Includes a tax expense of $1.1 million.~~

~~(2)Includes a tax expense of $1.1 million.~~

~~(3)~~

~~Includes a tax expense of $1.2 million.~~

See accompanying notes to consolidated financial statements.

Table of Contents

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Consolidated Statements of Changes in Members’ Equity (Continued)

(In millions)


		Common Units			Accumulated Other Comprehensive Loss		Non-Controlling Interest		Total		Redeemable Non-Controlling Interest (Temporary Equity)			Common Units			Accumulated Other Comprehensive Loss		Non-Controlling Interest		Total		Redeemable Non-Controlling Interest (Temporary Equity)
		$		Units	$		$		$		$			$		Units	$		$		$		$
		(Unaudited)												(Unaudited)
Balance, December 31, 2019		$	2,135.5	487.8	$	(11.0)	$	1,681.6	$	3,806.1	$	5.2
Balance, December 31, 2020													Balance, December 31, 2020	$	1,508.8	489.4	$	(15.3)	$	1,719.5	$	3,213.0	$	—
Conversion of restricted units for common units, net of units withheld for taxes	Conversion of restricted units for common units, net of units withheld for taxes	(4.0)		1.3	—		—		(4.0)		—		Conversion of restricted units for common units, net of units withheld for taxes	(1.2)		0.7	—		—		(1.2)		—
Unit-based compensation	Unit-based compensation	12.3		—	—		—		12.3		—		Unit-based compensation	6.5		—	—		—		6.5		—
Contributions from non-controlling interests	Contributions from non-controlling interests	—		—	—		37.1		37.1		—		Contributions from non-controlling interests	—		—	—		0.9		0.9		—
Distributions	Distributions	(93.3)		—	—		(24.4)		(117.7)		(0.3)		Distributions	(47.1)		—	—		(25.8)		(72.9)		(0.2)
Unrealized loss on designated cash flow hedge (1)		—		—	(13.1)		—		(13.1)		—
Unrealized gain on designated cash flow hedge (1)													Unrealized gain on designated cash flow hedge (1)	—		—	3.6		—		3.6		—
Fair value adjustment related to redeemable non-controlling interest	Fair value adjustment related to redeemable non-controlling interest	0.7		—	—		—		0.7		(0.9)		Fair value adjustment related to redeemable non-controlling interest	(0.1)		—	—		—		(0.1)		0.2
Redemption of non-controlling interest		��		—	—		—		—		(4.0)

Net income (loss)	Net income (loss)	(286.8)		—	—		26.4		(260.4)		—		Net income (loss)	(12.7)		—	—		25.3		12.6		—
Balance, March 31, 2020		1,764.4		489.1	(24.1)		1,720.7		3,461.0		—
Conversion of restricted units for common units, net of units withheld for taxes		(0.3)		0.4	—		—		(0.3)		—
Unit-based compensation		6.8		—	—		—		6.8		—
Contributions from non-controlling interests		—		—	—		13.2		13.2		—
Distributions		(46.5)		—	—		(35.9)		(82.4)		—
Unrealized gain on designated cash flow hedge (2)		—		—	1.5		—		1.5		—
Net income		4.1		—	—		25.7		29.8		—
Balance, June 30, 2020		1,728.5		489.5	(22.6)		1,723.7		3,429.6		—
Conversion of restricted units for common units, net of units withheld for taxes		(0.4)		0.2	—		—		(0.4)		—
Unit-based compensation		7.2		—	—		—		7.2		—
Contributions from non-controlling interests		—		—	—		1.9		1.9		—
Distributions		(46.4)		—	—		(23.3)		(69.7)		(0.3)
Unrealized gain on designated cash flow hedge (3)		—		—	3.6		—		3.6		—
Fair value adjustment related to redeemable non-controlling interest		(0.3)		—	—		—		(0.3)		0.3
Net income		12.6		—	—		26.6		39.2		—
Balance, September 30, 2020		$	1,701.2	489.7	$	(19.0)	$	1,728.9	$	3,411.1	$	—
Balance, March 31, 2021													Balance, March 31, 2021	$	1,454.2	490.1	$	(11.7)	$	1,719.9	$	3,162.4	$	—

____________________________

(1)Includes ~~a tax benefit of $4.0 million.~~

~~(2)Includes a tax expense of $0.5 million.~~

~~(3)Includes a~~ tax expense of $1.1 million.

See accompanying notes to consolidated financial statements.

Table of Contents

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Consolidated Statements of Cash Flows

(In millions)


		Nine Months Ended September 30,					Three Months Ended March 31,
		2021		2020			2022		2021
		(Unaudited)					(Unaudited)
Cash flows from operating activities:	Cash flows from operating activities:					Cash flows from operating activities:
Net income (loss)		$	54.3	$	(191.4)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Impairments		—		354.5
Net income						Net income	$	66.0	$	12.6
Adjustments to reconcile net income to net cash provided by operating activities:						Adjustments to reconcile net income to net cash provided by operating activities:

Depreciation and amortization	Depreciation and amortization	455.9		481.3		Depreciation and amortization	152.9		151.0
Utility credits, net of usage		(38.2)		—
Deferred income tax (benefit) expense		12.2		(17.1)
Utility credits redeemed (earned)						Utility credits redeemed (earned)	5.6		(40.4)
Deferred income tax expense						Deferred income tax expense	3.0		1.3
Loss on disposition of assets						Loss on disposition of assets	5.1		—
Non-cash unit-based compensation						Non-cash unit-based compensation	6.6		6.5

Non-cash unit-based compensation		19.3		24.6
Amortization of designated cash flow hedge		9.6		0.1
Payments to terminate interest rate swaps		(1.8)		—
Non-cash loss on derivatives recognized in net income (loss)		37.5		7.3
Gain on extinguishment of debt		—		(32.0)

Non-cash loss on derivatives recognized in net income						Non-cash loss on derivatives recognized in net income	17.3		7.8

Amortization of debt issuance costs and net discount of senior unsecured notes	Amortization of debt issuance costs and net discount of senior unsecured notes	3.9		3.1		Amortization of debt issuance costs and net discount of senior unsecured notes	1.3		1.2

Loss from unconsolidated affiliate investments						Loss from unconsolidated affiliate investments	1.1		6.3
Other operating activities	Other operating activities	6.8		2.8		Other operating activities	(1.1)		1.4
Changes in assets and liabilities:	Changes in assets and liabilities:					Changes in assets and liabilities:
Accounts receivable, accrued revenue, and other	Accounts receivable, accrued revenue, and other	(196.5)		85.3		Accounts receivable, accrued revenue, and other	(139.9)		(18.7)
Natural gas and NGLs inventory, prepaid expenses, and other	Natural gas and NGLs inventory, prepaid expenses, and other	(80.3)		(12.7)		Natural gas and NGLs inventory, prepaid expenses, and other	(32.8)		1.2
Accounts payable, accrued product purchases, and other accrued liabilities	Accounts payable, accrued product purchases, and other accrued liabilities	316.5		(144.8)		Accounts payable, accrued product purchases, and other accrued liabilities	222.6		95.6
Net cash provided by operating activities	Net cash provided by operating activities	599.2		561.0		Net cash provided by operating activities	307.7		225.8
Cash flows from investing activities:	Cash flows from investing activities:					Cash flows from investing activities:
Additions to property and equipment	Additions to property and equipment	(104.7)		(254.4)		Additions to property and equipment	(60.2)		(23.5)

Acquisitions, net of cash acquired		(56.7)		—

Other investing activities	Other investing activities	6.0		3.7		Other investing activities	1.0		4.3
Net cash used in investing activities	Net cash used in investing activities	(155.4)		(250.7)		Net cash used in investing activities	(59.2)		(19.2)
Cash flows from financing activities:	Cash flows from financing activities:					Cash flows from financing activities:
Proceeds from borrowings	Proceeds from borrowings	829.5		690.0		Proceeds from borrowings	500.0		200.0
Repayments on borrowings	Repayments on borrowings	(1,034.5)		(776.0)		Repayments on borrowings	(550.0)		(300.0)

Distribution to members		(140.4)		(186.2)
Distributions to members						Distributions to members	(56.4)		(47.1)
Distributions to non-controlling interests	Distributions to non-controlling interests	(88.2)		(84.2)		Distributions to non-controlling interests	(34.6)		(26.0)
Redemption of Series B Preferred Units						Redemption of Series B Preferred Units	(50.5)		—
Contributions by non-controlling interests	Contributions by non-controlling interests	2.4		52.2		Contributions by non-controlling interests	7.3		0.9
Common unit repurchases	Common unit repurchases	(14.5)		—		Common unit repurchases	(17.0)		—
Other financing activities	Other financing activities	(1.6)		(4.6)		Other financing activities	(4.8)		(1.2)
Net cash used in financing activities	Net cash used in financing activities	(447.3)		(308.8)		Net cash used in financing activities	(206.0)		(173.4)
Net increase (decrease) in cash and cash equivalents		(3.5)		1.5
Net increase in cash and cash equivalents						Net increase in cash and cash equivalents	42.5		33.2
Cash and cash equivalents, beginning of period	Cash and cash equivalents, beginning of period	39.6		77.4		Cash and cash equivalents, beginning of period	26.2		39.6
Cash and cash equivalents, end of period	Cash and cash equivalents, end of period	$	36.1	$	78.9	Cash and cash equivalents, end of period	$	68.7	$	72.8

Supplemental disclosures of cash flow information:	Supplemental disclosures of cash flow information:					Supplemental disclosures of cash flow information:
Cash paid for interest	Cash paid for interest	$	130.1	$	125.7	Cash paid for interest	$	29.4	$	17.2
Cash paid (refunded) for income taxes		$	0.2	$	(0.1)

Non-cash investing activities:	Non-cash investing activities:					Non-cash investing activities:
Non-cash accrual of property and equipment	Non-cash accrual of property and equipment	$	5.1	$	(27.2)	Non-cash accrual of property and equipment	$	(0.2)	$	(2.7)
Non-cash acquisitions		$	16.9	$	—

Right-of-use assets obtained in exchange for operating lease liabilities	Right-of-use assets obtained in exchange for operating lease liabilities	$	10.7	$	9.1	Right-of-use assets obtained in exchange for operating lease liabilities	$	8.5	$	10.2
Non-cash financing activities:
Redemption of non-controlling interest		$	—	$	(4.0)

See accompanying notes to consolidated financial statements.

Table of Contents

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements

~~September 30, 2021~~March 31, 2022

(Unaudited)

(1) General

In this report, the terms “Company” or “Registrant,” as well as the terms “ENLC,” “our,” “we,” “us,” or like terms, are sometimes used as abbreviated references to EnLink Midstream, LLC itself or EnLink Midstream, LLC together with its consolidated subsidiaries, including ENLK and its consolidated subsidiaries. References in this report to “EnLink Midstream Partners, LP,” the “Partnership,” “ENLK,” or like terms refer to EnLink Midstream Partners, LP itself or EnLink Midstream Partners, LP together with its consolidated subsidiaries, including the Operating Partnership.

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

ENLC is a Delaware limited liability company formed in October 2013. The Company’s common units are traded on the New York Stock Exchange under the symbol “ENLC.” ENLC owns all of ENLK’s common units and also owns all of the membership interests of the General Partner. The General Partner manages ENLK’s operations and activities.

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 midstream energy asset network includes approximately ~~12,000~~12,100 miles of pipelines, 2322 natural gas processing plants with approximately 5.5 Bcf/d of processing capacity, 7 fractionators with approximately ~~290,000~~320,000 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. Our operations are based in the United States, and our sales are derived primarily from domestic customers.

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.

Table of Contents

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

Across our businesses, we primarily earn our fees through various fee-based contractual arrangements, which include stated fee-only contract arrangements or arrangements with fee-based components where we purchase and resell commodities in connection with providing the related service and earn a net margin as our fee. We earn our net margin under our purchase and resell contract arrangements primarily as a result of stated service-related fees that are deducted from the price of the commodities purchased. While our transactions vary in form, the essential element of most of our transactions is the use of our assets to transport a product or provide a processed product to an end-user or marketer at the tailgate of the plant, pipeline, or barge, truck, or rail terminal.

c.~~COVID-19 Update~~

On March 11, 2020, the World Health Organization declared the ongoing coronavirus (COVID-19) outbreak a pandemic and recommended containment and mitigation measures worldwide. There remains considerable uncertainty regarding how long the COVID-19 pandemic (including variants of the virus) will persist and affect economic conditions and the extent and duration of changes in consumer behavior.

(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, ~~2020.~~2021 filed with the Commission on February 16, 2022. 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 members’ equity or net ~~income (loss).~~income. All significant intercompany balances and transactions have been eliminated in consolidation.

b.Revenue Recognition

The following table summarizes the contractually committed fees (in millions) 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. Under these agreements, our customers or suppliers agree to transport or process a minimum volume of commodities on our system over an agreed period. If a customer or supplier fails to meet the minimum volume specified in such agreement, the customer or supplier is obligated to pay a contractually determined fee based upon the shortfall between actual volumes and the contractually stated volumes. 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. We record revenue under MVC and firm transportation contracts during periods of shortfall when it is known that the customer cannot, or will not, make up the deficiency. These fees do not represent the shortfall amounts we expect to collect under our MVC and firm transportation contracts, as we generally do not expect volume shortfalls to equal the full amount of the contractual MVCs and firm transportation contracts during these periods.

Contractually Committed Fees Commitments (1)
2021 (remaining) $ 38.9
2022 136.3
2023 123.5
2024 107.6
2025 63.7
Thereafter 347.3
Total $ 817.3

~~____________________________~~

~~(1)Amounts do not represent expected shortfall under these commitments.~~

~~Table of Contents~~

~~ENLINK MIDSTREAM, LLC AND SUBSIDIARIES~~

~~Notes to Consolidated Financial Statements (Continued)~~

~~(Unaudited)~~

c.~~Acquisition of Business~~

On April 30, 2021, we completed the acquisition of Amarillo Rattler, LLC, the owner of a gathering and processing system located in the Midland Basin. In connection with the purchase, we entered into an amended and restated gas gathering and processing agreement with Diamondback Energy, strengthening our dedicated acreage position with Diamondback Energy. We acquired the system with an upfront payment of $50.0 million, which was paid with cash-on-hand, with an additional $10 million to be paid on April 30, 2022, and contingent consideration capped at $15 million and payable between 2024 and 2026 based on Diamondback Energy’s drilling activity above historical levels.

Under the acquisition method of accounting, the acquired assets of Amarillo Rattler, LLC have been recorded at their respective fair values as of the date of the acquisition. Determining the fair value of the assets of Amarillo Ratter, LLC requires judgment and certain assumptions to be made, particularly related to the valuation of acquired customer relationships. The inputs and assumptions related to the customer relationships are categorized as level 3 in the fair value hierarchy. On a historical pro forma basis, our consolidated revenues, net income (loss), total assets, and earnings per unit amounts would not have differed materially had the acquisition been completed on January 1, 2021 rather than April 30, 2021. The following table presents the fair value of the identified assets received and liabilities assumed at the acquisition date (in millions):


~~Consideration~~
~~Cash (including working capital payment)~~	$	~~50.6~~
~~Installment payable~~	~~10.0~~
~~Contingent consideration fair value (1)~~	~~6.9~~
~~Total consideration:~~	$	~~67.5~~

~~Purchase price allocation~~
~~Assets acquired:~~
~~Current assets (including $1.3 million in cash)~~	$	~~1.4~~
~~Property and equipment~~	~~16.3~~
~~Intangible assets~~	~~50.6~~
~~Other assets, net (2)~~	~~0.6~~
~~Liabilities assumed:~~
~~Current liabilities~~	~~(0.8)~~
~~Other long-term liabilities (2)~~	~~(0.6)~~
~~Net assets acquired~~	$	~~67.5~~

~~____________________________~~

~~(1)The estimated fair value of the Amarillo Rattler, LLC contingent consideration was calculated in accordance with the fair value guidance contained in ASC 820,~~ ~~Fair Value Measurements. There are a number of assumptions and estimates factored into these fair values and actual contingent consideration payments could differ from the estimated fair values.~~

~~(2)~~“Other assets, net” and “Other long-term liabilities” consist of the right-of-use asset and lease liability, respectively, recorded from a lease obtained through the acquisition of Amarillo Rattler, LLC.


Contractually Committed Fees	Commitments
2022 (remaining)	$	110.3
2023	132.0
2024	112.0
2025	65.1
2026	57.9
Thereafter	289.7
Total	$	767.0

(3) Intangible 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 ranged from 10 to 20 years at the time the intangible assets were originally recorded. The weighted average amortization period for intangible assets is 14.9 years.

1312

Table of Contents

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

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


		Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount			Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount
Nine Months Ended September 30, 2021
Three Months Ended March 31, 2022								Three Months Ended March 31, 2022
Customer relationships, beginning of period	Customer relationships, beginning of period	$	1,794.2	$	(668.8)	$	1,125.4	Customer relationships, beginning of period	$	1,844.8	$	(795.1)	$	1,049.7
Customer relationships obtained from acquisition of business		50.6		—		50.6
Amortization expense	Amortization expense	—		(94.4)		(94.4)		Amortization expense	—		(32.8)		(32.8)

Customer relationships, end of period	Customer relationships, end of period	$	1,844.8	$	(763.2)	$	1,081.6	Customer relationships, end of period	$	1,844.8	$	(827.9)	$	1,016.9

~~The weighted average amortization period for intangible assets is 14.9 years.~~ Amortization expense was ~~$31.9~~$32.8 million and $30.9 million for the three months ended ~~September 30,~~March 31, 2022 and 2021, ~~and 2020, respectively, and $94.4 million and $92.7 million for the nine months ended September 30, 2021 and 2020,~~ respectively.

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


2021 (remaining)		$	31.9
2022		127.6
2022 (remaining)				2022 (remaining)	$	95.6
2023	2023	127.6		2023	127.6
2024	2024	127.6		2024	127.6
2025	2025	110.3		2025	110.2
2026				2026	106.3
Thereafter	Thereafter	556.6		Thereafter	449.6

Total	Total	$	1,081.6	Total	$	1,016.9

(4) Related Party Transactions

(a) Transactions with Cedar Cove ~~JV.~~ JV

For the three ~~and nine~~ months ended ~~September 30,~~March 31, 2022 and 2021, we recorded cost of sales of ~~$4.9~~$10.6 million and ~~$11.7 million, respectively, and for the three and nine months ended September 30, 2020, we recorded cost of sales of $2.0 million and $6.2~~$3.2 million, respectively, related to our purchase of residue gas and NGLs from the Cedar Cove JV subsequent to processing at our Central Oklahoma processing facilities. Additionally, we had accounts payable balances related to transactions with the Cedar Cove JV of ~~$1.9~~$5.8 million and ~~$1.0~~$1.6 million at ~~September 30, 2021~~March 31, 2022 and December 31, ~~2020,~~2021, respectively.

(b) Transactions with GIP

~~Transactions with GIP~~General and Administrative Expenses. . For the ~~nine~~three months ended ~~September 30,~~March 31, 2021, we recorded general and administrative expenses of ~~$0.2~~$0.1 million related to personnel secondment services provided by GIP. We did not record any expenses related to transactions with GIP for the three months ended ~~September 30, 2021. For each~~March 31, 2022.

GIP Repurchase Agreement. On February 15, 2022, we and GIP entered into an agreement pursuant to which we are repurchasing, on a quarterly basis, a pro rata portion of the ~~three~~ENLC common units held by GIP, based upon the number of common units purchased by us during the applicable quarter from public unitholders under our common unit repurchase program. The number of ENLC common units held by GIP that we repurchase in any quarter is calculated such that GIP’s then-existing economic ownership percentage of our outstanding common units is maintained after our repurchases of common units from public unitholders are taken into account, and ~~nine months ended September 30, 2020,~~the per unit price we ~~recorded general and administrative expenses of $0.2 million related~~pay to ~~personnel secondment services provided~~GIP is the average per unit price paid by ~~GIP.~~us for the common units repurchased from public unitholders. See “Note 8—Members’ Equity” for additional information on the activity relating to the GIP repurchase agreement.

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

1413

Table of Contents

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

(5) Long-Term Debt

As of ~~September 30, 2021~~March 31, 2022 and December 31, ~~2020,~~2021, long-term debt consisted of the following (in millions):


		September 30, 2021						December 31, 2020							March 31, 2022						December 31, 2021
		Outstanding Principal		Premium (Discount)		Long-Term Debt		Outstanding Principal		Premium (Discount)		Long-Term Debt			Outstanding Principal		Premium (Discount)		Long-Term Debt		Outstanding Principal		Premium (Discount)		Long-Term Debt
Term Loan due 2021 (1)		$	150.0	$	—	$	150.0	$	350.0	$	—	$	350.0

Consolidated Credit Facility due 2024(1)	Consolidated Credit Facility due 2024(1)	—		—		—		—		—		—		Consolidated Credit Facility due 2024(1)	$	—	$	—	$	—	$	15.0	$	—	$	15.0
AR Facility due 2024 (2)	AR Facility due 2024 (2)	245.0		—		245.0		250.0		—		250.0		AR Facility due 2024 (2)	315.0		—		315.0		350.0		—		350.0
ENLK’s 4.40% Senior unsecured notes due 2024	ENLK’s 4.40% Senior unsecured notes due 2024	521.8		0.8		522.6		521.8		1.1		522.9		ENLK’s 4.40% Senior unsecured notes due 2024	521.8		0.6		522.4		521.8		0.7		522.5
ENLK’s 4.15% Senior unsecured notes due 2025	ENLK’s 4.15% Senior unsecured notes due 2025	720.8		(0.4)		720.4		720.8		(0.6)		720.2		ENLK’s 4.15% Senior unsecured notes due 2025	720.8		(0.4)		720.4		720.8		(0.4)		720.4
ENLK’s 4.85% Senior unsecured notes due 2026	ENLK’s 4.85% Senior unsecured notes due 2026	491.0		(0.3)		490.7		491.0		(0.4)		490.6		ENLK’s 4.85% Senior unsecured notes due 2026	491.0		(0.3)		490.7		491.0		(0.3)		490.7
ENLC’s 5.625% Senior unsecured notes due 2028	ENLC’s 5.625% Senior unsecured notes due 2028	500.0		—		500.0		500.0		—		500.0		ENLC’s 5.625% Senior unsecured notes due 2028	500.0		—		500.0		500.0		—		500.0
ENLC’s 5.375% Senior unsecured notes due 2029	ENLC’s 5.375% Senior unsecured notes due 2029	498.7		—		498.7		498.7		—		498.7		ENLC’s 5.375% Senior unsecured notes due 2029	498.7		—		498.7		498.7		—		498.7
ENLK’s 5.60% Senior unsecured notes due 2044	ENLK’s 5.60% Senior unsecured notes due 2044	350.0		(0.2)		349.8		350.0		(0.2)		349.8		ENLK’s 5.60% Senior unsecured notes due 2044	350.0		(0.2)		349.8		350.0		(0.2)		349.8
ENLK’s 5.05% Senior unsecured notes due 2045	ENLK’s 5.05% Senior unsecured notes due 2045	450.0		(5.6)		444.4		450.0		(5.7)		444.3		ENLK’s 5.05% Senior unsecured notes due 2045	450.0		(5.4)		444.6		450.0		(5.5)		444.5
ENLK’s 5.45% Senior unsecured notes due 2047	ENLK’s 5.45% Senior unsecured notes due 2047	500.0		(0.1)		499.9		500.0		(0.1)		499.9		ENLK’s 5.45% Senior unsecured notes due 2047	500.0		(0.1)		499.9		500.0		(0.1)		499.9
Debt classified as long-term	Debt classified as long-term	$	4,427.3	$	(5.8)	4,421.5		$	4,632.3	$	(5.9)	4,626.4		Debt classified as long-term	$	4,347.3	$	(5.8)	4,341.5		$	4,397.3	$	(5.8)	4,391.5
Debt issuance costs (3)						(28.9)						(32.6)
Less: Current maturities of long-term debt (1)						(150.0)						(349.8)
Debt issuance cost (3)														Debt issuance cost (3)					(26.5)						(27.8)

Long-term debt, net of unamortized issuance cost	Long-term debt, net of unamortized issuance cost					$	4,242.6					$	4,244.0	Long-term debt, net of unamortized issuance cost					$	4,315.0					$	4,363.7

____________________________

(1)Bears interest based on Prime and/or LIBOR plus an applicable margin. The effective interest rate was ~~1.6% and 1.7%~~3.9% at ~~September 30, 2021 and~~ December 31, ~~2020, respectively. The Term Loan will mature on December 10,~~ 2021. Therefore, the outstanding principal balance, net of debt issuance costs, is classified as “Current maturities of long-term debt” on the consolidated balance sheet as of September 30, 2021 and December 31, 2020, respectively.

(2)Bears interest based on LMIR and/or LIBOR plus an applicable margin. The effective interest rate was 1.5% and 1.2% ~~and 2.0%~~ at ~~September 30, 2021~~March 31, 2022 and December 31, ~~2020,~~2021, respectively.

(3)Net of accumulated amortization of ~~$17.5~~$19.7 million and ~~$14.1~~$18.4 million at ~~September 30, 2021~~March 31, 2022 and December 31, ~~2020,~~2021, respectively.

~~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. In May 2021 and September 2021, we repaid $100.0 million and $100.0 million, respectively, of the borrowings under the Term Loan due December 2021. The outstanding balance of the Term Loan was $150.0 million as of September 30, 2021. The obligations under the Term Loan are unsecured.

Under the terms of the Term Loan, if we consummate one or more acquisitions in which the aggregate purchase price is $50.0 million or more, we 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. In April 2021, we completed the acquisition of Amarillo Rattler, LLC with an aggregate purchase price in excess of $50.0 million and elected to increase the maximum allowed ratio of consolidated indebtedness to consolidated EBITDA to 5.5 to 1.0 through its maturity date. At September 30, 2021, we were in compliance with and expect to be in compliance with the financial covenants of the Term Loan until the Term Loan matures on December 10, 2021.

~~Table of Contents~~

~~ENLINK MIDSTREAM, LLC AND SUBSIDIARIES~~

~~Notes to Consolidated Financial Statements (Continued)~~

~~(Unaudited)~~

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’s obligations under the Consolidated Credit Facility are accelerated due to a default, ENLK will be liable for the entire outstanding balance and 105% of the outstanding letters of credit under the Consolidated Credit Facility. There were no outstanding borrowings under the Consolidated Credit Facility and ~~$41.1~~$44.3 million outstanding letters of credit as of ~~September 30, 2021.~~March 31, 2022.

Under the terms of the Consolidated Credit Facility, if we consummate one or more acquisitions in which the aggregate purchase price is $50.0 million or more, we 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. In April 2021, we completed the acquisition of Amarillo Rattler, LLC with an aggregate purchase price in excess of $50.0 million and elected to increase the maximum allowed ratio of consolidated indebtedness to consolidated EBITDA to 5.5 to 1.0 through the first quarter of 2022. At ~~September 30, 2021,~~March 31, 2022, we were in compliance with and expect to be in compliance with the financial covenants of the Consolidated Credit Facility for at least the next twelve months.

AR Facility

On October 21, 2020, EnLink Midstream Funding, LLC, a bankruptcy-remote special purpose entity that is an indirect subsidiary of ENLC (the “SPV”) entered into the AR Facility to borrow up to $250.0 million. In connection with the AR Facility, certain subsidiaries of ENLC sold and contributed, and will continue to sell or contribute, their accounts receivable to the SPV to be held as collateral for borrowings under the AR Facility. ~~The SPV’s assets are not available to satisfy the obligations of ENLC or any of its affiliates.~~

On February 26, 2021, the SPV entered into the first amendment to the AR Facility that, among other things: (i) increased the AR Facility limit and lender commitments by $50.0 million to $300.0 million, (ii) reduced the Adjusted LIBOR and LMIR (each as defined in the AR Facility) minimum floor to zero, rather than the previous 0.375%, and (iii) reduced the effective drawn fee to 1.25% rather than the previous 1.625%.

On September 24, 2021, the SPV entered into the second amendment to the AR Facility that, among other things: (i) increased the AR Facility and lender commitments by $50.0 million to $350.0 million, (ii) extended the scheduled termination date of the facility from October 20, 2023 to September 24, 2024, and (iii) reduced the effective drawn fee to 1.10% rather than the previous 1.25%.

~~Since our investment in the SPV is not sufficient to finance its activities without additional support from us, the SPV is a variable interest entity.~~ We are the primary beneficiary of the SPV ~~because we have the power to direct the activities that most significantly affect its economic performance~~ and ~~we are obligated to absorb its losses or receive its benefits from operations. Since we are the primary beneficiary of the SPV,~~ we consolidate its assets and liabilities, which consist primarily of billed and unbilled accounts receivable of ~~$708.1 million and long-term debt of $245.0 million as of September 30, 2021.~~

The amount available for borrowings at any one time under the AR Facility is limited to a borrowing base amount calculated based on the outstanding balance of eligible receivables held as collateral, subject to certain reserves, concentration limits, and other limitations.$882.6 million. As of ~~September 30, 2021,~~March 31, 2022, the AR Facility had a borrowing base of $350.0 ~~million. Borrowings~~million and there were $315.0 million in outstanding borrowings under the AR Facility bear interest (based on LIBOR or LMIR (as defined in the AR Facility)) plus a drawn fee in the amount of 1.10% at September 30, 2021. The SPV also pays a fee on the undrawn committed amount of the AR Facility. ~~Interest and fees payable by the SPV under the AR Facility are due monthly.~~

The AR Facility is scheduled to terminate on September 24, 2024, unless extended or earlier terminated in accordance with its terms, at which time no further advances will be available and the obligations under the AR Facility must be 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 AR Facility become due and payable.

The AR Facility includes covenants, indemnification provisions, and events of default, including those providing for termination of the AR Facility and the acceleration of amounts owed by the SPV under the AR Facility if, among other things, a borrowing base deficiency exists, there is an event of default under the Consolidated Credit Facility, the Term Loan or certain other indebtedness, certain events negatively affecting the overall credit quality of the receivables held as collateral occur, a

~~Table of Contents~~

~~ENLINK MIDSTREAM, LLC AND SUBSIDIARIES~~

~~Notes to Consolidated Financial Statements (Continued)~~

~~(Unaudited)~~

~~change of control occurs, or if the consolidated leverage ratio of ENLC exceeds limits identical to those in the Consolidated Credit Facility and the Term Loan.~~

At ~~September 30, 2021,~~March 31, 2022, we were in compliance with and expect to be in compliance with the financial covenants of the AR Facility for at least the next twelve months.

Table of Contents

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

(6) Income Taxes

The components of our income tax ~~benefit (expense)~~expense are as follows (in millions):
Three Months Ended
September 30, Nine Months Ended
September 30,
2021 2020 2021 2020
Current income tax expense $ (0.1) $ (0.4) $ (0.2) $ (1.1)
Deferred income tax benefit (expense) (4.3) (5.6) (12.2) 17.1
Income tax benefit (expense) $ (4.4) $ (6.0) $ (12.4) $ 16.0


	Three Months Ended March 31,
	2022		2021
Current income tax expense	$	(0.2)	$	(0.1)
Deferred income tax expense	(3.0)		(1.3)
Income tax expense	$	(3.2)	$	(1.4)

The following schedule reconciles ~~total~~ income tax ~~benefit (expense)~~expense and the amount calculated by applying the statutory U.S. federal tax rate to income ~~(loss)~~ before non-controlling interest and income taxes (in millions):


		Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended March 31,
		2021		2020		2021		2020			2022		2021
Expected income tax benefit (expense) based on federal statutory rate	Expected income tax benefit (expense) based on federal statutory rate	$	(2.0)	$	(3.6)	$	4.2	$	60.0	Expected income tax benefit (expense) based on federal statutory rate	$	(8.1)	$	2.4
State income tax benefit (expense), net of federal benefit	State income tax benefit (expense), net of federal benefit	(0.3)		(0.6)		0.5		6.4		State income tax benefit (expense), net of federal benefit	(1.1)		0.2
Unit-based compensation (1)	Unit-based compensation (1)	(0.2)		(1.6)		(3.1)		(6.0)		Unit-based compensation (1)	(2.0)		(2.5)
Non-deductible expense related to goodwill impairment		—		—		—		(43.4)

Change in valuation allowance	Change in valuation allowance	(1.6)		—		(3.8)		—		Change in valuation allowance	7.1		(1.2)
Oklahoma statutory rate change (2)		—		—		(7.6)		—
Other	Other	(0.3)		(0.2)		(2.6)		(1.0)		Other	0.9		(0.3)
Income tax benefit (expense)		$	(4.4)	$	(6.0)	$	(12.4)	$	16.0
Income tax expense										Income tax expense	$	(3.2)	$	(1.4)

____________________________

(1)Related to book-to-tax differences recorded upon the vesting of restricted incentive units.

~~(2)~~Oklahoma House Bill 2960 resulted in a change in the corporate income tax rate from 6% to 4%, effective January 1, 2022. Accordingly, we recorded deferred tax expense in the amount of $7.6 million for the nine months ended September 30, 2021 due to a remeasurement of deferred tax assets.

Deferred Tax Assets and Liabilities

Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. The deferred tax liabilities, net of deferred tax assets, are included in “Deferred tax liability, net” in the consolidated balance sheets. As of ~~September 30, 2021,~~March 31, 2022, we had ~~$124.2~~$140.5 million of deferred tax liabilities, net of ~~$484.1~~$484.8 million of deferred tax assets, which included a ~~$157.1~~$144.5 million valuation allowance. As of December 31, ~~2020,~~2021, we had ~~$108.6~~$137.5 million of deferred tax liabilities, net of ~~$396.0~~$481.6 million of deferred tax assets, which included a ~~$153.3~~$151.6 million valuation allowance.

A valuation allowance is established to reduce deferred tax assets if all, or some portion, of such assets will more than likely not be realized. We have established a valuation allowance ~~of $153.3 million as of December 31, 2020,~~ primarily related to federal and state tax operating loss carryforwards for which we do not believe a tax benefit is more likely than not to be realized. ~~For the three and nine months ended September 30, 2021, we recorded a $1.6 million and $3.8 million valuation allowance adjustment, respectively.~~ As of ~~September 30, 2021,~~March 31, 2022, management believes it is more likely than not that the Company will realize the benefits of the deferred tax assets, net of valuation allowance.

1715

Table of Contents

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

(7) Certain Provisions of the ENLK Partnership Agreement

a.Series B Preferred Units

As of ~~September 30, 2021~~March 31, 2022 and December 31, ~~2020,~~2021, there were ~~60,650,397~~54,168,359 and ~~60,197,784~~57,501,693 Series B Preferred Units issued and outstanding, respectively.

~~On August 4, 2021, Enfield Holdings, L.P. (“Enfield”) sold all of its~~In January 2022, we redeemed 3,333,334 Series B Preferred Units ~~and~~for total consideration of $50.5 million plus accrued distributions. In addition, upon such redemption, a corresponding number of ENLC Class C Common Units ~~representing limited liability company interests in ENLC to Brookfield Infrastructure Partners and funds managed by Oaktree Capital Management, L.P. As a result~~were automatically cancelled. The redemption price represents 101% of ~~this sale,~~ the ~~right of~~preferred units’ par value. In connection with the Series B Preferred Unit redemption, we have agreed with the holders of the Series B Preferred Units ~~and Class C Common Units to designate~~that we will pay cash in lieu of making a ~~representative to~~quarterly PIK distribution through the ~~board~~distribution declared for the fourth quarter of ~~directors of the Managing Member was terminated.~~2022.

A summary of the distribution activity relating to the Series B Preferred Units during the ~~nine~~three months ended ~~September 30,~~March 31, 2022 and 2021 ~~and 2020~~ is provided below:
Declaration period Distribution paid as additional Series B Preferred Units Cash Distribution (in millions) Date paid/payable
2021
Fourth Quarter of 2020 150,494 $ 16.9 February 12, 2021
First Quarter of 2021 150,871 $ 17.0 May 14, 2021
Second Quarter of 2021 151,248 $ 17.0 August 13, 2021
Third Quarter of 2021 151,626 $ 17.1 November 12, 2021
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


Declaration period	Distribution paid as additional Series B Preferred Units	Cash Distribution (in millions)		Date paid/payable
2022
Fourth Quarter of 2021	—	$	19.2	February 11, 2022 (1)
First Quarter of 2022	—	$	17.5	May 13, 2022 (2)



2021
Fourth Quarter of 2020	150,494	$	16.9	February 12, 2021
First Quarter of 2021	150,871	$	17.0	May 14, 2021

____________________________

(1)In December 2021 and January 2022, we paid $0.9 million and $1.0 million, respectively, of accrued distributions on the Series B Preferred Units redeemed.

(2)In January 2022, we paid $0.3 million of accrued distributions on the Series B Preferred Units redeemed. The remaining distribution of $17.2 million related to the first quarter of 2022 is payable May 13, 2022.

b.Series C Preferred Units

As of ~~September 30, 2021~~March 31, 2022 and December 31, ~~2020,~~2021, there were 400,000 Series C Preferred Units issued and outstanding, respectively. ~~ENLK distributed $12.0 million~~There was no distribution activity related to ~~holders of~~the Series C Preferred Units during the ~~nine~~three months ended ~~September 30, 2021~~March 31, 2022 and ~~2020, respectively.~~2021.

Table of Contents

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

(8) Members’ Equity

a.Common Unit Repurchase Program

In November 2020, the board of directors of the Managing Member authorized a common unit repurchase program for the repurchase of up to $100.0 million of outstanding ENLC common units and reauthorized such program in April 2021. The Board reauthorized ENLC’s common unit repurchase program and reset the amount available for repurchases of outstanding common units at up to $100.0 million effective January 1, 2022. Repurchases under the common unit repurchase program will be made, in accordance with applicable securities laws, from time to time in open market or private transactions and may be made pursuant to a trading plan meeting the requirements of Rule 10b5-1 under the ~~Securities~~ Exchange ~~Act of 1934, as amended (the “Exchange Act”).~~Act. The repurchases will depend on market conditions and may be discontinued at any time.

For the three months ended ~~September 30, 2021,~~March 31, 2022, ENLC repurchased ~~2,076,545~~2,093,842 outstanding ENLC common units for an aggregate cost, including commissions, of ~~$12.5~~$17.0 million, or an average of ~~$6.02~~$8.12 per common unit. For the ~~nine~~three months ended ~~September 30,~~March 31, 2021, ~~ENLC repurchased 2,394,296~~we did not repurchase any outstanding ENLC common units.

b.GIP Repurchase Agreement

On May 2, 2022, we repurchased 675,095 ENLC common units held by GIP for an aggregate cost ~~including commissions,~~ of ~~$14.5~~$6.0 million, or an average of ~~$6.05~~$8.92 per common unit. These units represent GIP’s pro rata share of the aggregate number of common units repurchased by us under our common unit repurchase program during the period from February 15, 2022 (the date on which the Repurchase Agreement was signed) through March 31, 2022. The $8.92 price per common unit is the average per unit price paid by us for the common units repurchased from public unitholders during the same period.

~~Table of Contents~~

~~ENLINK MIDSTREAM, LLC AND SUBSIDIARIES~~

~~Notes to Consolidated Financial Statements (Continued)~~

~~(Unaudited)~~

b.c.Earnings Per Unit and Dilution Computations

As required under ASC 260, Earnings Per Share, unvested share-based payments that entitle employees to receive non-forfeitable distributions are considered participating securities for earnings per unit calculations. The following table reflects the computation of basic and diluted earnings per unit for the periods presented (in millions, except per unit amounts):


		Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended March 31,
		2021		2020		2021		2020			2022		2021
Distributed earnings allocated to:	Distributed earnings allocated to:									Distributed earnings allocated to:
Common units (1)	Common units (1)	$	45.8	$	45.9	$	137.7	$	137.6	Common units (1)	$	54.4	$	45.9
Unvested restricted units (1)	Unvested restricted units (1)	1.0		0.7		3.2		2.3		Unvested restricted units (1)	1.1		1.1
Total distributed earnings	Total distributed earnings	$	46.8	$	46.6	$	140.9	$	139.9	Total distributed earnings	$	55.5	$	47.0
Undistributed loss allocated to:	Undistributed loss allocated to:									Undistributed loss allocated to:
Common units	Common units	$	(43.9)	$	(33.4)	$	(169.3)	$	(403.0)	Common units	$	(19.9)	$	(58.3)
Unvested restricted units	Unvested restricted units	(1.0)		(0.6)		(4.0)		(7.0)		Unvested restricted units	(0.4)		(1.4)
Total undistributed loss	Total undistributed loss	$	(44.9)	$	(34.0)	$	(173.3)	$	(410.0)	Total undistributed loss	$	(20.3)	$	(59.7)
Net income (loss) attributable to ENLC allocated to:	Net income (loss) attributable to ENLC allocated to:									Net income (loss) attributable to ENLC allocated to:
Common units	Common units	$	1.9	$	12.5	$	(31.6)	$	(265.4)	Common units	$	34.5	$	(12.4)
Unvested restricted units	Unvested restricted units	—		0.1		(0.8)		(4.7)		Unvested restricted units	0.7		(0.3)
Total net income (loss) attributable to ENLC	Total net income (loss) attributable to ENLC	$	1.9	$	12.6	$	(32.4)	$	(270.1)	Total net income (loss) attributable to ENLC	$	35.2	$	(12.7)
Basic and diluted total net income (loss) attributable to ENLC per unit:
Net income (loss) attributable to ENLC per unit:										Net income (loss) attributable to ENLC per unit:
Basic	Basic	$	—	$	0.03	$	(0.07)	$	(0.55)	Basic	$	0.07	$	(0.03)
Diluted	Diluted	$	—	$	0.03	$	(0.07)	$	(0.55)	Diluted	$	0.07	$	(0.03)

____________________________

(1)Represents distribution activity consistent with the distribution activity ~~described in “Distributions~~”table below.

Table of Contents

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

The following are the unit amounts used to compute the basic and diluted earnings per unit for the periods presented (in millions):


		Three Months Ended September 30,		Nine Months Ended September 30,			Three Months Ended March 31,
		2021	2020	2021	2020		2022	2021
Basic weighted average units outstanding:	Basic weighted average units outstanding:					Basic weighted average units outstanding:
Weighted average common units outstanding	Weighted average common units outstanding	488.6	489.7	489.6	489.2	Weighted average common units outstanding	484.0	490.0

Diluted weighted average units outstanding:	Diluted weighted average units outstanding:					Diluted weighted average units outstanding:
Weighted average basic common units outstanding	Weighted average basic common units outstanding	488.6	489.7	489.6	489.2	Weighted average basic common units outstanding	484.0	490.0
Dilutive effect of non-vested restricted units (1)	Dilutive effect of non-vested restricted units (1)	6.2	1.2	—	—	Dilutive effect of non-vested restricted units (1)	6.6	—

Total weighted average diluted common units outstanding	Total weighted average diluted common units outstanding	494.8	490.9	489.6	489.2	Total weighted average diluted common units outstanding	490.6	490.0

____________________________

(1)All common unit equivalents were antidilutive for the ~~nine~~three months ended ~~September 30,~~March 31, 2021, ~~and 2020, respectively,~~ since a net loss existed for ~~those periods.~~that period.

All outstanding units were included in the computation of diluted earnings per unit and weighted based on the number of days such units were outstanding during the period presented.

~~Table of Contents~~

~~ENLINK MIDSTREAM, LLC AND SUBSIDIARIES~~

~~Notes to Consolidated Financial Statements (Continued)~~

~~(Unaudited)~~

c.d.Distributions

A summary of our distribution activity related to the ENLC common units for the ~~nine~~three months ended ~~September 30,~~March 31, 2022 and 2021, ~~and 2020,~~ respectively, is provided below:

Declaration period

Distribution/unit

Date paid/payable

2022

Fourth Quarter of 2021

0.11250

February 11, 2022

First Quarter of 2022

0.11250

May 13, 2022

2021

Fourth Quarter of 2020

0.09375

February 12, 2021

First Quarter of 2021

0.09375

May 14, 2021

~~Second Quarter of 2021~~

~~0.09375~~

~~August 13, 2021~~

~~Third Quarter of 2021~~

~~0.09375~~

~~November 12, 2021~~

~~2020~~

~~Fourth Quarter of 2019~~

~~0.1875~~

~~February 13, 2020~~

~~First Quarter of 2020~~

~~0.09375~~

~~May 13, 2020~~

~~Second Quarter of 2020~~

~~0.09375~~

~~August 13, 2020~~

~~Third Quarter of 2020~~

~~0.09375~~

~~November 13, 2020~~

~~(9) Investment in Unconsolidated Affiliates~~

As of September 30, 2021, 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,
2021 2020 2021 2020
GCF
Distributions $ — $ — $ 3.5 $ 1.6
Equity in income (loss) $ (1.7) $ 0.4 $ (8.1) $ 2.5
Cedar Cove JV
Distributions $ 0.1 $ — $ 0.3 $ 0.4
Equity in loss $ (0.6) $ (0.6) $ (1.8) $ (1.7)
Total
Distributions $ 0.1 $ — $ 3.8 $ 2.0
Equity in income (loss) $ (2.3) $ (0.2) $ (9.9) $ 0.8

~~The following table shows the balances related to our investment in unconsolidated affiliates as of September 30, 2021 and December 31, 2020 (in millions):~~
September 30, 2021 December 31, 2020
GCF $ 29.0 $ 40.6
Cedar Cove JV (1) (1.1) 1.0
Total investment in unconsolidated affiliates $ 27.9 $ 41.6

~~____________________________~~

~~(1)As of September 30, 2021, our investment in the Cedar Cove JV is classified as “Other long-term liabilities” on the consolidated balance sheet.~~

2018

Table of Contents

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

~~(10)~~(9) Employee Incentive Plans

a.Long-Term Incentive Plans

We account for unit-based compensation in accordance with ASC 718,~~Compensation—Stock Compensation~~, 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 the General Partner is recorded by ENLK since ENLC has no substantial or managed operating activities other than its interests in ENLK.

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


		Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended March 31,
		2021		2020		2021		2020			2022		2021
Cost of unit-based compensation charged to operating expense	Cost of unit-based compensation charged to operating expense	$	1.5	$	2.0	$	4.9	$	6.2	Cost of unit-based compensation charged to operating expense	$	1.6	$	1.7
Cost of unit-based compensation charged to general and administrative expense	Cost of unit-based compensation charged to general and administrative expense	4.9		6.4		14.4		18.4		Cost of unit-based compensation charged to general and administrative expense	5.0		4.8
Total unit-based compensation expense	Total unit-based compensation expense	$	6.4	$	8.4	$	19.3	$	24.6	Total unit-based compensation expense	$	6.6	$	6.5
Amount of related income tax benefit recognized in net income (loss) (1)		$	1.5	$	2.0	$	4.5	$	5.8
Amount of related income tax benefit recognized in net income (1)										Amount of related income tax benefit recognized in net income (1)	$	1.6	$	1.5

____________________________

(1)For the three ~~and nine~~ months ended ~~September 30,~~March 31, 2022 and 2021, the amount of related income tax benefit recognized in net income excluded ~~$0.2~~$2.0 million and ~~$3.1~~$2.5 million, respectively, of income tax expense respectively, related to book-to-tax differences recorded upon the vesting of restricted units. For the three and nine months ended September 30, 2020, the amount of related income tax benefit recognized in net income (loss) excluded $1.6 million and $6.0 million of income tax expense, respectively, related to book-to-tax differences recorded upon the vesting of restricted units.

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~~three months ended ~~September 30, 2021~~March 31, 2022 is provided below:


		Nine Months Ended September 30, 2021					Three Months Ended March 31, 2022
ENLC Restricted Incentive Units:	ENLC Restricted Incentive Units:	Number of Units		Weighted Average Grant-Date Fair Value		ENLC Restricted Incentive Units:	Number of Units		Weighted Average Grant-Date Fair Value
Non-vested, beginning of period	Non-vested, beginning of period	5,350,086		$	8.45	Non-vested, beginning of period	7,507,471		$	5.46
Granted (1)	Granted (1)	3,926,541		3.85		Granted (1)	1,761,711		8.87
Vested (1)(2)	Vested (1)(2)	(1,234,251)		13.01		Vested (1)(2)	(1,032,738)		10.35
Forfeited	Forfeited	(478,554)		6.11		Forfeited	(2,022)		3.71
Non-vested, end of period	Non-vested, end of period	7,563,822		$	5.47	Non-vested, end of period	8,234,422		$	5.58
Aggregate intrinsic value, end of period (in millions)	Aggregate intrinsic value, end of period (in millions)	$	51.6			Aggregate intrinsic value, end of period (in millions)	$	79.5

____________________________

(1)Restricted incentive units typically vest at the end of three years. In March 2022, ENLC granted 193,935 restricted incentive units with a fair value of $1.7 million. These restricted incentives units vested immediately and are included in the restricted incentive units granted and vested line items.

(2)Vested units included ~~369,817~~278,866 units withheld for payroll taxes paid on behalf of employees.

~~Table of Contents~~

~~ENLINK MIDSTREAM, LLC AND SUBSIDIARIES~~

~~Notes to Consolidated Financial Statements (Continued)~~

~~(Unaudited)~~

A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2022 and 2021 ~~and 2020~~ is provided below (in millions):


		Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended March 31,
ENLC Restricted Incentive Units:	ENLC Restricted Incentive Units:	2021		2020		2021		2020		ENLC Restricted Incentive Units:	2022		2021
Aggregate intrinsic value of units vested	Aggregate intrinsic value of units vested	$	1.5	$	1.0	$	5.4	$	11.9	Aggregate intrinsic value of units vested	$	7.6	$	3.0
Fair value of units vested	Fair value of units vested	$	3.6	$	6.0	$	16.1	$	31.0	Fair value of units vested	$	10.7	$	10.2

Table of Contents

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

As of ~~September 30, 2021,~~March 31, 2022, there were ~~$17.7~~$24.5 million of unrecognized compensation costs that related to non-vested ENLC restricted incentive units. These costs are expected to be recognized over a weighted-average period of ~~1.6~~2.0 years.

c.ENLC Performance Units

ENLC grants performance awards under the 2014 Plan. The performance award agreements provide that the vesting of performance units (i.e., performance-based restricted incentive units) granted thereunder is dependent on the achievement of certain performance goals over the applicable performance period. At the end of the vesting period, recipients receive distribution equivalents, if any, with respect to the number of performance units vested. The vesting of such units ranges from zero to 200% of the units granted depending on the extent to which the related performance goals are achieved over the relevant performance period.

The following table presents a summary of the performance units:


		Nine Months Ended September 30, 2021					Three Months Ended March 31, 2022
ENLC Performance Units:	ENLC Performance Units:	Number of Units		Weighted Average Grant-Date Fair Value		ENLC Performance Units:	Number of Units		Weighted Average Grant-Date Fair Value
Non-vested, beginning of period	Non-vested, beginning of period	2,351,241		$	8.82	Non-vested, beginning of period	3,574,827		$	6.40
Granted	Granted	1,388,139		4.70		Granted	598,286		11.45
Vested (1)	Vested (1)	(164,553)		26.73		Vested (1)	(708,361)		15.57

Non-vested, end of period	Non-vested, end of period	3,574,827		$	6.40	Non-vested, end of period	3,464,752		$	5.40
Aggregate intrinsic value, end of period (in millions)	Aggregate intrinsic value, end of period (in millions)	$	24.4			Aggregate intrinsic value, end of period (in millions)	$	33.4

____________________________

(1)Vested units included ~~63,901~~273,357 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 ~~nine~~three months ended ~~September 30,~~March 31, 2022 and 2021 ~~and 2020~~ is provided below (in millions). ~~No performance units vested for the three months ended September 30, 2021 and 2020.~~

Nine Months Ended
September 30,
ENLC Performance Units: 2021 2020
Aggregate intrinsic value of units vested $ 0.6 $ 0.9
Fair value of units vested $ 4.4 $ 5.5


	Three Months Ended March 31,
ENLC Performance Units:		2022		2021
Aggregate intrinsic value of units vested		$	5.6	$	0.6
Fair value of units vested		$	11.0	$	4.4

As of ~~September 30, 2021,~~March 31, 2022, there were ~~$9.7~~$15.5 million of unrecognized compensation costs that related to non-vested ENLC performance units. These costs are expected to be recognized over a weighted-average period of ~~1.7~~1.9 years.

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


ENLC Performance Units:	March 2022 (1)			January 2021
Grant-date fair value	$	11.90		$	4.70
Beginning TSR price	$	8.83		$	3.71
Risk-free interest rate	2.15		%	0.17		%
Volatility factor	75.00		%	71.00		%

____________________________

(1)Excludes ENLC performance units awarded March 1, 2022 with vesting conditions based on performance metrics. The 88,863 ENLC performance units have a grant-date fair value of $8.90 and will vest in February 2023.

Table of Contents

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

~~The following table presents a summary of the grant-date fair value assumptions by performance unit grant date:~~
ENLC Performance Units: January 2021 July 2020 March 2020 January 2020
Grant-date fair value $ 4.70 $ 2.33 $ 1.13 $ 7.69
Beginning TSR price $ 3.71 $ 2.52 $ 1.25 $ 6.13
Risk-free interest rate 0.17 % 0.17 % 0.42 % 1.62 %
Volatility factor 71.00 % 67.00 % 51.00 % 37.00 %

~~(11)~~(10) Derivatives

Interest Rate Swaps

In April 2019, we entered into $850.0 million of interest rate swaps 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.

In connection with the partial repayments of the Term Loan in September 2021, May 2021, and December 2020, we paid $0.5 million to terminate $100.0 million of the interest rate swaps, $1.3 million to terminate $100.0 million of the interest rate swaps, and $10.9 million to terminate $500.0 million of the interest rate swaps, respectively, for an aggregate termination of $700.0 million of the $850.0 million interest rate swaps and an aggregate settlement of $12.7 million of the outstanding derivative liability. The unrealized loss remains in accumulated other comprehensive income (loss) and will amortize into “Interest expense” on the consolidated statements of operations until the original maturity date of the Term Loan. For the three and nine months ended September 30, 2021, we amortized $3.5 million and $9.5 million, respectively, into interest expense out of accumulated other comprehensive income (loss) related to the partial terminations of the interest rate swaps. The remaining $150.0 million interest rate swaps were re-designated as a cash flow hedge on LIBOR-based borrowings and continue to be effective.

The components of the unrealized 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,
2021 2020 2021 2020
Change in fair value of interest rate swaps $ 5.0 $ 4.7 $ 14.5 $ (10.4)
Tax benefit (expense) (1.2) (1.1) (3.4) 2.4
Unrealized gain (loss) on designated cash flow hedge $ 3.8 $ 3.6 $ 11.1 $ (8.0)


	Three Months Ended March 31,
	2022		2021
Change in fair value of interest rate swaps	$	0.1	$	4.7
Tax expense	—		(1.1)
Unrealized gain on designated cash flow hedge	$	0.1	$	3.6

The interest expense, recognized from accumulated other comprehensive loss from the monthly settlement of our interest rate swaps and amortization of the termination payments, included in our consolidated statements of operations were as follows (in millions):
Three Months Ended
September 30, Nine Months Ended
September 30,
2021 2020 2021 2020
Interest expense $ 5.0 $ 4.6 $ 14.6 $ 9.6


	Three Months Ended March 31,
	2022		2021
Interest expense	$	0.1	$	4.8

We expect to recognize an additional ~~$3.7~~$0.1 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, 2021 December 31, 2020
Fair value of derivative liabilities—current $ (0.7) $ (7.6)

~~Table of Contents~~

~~ENLINK MIDSTREAM, LLC AND SUBSIDIARIES~~

~~Notes to Consolidated Financial Statements (Continued)~~

~~(Unaudited)~~

Commodity Swaps

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


		Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended March 31,
		2021		2020		2021		2020			2022		2021
Change in fair value of derivatives	Change in fair value of derivatives	$	(1.2)	$	(2.2)	$	(32.9)	$	(8.0)	Change in fair value of derivatives	$	(15.1)	$	(7.9)
Realized loss on derivatives	Realized loss on derivatives	(32.4)		(2.9)		(122.3)		(0.3)		Realized loss on derivatives	(16.1)		(75.5)
Loss on derivative activity	Loss on derivative activity	$	(33.6)	$	(5.1)	$	(155.2)	$	(8.3)	Loss on derivative activity	$	(31.2)	$	(83.4)

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


		September 30, 2021		December 31, 2020			March 31, 2022		December 31, 2021
Fair value of derivative assets—current	Fair value of derivative assets—current	$	75.3	$	25.0	Fair value of derivative assets—current	$	68.1	$	22.4
Fair value of derivative assets—long-term	Fair value of derivative assets—long-term	2.2		4.9		Fair value of derivative assets—long-term	0.1		0.2
Fair value of derivative liabilities—current	Fair value of derivative liabilities—current	(110.2)		(29.5)		Fair value of derivative liabilities—current	(97.2)		(34.9)
Fair value of derivative liabilities—long-term	Fair value of derivative liabilities—long-term	(2.3)		(2.5)		Fair value of derivative liabilities—long-term	(0.6)		(2.2)
Net fair value of commodity swaps	Net fair value of commodity swaps	$	(35.0)	$	(2.1)	Net fair value of commodity swaps	$	(29.6)	$	(14.5)

Table of Contents

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

Set forth below are the summarized notional volumes and fair values of all instruments related to commodity swaps that we held for price risk management purposes and the related physical offsets at ~~September 30, 2021~~March 31, 2022 (in millions). The remaining term of the contracts extend no later than ~~January~~July 2023.

September 30, 2021

March 31, 2022

Commodity

Instruments

Unit

Volume

Net Fair Value

Commodity

Instruments

Unit

Volume

Net Fair Value

NGL (short contracts)

Swaps

Gallons

(169.3)

(56.3)

NGL (short contracts)

Swaps

Gals

(181.4)

(29.7)

NGL (long contracts)

Swaps

Gallons

7.8

1.4

Natural gas (short contracts)

Swaps

MMbtu

(9.8)

(17.6)

Natural gas (short contracts)

Swaps

MMbtu

(3.7)

(3.9)

Natural gas (long contracts)

Swaps

MMbtu

14.2

25.0

Natural gas (long contracts)

Swaps

MMbtu

2.8

2.9

Crude and condensate (short contracts)

Swaps

MMbbls

(7.8)

(32.7)

Crude and condensate (short contracts)

Swaps

MMbbls

(4.7)

(59.3)

Crude and condensate (long contracts)

Swaps

MMbbls

3.8

45.2

Crude and condensate (long contracts)

Swaps

MMbbls

4.0

60.4

Total fair value of commodity swaps

(35.0)

Total fair value of commodity swaps

(29.6)

On all transactions where we are exposed to counterparty risk, we analyze the counterparty’s financial condition prior to entering into an agreement, establish limits, and monitor the appropriateness of these limits on an ongoing basis. We primarily deal with financial institutions when entering into financial derivatives on commodities. We have entered into Master ISDAs that allow for netting of swap contract receivables and payables in the event of default by either party. If our counterparties failed to perform under existing commodity swap contracts, the maximum loss on our gross receivable position of ~~$77.5~~$68.2 million as of ~~September 30, 2021~~March 31, 2022 would be reduced to ~~zero~~$0.7 million due to the offsetting of gross fair value payables against gross fair value receivables as allowed by the ISDAs.

2422

Table of Contents

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

~~(12)~~(11) Fair Value Measurements

Assets and liabilities measured at fair value on a recurring basis are summarized below (in millions):
Level 2
September 30, 2021 December 31, 2020
Interest rate swaps (1) $ (0.7) $ (7.6)
Commodity swaps (2) $ (35.0) $ (2.1)


	Level 2
	March 31, 2022		December 31, 2021

Commodity swaps (1)	$	(29.6)	$	(14.5)

____________________________

(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 Measurement~~.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, 2021				December 31, 2020					March 31, 2022				December 31, 2021
		Carrying Value		Fair Value		Carrying Value		Fair Value			Carrying Value		Fair Value		Carrying Value		Fair Value
Long-term debt (1)	Long-term debt (1)	$	4,392.6	$	4,466.7	$	4,593.8	$	4,318.2	Long-term debt (1)	$	4,315.0	$	4,154.6	$	4,363.7	$	4,520.0
Installment payable (2)	Installment payable (2)	$	10.0	$	10.0	$	—	$	—	Installment payable (2)	$	10.0	$	10.0	$	10.0	$	10.0
Contingent consideration (2)	Contingent consideration (2)	$	6.9	$	6.9	$	—	$	—	Contingent consideration (2)	$	6.9	$	6.9	$	6.9	$	6.9

____________________________

(1)The carrying value of long-term debt ~~includes current maturities and~~ is reduced by debt issuance ~~costs~~cost, net of ~~$28.9~~accumulated amortization, of $26.5 million and ~~$32.6~~$27.8 million as of ~~September 30, 2021~~March 31, 2022 and December 31, ~~2020,~~2021, respectively. The respective fair values do not factor in debt issuance costs.

(2)Consideration paid for the acquisition of Amarillo Rattler, LLC included ~~$10~~a $10.0 million ~~to be~~installment payable, which was paid on April 30, 2022, and a contingent consideration capped at ~~$15~~$15.0 million and payable between 2024 and 2026 based on Diamondback ~~Energy’s~~E&P LLC’s drilling activity above historical levels. Estimated fair values were calculated using a discounted cash flow analysis that utilized Level 3 inputs. ~~For additional information regarding this transaction, refer to “Note 2—Significant Accounting Policies.”~~

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

The fair values of all senior unsecured notes as of ~~September 30, 2021~~March 31, 2022 and December 31, ~~2020~~2021 were based on Level 2 inputs from third-party market quotations.

2523

Table of Contents

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

~~(13)~~(12) Segment Information

~~Starting in the first quarter of 2021, we began evaluating~~We evaluate the financial performance of our segments by including realized and unrealized gains and losses resulting from commodity swaps activity in the Permian, Louisiana, Oklahoma, and North Texas segments. Commodity swaps activity was previously reported in the Corporate segment. We have recast segment information for all presented periods prior to the first quarter of 2021 to conform to current period presentation. Identification of the majority of our operating segments is based principally upon geographic regions served:

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

•Louisiana Segment. The Louisiana segment includes our natural gas and NGL pipelines, natural gas processing plants, natural gas and NGL storage facilities, and fractionation facilities 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

•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, and our ~~general~~ corporate assets and expenses.

2624

Table of Contents

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

We evaluate the performance of our operating segments based on segment profit and adjusted gross margin. Adjusted gross margin is a non-GAAP financial measure. Summarized financial information for our reportable segments is shown in the following tables (in millions):


		Permian		Louisiana		Oklahoma		North Texas		Corporate		Totals			Permian		Louisiana		Oklahoma		North Texas		Corporate		Totals
Three Months Ended September 30, 2021
Three Months Ended March 31, 2022														Three Months Ended March 31, 2022
Natural gas sales	Natural gas sales	$	159.3	$	183.2	$	58.2	$	32.2	$	—	$	432.9	Natural gas sales	$	195.6	$	211.5	$	76.3	$	25.4	$	—	$	508.8
NGL sales	NGL sales	0.4		898.6		0.3		(0.1)		—		899.2		NGL sales	—		1,151.5		3.1		(0.1)		—		1,154.5
Crude oil and condensate sales	Crude oil and condensate sales	194.4		62.5		21.2		—		—		278.1		Crude oil and condensate sales	272.0		73.9		34.7		—		—		380.6

Product sales	Product sales	354.1		1,144.3		79.7		32.1		—		1,610.2		Product sales	467.6		1,436.9		114.1		25.3		—		2,043.9

NGL sales—related parties	NGL sales—related parties	301.4		39.5		180.2		131.2		(652.3)		—		NGL sales—related parties	399.8		36.9		208.1		146.9		(791.7)		—
Crude oil and condensate sales—related parties	Crude oil and condensate sales—related parties	—		—		—		1.5		(1.5)		—		Crude oil and condensate sales—related parties	—		—		0.3		3.0		(3.3)		—
Product sales—related parties	Product sales—related parties	301.4		39.5		180.2		132.7		(653.8)		—		Product sales—related parties	399.8		36.9		208.4		149.9		(795.0)		—
Gathering and transportation	Gathering and transportation	12.8		16.3		44.6		39.0		—		112.7		Gathering and transportation	13.6		16.3		42.7		38.8		—		111.4
Processing	Processing	7.5		0.9		26.5		27.0		—		61.9		Processing	7.8		0.5		25.4		27.6		—		61.3
NGL services	NGL services	—		16.9		—		—		—		16.9		NGL services	—		23.9		—		—		—		23.9
Crude services	Crude services	5.5		10.3		2.8		0.1		—		18.7		Crude services	4.3		9.4		3.7		0.2		—		17.6
Other services	Other services	0.2		0.4		0.1		0.1		—		0.8		Other services	0.2		0.4		0.1		0.1		—		0.8
Midstream services	Midstream services	26.0		44.8		74.0		66.2		—		211.0		Midstream services	25.9		50.5		71.9		66.7		—		215.0

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

Other services—related parties	Other services—related parties	—		0.1		—		—		(0.1)		—		Other services—related parties	—		0.1		—		—		(0.1)		—
Midstream services—related parties	Midstream services—related parties	—		0.1		0.1		—		(0.2)		—		Midstream services—related parties	—		0.1		—		—		(0.1)		—
Revenue from contracts with customers	Revenue from contracts with customers	681.5		1,228.7		334.0		231.0		(654.0)		1,821.2		Revenue from contracts with customers	893.3		1,524.4		394.4		241.9		(795.1)		2,258.9
Cost of sales, exclusive of operating expenses and depreciation and amortization (1)	Cost of sales, exclusive of operating expenses and depreciation and amortization (1)	(576.6)		(1,110.8)		(218.0)		(149.4)		654.0		(1,400.8)		Cost of sales, exclusive of operating expenses and depreciation and amortization (1)	(766.7)		(1,388.7)		(276.8)		(157.4)		795.1		(1,794.5)
Realized loss on derivatives	Realized loss on derivatives	(8.7)		(14.9)		(6.8)		(2.0)		—		(32.4)		Realized loss on derivatives	(2.4)		(6.6)		(3.7)		(3.4)		—		(16.1)
Change in fair value of derivatives	Change in fair value of derivatives	10.2		(8.8)		(2.3)		(0.3)		—		(1.2)		Change in fair value of derivatives	(5.9)		(5.6)		(7.1)		3.5		—		(15.1)
Adjusted gross margin	Adjusted gross margin	106.4		94.2		106.9		79.3		—		386.8		Adjusted gross margin	118.3		123.5		106.8		84.6		—		433.2
Operating expenses	Operating expenses	(37.3)		(30.5)		(19.8)		(19.3)		—		(106.9)		Operating expenses	(45.3)		(33.0)		(21.0)		(21.6)		—		(120.9)
Segment profit	Segment profit	69.1		63.7		87.1		60.0		—		279.9		Segment profit	73.0		90.5		85.8		63.0		—		312.3
Depreciation and amortization	Depreciation and amortization	(35.4)		(34.6)		(52.3)		(28.5)		(2.2)		(153.0)		Depreciation and amortization	(36.7)		(35.5)		(50.9)		(28.4)		(1.4)		(152.9)

Gain on disposition of assets		0.1		0.2		—		0.1		—		0.4
Gain (loss) on disposition of assets														Gain (loss) on disposition of assets	—		0.2		0.2		(5.5)		—		(5.1)
General and administrative	General and administrative	—		—		—		—		(28.2)		(28.2)		General and administrative	—		—		—		—		(29.0)		(29.0)
Interest expense, net of interest income	Interest expense, net of interest income	—		—		—		—		(60.1)		(60.1)		Interest expense, net of interest income	—		—		—		—		(55.1)		(55.1)

Loss from unconsolidated affiliates		—		—		—		—		(2.3)		(2.3)

Loss from unconsolidated affiliate investments														Loss from unconsolidated affiliate investments	—		—		—		—		(1.1)		(1.1)
Other income														Other income	—		—		—		—		0.1		0.1
Income (loss) before non-controlling interest and income taxes	Income (loss) before non-controlling interest and income taxes	$	33.8	$	29.3	$	34.8	$	31.6	$	(92.8)	$	36.7	Income (loss) before non-controlling interest and income taxes	$	36.3	$	55.2	$	35.1	$	29.1	$	(86.5)	$	69.2
Capital expenditures	Capital expenditures	$	25.8	$	0.4	$	10.3	$	3.3	$	0.6	$	40.4	Capital expenditures	$	34.2	$	5.7	$	15.4	$	3.1	$	1.6	$	60.0

____________________________

(1)Includes related party cost of sales of ~~$4.9~~$10.6 million for the three months ended ~~September 30, 2021 and excludes all operating expenses as well as depreciation and amortization related to our operating segments of $150.8 million for the three months ended September 30, 2021.~~March 31, 2022.

2725

Table of Contents

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)


		Permian		Louisiana		Oklahoma		North Texas		Corporate		Totals			Permian		Louisiana		Oklahoma		North Texas		Corporate		Totals
Three Months Ended September 30, 2020
Three Months Ended March 31, 2021														Three Months Ended March 31, 2021
Natural gas sales	Natural gas sales	$	46.5	$	76.4	$	40.1	$	16.0	$	—	$	179.0	Natural gas sales	$	125.0	$	121.2	$	35.9	$	51.0	$	—	$	333.1
NGL sales	NGL sales	0.1		402.3		1.2		—		—		403.6		NGL sales	—		626.0		0.6		1.2		—		627.8
Crude oil and condensate sales	Crude oil and condensate sales	82.6		21.7		9.2		—		—		113.5		Crude oil and condensate sales	107.3		41.1		13.6		—		—		162.0

Product sales	Product sales	129.2		500.4		50.5		16.0		—		696.1		Product sales	232.3		788.3		50.1		52.2		—		1,122.9

NGL sales—related parties	NGL sales—related parties	95.6		3.3		85.4		21.4		(205.7)		—		NGL sales—related parties	164.9		23.6		113.1		80.9		(382.5)		—
Crude oil and condensate sales—related parties	Crude oil and condensate sales—related parties	—		—		—		0.7		(0.7)		—		Crude oil and condensate sales—related parties	—		—		—		1.5		(1.5)		—
Product sales—related parties	Product sales—related parties	95.6		3.3		85.4		22.1		(206.4)		—		Product sales—related parties	164.9		23.6		113.1		82.4		(384.0)		—
Gathering and transportation	Gathering and transportation	17.9		10.7		56.7		43.4		—		128.7		Gathering and transportation	9.7		15.8		51.3		40.4		—		117.2
Processing	Processing	8.0		0.3		32.4		33.3		—		74.0		Processing	8.2		0.5		15.9		27.1		—		51.7
NGL services	NGL services	—		14.2		—		—		—		14.2		NGL services	—		22.0		—		0.1		—		22.1
Crude services	Crude services	3.8		12.2		3.7		—		—		19.7		Crude services	3.5		9.9		3.3		0.2		—		16.9
Other services	Other services	0.2		0.4		0.1		0.2		—		0.9		Other services	0.2		0.5		0.2		0.1		—		1.0
Midstream services	Midstream services	29.9		37.8		92.9		76.9		—		237.5		Midstream services	21.6		48.7		70.7		67.9		—		208.9

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

Other services—related parties														Other services—related parties	—		2.3		—		—		(2.3)		—
Midstream services—related parties	Midstream services—related parties	—		—		0.1		—		(0.1)		—		Midstream services—related parties	—		2.3		0.1		—		(2.4)		—
Revenue from contracts with customers	Revenue from contracts with customers	254.7		541.5		228.9		115.0		(206.5)		933.6		Revenue from contracts with customers	418.8		862.9		234.0		202.5		(386.4)		1,331.8
Cost of sales, exclusive of operating expenses and depreciation and amortization (1)	Cost of sales, exclusive of operating expenses and depreciation and amortization (1)	(185.4)		(441.4)		(101.0)		(28.2)		206.5		(549.5)		Cost of sales, exclusive of operating expenses and depreciation and amortization (1)	(325.6)		(740.4)		(151.0)		(104.1)		386.4		(934.7)
Realized loss on derivatives	Realized loss on derivatives	(0.4)		(0.6)		(1.7)		(0.2)		—		(2.9)		Realized loss on derivatives	(56.9)		(10.7)		(6.0)		(1.9)		—		(75.5)
Change in fair value of derivatives	Change in fair value of derivatives	0.9		(2.7)		(0.3)		(0.1)		—		(2.2)		Change in fair value of derivatives	(5.3)		(0.4)		(1.8)		(0.4)		—		(7.9)
Adjusted gross margin	Adjusted gross margin	69.8		96.8		125.9		86.5		—		379.0		Adjusted gross margin	31.0		111.4		75.2		96.1		—		313.7
Operating expenses	Operating expenses	(22.9)		(31.1)		(20.1)		(20.2)		—		(94.3)		Operating expenses	11.8		(29.2)		(19.7)		(19.2)		—		(56.3)
Segment profit	Segment profit	46.9		65.7		105.8		66.3		—		284.7		Segment profit	42.8		82.2		55.5		76.9		—		257.4
Depreciation and amortization	Depreciation and amortization	(31.9)		(36.9)		(53.0)		(36.8)		(1.7)		(160.3)		Depreciation and amortization	(33.5)		(36.1)		(50.7)		(28.7)		(2.0)		(151.0)

Gain on disposition of assets		—		—		—		1.8		—		1.8
Gain (loss) on disposition of assets														Gain (loss) on disposition of assets	0.1		(0.1)		—		—		—		—
General and administrative	General and administrative	—		—		—		—		(25.7)		(25.7)		General and administrative	—		—		—		—		(26.0)		(26.0)
Interest expense, net of interest income	Interest expense, net of interest income	—		—		—		—		(55.5)		(55.5)		Interest expense, net of interest income	—		—		—		—		(60.0)		(60.0)

Loss from unconsolidated affiliates		—		—		—		—		(0.2)		(0.2)
Other income		—		—		—		—		0.4		0.4
Loss from unconsolidated affiliate investments														Loss from unconsolidated affiliate investments	—		—		—		—		(6.3)		(6.3)
Other loss														Other loss	—		—		—		—		(0.1)		(0.1)
Income (loss) before non-controlling interest and income taxes	Income (loss) before non-controlling interest and income taxes	$	15.0	$	28.8	$	52.8	$	31.3	$	(82.7)	$	45.2	Income (loss) before non-controlling interest and income taxes	$	9.4	$	46.0	$	4.8	$	48.2	$	(94.4)	$	14.0

Capital expenditures	Capital expenditures	$	28.5	$	8.5	$	2.6	$	3.0	$	0.6	$	43.2	Capital expenditures	$	13.3	$	2.8	$	1.9	$	2.4	$	0.4	$	20.8

____________________________

(1)Includes related party cost of sales of ~~$2.0~~$3.2 million for the three months ended ~~September 30, 2020 and excludes all operating expenses as well as depreciation and amortization related to our operating segments of $158.6 million for the three months ended September 30, 2020.~~March 31, 2021.

~~Table of Contents~~

~~ENLINK MIDSTREAM, LLC AND SUBSIDIARIES~~

~~Notes to Consolidated Financial Statements (Continued)~~

~~(Unaudited)~~

Permian Louisiana Oklahoma North Texas Corporate Totals
Nine Months Ended September 30, 2021
Natural gas sales $ 381.7 $ 426.4 $ 139.7 $ 109.4 $ — $ 1,057.2
NGL sales 0.9 2,231.2 1.3 1.0 — 2,234.4
Crude oil and condensate sales 472.1 154.5 50.5 — — 677.1
Product sales 854.7 2,812.1 191.5 110.4 — 3,968.7
NGL sales—related parties 661.8 93.3 430.4 306.4 (1,491.9) —
Crude oil and condensate sales—related parties — — 0.1 5.1 (5.2) —
Product sales—related parties 661.8 93.3 430.5 311.5 (1,497.1) —
Gathering and transportation 34.3 48.5 141.8 117.6 — 342.2
Processing 21.7 1.9 70.5 81.1 — 175.2
NGL services — 56.0 — 0.2 — 56.2
Crude services 13.0 29.8 9.5 0.5 — 52.8
Other services 0.6 1.3 0.5 0.4 — 2.8
Midstream services 69.6 137.5 222.3 199.8 — 629.2
Crude services—related parties — — 0.2 — (0.2) —
Other services—related parties — 2.4 — — (2.4) —
Midstream services—related parties — 2.4 0.2 — (2.6) —
Revenue from contracts with customers 1,586.1 3,045.3 844.5 621.7 (1,499.7) 4,597.9
Cost of sales, exclusive of operating expenses and depreciation and amortization (1) (1,304.5) (2,690.1) (533.9) (361.8) 1,499.7 (3,390.6)
Realized loss on derivatives (69.8) (32.0) (15.7) (4.8) — (122.3)
Change in fair value of derivatives (3.0) (18.6) (9.4) (1.9) — (32.9)
Adjusted gross margin 208.8 304.6 285.5 253.2 — 1,052.1
Operating expenses (52.9) (91.4) (57.3) (58.4) — (260.0)
Segment profit 155.9 213.2 228.2 194.8 — 792.1
Depreciation and amortization (103.5) (106.8) (153.6) (86.0) (6.0) (455.9)
Gain on disposition of assets 0.2 0.3 — 0.2 — 0.7
General and administrative — — — — (80.3) (80.3)
Interest expense, net of interest income — — — — (180.1) (180.1)
Loss from unconsolidated affiliates — — — — (9.9) (9.9)
Other income — — — — 0.1 0.1
Income (loss) before non-controlling interest and income taxes $ 52.6 $ 106.7 $ 74.6 $ 109.0 $ (276.2) $ 66.7
Capital expenditures $ 78.6 $ 5.4 $ 17.1 $ 7.6 $ 1.1 $ 109.8

~~____________________________~~

~~(1)~~Includes related party cost of sales of $11.7 million for the nine months ended September 30, 2021 and excludes all operating expenses as well as depreciation and amortization related to our operating segments of $449.9 million for the nine months ended September 30, 2021.

~~Table of Contents~~

~~ENLINK MIDSTREAM, LLC AND SUBSIDIARIES~~

~~Notes to Consolidated Financial Statements (Continued)~~

~~(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 — 1060.3
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, exclusive of operating expenses and depreciation and amortization (1) (637.7) (1,213.6) (255.8) (74.1) 478.7 (1,702.5)
Realized gain (loss) on derivatives (0.6) 1.9 (1.7) 0.1 — (0.3)
Change in fair value of derivatives 2.3 (7.8) (2.4) (0.1) — (8.0)
Adjusted gross margin 195.0 295.2 368.8 268.0 — 1,127.0
Operating expenses (71.1) (90.4) (62.4) (59.2) — (283.1)
Segment profit 123.9 204.8 306.4 208.8 — 843.9
Depreciation and amortization (92.1) (109.3) (163.7) (110.4) (5.8) (481.3)
Impairments (184.6) (169.9) — — — (354.5)
Gain (loss) on disposition of assets (4.9) 0.1 0.1 1.9 — (2.8)
General and administrative — — — — (79.6) (79.6)
Interest expense, net of interest income — — — — (166.3) (166.3)
Gain on extinguishment of debt — — — — 32.0 32.0
Income from unconsolidated affiliates — — — — 0.8 0.8
Other income — — — — 0.4 0.4
Income (loss) before non-controlling interest and income taxes $ (157.7) $ (74.3) $ 142.8 $ 100.3 $ (218.5) $ (207.4)
Capital expenditures $ 161.4 $ 39.3 $ 14.1 $ 10.7 $ 1.7 $ 227.2

~~____________________________~~

~~(1)~~Includes related party cost of sales of $6.2 million for the nine months ended September 30, 2020 and excludes all operating expenses as well as depreciation and amortization related to our operating segments of $475.5 million for the nine months ended September 30, 2020.

3026

Table of Contents

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

The table below represents information about segment assets as of ~~September 30, 2021~~March 31, 2022 and December 31, ~~2020~~2021 (in millions):
Segment Identifiable Assets: September 30, 2021 December 31, 2020
Permian $ 2,391.2 $ 2,236.3
Louisiana 2,489.4 2,312.4
Oklahoma 2,661.5 2,847.6
North Texas 938.0 1,008.6
Corporate (1) 146.4 146.0
Total identifiable assets $ 8,626.5 $ 8,550.9


Segment Identifiable Assets:	March 31, 2022		December 31, 2021
Permian	$	2,500.2	$	2,358.6
Louisiana	2,442.9		2,428.6
Oklahoma	2,582.9		2,619.5
North Texas	866.8		896.8
Corporate (1)	247.4		179.7
Total identifiable assets	$	8,640.2	$	8,483.2

____________________________

(1)Accounts receivable and accrued revenue sold to the SPV for collateral under the AR Facility are included within the Permian, Louisiana, Oklahoma, and North Texas segments.

~~(14)~~(13) Other Information

The following tables present additional detail for other current assets and other current liabilities, which consists of the following (in millions):


Other current assets:	Other current assets:	September 30, 2021		December 31, 2020		Other current assets:	March 31, 2022		December 31, 2021
Natural gas and NGLs inventory	Natural gas and NGLs inventory	$	116.6	$	44.9	Natural gas and NGLs inventory	$	73.6	$	49.4
Prepaid expenses and other	Prepaid expenses and other	39.6		13.8		Prepaid expenses and other	39.1		34.2
Other current assets	Other current assets	$	156.2	$	58.7	Other current assets	$	112.7	$	83.6

Other current liabilities: September 30, 2021 December 31, 2020
Accrued interest $ 71.7 $ 35.7
Accrued wages and benefits, including taxes 26.0 22.5
Accrued ad valorem taxes 32.4 26.5
Capital expenditure accruals 15.0 10.6
Short-term lease liability 15.8 16.3
Operating expense accruals 11.7 8.4
Other 43.3 29.1
Other current liabilities $ 215.9 $ 149.1


Other current liabilities:	March 31, 2022		December 31, 2021
Accrued interest	$	71.5	$	47.2
Accrued wages and benefits, including taxes	9.6		33.1
Accrued ad valorem taxes	12.6		28.3
Capital expenditure accruals	22.2		23.2
Deferred revenue	24.1		3.7
Short-term lease liability	20.3		18.1
Installment payable (1)	10.0		10.0
Inactive easement commitment (2)	9.9		9.8
Operating expense accruals	11.7		9.6
Other	23.5		19.9
Other current liabilities	$	215.4	$	202.9

____________________________

(1)Consideration paid for the acquisition of Amarillo Rattler, LLC included an installment payable, which was paid on April 30, 2022.

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

~~(15)~~(14) Commitments and Contingencies

In February 2021, the areas in which we operate experienced a severe winter storm, with extreme cold, ice, and snow occurring over an unprecedented period of approximately 10 days (“Winter Storm Uri”). As a result of Winter Storm Uri, we have ~~several pending~~encountered customer billing disputes related to the delivery of gas during the storm, including one that ~~has~~ resulted in litigation. The litigation is between one of our subsidiaries, EnLink Gas Marketing, LP (“EnLink Gas”), and Koch Energy Services, LLC (“Koch”) in the 162nd District Court in Dallas County, Texas. The dispute centers on whether EnLink Gas was excused from delivering gas or performing under certain delivery or purchase obligations during Winter Storm Uri, given our declaration of force majeure during the storm. Koch has invoiced us approximately $53.9 million (after subtracting amounts owed to EnLink Gas) and does not recognize the declaration of force majeure. We believe the declaration of force majeure was valid and appropriate and we ~~could be~~intend to vigorously defend against Koch’s claims.

Another of our subsidiaries, EnLink Energy GP, LLC, is also involved in ~~other disputes and~~ litigation arising out of Winter Storm Uri. This matter is a multi-district litigation currently pending in Harris County, Texas, in which multiple individual plaintiffs assert personal injury and property damage claims arising out of Winter Storm Uri against an aggregate of over 350 power generators,

Table of Contents

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

transmission/distribution utility, retail electric provider, and natural gas defendants across over 150 filed cases. We believe the ~~storm in the future.~~claims against our subsidiary lack merit and we intend to vigorously defend against such claims.

WeIn addition, we are involved in various litigation and administrative proceedings arising in the normal course of business. ~~We cannot currently predict the outcome of these contingencies and therefore have not accrued any costs associated with potential claims.~~ In the opinion of management, any liabilities that may result from ~~such~~these claims would not, individually or in the aggregate, have a material adverse effect on our financial position, results of operations, or cash flows.

We may also be involved from time to time in the future in various proceedings in the normal course of business, including litigation on disputes related to contracts, property rights, property use or damage (including nuisance claims), personal injury, or the value of pipeline easements or other rights obtained through the exercise of eminent domain or common carrier rights.

3128

Table of Contents

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

ENLC is a Delaware limited liability company formed in October 2013. ENLC’s ~~material~~ assets consist of all of the outstanding common units of ENLK and all of the membership interests of the General Partner. All of our midstream energy assets are owned and operated by ENLK and its subsidiaries. We primarily focus on providing midstream energy services, including:

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

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

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

Our midstream energy asset network includes approximately ~~12,000~~12,100 miles of pipelines, 2322 natural gas processing plants with approximately 5.5 Bcf/d of processing capacity, seven fractionators with approximately ~~290,000~~320,000 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.

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

We manage our consolidated operations by focusing on adjusted gross 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

~~Table of Contents~~

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. Adjusted gross margin is a non-GAAP financial measure and is explained in greater detail under “Non-GAAP Financial Measures” below. Approximately ~~88%~~90% of our

Table of Contents

adjusted gross margin was derived from fee-based contractual arrangements with minimal direct commodity price exposure for the ~~nine~~three months ended ~~September 30, 2021.~~March 31, 2022.

Our revenues and adjusted gross 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.

The following customers ~~represent a significant percentage~~individually represented greater than 10% of our consolidated revenues for the three months ended March 31, 2022 and ~~the~~2021. The loss of ~~the customer~~these customers would have a material adverse impact on our results of operations because the revenues and adjusted gross margin received from transactions with these customers is material to us. No other customers represented greater than 10% of our consolidated revenues during the periods presented.


		Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended March 31,
		2021		2020		2021		2020			2022		2021
Devon		6.9	%	14.2	%	7.1	%	14.7	%

Dow Hydrocarbons and Resources LLC	Dow Hydrocarbons and Resources LLC	14.0	%	15.2	%	14.5	%	13.2	%	Dow Hydrocarbons and Resources LLC	13.9	%	14.5	%
Marathon Petroleum Corporation	Marathon Petroleum Corporation	12.2	%	7.6	%	13.1	%	12.7	%	Marathon Petroleum Corporation	16.1	%	14.8	%

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 adjusted gross 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 adjusted gross margins from our gathering and processing services primarily through different contractual arrangements: processing margin (“margin”) contracts, POL contracts, POP contracts, fixed-fee based contracts, or a

~~Table of Contents~~

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 adjusted gross

Table of Contents

margins are higher during periods of high NGL prices relative to natural gas prices. Adjusted gross margin results under POL contracts are impacted only by the value of the liquids produced with margins higher during periods of higher liquids prices. Adjusted gross 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 adjusted gross 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.

CCS Business

We are currently developing an integrated offering to bring CCS services to businesses along the Mississippi River corridor in Louisiana, one of the highest CO2 emitting regions in the United States. We believe our existing asset footprint, including our extensive network of natural gas pipelines in Louisiana, our operating expertise and our customer relationships, provide EnLink an advantage in building a CCS business.

Recent Developments Affecting Industry Conditions and Our Business

Current Market Environment

The midstream energy business environment and our business are affected by the level of production of natural gas and oil in the areas in which we operate and the various factors that affect this production, including commodity prices, capital markets trends, competition, and regulatory changes. We believe these factors will continue to affect production and therefore the demand for midstream services and our business in the future. To the extent these factors vary from our underlying assumptions, our business and actual results could vary materially from market expectations and from the assumptions discussed in this section.

Production levels by our exploration and production customers are driven in large part by the level of oil and natural gas prices. New drilling activity is necessary to maintain or increase production levels as oil and natural gas wells experience production declines over time. New drilling activity generally moves in the same direction as crude oil and natural gas prices as those prices drive investment returns and cash flow available for reinvestment by exploration and production companies. Accordingly, our operations are affected by the level of crude, natural gas, and NGL prices, the relationship among these prices, and related activity levels from our customers.

There has been, and we believe there will continue to be, volatility in commodity prices and in the relationships among NGL, crude oil, and natural gas prices. ~~Although commodity~~Commodity markets have now fully recovered from the reduction in global demand and low market prices experienced in 2020 due to the COVID-19 ~~pandemic,~~pandemic. However, oil and natural gas prices continue to remain volatile. ~~Natural~~Oil and natural gas prices, ~~in particular,~~rose during 2021 and have risen ~~quickly during 2021, at~~very rapidly in 2022 due to various factors, including a rebound in demand from economic activity after COVID-19 shutdowns, supply issues, and geopolitical risks, including Russia’s invasion of Ukraine. As of the date of this report, ~~and~~ the market price isfor both oil and natural gas are at ~~a level~~ higher levels than iteither has traded in many years.

Capital markets and the demands of public investors also affect producer behavior, production levels, and our business. Over the last several years, public investors have exerted pressure on oil and natural gas producers to increase capital discipline and focus on higher investment returns even if it means lower growth. In addition, the ability of companies in the oil and gas industry to access the capital markets on favorable terms has been ~~somewhat~~ negatively ~~impacted.~~impacted during this same period. This demand by investors for increased capital discipline from energy companies, as well as the difficulties in accessing capital markets, ~~has~~ led to more modest capital investment by producers, curtailed drilling and production activity, and, accordingly, slower growth for us and other midstream companies during the past few years. This trend was amplified in 2020 ~~as a result of~~by the COVID-19 pandemic, which reduced demand ~~destruction. Although volumes~~for commodities. However, in response to the rise of oil and natural gas prices during 2021 and in 2022 to date, capital investments by United States oil and natural gas producers have ~~now generally recovered~~begun to ~~pre-pandemic levels,~~rise modestly, although global capital investments by oil and natural gas producers remain at relatively low levels compared to historical levels and producers continue to remain ~~cautious, even as crude oil and natural gas prices have steadily increased during 2021.~~cautious.

Producers generally focus their drilling activity on certain producing basins depending on commodity price fundamentals and favorable drilling economics. In the last few years, many producers have increasingly focused their activities in the Permian

Table of Contents

Basin, because of the availability of higher investment returns. Currently, a large percentage of all drilling rigs operating in the United States are operating in the Permian Basin. As a result of this concentration of drilling activity in the Permian Basin, other basins, including those in which we operate in Oklahoma and North Texas, have experienced reduced ~~incremental new~~ investment and declines in volumes ~~produced. In contrast, we~~produced, although that situation has begun to change as producers now see more opportunity in both Oklahoma and North Texas, given higher oil and natural gas prices. We continue to experience an increase in volumes in our Permian segment as our operations in that basin are in a favorable position relative to producer activity.

~~Table of Contents~~

Our Louisiana segment, while subject to commodity ~~prices and capital markets developments,~~price trends, is less dependent on gathering and processing activities and more affected by industrial demand for the natural gas and NGLs that we supply. Industrial demand along the Gulf Coast region has remained strong ~~from the second half of 2020~~throughout 2021 and through the first ~~three quarters~~quarter of ~~2021,~~2022, supported by regional industrial activity and export markets. Our activities and, in turn, our financial performance in the Louisiana segment are highly dependent on the availability of natural gas and NGLs produced by our upstream gathering and processing business and by other market participants. To date, the supply of natural gas and NGLs has remained at levels sufficient for us to supply our customers, and maintaining such supply is a key business focus.

For additional discussion regarding these factors, see “Item 1A—Risk Factors—Business and Industry Risks” in our Annual Report on Form 10-K for the year ended December 31, 2021 filed with the Commission on February ~~17, 2021.~~16, 2022.

~~Winter Storm Uri and Other~~Extreme Weather Events

From time to time our operations may be affected by extreme weather events such as Winter Storm Uri in February 2021. During the third quarter of 2021, we experienced a temporary loss of some processing volumes in our Louisiana operations due to the effects of Hurricane Ida, which forced a temporary shut-down of some of our operationsice storms and ~~those of our downstream customers. All of our operations and those of our customers are now operating normally.~~

hurricanes. In February 2021, ~~the~~certain areas in which we operate experienced a severe winter storm, with extreme cold, ice, and snow occurring over an unprecedented period of approximately 10 days (“Winter Storm Uri”). Winter Storm Uri adversely affected ~~the Company’s~~our facilities and activities across ~~the Company’s~~our footprint, as it did for producers and other midstream companies located in these areas. The severe cold temperatures caused production freeze-offs and also led some producers to proactively shut-in their wells to preserve well integrity. As a result, ~~the Company’s~~our gathering and processing volumes were significantly reduced during this period, with peak volume declines ranging between 44% and 92%, depending on the region. ~~The Company~~We responded to the challenges presented by the storm by taking active steps to ensure the resiliency of ~~the Company’s~~our assets and the protection of the health and well-being of ~~its~~our employees. ~~The Company’s~~Our operations and ~~its~~ gathering and processing volumes returned to normal levels by the end of the first quarter of 2021.

The lack of gathered and processed volumes during Winter Storm Uri presented a number of commercial challenges, including the management of losses on derivative contracts and firm commodity sales contracts and making outlays to meet one-time operating expenses for storm recovery. To balance these challenges, the Company was able to use its integrated asset base to make limited incremental gas available to support local markets and to use its storage volumes in Louisiana to help offset lower natural gas and NGL supplies. Additionally, because of idled operations and elevated power prices, the Company was able to earn approximately $49 million in utility credits for unused electricity which had been purchased on a firm basis. These utility credits can be used to offset future power payments. However, becauseBecause of the magnitude and unprecedented nature of ~~the storm,~~Winter Storm Uri, we cannot predict the full impact that ~~Winter Storm Uri~~the storm may have on our future results of operations. The ultimate impacts will depend on future developments, including, among other factors, the outcome of pending billing disputes or litigation with customers and regulatory actions by state legislatures and other entities responsible for the regulation and pricing of electricity and the electrical grid.

COVID-19 Update

On March 11, 2020, the World Health Organization declared the ongoing coronavirus (COVID-19) outbreak a pandemic and recommended containment and mitigation measures worldwide. 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. Beginning in March 2020, 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 also continue to promote heightened awareness and vigilance, hygiene, and implementation of more stringent cleaning protocols across~~evaluate our ~~facilities and operations and we continue to evaluate and adjust our preventative measures,~~ response plans and business practices ~~with the~~to meet any evolving impacts of ~~COVID-19. We have continued to maintain these COVID protocols since~~COVID-19 and its variants. Since the inception of the pandemic, ~~and to date~~ we have not experienced any significant COVID-19 related operational disruptions.

~~There~~Although the global impacts of COVID-19 have reduced significantly since the beginning of year, there remains considerable uncertainty regarding how long the COVID-19 pandemic (including variants of the virus) will persist and affect economic ~~conditions and the extent and duration of changes in consumer behavior.~~conditions.

We cannot predict the full impact that the COVID-19 pandemic or ~~the~~any related volatility in oil and natural gas markets ~~related to COVID-19~~ 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 pandemic, including variants of the virus, the speed at which the population is vaccinated against the virus and the efficacy of the vaccines, the ~~impact of the~~ emergence of any new variants of

~~Table of Contents~~

the virus against which vaccines are less effective, the effect of the pandemic on economic, social, and other aspects of everyday life, the consequences of governmental and other measures designed to prevent the spread of the virus, actions taken by members of OPEC+ and other foreign, oil-exporting countries, actions taken by governmental authorities, customers, suppliers, and other third parties, and the timing and extent to which normal economic, social, and operating conditionsfully resume. 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 crude 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).

Table of Contents

For additional discussion regarding risks associated with the COVID-19 pandemic, see “Item 1A—Risk Factors—The ongoing coronavirus (COVID-19) pandemic has adversely affected and could continue to adversely affect our business, financial condition, and results of operations” in our Annual Report on Form 10-K for the year ended December 31, 2021 filed with the Commission on February ~~17, 2021.~~16, 2022.

Regulatory Developments

On January 20, 2021, the Biden Administration came into office and immediately issued a number of executive orders related to climate change and the production of oil and gas that could affect our operations and those of our customers. On his first day in office, President Biden signed an instrument reentering the United States into the Paris Agreement, effective February 19, 2021, and issued an executive order on “Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis” seeking to adopt new regulations and policies to address climate change and suspend, revise, or rescind prior agency actions that are identified as conflicting with the Biden Administration’s climate policies. In addition, on January 27, 2021, President Biden issued an executive order ~~which has since been challenged,~~ indefinitely suspending new oil and natural gas leases on public lands or in offshore waters pending completion of an ongoing comprehensive review and reconsideration of federal oil and gas permitting and leasing practices. On June 15, 2021, however, a judge in the U.S. District Court for the Western District of Louisiana issued a nationwide temporary injunction blocking the suspension. The Department of the Interior appealed the U.S. District Court’s ruling but resumed oil and gas leasing pending resolution of the appeal. In November 2021, the Department of the Interior completed its review and issued a report on the federal oil and gas leasing program. The Department of the Interior’s report recommends several changes to federal leasing practices, including changes to royalty payments, bidding, and bonding requirements. On April 15, 2022, the Department of the Interior announced it would make roughly 144,000 acres of federal land available for new drilling, a significant reduction from the footprint of land that had been under evaluation for leasing. The new leases would also require companies to pay royalties of 18.75% of the value of extracted oil and gas products, up from 12.5%. Furthermore, on April 22, 2021, at a global summit on climate change, President Biden committed the United States to target emissions reductions of 50-52% of 2005 levels by 2030. Lastly, on June 30, 2021, President Biden signed into law a reinstatement of regulations put in place during the Obama administration regarding methane emissions. The Company had previously complied with these regulations during the Obama administration and does not expect the reinstatement to have a material effect on the Company or its operations. The Biden Administration could also seek, in the future, to put into place additional executive orders, policy and regulatory reviews, or seek to have Congress pass legislation that could adversely affect the production of oil and natural gas, and our operations and those of our customers.

Only a small percentage of our operations are derived from customers operating on public land, mainly in the Delaware Basin. Our operations in the Delaware Basin ~~and these activities~~ are expected to represent only approximately 4%6% of our total segment profit, net to EnLink, during ~~2021.~~2022. In addition, we have a robust program to monitor and prevent methane emissions in our operations and we maintain a comprehensive environmental program that is embedded in our operations. However, our activities that take place on public lands require that we and our producer customers obtain leases, permits, and other approvals from the federal government. While the status of recent and future rules and rulemaking initiatives under the Biden Administration remain uncertain, the regulations that might result from such initiatives, could lead to increased costs for us or our customers, difficulties in obtaining leases, permits, and other approvals for us and our customers, reduced utilization of our gathering, processing and pipeline systems or reduced rates under renegotiated transportation or storage agreements in affected regions. These impacts could, in turn, adversely affect our business, financial condition, results of operations or cash flows, including our ability to make cash distributions to our unitholders.

For more information, see our risk factors under “Environmental, Legal Compliance, and Regulatory Risk” in Section 1A “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2021 filed with the Commission on February ~~17, 2021.~~16, 2022.

Other Recent Developments

~~Bridgeport CO~~2 ~~Project.~~ We have entered into an agreement with Continental Carbonic Products, Inc., a wholly owned subsidiary of Matheson Tri-Gas, Inc., and member of the Nippon Sanso Holdings Corporation group of companies, to capture and sell CO2 ~~emitted from our Bridgeport processing plant in North Texas. The CO~~2 will be sold on a firm basis for 15 years and will be converted into food-grade products. This project is expected to be in service in early 2024. The project makes meaningful progress toward our goal of a 30% reduction in total CO2~~-equivalent emissions intensity by 2030, while being modestly profitable.~~

~~Common Unit Repurchase Program~~CCS—Talos Alliance. In ~~November 2020, the board~~February 2022, we signed a memorandum of ~~directors~~understanding with Talos Energy Inc. (“Talos”) to provide a complete CCS offering for industrial-scale emitters in Louisiana, utilizing our midstream assets combined with Talos’ subsurface assets. Talos has secured approximately 26,000 acres in Louisiana, providing sequestration capacity of ~~the Managing Member authorized a common unit repurchase program for the repurchase of up to $100.0~~over 500 million of outstanding ENLC common units and reauthorized such program in April 2021. The repurchases will be made, in accordance with applicable securities laws, from time to time in open market or private transactions and may be made pursuant to a trading plan meeting the requirements of Rule 10b5-1 under the Exchange Act. The repurchases will depend on market conditions and may be discontinued at any time.metric tonnes.

~~Table of Contents~~

For the three months ended September 30, 2021, ENLC repurchased 2,076,545 outstanding ENLC common units for an aggregate cost, including commissions, of $12.5 million, or an average of $6.02 per common unit. For the nine months ended September 30, 2021, ENLC repurchased 2,394,296 outstanding ENLC common units for an aggregate cost, including commissions, of $14.5 million, or an average of $6.05 per common unit.

~~Organic Growth~~

Phantom Processing Plant. In ~~September~~November 2021, we ~~established a plan to relocate~~began moving equipment and facilities associated with the Thunderbird processing plant ~~from~~in Central Oklahoma to the Midland Basin. This processing plant relocation is expected to increase the processing capacity of our Permian Basin processing facilities by approximately 200 MMcf/d. We expect to complete the relocation in the ~~second half~~fourth quarter of 2022.

~~Amarillo Rattler Acquisition.~~Common Unit Repurchase Program. Effective January 1, 2022, the Board reauthorized our common unit repurchase program and reset the amount available for repurchases of outstanding common units at up to $100.0 million. For the three

Table of Contents

months ended March 31, 2022, ENLC repurchased 2,093,842 outstanding ENLC common units for an aggregate cost, including commissions, of $17.0 million, or an average of $8.12 per common unit.

GIP Repurchase Agreement. On February 15, 2022, we and GIP entered into an agreement pursuant to which we are repurchasing, on a quarterly basis, a pro rata portion of the ENLC common units held by GIP, based upon the number of common units purchased by us during the applicable quarter from public unitholders under our common unit repurchase program. The number of ENLC common units held by GIP that we repurchase in any quarter is calculated such that GIP’s then-existing economic ownership percentage of our outstanding common units is maintained after our repurchases of common units from public unitholders are taken into account, and the per unit price we pay to GIP is the average per unit price paid by us for the common units repurchased from public unitholders.

On May 2, 2022, we repurchased 675,095 ENLC common units held by GIP for an aggregate cost of $6.0 million, or an average of $8.92 per common unit. These units represent GIP’s pro rata share of the aggregate number of common units repurchased by us under our common unit repurchase program during the period from February 15, 2022 (the date on which the Repurchase Agreement was signed) through March 31, 2022. The $8.92 price per common unit is the average per unit price paid by us for the common units repurchased from public unitholders during the same period. ~~On April 30,~~For more information about our repurchase agreement with GIP, see Part II, “9B. Other Information” of our Annual Report on Form 10-K for the year ended December 31, 2021 filed with the Commission on February 16, 2022.

Redemption of Series B Preferred Units. In January 2022, we ~~completed~~redeemed 3,333,334 Series B Preferred Units for total consideration of $50.5 million plus accrued distributions. In addition, upon such redemption, a corresponding number of ENLC Class C Common Units were automatically cancelled. The redemption price represents 101% of the ~~acquisition of Amarillo Rattler, LLC, the owner of a gathering and processing system located in the Midland Basin.~~preferred units’ par value. In connection with the ~~purchase,~~Series B Preferred Unit redemption, we ~~entered into an amended and restated gas gathering and processing agreement~~have agreed with ~~Diamondback Energy, strengthening our dedicated acreage position~~the holders of the Series B Preferred Units that we will pay cash in lieu of making a quarterly PIK distribution through the distribution declared for the fourth quarter of 2022. See “Item 1. Financial Statements—Note 7” for more information regarding distributions with ~~Diamondback Energy. We acquired~~respect to the system with an upfront payment of $50.0 million, which was paid with cash-on-hand, with an additional $10 million to be paid on April 30, 2022, and contingent consideration capped at $15 million and payable between 2024 and 2026 based on Diamondback Energy’s drilling activity above historical levels.Series B Preferred Units.

~~War Horse Processing Plant.~~ In December 2020, we began moving equipment and facilities previously associated with the Battle Ridge processing plant in Central Oklahoma to the Permian Basin. The War Horse processing plant began operations in the third quarterTable of ~~2021. We are currently expanding the capacity of the War Horse processing plant to approximately 95 MMcf/d, which we expect to complete in the fourth quarter of 2021.~~Contents

Non-GAAP Financial Measures

To assist management in assessing our business, we use the following non-GAAP financial measures: adjusted gross ~~margin,~~margin; adjusted earnings before interest, taxes, and depreciation and amortization (“adjusted EBITDA”); and free cash flow after distributions.

Adjusted Gross Margin

We define adjusted gross margin as revenues less cost of sales, exclusive of operating expenses and depreciation and ~~amortization related to our operating segments.~~amortization. We present adjusted gross margin by segment in “Results of Operations.” We disclose adjusted gross margin in addition to gross margin as defined by GAAP because it is the primary performance measure used by our management to evaluate consolidated operations. We believe adjusted gross 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 the 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 exclude all operating expenses and depreciation and amortization ~~related to our operating segments~~ from adjusted gross 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 adjusted gross margin is gross margin. Adjusted gross margin should not be considered an alternative to, or more meaningful than, gross margin as determined in accordance with GAAP. Adjusted gross margin has important limitations because it excludes all operating expenses and depreciation and amortization ~~related to our operating segments~~ that affect gross margin. Our adjusted gross margin may not be comparable to similarly titled measures of other companies because other entities may not calculate these amounts in the same manner.

~~Table of Contents~~

The following table reconciles total revenues and gross margin to adjusted gross margin (in millions):
Three Months Ended
September 30, Nine Months Ended
September 30,
2021 2020 2021 2020
Total revenues $ 1,787.6 $ 928.5 $ 4,442.7 $ 2,829.5
Cost of sales, exclusive of operating expenses and depreciation and amortization (1) (1,400.8) (549.5) (3,390.6) (1,702.5)
Operating expenses (106.9) (94.3) (260.0) (283.1)
Depreciation and amortization (153.0) (160.3) (455.9) (481.3)
Gross margin 126.9 124.4 336.2 362.6
Operating expenses 106.9 94.3 260.0 283.1
Depreciation and amortization 153.0 160.3 455.9 481.3
Adjusted gross margin $ 386.8 $ 379.0 $ 1,052.1 $ 1,127.0

~~____________________________~~

~~(1)~~Excludes all operating expenses as well as depreciation and amortization related to our operating segments of $150.8 million and $158.6 million for the three months ended September 30, 2021 and 2020, respectively, and $449.9 million and $475.5 million for the nine months ended September 30, 2021 and 2020, respectively.


	Three Months Ended March 31,
	2022		2021
Total revenues	$	2,227.7	$	1,248.4
Cost of sales, exclusive of operating expenses and depreciation and amortization	(1,794.5)		(934.7)
Operating expenses	(120.9)		(56.3)
Depreciation and amortization	(152.9)		(151.0)
Gross margin	159.4		106.4
Operating expenses	120.9		56.3
Depreciation and amortization	152.9		151.0
Adjusted gross margin	$	433.2	$	313.7

Table of Contents

Adjusted EBITDA

We define adjusted EBITDA as net income (loss) plus (less) interest expense, net of interest income; depreciation and amortization; impairments; (income) loss from unconsolidated affiliate investments; distributions from unconsolidated affiliate investments; (gain) loss on disposition of assets; (gain) loss on extinguishment of debt; unit-based compensation; income tax expense (benefit); unrealized (gain) loss on commodity swaps; costs associated with the relocation of processing facilities; accretion expense associated with asset retirement obligations; transaction costs; (non-cash rent); and (non-controlling interest share of adjusted EBITDA from joint ventures). Adjusted EBITDA is one of the primary metrics used in our short-term incentive program for compensating employees. In addition, adjusted EBITDA is used as a supplemental liquidity and performance measure by our management and by external users of our financial statements, such as investors, commercial banks, research analysts, and others, to assess:

•the financial performance of our assets without regard to financing methods, capital structure, or historical cost basis;

•the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness, and make cash distributions to our unitholders;

•our operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing methods or capital structure; and

•the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

The GAAP measures most directly comparable to adjusted EBITDA are net income (loss) and net cash provided by operating activities. Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income (loss), operating income (loss), net cash provided by operating activities, or any other measure of financial performance presented in accordance with GAAP. Adjusted EBITDA may not be comparable to similarly titled measures of other companies because other companies may not calculate adjusted EBITDA in the same manner.

Adjusted EBITDA does not include interest expense, net of interest income; income tax expense (benefit); and depreciation and amortization. Because we have borrowed money to finance our operations, interest expense is a necessary element of our costs and our ability to generate cash available for distribution. Because we have capital assets, depreciation and amortization are also necessary elements of our costs. Therefore, any measures that exclude these elements have material limitations. To compensate for these limitations, we believe that it is important to consider net income (loss) and net cash provided by operating activities as determined under GAAP, as well as adjusted EBITDA, to evaluate our overall performance.

3836

Table of Contents

The following table reconciles net income ~~(loss)~~ to adjusted EBITDA (in millions):


		Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended March 31,
		2021		2020		2021		2020			2022		2021
Net income (loss)		$	32.3	$	39.2	$	54.3	$	(191.4)
Net income										Net income	$	66.0	$	12.6
Interest expense, net of interest income	Interest expense, net of interest income	60.1		55.5		180.1		166.3		Interest expense, net of interest income	55.1		60.0
Depreciation and amortization	Depreciation and amortization	153.0		160.3		455.9		481.3		Depreciation and amortization	152.9		151.0
Impairments		—		—		—		354.5
(Income) loss from unconsolidated affiliates		2.3		0.2		9.9		(0.8)
Distributions from unconsolidated affiliates		0.1		—		3.8		2.0
(Gain) loss on disposition of assets		(0.4)		(1.8)		(0.7)		2.8
Gain on extinguishment of debt		—		—		—		(32.0)

Loss from unconsolidated affiliate investments										Loss from unconsolidated affiliate investments	1.1		6.3
Distributions from unconsolidated affiliate investments										Distributions from unconsolidated affiliate investments	0.2		3.6
Loss on disposition of assets										Loss on disposition of assets	5.1		—

Unit-based compensation	Unit-based compensation	6.4		8.4		19.3		24.6		Unit-based compensation	6.6		6.5
Income tax expense (benefit)		4.4		6.0		12.4		(16.0)
Income tax expense										Income tax expense	3.2		1.4
Unrealized loss on commodity swaps	Unrealized loss on commodity swaps	1.2		2.2		32.9		8.0		Unrealized loss on commodity swaps	15.1		7.9
Costs associated with the relocation of processing facilities (1)	Costs associated with the relocation of processing facilities (1)	8.8		—		26.6		—		Costs associated with the relocation of processing facilities (1)	11.3		7.6
Other (2)	Other (2)	(0.2)		(0.3)		(0.2)		(0.8)		Other (2)	0.3		(0.4)
Adjusted EBITDA before non-controlling interest	Adjusted EBITDA before non-controlling interest	268.0		269.7		794.3		798.5		Adjusted EBITDA before non-controlling interest	316.9		256.5
Non-controlling interest share of adjusted EBITDA from joint ventures (3)	Non-controlling interest share of adjusted EBITDA from joint ventures (3)	(11.6)		(8.1)		(31.0)		(21.8)		Non-controlling interest share of adjusted EBITDA from joint ventures (3)	(12.6)		(7.1)
Adjusted EBITDA, net to ENLC	Adjusted EBITDA, net to ENLC	$	256.4	$	261.6	$	763.3	$	776.7	Adjusted EBITDA, net to ENLC	$	304.3	$	249.4

____________________________

(1)Represents cost incurred that are not part of our ongoing operations related to the relocation of equipment and facilities from the Thunderbird processing plant and Battle Ridge processing plant in the Oklahoma segment to the Permian segment. The relocation of equipment and facilities from the Battle Ridge processing plant ~~in the Oklahoma segment, to the Permian segment that we~~was completed in the third quarter of 2021 and ~~is not part~~we expect to complete the relocation of ~~our ongoing operations.~~equipment and facilities from the Thunderbird processing plant in the fourth quarter of 2022.

(2)Includes accretion expense associated with asset retirement ~~obligations; transaction costs,~~obligations and non-cash rent, which relates to lease incentives pro-rated over the lease term.

(3)Non-controlling interest share of adjusted EBITDA from joint ventures includes NGP’s 49.9% share of adjusted EBITDA from the Delaware Basin JV and Marathon Petroleum Corporation’s 50% share of adjusted EBITDA from the Ascension ~~JV, and other minor non-controlling interests.~~JV.

3937

Table of Contents

Free Cash Flow After Distributions

We define free cash flow after distributions as adjusted EBITDA, net to ENLC, plus (less) (growth and maintenance capital expenditures, excluding capital expenditures that were contributed by other entities and relate to the non-controlling interest share of our consolidated entities); (interest expense, net of interest income); (distributions declared on common units); (accrued cash distributions on Series B Preferred Units and Series C Preferred Units paid or expected to be paid); (costs associated with the relocation of processing facilities); non-cash interest (income)/expense; (payments to terminate interest rate swaps); (current income taxes); and proceeds from the sale of equipment and land.

Free cash flow after distributions is the principal cash flow metric used by the ~~Company in its public reporting.~~Company. Free cash flow after distributions is one of the primary metrics used in our short-term incentive program for compensating employees. It is also used as a supplemental liquidity measure by our management and by external users of our financial statements, such as investors, commercial banks, research analysts, and others, to assess the ability of our assets to generate cash sufficient to pay interest costs, pay back our indebtedness, make cash distributions, and make capital expenditures.

Growth capital expenditures generally include capital expenditures made for acquisitions or capital improvements that we expect will increase our asset base, operating income, or operating capacity over the long-term. Examples of growth capital expenditures include the acquisition of assets and the construction or development of additional pipeline, storage, well connections, gathering, or processing assets, in each case, to the extent such capital expenditures are expected to expand our asset base, operating capacity, or our operating income.

Maintenance capital expenditures include capital expenditures made to replace partially or fully depreciated assets in order to maintain the existing operating capacity of the assets and to extend their useful lives. Examples of maintenance capital expenditures are expenditures to refurbish and replace pipelines, gathering assets, well connections, compression assets, and processing assets up to their original operating capacity, to maintain pipeline and equipment reliability, integrity, and safety, and to address environmental laws and regulations.

The GAAP measure most directly comparable to free cash flow after distributions is net cash provided by operating activities. Free cash flow after distributions should not be considered an alternative to, or more meaningful than, net income (loss), operating income (loss), net cash provided by operating activities, or any other measure of liquidity presented in accordance with GAAP. Free cash flow after distributions has important limitations because it excludes some items that affect net income (loss), operating income (loss), and net cash provided by operating activities. Free cash flow after distributions may not be comparable to similarly titled measures of other companies because other companies may not calculate this non-GAAP metric in the same manner. To compensate for these limitations, we believe that it is important to consider net cash provided by operating activities determined under GAAP, as well as free cash flow after distributions, to evaluate our overall liquidity.

4038

Table of Contents

The following table reconciles net cash provided by operating activities to adjusted EBITDA and free cash flow after distributions (in millions):


		Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended March 31,
		2021		2020		2021		2020			2022		2021
Net cash provided by operating activities	Net cash provided by operating activities	$	197.0	$	244.2	$	599.2	$	561.0	Net cash provided by operating activities	$	307.7	$	225.8
Interest expense (1)	Interest expense (1)	55.1		54.5		166.6		163.1		Interest expense (1)	53.7		55.9
Utility credits, net of usage (2)		(5.6)		—		38.2		—
Payments to terminate interest rate swaps (3)		0.5		—		1.8		—
Utility credits (redeemed) earned (2)										Utility credits (redeemed) earned (2)	(5.6)		40.4
Accruals for settled commodity swap transactions	Accruals for settled commodity swap transactions	(2.1)		0.9		(4.6)		0.7		Accruals for settled commodity swap transactions	(2.2)		0.1
Distributions from unconsolidated affiliate investment in excess of earnings	Distributions from unconsolidated affiliate investment in excess of earnings	0.1		(0.4)		3.8		0.4		Distributions from unconsolidated affiliate investment in excess of earnings	0.2		3.6
Costs associated with the relocation of processing facilities (4)		8.8		—		26.6		—
Other (5)		(0.2)		0.4		2.4		1.1
Costs associated with the relocation of processing facilities (3)										Costs associated with the relocation of processing facilities (3)	11.3		7.6
Other (4)										Other (4)	1.7		1.2
Changes in operating assets and liabilities which (provided) used cash:	Changes in operating assets and liabilities which (provided) used cash:									Changes in operating assets and liabilities which (provided) used cash:
Accounts receivable, accrued revenues, inventories, and other	Accounts receivable, accrued revenues, inventories, and other	167.6		46.5		276.8		(72.6)		Accounts receivable, accrued revenues, inventories, and other	172.7		17.5
Accounts payable, accrued product purchases, and other accrued liabilities	Accounts payable, accrued product purchases, and other accrued liabilities	(153.2)		(76.4)		(316.5)		144.8		Accounts payable, accrued product purchases, and other accrued liabilities	(222.6)		(95.6)
Adjusted EBITDA before non-controlling interest	Adjusted EBITDA before non-controlling interest	268.0		269.7		794.3		798.5		Adjusted EBITDA before non-controlling interest	316.9		256.5
Non-controlling interest share of adjusted EBITDA from joint ventures (6)		(11.6)		(8.1)		(31.0)		(21.8)
Non-controlling interest share of adjusted EBITDA from joint ventures (5)										Non-controlling interest share of adjusted EBITDA from joint ventures (5)	(12.6)		(7.1)
Adjusted EBITDA, net to ENLC	Adjusted EBITDA, net to ENLC	256.4		261.6		763.3		776.7		Adjusted EBITDA, net to ENLC	304.3		249.4
Growth capital expenditures, net to ENLC (7)		(33.2)		(32.6)		(89.1)		(165.9)
Maintenance capital expenditures, net to ENLC (7)		(6.9)		(5.0)		(19.1)		(20.9)
Growth capital expenditures, net to ENLC (6)										Growth capital expenditures, net to ENLC (6)	(40.5)		(15.9)
Maintenance capital expenditures, net to ENLC (6)										Maintenance capital expenditures, net to ENLC (6)	(13.9)		(4.7)
Interest expense, net of interest income	Interest expense, net of interest income	(60.1)		(55.5)		(180.1)		(166.3)		Interest expense, net of interest income	(55.1)		(60.0)
Distributions declared on common units	Distributions declared on common units	(46.6)		(46.4)		(140.0)		(139.3)		Distributions declared on common units	(55.5)		(46.7)
ENLK preferred unit accrued cash distributions (8)		(23.0)		(22.9)		(69.0)		(68.5)
Costs associated with the relocation of processing facilities (4)		(8.8)		—		(26.6)		—
Non-cash interest expense		2.7		—		7.3		—
Payments to terminate interest rate swaps (3)		(0.5)		—		(1.8)		—
Other (9)		0.5		2.9		1.3		3.1
ENLK preferred unit accrued cash distributions (7)										ENLK preferred unit accrued cash distributions (7)	(23.5)		(23.0)
Costs associated with the relocation of processing facilities (3)										Costs associated with the relocation of processing facilities (3)	(11.3)		(7.6)

Other (8)										Other (8)	0.4		2.7
Free cash flow after distributions	Free cash flow after distributions	$	80.5	$	102.1	$	246.2	$	218.9	Free cash flow after distributions	$	104.9	$	94.2

____________________________

(1)Net of amortization of debt issuance costs, net discount of senior unsecured notes, and designated cash flow hedge, which are included in interest expense but not included in net cash provided by operating activities, and non-cash interest income, which is netted against interest expense but not included in adjusted EBITDA.

(2)Under our utility agreements, we are entitled to a base load of electricity and pay or receive credits, based on market pricing, when we exceed or do not use the base load amounts. Due to Winter Storm Uri, we received credits from our utility providers based on market rates for our unused electricity. These utility credits are recorded as “Other current assets” or “Other assets, net” on our consolidated balance sheets depending on the timing of their expected usage, and amortized as we incur utility expenses.

(3)Represents ~~cash paid for the early terminations~~cost incurred that are not part of our ~~interest rate swaps due~~ongoing operations related to the ~~partial repayments~~relocation of equipment and facilities from the ~~Term Loan~~Thunderbird processing plant and Battle Ridge processing plant in ~~May and September 2021. See “Item 1. Financial Statements—Note 11” for information on~~ the ~~partial terminations of our interest rate swaps.~~

~~(4)Represents cost incurred related~~Oklahoma segment to the Permian segment. The relocation of equipment and facilities from the Battle Ridge processing plant ~~in the Oklahoma segment, to the Permian segment that we~~was completed in the third quarter of 2021 and ~~is not part~~we expect to complete the relocation of ~~our ongoing operations.~~equipment and facilities from the Thunderbird processing plant in the fourth quarter of 2022.

~~(5)~~(4)Includes current income tax ~~expense; transaction costs;~~expense and non-cash rent, which relates to lease incentives pro-rated over the lease term.

~~(6)~~(5)Non-controlling interest share of adjusted EBITDA from joint ventures includes NGP’s 49.9% share of adjusted EBITDA from the Delaware Basin JV and Marathon Petroleum Corporation’s 50% share of adjusted EBITDA from the Ascension ~~JV, and other minor non-controlling interests.~~JV.

~~(7)~~(6)Excludes capital expenditures that were contributed by other entities and relate to the non-controlling interest share of our consolidated entities.

~~(8)~~(7)Represents the cash distributions earned by the Series B Preferred Units and Series C Preferred Units. See “Item 1. Financial Statements—Note 7” for information on the cash distributions earned by holders of the Series B Preferred Units and Series C Preferred Units. Cash distributions to be paid to holders of the Series B Preferred Units and Series C Preferred Units are not available to common unitholders.

~~(9)~~(8)Includes current income tax expense, non-cash interest (income)/expense, and proceeds from the sale of surplus or unused equipment and land, which occurred in the normal operation of our business.

4139

Table of Contents

Results of Operations

The tables below set forth certain financial and operating data for the periods indicated. We evaluate the performance of our consolidated operations by focusing on adjusted gross margin, while we evaluate the performance of our operating segments based on segment profit and adjusted gross margin, as reflected in the tables below (in millions, except volumes):


		Permian		Louisiana		Oklahoma		North Texas		Corporate		Totals			Permian		Louisiana		Oklahoma		North Texas		Corporate		Totals
Three Months Ended September 30, 2021
Three Months Ended March 31, 2022														Three Months Ended March 31, 2022
Gross margin	Gross margin	$	33.7	$	29.1	$	34.8	$	31.5	$	(2.2)	$	126.9	Gross margin	$	36.3	$	55.0	$	34.9	$	34.6	$	(1.4)	$	159.4

Depreciation and amortization	Depreciation and amortization	35.4		34.6		52.3		28.5		2.2		153.0		Depreciation and amortization	36.7		35.5		50.9		28.4		1.4		152.9
Segment profit	Segment profit	69.1		63.7		87.1		60.0		—		279.9		Segment profit	73.0		90.5		85.8		63.0		—		312.3
Operating expenses	Operating expenses	37.3		30.5		19.8		19.3		—		106.9		Operating expenses	45.3		33.0		21.0		21.6		—		120.9
Adjusted gross margin	Adjusted gross margin	$	106.4	$	94.2	$	106.9	$	79.3	$	—	$	386.8	Adjusted gross margin	$	118.3	$	123.5	$	106.8	$	84.6	$	—	$	433.2

Three Months Ended September 30, 2020
Three Months Ended March 31, 2021														Three Months Ended March 31, 2021
Gross margin	Gross margin	$	15.0	$	28.8	$	52.8	$	29.5	$	(1.7)	$	124.4	Gross margin	$	9.3	$	46.1	$	4.8	$	48.2	$	(2.0)	$	106.4

Depreciation and amortization	Depreciation and amortization	31.9		36.9		53.0		36.8		1.7		160.3		Depreciation and amortization	33.5		36.1		50.7		28.7		2.0		151.0
Segment profit	Segment profit	46.9		65.7		105.8		66.3		—		284.7		Segment profit	42.8		82.2		55.5		76.9		—		257.4
Operating expenses	Operating expenses	22.9		31.1		20.1		20.2		—		94.3		Operating expenses	(11.8)		29.2		19.7		19.2		—		56.3
Adjusted gross margin	Adjusted gross margin	$	69.8	$	96.8	$	125.9	$	86.5	$	—	$	379.0	Adjusted gross margin	$	31.0	$	111.4	$	75.2	$	96.1	$	—	$	313.7

Permian Louisiana Oklahoma North Texas Corporate Totals
Nine Months Ended September 30, 2021
Gross margin $ 52.4 $ 106.4 $ 74.6 $ 108.8 $ (6.0) $ 336.2
Depreciation and amortization 103.5 106.8 153.6 86.0 6.0 455.9
Segment profit 155.9 213.2 228.2 194.8 — 792.1
Operating expenses 52.9 91.4 57.3 58.4 — 260.0
Adjusted gross margin $ 208.8 $ 304.6 $ 285.5 $ 253.2 $ — $ 1,052.1
Nine Months Ended September 30, 2020
Gross margin $ 31.8 $ 95.5 $ 142.7 $ 98.4 $ (5.8) $ 362.6
Depreciation and amortization 92.1 109.3 163.7 110.4 5.8 481.3
Segment profit 123.9 204.8 306.4 208.8 — 843.9
Operating expenses 71.1 90.4 62.4 59.2 — 283.1
Adjusted gross margin $ 195.0 $ 295.2 $ 368.8 $ 268.0 $ — $ 1,127.0


	Three Months Ended March 31,
	2022	2021
Midstream Volumes:
Permian Segment
Gathering and Transportation (MMbtu/d)	1,347,100	925,600
Processing (MMbtu/d)	1,256,300	876,100
Crude Oil Handling (Bbls/d)	150,700	108,200
Louisiana Segment
Gathering and Transportation (MMbtu/d)	2,497,700	2,151,300

Crude Oil Handling (Bbls/d)	15,900	15,000
NGL Fractionation (Gals/d)	8,033,900	7,106,200
Brine Disposal (Bbls/d)	3,000	1,400
Oklahoma Segment
Gathering and Transportation (MMbtu/d)	1,000,700	937,300
Processing (MMbtu/d)	1,029,500	955,400
Crude Oil Handling (Bbls/d)	23,800	17,500
North Texas Segment
Gathering and Transportation (MMbtu/d)	1,364,000	1,356,900
Processing (MMbtu/d)	614,300	624,600

Table of Contents

Three Months Ended
September 30, Nine Months Ended
September 30,
2021 2020 2021 2020
Midstream Volumes:
Permian Segment
Gathering and Transportation (MMbtu/d) 1,111,800 923,400 1,021,800 875,200
Processing (MMbtu/d) 1,062,800 929,900 966,500 895,800
Crude Oil Handling (Bbls/d) 157,500 99,100 129,400 115,000
Louisiana Segment
Gathering and Transportation (MMbtu/d) 2,013,900 1,961,100 2,101,000 1,959,600
Crude Oil Handling (Bbls/d) 17,600 15,700 16,000 16,300
NGL Fractionation (Gals/d) 7,050,500 7,462,600 7,295,100 7,665,700
Brine Disposal (Bbls/d) 3,300 1,100 2,500 1,400
Oklahoma Segment
Gathering and Transportation (MMbtu/d) 996,900 1,113,900 983,700 1,142,800
Processing (MMbtu/d) 1,004,400 1,125,600 999,900 1,120,800
Crude Oil Handling (Bbls/d) 20,000 25,600 20,400 30,800
North Texas Segment
Gathering and Transportation (MMbtu/d) 1,377,600 1,450,900 1,370,700 1,505,100
Processing (MMbtu/d) 627,900 669,000 626,700 679,800

Three Months Ended ~~September 30, 2021~~March 31, 2022 Compared to Three Months Ended ~~September 30, 2020~~March 31, 2021

Gross Margin. Gross margin was ~~$126.9~~$159.4 million for the three months ended ~~September 30, 2021~~March 31, 2022 compared to ~~$124.4~~$106.4 million for the three months ended ~~September 30, 2020,~~March 31, 2021, an increase of ~~$2.5~~$53.0 million. The primary contributors to the increase were as ~~follows (in millions):~~follows:

•Permian Segment. Gross margin was ~~$33.7~~$36.3 million for the three months ended ~~September 30, 2021~~March 31, 2022 compared to ~~$15.0~~$9.3 million for the three months ended ~~September 30, 2020,~~March 31, 2021, an increase of ~~$18.7~~$27.0 million primarily due to the following:

◦Adjusted gross margin in the Permian segment increased ~~$36.6~~$87.3 million, which was primarily driven by:

•A ~~$34.2~~$71.5 million increase to adjusted gross margin associated with our Permian gas assets. Adjusted gross margin, excluding derivative activity, increased ~~$32.8~~$20.1 million, which was primarily due to higher volumes from existing customers. Derivative activity associated with our Permian gas assets increased margin by ~~$1.4~~$51.4 million, which included ~~$11.9~~$56.7 million from decreased realized losses, primarily due to realized losses from Winter Storm Uri in February 2021, and $5.3 million from increased unrealized ~~gains and was partially offset by $10.5 million from increased realized~~ losses.

•A ~~$2.4~~$15.8 million increase to adjusted gross margin associated with our Permian crude assets. Adjusted gross margin, excluding derivative activity, increased ~~$2.8~~$13.3 million, which was primarily due to higher volumes from existing ~~customers.~~customers and the timing of physical trades. Derivative activity associated with our Permian crude assets ~~decreased~~increased margin by ~~$0.4~~$2.5 million, which included ~~$2.6 million from increased unrealized losses and was partially offset by~~ $2.2 million from increased realized losses and $4.7 million from increased unrealized gains.

◦Operating expenses in the Permian segment increased ~~$14.4~~$57.1 million primarily due to ~~increases~~$40.0 million of utility credits that we received because our electricity usage was below our contractual base load amounts during Winter Storm Uri in February 2021. Operating expenses also increased due to higher construction fees and services ~~related to the relocation of the War Horse processing plant,~~ and ~~higher~~increases in materials and supplies expense and compressor rentals due to higher volumes.

◦Depreciation and amortization in the Permian segment increased ~~$3.5~~$3.2 million primarily due to new assets placed into service, including ~~the Tiger processing plant in August 2020 and~~ gathering and processing assets associated with the acquisition of Amarillo Rattler, LLC in April 2021.

~~Table of Contents~~

•Louisiana Segment. Gross margin was ~~$29.1~~$55.0 million for the three months ended ~~September 30, 2021~~March 31, 2022 compared to ~~$28.8~~$46.1 million for the three months ended ~~September 30, 2020,~~March 31, 2021, an increase of ~~$0.3~~$8.9 million primarily due to the following:

◦Adjusted gross margin in the Louisiana segment ~~decreased $2.6~~increased $12.1 million, resulting from:

•A $3.7 million decrease to adjusted gross margin associated with our Louisiana gas assets. Adjusted gross margin, excluding derivative activity, increased $6.8 million, which was primarily due to increased gathering and transportation fees as a result of higher volumes transported in addition to increased storage and hub fees following the acquisition of the Jefferson Island storage facility in December 2020. Derivative activity associated with our Louisiana gas assets decreased margin by $10.5 million, which included $7.1 million from increased unrealized losses and $3.4 million from increased realized losses.

•A $0.1 million decrease to adjusted gross margin associated with our ORV crude assets. Adjusted gross margin, excluding derivative activity, increased $0.2 million, which was primarily due to higher volumes. Derivative activity associated with our ORV crude assets decreased margin by $0.3 million due to $0.3 million from increased realized losses.

•~~A $1.2~~$10.3 million increase to adjusted gross margin associated with our Louisiana NGL transmission and fractionation assets. Adjusted gross margin, excluding derivative activity, increased ~~$10.8~~$7.6 million, which was primarily due to ~~favorable market prices on NGL sales.~~higher volumes from existing customers. Derivative activity associated with our Louisiana NGL transmission and fractionation assets increased margin by $2.7 million, which included $7.0 million from decreased realized losses and $4.3 million from increased unrealized losses.

•A $0.9 million increase to adjusted gross margin associated with our Louisiana gas assets. Adjusted gross margin, excluding derivative activity, increased $4.4 million, which was primarily due to higher volumes from existing customers. Derivative activity associated with our Louisiana gas assets decreased margin by ~~$9.6~~$3.5 million, which included ~~$10.6~~$2.6 million from increased realized losses and ~~was partially offset by $1.0~~$0.9 million from increased unrealized losses.

•A $0.9 million increase to adjusted gross margin associated with our ORV crude assets. Adjusted gross margin, excluding derivative activity, increased $1.2 million, which was primarily due to higher volumes from existing customers. Derivative activity associated with our ORV crude assets decreased ~~unrealized~~margin by $0.3 million from increased realized losses.

◦Operating expenses in the Louisiana segment ~~decreased $0.6~~increased $3.8 million primarily due to ~~decreased~~increases in utility costs and construction fees and ~~services and ad valorem taxes. These increases were partially offset by higher utility costs.~~services.

◦Depreciation and amortization in the Louisiana segment decreased ~~$2.3~~$0.6 million primarily due to changes in estimated useful lives of certain non-core assets that were fully depreciated in the second quarter of 2021.

Table of Contents

•Oklahoma Segment. Gross margin was ~~$34.8~~$34.9 million for the three months ended ~~September 30, 2021~~March 31, 2022 compared to ~~$52.8~~$4.8 million for the three months ended ~~September 30, 2020, a decrease~~March 31, 2021, an increase of ~~$18.0~~$30.1 million primarily due to the following:

◦Adjusted gross margin in the Oklahoma segment ~~decreased $19.0~~increased $31.6 million, resulting from:

•A ~~$18.3~~$29.5 million ~~decrease~~increase to adjusted gross margin associated with our Oklahoma gas assets. Adjusted gross margin, excluding derivative activity, ~~decreased $11.2~~increased $32.9 million, which was primarily due to ~~a $13.7 million decrease in adjusted gross margin resulting~~higher volumes from ~~the expiration of the MVC provision of a gathering and processing contract at the end of 2020.~~existing customers. Derivative activity associated with our Oklahoma gas assets decreased margin by ~~$7.1~~$3.4 million, which included ~~$5.1~~$2.3 million from ~~increased~~decreased realized losses and ~~$2.0~~$5.7 million from increased unrealized losses.

•A ~~$0.7~~$2.1 million ~~decrease~~increase to adjusted gross margin associated with our Oklahoma crude ~~assets,~~assets. Adjusted gross margin, excluding derivative activity, increased $1.7 million, which was primarily due to ~~lower~~higher volumes from ~~our~~ existing customers. Derivative activity associated with our Oklahoma crude assets increased margin by $0.4 million from decreased unrealized losses.

◦Operating expenses in the Oklahoma segment ~~decreased $0.3~~increased $1.3 million primarily due to ~~reductions~~increases in ~~compressor rentals.~~materials and supplies expense and construction fees and services. These increases were partially offset by a decrease in operation and maintenance costs and ad valorem taxes.

◦Depreciation and amortization in the Oklahoma segment ~~decreased $0.7~~increased $0.2 million ~~primarily~~ due to additional assets placed in service, partially offset by the ~~relocation~~transfer of ~~the Battle Ridge processing plant~~equipment to the ~~War Horse~~Phantom and Warhorse processing ~~plant.~~facilities.

~~Table of Contents~~

•North Texas Segment. Gross margin was ~~$31.5~~$34.6 million for the three months ended ~~September 30, 2021~~March 31, 2022 compared to ~~$29.5~~$48.2 million for the three months ended ~~September 30, 2020, an increase~~March 31, 2021, a decrease of ~~$2.0~~$13.6 million primarily due to the following:

◦Adjusted gross margin in the North Texas segment decreased ~~$7.2~~$11.5 million. Adjusted gross margin, excluding derivative activity, decreased ~~$5.2~~$13.9 million, which was primarily due to ~~decreased revenues due to lower volumes~~favorable market pricing resulting from ~~our existing customers.~~Winter Storm Uri in February 2021. Derivative activity associated with our North Texas segment ~~decreased~~increased margin by ~~$2.0~~$2.4 million, which included ~~$1.8~~$1.5 million from increased realized losses and ~~$0.2~~$3.9 million from increased unrealized ~~losses.~~gains.

◦Operating expenses in the North Texas segment ~~decreased $0.9~~increased $2.4 million primarily due to ~~reductions~~increases in ~~construction fees~~materials and ~~services, ad valorem~~supplies expense, sales and use taxes, and ~~compressor rentals.~~utility costs. These increases were partially offset by a decrease in operations and maintenance costs.

◦Depreciation and amortization in the North Texas segment decreased ~~$8.3~~$0.3 million primarily due to ~~a change in the estimated useful lives of certain non-core~~ assets ~~that were fully depreciated at~~reaching the end of ~~2020.~~their depreciable lives.

•Corporate Segment. Gross margin was negative ~~$2.2~~$1.4 million for the three months ended ~~September 30, 2021~~March 31, 2022 compared to negative ~~$1.7~~$2.0 million for the three months ended ~~September 30, 2020.~~March 31, 2021. Corporate gross margin consists of depreciation and amortization of corporate assets.

General and Administrative Expenses. General and administrative expenses were ~~$28.2~~$29.0 million for the three months ended ~~September 30, 2021~~March 31, 2022 compared to ~~$25.7~~$26.0 million for the three months ended ~~September 30, 2020,~~March 31, 2021, an increase of ~~$2.5~~$3.0 million. The increase was primarily due to labor and benefits costs ~~which increased $4.1 million,~~ and ~~was partially offset by unit-based compensation costs, which decreased $1.5 million.~~consulting fees and services.

Table of Contents

Interest Expense. Interest expense was ~~$60.1~~$55.1 million for the three months ended ~~September 30, 2021~~March 31, 2022 compared to ~~$55.5~~$60.0 million for the three months ended ~~September 30, 2020, an increase~~March 31, 2021, a decrease of ~~$4.6~~$4.9 million. Interest expense consisted of the following (in millions):


		Three Months Ended September 30,					Three Months Ended March 31,
		2021		2020			2022		2021
ENLK and ENLC Senior Notes	ENLK and ENLC Senior Notes	$	50.3	$	43.3	ENLK and ENLC Senior Notes	$	50.3	$	50.3
Term Loan	Term Loan	1.0		3.6		Term Loan	—		1.4
Consolidated Credit Facility	Consolidated Credit Facility	1.3		3.4		Consolidated Credit Facility	2.3		1.3
AR Facility	AR Facility	1.0		—		AR Facility	1.1		1.2
Capitalized interest	Capitalized interest	—		(0.6)		Capitalized interest	—		(0.2)
Amortization of debt issuance costs and net discount of senior unsecured notes	Amortization of debt issuance costs and net discount of senior unsecured notes	1.4		0.9		Amortization of debt issuance costs and net discount of senior unsecured notes	1.3		1.2
Interest rate swap - realized		5.0		4.6
Other		0.1		0.3
Interest rate swaps - realized						Interest rate swaps - realized	0.1		4.8

Total	Total	$	60.1	$	55.5	Total	$	55.1	$	60.0

~~Income (Loss)~~Loss from Unconsolidated Affiliate Investments. Loss from unconsolidated affiliate investments was ~~$2.3~~$1.1 million for the three months ended ~~September 30, 2021~~March 31, 2022 compared to a loss of ~~$0.2~~$6.3 million for the three months ended ~~September 30, 2020, an increased~~March 31, 2021, a reduction in loss of ~~$2.1~~$5.2 million. The ~~increased~~reduction in loss was primarily attributable to a reduction in loss of ~~income of $2.1~~$5.0 million from our GCF investment, as a result of the GCF assets being ~~temporarily~~ idled beginning in January ~~2021.~~2021, and a reduction in loss of $0.2 million from our Cedar Cove JV.

Income Tax ~~Benefit (Expense).~~Expense. Income tax expense was ~~$4.4~~$3.2 million for the three months ended ~~September 30, 2021~~March 31, 2022 compared to an income tax expense of ~~$6.0~~$1.4 million for the three months ended ~~September 30, 2020.~~March 31, 2021. The ~~decrease~~increase in income tax expense was primarily attributable to the ~~decrease~~increase in income between periods. See “Item 1. Financial Statements—Note 6” for additional information.

Net Income ~~(Loss)~~ Attributable to Non-Controlling Interest. Net income attributable to non-controlling interest was ~~$30.4~~$30.8 million for the three months ended ~~September 30, 2021~~March 31, 2022 compared to net income of ~~$26.6~~$25.3 million for the three months ended ~~September 30, 2020,~~March 31, 2021, an increase of ~~$3.8~~$5.5 million. ENLC’s non-controlling interest is comprised of Series B Preferred Units, Series C Preferred Units, NGP’s 49.9% share of the Delaware Basin JV, and Marathon Petroleum Corporation’s 50% share of the Ascension JV.

~~Table of Contents~~

~~Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020~~

~~Gross Margin.~~ ~~Gross margin was $336.2 million for the nine months ended September 30, 2021 compared to $362.6 million for the nine months ended September 30, 2020, a decrease of $26.4 million.~~ The ~~primary contributors to the decrease were as follows (in millions):~~

•~~Permian Segment.~~ ~~Gross margin was $52.4 million for the nine months ended September 30, 2021 compared to $31.8 million for the nine months ended September 30, 2020, an~~ increase ~~of $20.6 million primarily due to the following:~~

◦~~Adjusted gross margin~~ in ~~the Permian segment increased $13.8 million, which was primarily driven by:~~

•~~A $12.6 million increase to adjusted gross margin associated with our Permian gas assets. Adjusted gross margin, excluding derivative activity, increased $90.1 million, which~~income was primarily due to higher volumes and due to significant favorable commodity prices on sales in our Permian gas assets from Winter Storm Uri. Derivative activity associated with our Permian gas assets decreased margin by $77.5 million, which included $75.1 million from increased realized losses and $2.4 million from increased unrealized losses.

•~~A $1.2~~a $4.6 million increase to adjusted gross margin associated with our Permian crude assets. Adjusted gross margin, excluding derivative activity, decreased $1.8 million, which was primarily due to weather disruptions from Winter Storm Uri and storage fees earned in April of 2020 due to the negative futures price of crude. Derivative activity associated with our Permian crude assets increased margin by $3.0 million, which included $5.9 million from increased realized gains and was partially offset by $2.9 million from decreased unrealized gains.

◦Operating expenses in the Permian segment decreased $18.2 million primarily due to lower utility costs as a result of approximately $48.1 million of utility credits that we received because our electricity usage was below our contractual base load amounts during Winter Storm Uri, which entitled us to credits based on market rates for our unused electricity. These credits can be used to offset future utility payments. Operating expenses also decreased due to lower labor and benefits expense as a result of reductions in workforce in April 2020. These decreases were partially offset by increases in construction fees and services related to the relocation of the War Horse processing plant, increases in materials and supplies expense and compressor rentals due to higher volumes, and increases in sales and use taxes as a result of tax refunds in the first half of 2020.

◦Depreciation and amortization in the Permian segment increased $11.4 million primarily due to new assets placed into service, including the Tiger processing plant in August 2020 and acquisition of the Amarillo Rattler, LLC gathering and processing system in April 2021.

•~~Louisiana Segment.~~ Gross margin was $106.4 million for the nine months ended September 30, 2021 compared to $95.5 million for the nine months ended September 30, 2020, an increase of $10.9 million primarily due to the following:

◦~~Adjusted gross margin in the Louisiana segment increased $9.4 million, resulting from:~~

•A $12.1 million increase to adjusted gross margin associated with our Louisiana NGL transmission and fractionation assets. Adjusted gross margin, excluding derivative activity, increased $40.0 million, which was primarily due to favorable market prices on NGL sales. Derivative activity associated with our Louisiana NGL transmission and fractionation assets decreased margin by $27.9 million, which included $29.6 million from increased realized losses and was partially offset by $1.7 million from decreased unrealized losses.

•A $2.5 million decrease to adjusted gross margin associated with our ORV crude assets. Adjusted gross margin, excluding derivative activity, decreased $4.5 million, which was primarily due to lower volumes. Derivative activity associated with our ORV crude assets increased margin by $2.0 million, which included $1.1 million from increased unrealized gains and $0.9 million from decreased realized losses.

•A $0.2 million decrease to adjusted gross margin associated with our Louisiana gas assets. Adjusted gross margin, excluding derivative activity, increased $18.6 million, which was primarily due to increased gathering and transportation fees as a result of higher volumes transported in addition to increased storage and hub fees following the acquisition of the Jefferson Island storage facility in December 2020. Derivative activity associated with our Louisiana gas assets decreased margin by $18.8

~~Table of Contents~~

~~million, which included $13.6 million from increased unrealized losses and $5.2 million from increased realized losses.~~

◦Operating expenses in the Louisiana segment increased $1.0 million primarily due to increased materials and supplies expense and utilities. This increase was partially offset by lower labor and benefits expense as a result of reductions in workforce in April 2020 and ad valorem taxes.

◦Depreciation and amortization in the Louisiana segment decreased $2.5 million primarily due to the impairment of assets in the first quarter of 2020, partially offset by changes in estimated useful lives of certain non-core assets.

•~~Oklahoma Segment.~~ Gross margin was $74.6 million for the nine months ended September 30, 2021 compared to $142.7 million for the nine months ended September 30, 2020, a decrease of $68.1 million primarily due to the following:

◦~~Adjusted gross margin in the Oklahoma segment decreased $83.3 million, resulting from:~~

•A $82.2 million decrease to adjusted gross margin associated with our Oklahoma gas assets. Adjusted gross margin, excluding derivative activity, decreased $57.7 million, which was primarily due to lower volumes from our existing customers, including weather disruptions from Winter Storm Uri, and a $38.6 million decrease in adjusted gross margin resulting from the expiration of the MVC provision of a gathering and processing contract at the end of 2020. Derivative activity associated with our Oklahoma gas assets decreased margin by $24.5 million, which included $15.0 million from increased realized losses and $9.5 million from increased unrealized losses.

•A $1.1 million decrease to adjusted gross margin associated with our Oklahoma crude assets. Adjusted gross margin, excluding derivative activity, decreased $4.6 million, which was primarily due to lower volumes from our existing customers and partially as a result of weather disruptions from Winter Storm Uri. Derivative activity associated with our Oklahoma crude assets increased margin by $3.5 million, which included $2.5 million from increased unrealized gains and $1.0 million from increased realized gains.

◦Operating expenses in the Oklahoma segment decreased $5.1 million primarily due to reductions in compressor rentals and lower labor and benefits expense as a result of reductions in workforce in April 2020. These decreases were partially offset by higher costs in 2021 to decommission equipment from the Battle Ridge processing plant to be moved to the War Horse processing plant.

◦~~Depreciation and amortization in the Oklahoma segment decreased $10.1 million primarily due to the relocation of the Battle Ridge processing plant to the War Horse processing plant.~~

•~~North Texas Segment.~~ Gross margin was $108.8 million for the nine months ended September 30, 2021 compared to $98.4 million for the nine months ended September 30, 2020, an increase of $10.4 million primarily due to the following:

◦Adjusted gross margin in the North Texas segment decreased $14.8 million. Adjusted gross margin, excluding derivative activity, decreased $8.1 million, which was primarily due to lower volumes from our existing customers. Derivative activity associated with our North Texas segment decreased margin by $6.7 million, which included $4.9 million from increased realized losses and $1.8 million from increased unrealized losses.

◦Operating expenses in the North Texas segment decreased $0.8 million primarily due to reductions in compressor rentals, reductions to labor and benefits expense as a result of reductions in workforce in April 2020, reductions to utility costs, and reductions in ad valorem taxes. These decreases were partially offset by increases in materials and supplies expense and operation and maintenance costs, and increases in sales and use taxes as a result of tax refunds in the first half of 2020.

◦Depreciation and amortization in the North Texas segment decreased $24.4 million primarily due to a change in the estimated useful lives of certain non-core assets that were fully depreciated at the end of 2020.

~~Table of Contents~~

•~~Corporate Segment.~~ Gross margin was negative $6.0 million for the nine months ended September 30, 2021 compared to negative $5.8 million for the nine months ended September 30, 2020. Corporate gross margin consists of depreciation and amortization of corporate assets.

~~Impairments.~~ For the nine months ended September 30, 2021, we did not recognize an impairment expense. For the nine months ended September 30, 2020, we recognized impairment expense related to goodwill and property and equipment, including cancelled projects. Impairment expense is composed of the following amounts (in millions):


	Nine Months Ended September 30,
	~~2020~~
~~Goodwill impairment~~	$	~~184.6~~
~~Property and equipment impairment~~	~~168.0~~
~~Cancelled projects~~	~~1.9~~
~~Total~~	$	~~354.5~~

~~General and Administrative Expenses.~~ General and administrative expenses were $80.3 million for the nine months ended September 30, 2021 compared to $79.6 million for the nine months ended September 30, 2020, an increase of $0.7 million. The increase was primarily due to labor and benefits costs, which increased $2.3 million; transaction and transition costs, which increased $1.0 million primarily due to the Amarillo Rattler, LLC acquisition in April 2021; franchise taxes, which increased $0.6 million primarily due to franchise tax refunds in the first half of 2020; and $0.7 million from consulting fees and services. These increases were partially offset by a $4.0 million decrease to unit-based compensation costs.

~~Interest Expense.~~ Interest expense was $180.1 million for the nine months ended September 30, 2021 compared to $166.3 million for the nine months ended September 30, 2020, an increase of $13.8 million, or 8.3%. Interest expense consisted of the following (in millions):
Nine Months Ended
September 30,
2021 2020
ENLK and ENLC Senior Notes $ 150.9 $ 130.6
Term Loan 3.7 14.2
Consolidated Credit Facility 4.0 11.6
AR Facility 3.0 —
Capitalized interest (0.3) (3.1)
Amortization of debt issuance costs and net discount of senior unsecured notes 3.9 3.1
Interest rate swap - realized 14.6 9.6
Other 0.3 0.3
Total $ 180.1 $ 166.3

~~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.~~

~~Income (Loss) from Unconsolidated Affiliate Investments.~~ Loss from unconsolidated affiliate investments was $9.9 million for the nine months ended September 30, 2021 compared to income of $0.8 million for the nine months ended September 30, 2020, a decrease of income of $10.7 million. The decrease was attributable to a reduction of income of $10.6 million from our GCF investment, as a result of the GCF assets being temporarily idled beginning in January 2021, and additional losses of $0.1 million from our Cedar Cove JV.

~~Income Tax Expense.~~ Income tax expense was $12.4 million for the nine months ended September 30, 2021 compared to an income tax benefit of $16.0 million for the nine months ended September 30, 2020. The decrease in income tax benefit was primarily attributable to the decrease in loss between periods. See “Item 1. Financial Statements—Note 6” for additional information.

~~Net Income (Loss) Attributable to Non-Controlling Interest.~~ Net income attributable to non-controlling interest was $86.7 million for the nine months ended September 30, 2021 compared to net income of $78.7 million for the nine months ended September 30, 2020, an increase of $8.0 million. ENLC’s non-controlling interest is comprised of Series B Preferred Units,

~~Table of Contents~~

~~Series C Preferred Units,~~ NGP’s 49.9% share of the Delaware Basin JV and a $1.0 million increase attributable to Marathon Petroleum Corporation’s 50% share of the Ascension JV. These increases were offset by $0.1 million reduction in income attributable to the Series B Preferred Units following the partial redemptions of the Series B Units in December 2021 and January 2022.

Critical Accounting Policies

Information regarding our critical accounting policies is included in “Item 7. Management’s Discussion and Analysis of Financial ~~Conditions~~Condition and Results of Operations” of our Annual Report on Form 10-K for the year ended December 31, ~~2020~~2021 filed with the Commission on February ~~17, 2021.~~16, 2022.

Liquidity and Capital Resources

Cash Flows from Operating Activities. Net cash provided by operating activitieswas ~~$599.2~~$307.7 million for the ~~nine~~three months ended ~~September 30, 2021~~March 31, 2022 compared to ~~$561.0~~$225.8 million for the ~~nine~~three months ended ~~September 30, 2020.~~March 31, 2021. Operating cash flows before working capital and changes in working capital for the comparative periods were as follows (in millions):


		Nine Months Ended September 30,					Three Months Ended March 31,
		2021		2020			2022		2021
Operating cash flows before working capital	Operating cash flows before working capital	$	559.5	$	633.2	Operating cash flows before working capital	$	257.8	$	147.7
Changes in working capital	Changes in working capital	39.7		(72.2)		Changes in working capital	49.9		78.1

Operating cash flows before changes in working capital ~~decreased $73.7~~increased $110.1 million for the ~~nine~~three months ended ~~September 30, 2021~~March 31, 2022 compared to the ~~nine~~three months ended ~~September 30, 2020.~~March 31, 2021. The primary ~~contributors~~contributor to the ~~decrease~~increase in operating cash flows ~~were~~was as follows:

•Gross margin, excluding depreciation and amortization, non-cash commodity swap activity, utility credits redeemed or earned, and unit-based compensation, ~~decreased $61.1~~increased $110.3 million. For more information regarding the changes in gross

Table of Contents

margin for the ~~nine~~three months ended ~~September 30, 2021~~March 31, 2022 compared to the ~~nine~~three months ended ~~September 30, 2020,~~March 31, 2021, see “Results of Operations.”

•~~General and administrative expenses excluding unit-based compensation increased $4.7 million. For more information, see “Results of Operations.”~~

•~~Interest expense, excluding amortization of debt issuance costs, net discount of senior unsecured notes, and designated cash flow hedge, increased $3.5 million.~~

The changes in working capital for the ~~nine~~three months ended ~~September 30, 2021~~March 31, 2022 compared to the ~~nine~~three months ended ~~September 30, 2020~~March 31, 2021 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 ~~$155.4~~$59.2 million for the ~~nine~~three months ended ~~September 30, 2021~~March 31, 2022 compared to ~~$250.7~~$19.2 million for the ~~nine~~three months ended ~~September 30, 2020. Investing cash flows are primarily related to capital expenditures. Capital expenditures decreased from $254.4 million for~~March 31, 2021. Our primary investing activities consisted of the ~~nine months ended September 30, 2020 to $104.7 million for the nine months ended September 30, 2021.~~ following (in millions):


	Three Months Ended March 31,
	2022		2021

Additions to property and equipment (1)	$	(60.2)	$	(23.5)

____________________________

(1)The ~~decrease~~increase in capital expenditures was ~~primarily~~ due to ~~the completion of major~~expansion projects ~~in 2020. The decrease in investing cash flows was partially offset by $56.7 million related~~ to ~~cash paid for the acquisition of assets, net of cash acquired, for the nine months ended September 30, 2021.~~accommodate increased volumes on our systems.

~~Table of Contents~~

Cash Flows from Financing Activities. Net cash used in financing activities was ~~$447.3~~$206.0 million for the ~~nine~~three months ended ~~September 30, 2021~~March 31, 2022 compared to ~~$308.8~~$173.4 million for the ~~nine~~three months ended ~~September 30, 2020.~~March 31, 2021. Our primary financing activities consisted of the following (in millions):
Nine Months Ended
September 30,
2021 2020
Net repayments on the Term Loan (1) $ (200.0) $ —
Net repayments on the AR Facility (1) (5.0) —
Net repayments on the Consolidated Credit Facility (1) — (50.0)
Net repurchases on ENLK’s senior unsecured notes (1) — (35.2)
Net repurchases on the 2029 Notes (1) — (0.8)
Contributions by non-controlling interests (2) 2.4 52.2
Distribution to members (140.4) (186.2)
Distributions to Series B Preferred unitholders (3) (50.9) (50.4)
Distributions to Series C Preferred unitholders (3) (12.0) (12.0)
Distributions to joint venture partners (4) (25.3) (21.8)
Common unit repurchases (5) (14.5) —


	Three Months Ended March 31,
	2022		2021

Net repayments on the AR Facility (1)	$	(35.0)	$	(100.0)
Net repayments on the Consolidated Credit Facility (1)	(15.0)		—


Contributions by non-controlling interests (2)	7.3		0.9
Distributions to members	(56.4)		(47.1)
Distributions to Series B Preferred Unitholders (3)	(18.6)		(16.9)

Redemption of Series B Preferred Units (3)	(50.5)		—
Distributions to joint venture partners (4)	(16.0)		(9.1)
Common unit repurchases (5)	(17.0)		—

____________________________

(1)See “Item 1. Financial Statements—Note 5” for more information regarding the ~~Term Loan, the Consolidated Credit Facility, the~~ AR Facility and the ~~senior unsecured notes.~~Consolidated Credit Facility.

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

(3)See “Item 1. Financial Statements—Note 7” for information on distributions to holders of the Series B Preferred Units and information on the partial redemption of the Series CB Preferred Units.

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

(5)See “Item 1. Financial Statements—Note 8” for more information regarding the ENLC common unit repurchase program.

Table of Contents

Capital Requirements

~~Capital Requirements.~~

The following table summarizes our expected remaining capital requirements for 2022 (in millions):


Capital expenditures, net to ENLC (1)	$	245
Operating expenses associated with the relocation of processing facilities (2)	34
Total	$	279

____________________________

(1)~~We expect our total~~Excludes capital expenditures that were contributed by other entities and ~~operating expenses,~~relate to the non-controlling interest share of our consolidated entities.

(2)Represents cost incurred that are not part of our ongoing operations related to the relocation of equipment and facilities from the Thunderbird processing plant in the Oklahoma segment to ~~be approximately $225 million for 2021.~~the Permian segment. We ~~have incurred approximately $136 million of capital expenditures and operating expenses, related~~expect to complete the relocation of equipment and facilities ~~for~~from the ~~nine months ended September 30, 2021.~~ Thunderbird processing plant in the fourth quarter of 2022.

Our primary capital projects for ~~the remainder of 2021~~2022 include ~~the expansion of the War Horse processing plant, the start of~~ the relocation of the Phantom processing plant, CCS-related initiatives, continued development of our existing systems through well connects, and other low-cost development projects. We expect to fund our remaining ~~2021~~2022 capital ~~expenditures~~requirements from operating cash ~~flows and capital contributions by joint venture partners that relate to the non-controlling interest share of our consolidated entities.~~flows.

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.

In August 2021, we received a $4.4 million grant from the Texas Commission on Environmental Quality (“TCEQ”) as a result of the TCEQ Emissions Reduction Incentive Grant Program. This grant will allow us to seek reimbursements for costs associated with upgrading compressor units that will result in reduced nitrogen oxide levels.

Off-Balance Sheet Arrangements. We had no off-balance sheet arrangements as of ~~September 30, 2021.~~March 31, 2022.

~~Table of Contents~~

Total Contractual Cash Obligations. A summary of our total contractual cash obligations as of ~~September 30, 2021~~March 31, 2022 is as follows (in millions):
Payments Due by Period
Total Remainder 2021 2022 2023 2024 2025 Thereafter
ENLC’s & ENLK’s senior unsecured notes $ 4,032.3 $ — $ — $ — $ 521.8 $ 720.8 $ 2,789.7
Term Loan (1) 150.0 150.0 — — — — —
Consolidated Credit Facility (2) — — — — — — —
AR Facility (3) 245.0 — — — 245.0 — —
Acquisition installment payable (4) 10.0 10.0 — — — —
Acquisition contingent consideration (5) 6.9 — — — 2.3 2.4 2.2
Interest payable on fixed long-term debt obligations 2,409.6 74.6 201.2 201.2 189.7 163.3 1,579.6
Operating lease obligations 113.2 5.2 17.0 11.6 10.1 9.8 59.5
Purchase obligations 4.4 4.4 — — — — —
Pipeline and trucking capacity and deficiency agreements (6) 176.0 12.4 46.6 38.7 29.2 24.8 24.3
Inactive easement commitment (7) 10.0 — 10.0 — — — —
Total contractual obligations $ 7,157.4 $ 246.6 $ 284.8 $ 251.5 $ 998.1 $ 921.1 $ 4,455.3


	Payments Due by Period
	Total		Remainder 2022		2023		2024		2025		2026		Thereafter
ENLC’s & ENLK’s senior unsecured notes	$	4,032.3	$	—	$	—	$	521.8	$	720.8	$	491.0	$	2,298.7
Consolidated Credit Facility (1)	—		—		—		—		—		—		—
AR Facility (2)	315.0		—		—		315.0		—		—		—
Acquisition installment payable (3)	10.0		10.0		—		—		—		—		—
Acquisition contingent consideration (4)	6.9		—		—		2.3		2.4		2.2		—
Interest payable on fixed long-term debt obligations	2,308.9		175.2		201.2		189.7		163.3		148.3		1,431.2
Operating lease obligations	116.6		17.7		19.2		10.5		9.8		8.9		50.5
Purchase obligations	4.6		4.6		—		—		—		—		—
Pipeline and trucking capacity and deficiency agreements (5)	297.8		38.1		55.7		44.2		39.4		30.9		89.5
Inactive easement commitment (6)	10.0		10.0		—		—		—		—		—
Total contractual obligations	$	7,102.1	$	255.6	$	276.1	$	1,083.5	$	935.7	$	681.3	$	3,869.9

____________________________

(1)~~The Term Loan matures on December 10, 2021.~~

~~(2)~~The Consolidated Credit Facility will mature on January 25, 2024. As of ~~September 30, 2021,~~March 31, 2022, there were no amounts outstanding under the Consolidated Credit Facility.

~~(3)~~(2)The AR Facility will terminate on September 24, 2024, unless extended or earlier terminated in accordance with its terms.

~~(4)~~(3)Amount related to the consideration of the Amarillo Rattler, LLC acquisition, ~~due~~which was paid on April 30, 2022.

~~(5)~~(4)The estimated fair value of the Amarillo Rattler, LLC contingent consideration was calculated in accordance with the fair value guidance contained in ASC ~~820,~~ ~~Fair Value Measurements~~.820. There are a number of assumptions and estimates factored into these fair values and actual contingent consideration payments could differ from these estimated fair values. See “Item 1. Financial Statements—Note ~~12”~~11” for additional information.

~~(6)~~(5)Consists of pipeline capacity payments for firm transportation and deficiency agreements.

~~(7)~~(6)Amount related to inactive easements paid as utilized by us with the balance due in August 2022 if not utilized.

Table of Contents

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

Our contractual cash obligations for the remainder of ~~2021~~2022 are expected to be funded from cash flows generated from our operations and the available capacity under the Consolidated Credit Facility, the AR Facility, or other debt sources.

Indebtedness

In October 2020, we entered into the AR Facility, which was originally a three-year committed accounts receivable securitization facility in the amount of up to $250.0 million. On September 24, 2021, the SPV entered into the Second Amendment to the Receivables Financing Agreement, which amended the AR Facility to, among other things, increase the facility limit and lender commitments to $350.0 million and extend the scheduled termination date to September 24, 2024. As of ~~September 30, 2021,~~March 31, 2022, the AR Facility had a borrowing base of $350.0 million and there ~~was $245.0~~were $315.0 million in outstanding borrowings under the AR Facility.

In addition, as of ~~September 30, 2021,~~March 31, 2022, we have $4.0 billion in aggregate principal amount of outstanding unsecured senior notes maturing from 2024 to ~~2047 and $150.0 million in outstanding principal on the Term Loan.~~2047. There were no outstanding borrowings under the Consolidated Credit Facility and ~~$41.1~~$44.3 million outstanding letters of credit as of ~~September 30, 2021.~~

~~Table of Contents~~

March 31, 2022.

Guarantees. The amounts outstanding on our senior unsecured notes ~~the Term Loan,~~ and the Consolidated Credit Facility are guaranteed in full by our subsidiary ENLK, including 105% of any letters of credit outstanding on the Consolidated Credit Facility. ENLK’s guarantees of these amounts are full, irrevocable, unconditional, and absolute, and cover all payment obligations arising under the senior unsecured notes ~~the Term Loan,~~ and the Consolidated Credit Facility. Liabilities under the guarantees rank equally in right of payment with all existing and future senior unsecured indebtedness of ENLK.

ENLC’s ~~material~~ assets consist of all of the outstanding common units of ENLK and all of the membership interests of the General Partner. Other than these equity interests, all of our ~~material~~ assets and operations are held by our non-guarantor operating subsidiaries. ENLK, directly and indirectly, owns all of these non-guarantor operating subsidiaries, which in some cases are joint ventures that are partially owned by a third party. As a result, the assets, liabilities, and results of operations of ENLK are not materially different than the corresponding amounts presented in our consolidated financial statements.

As of ~~September 30, 2021,~~March 31, 2022, ENLC records, on a stand-alone basis, transactions that do not occur at ENLK, which are primarily related to the taxation of ENLC and the elimination of intercompany ~~borrowings, and impairment of goodwill that only existed at ENLC.~~borrowings.

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

Inflation

Inflation in the United States has been relatively low in recent years. However, the annual U.S. inflation rate accelerated in 2021 and through the first quarter of 2022. It is widely expected that this trend will continue for the remainder of 2022. In addition, at its March 2022 meeting, the Federal Reserve announced that it would be increasing its target for the federal funds rate (the benchmark for most interest rates) for the first time since 2018. Although we do not expect inflation to have a material effect on our results, higher inflation may increase the cost to acquire or replace property and equipment and the cost of labor and supplies. To the extent permitted by competition, regulation, and our existing agreements, we have and will continue to pass along increased costs to our customers in the form of higher fees. Additionally, certain of our revenue generating contracts contain clauses that increase our fees based on changes in inflation metrics.

Recent Accounting Pronouncements

~~See “Item 8. Financial Statements and Supplementary Data—Note 2” in our Annual Report on Form 10-K filed with the Commission on February 17, 2021 for information on~~We have reviewed recently issued accounting pronouncements that became effective during the three months ended March 31, 2022 and ~~adopted accounting pronouncements.~~have determined that none would have a material impact to our consolidated financial statements.

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 and results to differ materially from those indicated herein. Therefore, you should not rely on any of these forward-looking

Table of Contents

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, environmental and climate change initiatives, our future capital structure and credit ratings, objectives, strategies, expectations, and intentions, the impact of the COVID-19 pandemic, Winter Storm Uri, and other weather related events 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,~~operations, or cash flows, include, without limitation, (a) the impact of the ongoing coronavirus (COVID-19) pandemic (including the impact of ~~the emergence of~~ any new variants of the virus) on our business, financial condition, and results of ~~operation,~~operations, (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, could adversely affect the price of our common units, and could result in a default or prepayment event under our credit facility and certain of our other debt, (e) the dependence on ~~Devon~~our significant customers for a substantial portion of the natural gas and crude that we gather, process, and transport, (f) developments that materially and adversely affect ~~Devon~~our significant customers 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) increasing scrutiny and changing expectations from stakeholders with respect to our environment, social, and governance practices, (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

~~Table of Contents~~

elsewhere in this Quarterly Report on Form 10-Q, ~~and~~ 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, ~~2020~~2021 filed with the Commission on February 16, 2022 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.

The legislation and potential new regulations may also require counterparties to our derivative instruments to spin off or result in such counterparties spinning 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

Table of Contents

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.

On January 14, 2021, the CFTC published final rules under the Dodd-Frank Act establishing position limit levels for certain energy commodity futures contracts, options and contracts on futures contracts directly or indirectly linked to core referenced futures contracts, and economically equivalent swaps. The position limit levels set the maximum position that a trader may own or control separately or in combination, net long or short, subject to exceptions for certain bona fide hedging transactions. These rules came into effect on March 15, 2021 with compliance dates starting from January 1, 2022.

Commodity Price Risk

We are also subject to direct risks due to fluctuations in commodity prices. ~~Approximately 88%~~While approximately 90% of our adjusted gross margin for the ~~nine~~three months ended ~~September 30, 2021~~March 31, 2022 was generated from arrangements with fee-based structures with minimal direct commodity price exposure, the remainder is subject to more direct commodity price exposure. Our exposure to these commodity price fluctuations is primarily in the gas processing component of our business. We currently earn adjusted gross margin 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 or (2) arrangements where we purchase and resell commodities in connection with providing the related service and earn a net margin through a fee-like deduction subtracted from the purchase price of the commodities. We may also purchase and resell commodities in arrangements under which we are subject to commodity price fluctuations. Although historically this has not been a material component of our adjusted gross margin, Winter Storm Uri caused sudden and significant price and volume fluctuations that resulted in increased adjusted gross margin that is exposed to commodity price fluctuations. For more information on Winter Storm Uri and its impact on the Company, see the discussion at “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Recent Developments Affecting Industry Conditions and Our Business—Winter Storm Uri” in this Report. For the nine months ended September 30, 2021, approximately 6% of our adjusted gross margin was generated from purchase and resell arrangements under which we are subject to commodity price fluctuations. This amount was substantially offset by derivative losses.

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

~~Table of Contents~~

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~~three months ended ~~September 30, 2021,~~March 31, 2022, less than 1% of our adjusted gross 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~~three months ended ~~September 30, 2021,~~March 31, 2022, approximately 5%9% of our adjusted gross 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.

Table of Contents

We manage our exposure to changes in commodity prices by hedging the impact of market fluctuations. Commodity swaps are used both to manage and hedge price and location risk related to these market exposures and to manage margins on offsetting fixed-price purchase or sale commitments for physical quantities of NGLs, natural gas, and crude and condensate. The following table presents the relevant pricing index for each commodity:


Commodity						Index
NGLs						Oil Price Information Service
Natural gas						Henry Hub Gas Daily
Crude and condensate						New York Mercantile Exchange

The following table sets forth certain information related to derivative instruments outstanding at September 30, 2021. These derivative instruments mitigate 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.March 31, 2022.

Period

Underlying

Notional Volume

We Pay

We Receive (1)

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

~~October 2021~~April 2022 - ~~September 2022~~March 2023

Ethane

~~710~~1,645 (MMbbls)

$~~0.4277/~~0.4280/Gal

Index

~~(1.1)~~(3.7)

~~October 2021~~April 2022 - ~~September 2022~~March 2023

Propane

2,190 (MMbbls)

Index

$~~1.2687/~~1.3296/Gal

~~(35.3)~~(21.3)

~~October 2021~~April 2022 - ~~September 2022~~March 2023

Normal butane

~~770~~465 (MMbbls)

Index

$~~1.4775/~~1.6025/Gal

~~(9.7)~~(4.7)

~~October 2021~~April 2022 - ~~December 2021~~April 2022

Natural gasoline

~~545~~20 (MMbbls)

Index

$~~1.7310/~~2.5327/Gal

~~(8.8)~~—

~~October 2021~~April 2022 - ~~March~~October 2022

Natural gas

~~65,737~~17,699 (MMbtu/d)

Index

$~~5.8769/~~5.6299/MMbtu

~~7.4~~ (1.0)

~~October 2021~~April 2022 - ~~January~~July 2023

Crude and condensate

~~7,075~~8,670 (MMbbls)

Index

$~~72.65/~~93.07/Bbl

~~7.0~~1.1

~~October 2021 - December 2022~~

~~Crude and condensate~~

~~4,504 (MMbbls)~~

~~$1.807/Bbl~~

~~Index (2)~~

~~5.5~~

~~(35.0)~~(29.6)

____________________________

(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

~~Table of Contents~~

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, 2021,~~March 31, 2022, outstanding natural gas swap agreements, NGL swap agreements, swing swap agreements, storage swap agreements, and other derivative instruments had a net fair value liability of ~~$35.0~~$29.6 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 ~~$16.6~~$25.4 million in the net fair value of these contracts as of ~~September 30, 2021.~~March 31, 2022.

Interest Rate Risk

We are exposed to interest rate risk on the ~~Term Loan, the~~ Consolidated Credit Facility and the AR Facility. At ~~September 30, 2021,~~March 31, 2022, we had ~~$150.0 million and $245.0~~$315.0 million in outstanding borrowings under the ~~Term Loan and the~~ AR ~~Facility, respectively.~~Facility. At ~~September 30, 2021,~~March 31, 2022, we had no outstanding borrowings under the Consolidated Credit Facility.

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 were designated as cash flow hedges. In connection with the partial repayments of the Term Loan in September 2021, May 2021, and December 2020, we terminated $700.0 million of the $850.0 million interest rate swaps. See “Item 1. Financial Statements—Note 11” for more information on our outstanding derivatives.

A 1.0% increase or decrease in interest rates would change our annualized interest expense by approximately ~~$1.5 million and $2.5~~$3.2 million for the ~~Term Loan~~AR Facility.

Amounts drawn on the Consolidated Credit Facility and the AR Facility ~~respectively. This change~~currently bear interest at rates based on LIBOR, which is beginning to be phased out. Both the Consolidated Credit Facility and the AR Facility include mechanisms to amend the facilities to reflect the establishment of an alternative to LIBOR, and the AR Facility has been amended to include a specific replacement reference rate alternative. The replacement rate for the AR Facility could result in a higher interest ~~expense~~rate than LIBOR. If no such contractual alternative is established for the Consolidated Credit Facility before the LIBOR phase out is complete, it would bear interest at the prime rate, which would be ~~partially offset by~~higher than LIBOR, until a ~~$1.5 million change related to our open interest rate swap hedge.~~contractual alternative is established.

We are not exposed to changes in interest rates with respect to ENLK’s senior unsecured notes due in 2024, 2025, 2026, 2044, 2045, or 2047 or our senior unsecured notes due in 2028 and 2029 as these are fixed-rate obligations. As of ~~September 30, 2021,~~March 31,

Table of Contents

2022, the estimated fair value of the senior unsecured notes was approximately ~~$4,071.7~~$3,839.6 million, based on the market prices of ENLK’s and our publicly traded debt at ~~September 30, 2021.~~March 31, 2022. 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 ~~$252.2~~$240.8 million decrease in fair value of the senior unsecured notes at ~~September 30, 2021.~~March 31, 2022. See “Item 1. Financial Statements—Note 5” for more information on our outstanding indebtedness.

Beginning on December 15, 2022, distributions on ENLK's Series C Preferred Units will be based on a floating rate tied to LIBOR plus 4.11% rather than a fixed rate and, therefore, the amount paid by ENLK as a distribution will be more sensitive to changes in interest rates.

Item 4. Controls and Procedures

a.Evaluation of Disclosure Controls and Procedures

Management of the Managing Member is responsible for establishing and maintaining adequate internal control over financial reporting and for the assessment of the effectiveness of internal control over financial reporting for us. We carried out an evaluation, under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer of the Managing Member, 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, 2021)~~(March 31, 2022), 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 Exchange Act 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 our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding 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, 2021~~March 31, 2022 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

5550

Table of Contents

PART II—OTHER INFORMATION

Item 1. Legal Proceedings

We are involved in various litigation and administrative proceedings arising in the normal course of business. For a discussion of certain litigation and similar proceedings, please refer to Note ~~15,~~14, “Commitments and Contingencies,” of the Notes to Consolidated Financial Statements contained in Part I of this Quarterly Report on Form 10-Q, which is incorporated by reference herein.

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, ~~2020.~~2021 filed with the Commission on February 16, 2022.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

During the three months ended ~~September 30, 2021,~~March 31, 2022, we re-acquired ENLC common units from certain employees in order to satisfy the employees’ tax liability in connection with the vesting of restricted incentive ~~units.~~units and we repurchased common units in open market transactions in connection with our common unit repurchase program.

Period Total Number of Units Purchased (1) Average Price Paid Per Unit Total Number of Units Purchased as Part of Publicly Announced Plans or Programs (2) Maximum Dollar Value of Units that May Yet Be Purchased under the Plans or Programs (in millions) (2)
July 1, 2021 to July 31, 2021 1,270,453 $ 6.35 1,268,827 $ 88.9
August 1, 2021 to August 31, 2021 400,231 5.38 313,583 $ 87.2
September 1, 2021 to September 30, 2021 495,708 5.61 494,135 $ 84.3
Total 2,166,392 $ 6.00 2,076,545


Period	Total Number of Units Purchased (1)	Average Price Paid Per Unit		Total Number of Units Purchased as Part of Publicly Announced Plans or Programs (2)	Maximum Dollar Value of Units that May Yet Be Purchased under the Plans or Programs (in millions) (2)
January 1, 2022 to January 31, 2022	1,625,954	$	7.57	1,148,473	$	91.3
February 1, 2022 to February 28, 2022	350,084	8.04		346,816	$	88.5
March 1, 2022 to March 31, 2022	670,027	9.14		598,553	$	83.0
Total	2,646,065	$	8.03	2,093,842

____________________________

(1)The total number of units purchased shown in the table includes ~~89,847~~552,223 units received by us from employees for the payment of personal income tax withholding on vesting transactions.

(2)~~On November 4, 2020, we announced a $100.0 million~~Effective January 1, 2022, the Board reauthorized our common unit repurchase ~~program. As~~program and reset the amount available for repurchases of ~~September 30, 2021,~~outstanding common units at up to $100.0 million. For the three months ended March 31, 2022, we repurchased a total of ~~2,777,910~~2,093,842 common units for an aggregate cost of ~~$15.7~~$17.0 million, or an average of ~~$5.63~~$8.12 per common ~~unit.~~unit under such program. Future repurchases under the program may be made from time to time in open market or private transactions and may be made pursuant to a trading plan meeting the requirements of Rule 10b5-1 under the Exchange Act. The repurchases will depend on market conditions and may be discontinued at any time. On February 15, 2022, we and GIP entered into an agreement pursuant to which we will repurchase, on a quarterly basis, a pro rata portion of the ENLC common units held by GIP, based upon the number of common units purchased by us during the applicable quarter from public unitholders under our common unit repurchase program. The number of ENLC common units held by GIP that we repurchase in any quarter will be calculated such that GIP’s then-existing economic ownership percentage of our outstanding common units is maintained after our repurchases of common units from public unitholders are taken into account, and the per unit price we pay to GIP will be the average per unit price paid by us for the common units repurchased from public unitholders. On May 2, 2022, we repurchased 675,095 ENLC common units held by GIP for an aggregate cost of $6.0 million, or an average of $8.92 per common unit. These units represent GIP’s pro rata share of the aggregate number of common units repurchased by us under our common unit repurchase program during the period from February 15, 2022 (the date on which the Repurchase Agreement was signed) through March 31, 2022. The $8.92 price per common unit is the average per unit price paid by us for the common units repurchased from public unitholders during the same period. For more information about our repurchase agreement with GIP, see Part II, “9B. Other Information” of our Annual Report on Form 10-K for the year ended December 31, 2021 filed with the Commission on February 16, 2022.

5651

Table of Contents

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 Formation of EnLink Midstream, LLC (incorporated by reference to Exhibit 3.1 to our Registration Statement on Form S-4, filed with the Commission on November 20, 2013, file No. 333-192419).
3.2	—	Certificate of Amendment to Certificate of Formation of EnLink Midstream, LLC (incorporated by reference to Exhibit 3.2 to Amendment No. 2 to our Registration Statement on Form S-4, filed with the Commission on January 21, 2014, file No. 333-192419).
3.3	—	Second Amended and Restated Operating Agreement of EnLink Midstream, LLC, 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. 001-36336).
3.4	—	Certificate of Formation of EnLink Midstream Manager, LLC (incorporated by reference to Exhibit 3.12 to our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2014, filed with the Commission on August 6, 2014, file No. 001-36336).
3.5	—	Certificate of Amendment to the Certificate of Formation of EnLink Midstream Manager, LLC (incorporated by reference to Exhibit 3.13 to our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2014, filed with the Commission on August 6, 2014, file No. 001-36336).
3.6	—	Second Amended and Restated Limited Liability Company Agreement of EnLink Midstream Manager, 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. 001-36336).
3.7	—	Certificate of Formation of EnLink Midstream GP, LLC (incorporated by reference to Exhibit 3.7 to EnLink Midstream Partners, LP’s Registration Statement on Form S-1, file No. 333-97779).
3.8	—	Certificate of Amendment to the Certificate of Formation of EnLink Midstream GP, LLC (incorporated by reference to Exhibit 3.12 to EnLink Midstream Partners, LP’s Registration Statement on Form S-3, filed with the Commission on March 10, 2014, file No. 333-194465).
3.9	—	Fourth Amended and Restated Limited Liability Company Agreement of EnLink Midstream GP, LLC, dated as of July 18, 2018 (incorporated by reference to Exhibit 3.2 to our Current Report on Form 8-K dated July 17, 2018, filed with the Commission on July 23, 2018, file No. 001-36366).
3.10	—	Certificate of Limited Partnership of EnLink Midstream Partners, LP (incorporated by reference to Exhibit 3.1 to EnLink Midstream Partners, LP’s Registration Statement on Form S-1, filed with the Commission on August 7, 2012, file No. 333-97779).
3.11	—	Certificate of Amendment to the Certificate of Limited Partnership of EnLink Midstream Partners, LP (incorporated by reference to Exhibit 3.2 to EnLink Midstream Partners, LP’s 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).
3.12	—	Second Amendment to the Certificate of Limited Partnership of EnLink Midstream Partners, LP (incorporated by reference to Exhibit 3.3 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated March 6, 2014, filed with the Commission on March 11, 2014, file No. 001-36340).
3.13	—	Third Amendment to the Certificate of Limited Partnership of EnLink Midstream Partners, LP (incorporated by reference to Exhibit 3.1 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated June 16, 2017, filed with the Commission on June 19, 2017, file No. 001-36340).
3.14	—	Tenth Amended and Restated Agreement of Limited Partnership of EnLink Midstream Partners, LP, dated as of January 25, 2019 (incorporated by reference to Exhibit 3.2 to our Current Report on Form 8-K dated January 25, 2019, filed with the Commission on January 29, 2019, file No. 001-36336).
















10.1†	—	EnLink Midstream, LLC 2014 Long-Term Incentive Plan, as amended and restated December 28, 2020 (the “2014 Plan”) (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K dated December 7, 2020 filed with the Commission on December 9, 2020, file No. 001-36336).
~~10.2~~	—	~~Second Amendment to the Receivables Financing~~Unit Repurchase Agreement, dated as of ~~September 24, 2021, by and among~~February 15, 2022 between EnLink Midstream, ~~Funding,~~ LLC, ~~as borrower, EnLink Midstream Operating, LP, as initial servicer,~~GIP III Stetson I, L.P. and ~~PNC Bank, National Association, as administrative agent and as lender and PNC Capital Markets LLC, as structuring agent and sustainability agent~~GIP III Stetson II, L.P. (incorporated by reference to Exhibit ~~10.1~~10.20 to our ~~Current~~Annual Report on Form ~~8-K dated September 24,~~10-K for the year ended December 31, 2021, filed with the Commission on ~~September 27, 2021,~~February 16, 2022, file No. 001-36336).
22.1	—	Subsidiary Guarantors (incorporated by reference to Exhibit 22.1 to our Annual Report on Form 10-K ~~dated~~for the year ended December 31, ~~2020,~~2021, filed with the Commission on February ~~17, 2021,~~16, 2022, file No. 001-36336).
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, LLC's Quarterly Report on Form 10-Q for the quarter ended ~~September 30, 2021,~~March 31, 2022, formatted in iXBRL (Inline eXtensible Business Reporting Language): (i) Consolidated Balance Sheets as of ~~September 30, 2021~~March 31, 2022 and December 31, ~~2020,~~2021, (ii) Consolidated Statements of Operations for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2022 and 2021, ~~and 2020,~~ (iii) Consolidated Statements of Changes in Members’ Equity for the three months ended ~~September 30, 2021 and 2020, June 30, 2021 and 2020, and~~ March 31, ~~2021~~2022 and ~~2020,~~2021, (iv) Consolidated Statements of Cash Flows for the ~~nine~~three months ended ~~September 30,~~March 31, 2022 and 2021, ~~and 2020,~~ 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 17 CFR § 232.105(d)(2) this exhibit is being provided to correct non-functioning hyperlinks corresponding to exhibit 10.3 in our Annual Report on Form 10-K filed with the Commission on February 17, 2021.

5752

Table of Contents

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, LLC

	By:	EnLink Midstream Manager, LLC, its managing member

	By:	/s/ J. PHILIPP ROSSBACH
		J. Philipp Rossbach
		Vice President and Chief Accounting Officer
		(Principal Accounting Officer)
~~November 3, 2021~~May 4, 2022

5853


Item	Item	Description	Page	Item	Description	Page

		PART I—FINANCIAL INFORMATION			PART I—FINANCIAL INFORMATION

1.	1.	Financial Statements	5	1.	Financial Statements	5

2.	2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	32	2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	29

3.	3.	Quantitative and Qualitative Disclosures About Market Risk	53	3.	Quantitative and Qualitative Disclosures About Market Risk	47

4.	4.	Controls and Procedures	55	4.	Controls and Procedures	50

		PART II—OTHER INFORMATION			PART II—OTHER INFORMATION

1.	1.	Legal Proceedings	56	1.	Legal Proceedings	51

1A.	1A.	Risk Factors	56	1A.	Risk Factors	51

2.	2.	Unregistered Sales of Equity Securities and Use of Proceeds	56	2.	Unregistered Sales of Equity Securities and Use of Proceeds	51

6.	6.	Exhibits	57	6.	Exhibits	52


Contractually Committed Fees	Commitments (1)
2021 (remaining)	$	38.9
2022	136.3
2023	123.5
2024	107.6
2025	63.7
Thereafter	347.3
Total	$	817.3


ENLC Performance Units:	January 2021			July 2020			March 2020			January 2020
Grant-date fair value	$	4.70		$	2.33		$	1.13		$	7.69
Beginning TSR price	$	3.71		$	2.52		$	1.25		$	6.13
Risk-free interest rate	0.17		%	0.17		%	0.42		%	1.62		%
Volatility factor	71.00		%	67.00		%	51.00		%	37.00		%


	Payments Due by Period
	Total		Remainder 2021		2022		2023		2024		2025		Thereafter
ENLC’s & ENLK’s senior unsecured notes	$	4,032.3	$	—	$	—	$	—	$	521.8	$	720.8	$	2,789.7
Term Loan (1)	150.0		150.0		—		—		—		—		—
Consolidated Credit Facility (2)	—		—		—		—		—		—		—
AR Facility (3)	245.0		—		—		—		245.0		—		—
Acquisition installment payable (4)	10.0				10.0		—		—		—		—
Acquisition contingent consideration (5)	6.9		—		—		—		2.3		2.4		2.2
Interest payable on fixed long-term debt obligations	2,409.6		74.6		201.2		201.2		189.7		163.3		1,579.6
Operating lease obligations	113.2		5.2		17.0		11.6		10.1		9.8		59.5
Purchase obligations	4.4		4.4		—		—		—		—		—
Pipeline and trucking capacity and deficiency agreements (6)	176.0		12.4		46.6		38.7		29.2		24.8		24.3
Inactive easement commitment (7)	10.0		—		10.0		—		—		—		—
Total contractual obligations	$	7,157.4	$	246.6	$	284.8	$	251.5	$	998.1	$	921.1	$	4,455.3