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 ~~June~~September 30, 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 ~~July 28,~~October 27, 2022, the Registrant had ~~478,933,388~~473,596,120 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. 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.
Agua Blanca Pipeline						The Agua Blanca Pipeline is a Delaware Basin intrastate natural gas pipeline servicing portions of Culberson, Loving, Pecos, Reeves, Ward, and Winkler counties and is owned by a joint venture between WhiteWater Midstream, LLC and MPLX LP.
Amarillo Rattler Acquisition						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.
AR Facility						An accounts receivable securitization facility of up to $500 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 August 1, 2025, unless extended or earlier terminated in accordance with its terms.
ASC						The 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.
Barnett Shale						A natural gas producing shale reservoir located in North Texas.
Bbl						Barrel.
Bcf						Billion cubic feet.
Beginning TSR Price						The beginning total shareholder return (“TSR”) price, which is the closing 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.
BKV						BKV Corporation.
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.
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.


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.”
Exchange Act						The Securities Exchange Act of 1934, as amended.
ExxonMobil						ExxonMobil Corporation.
GAAP						Generally accepted accounting principles in the United States of America.
Gal						Gallon.

Table of Contents


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.~~

~~Table of Contents~~


General Partner						EnLink Midstream GP, LLC, the general partner of ENLK.
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.
Mbbls						Thousand barrels.
MMbbls						Million barrels.
MMbtu						Million British thermal units.
MMcf						Million cubic feet.
MMgals						Million gallons.
MVC						Minimum volume commitment.
NGL						Natural gas liquid.
NGP						NGP Natural Resources XI, LP.

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 primarily in West Texas and New Mexico.
POL contracts						Percentage-of-liquids contracts.
POP contracts						Percentage-of-proceeds contracts.
Revolving Credit Facility						A $1.40 billion unsecured revolving credit facility entered into by ENLC that matures on June 3, 2027, which includes a $500.0 million letter of credit subfacility. The Revolving Credit Facility is guaranteed by ENLK.

Series B Preferred Unit						ENLK’s Series B Cumulative Convertible Preferred Unit.
Series C Preferred Unit						ENLK’s Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Unit.
SOFR						Secured overnight financing rate.
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 guaranteed. The Term Loan was paid upon maturity on December 10, 2021.

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PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Consolidated Balance Sheets

(In millions, except unit data)


		June 30, 2022		December 31, 2021			September 30, 2022		December 31, 2021
		(Unaudited)					(Unaudited)
ASSETS	ASSETS					ASSETS
Current assets:	Current assets:					Current assets:
Cash and cash equivalents	Cash and cash equivalents	$	18.1	$	26.2	Cash and cash equivalents	$	—	$	26.2
Accounts receivable:	Accounts receivable:					Accounts receivable:
Trade, net of allowance for bad debt of $0.3 and $0.3, respectively		101.1		94.9
Trade, net of allowance for bad debt of $0.1 and $0.3, respectively						Trade, net of allowance for bad debt of $0.1 and $0.3, respectively	137.0		94.9
Accrued revenue and other	Accrued revenue and other	913.7		693.3		Accrued revenue and other	810.6		693.3

Fair value of derivative assets	Fair value of derivative assets	95.6		22.4		Fair value of derivative assets	76.2		22.4
Other current assets	Other current assets	159.7		83.6		Other current assets	175.0		83.6
Total current assets	Total current assets	1,288.2		920.4		Total current assets	1,198.8		920.4
Property and equipment, net of accumulated depreciation of $4,570.4 and $4,332.0, respectively		6,259.0		6,388.3
Intangible assets, net of accumulated amortization of $859.8 and $795.1, respectively		985.0		1,049.7
Property and equipment, net of accumulated depreciation of $4,694.2 and $4,332.0, respectively						Property and equipment, net of accumulated depreciation of $4,694.2 and $4,332.0, respectively	6,497.7		6,388.3
Intangible assets, net of accumulated amortization of $891.7 and $795.1, respectively						Intangible assets, net of accumulated amortization of $891.7 and $795.1, respectively	953.1		1,049.7

Investment in unconsolidated affiliates	Investment in unconsolidated affiliates	53.0		28.0		Investment in unconsolidated affiliates	71.6		28.0
Fair value of derivative assets	Fair value of derivative assets	—		0.2		Fair value of derivative assets	0.7		0.2
Other assets, net	Other assets, net	93.6		96.6		Other assets, net	91.4		96.6
Total assets	Total assets	$	8,678.8	$	8,483.2	Total assets	$	8,813.3	$	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	$	177.9	$	139.6	Accounts payable and drafts payable	$	208.7	$	139.6

Accrued gas, NGLs, condensate, and crude oil purchases (1)	Accrued gas, NGLs, condensate, and crude oil purchases (1)	768.9		521.5		Accrued gas, NGLs, condensate, and crude oil purchases (1)	678.1		521.5
Fair value of derivative liabilities	Fair value of derivative liabilities	88.7		34.9		Fair value of derivative liabilities	52.2		34.9
Other current liabilities	Other current liabilities	184.1		202.9		Other current liabilities	218.3		202.9
Total current liabilities	Total current liabilities	1,219.6		898.9		Total current liabilities	1,157.3		898.9
Long-term debt, net of unamortized issuance cost	Long-term debt, net of unamortized issuance cost	4,320.0		4,363.7		Long-term debt, net of unamortized issuance cost	4,537.4		4,363.7

Other long-term liabilities	Other long-term liabilities	93.3		93.9		Other long-term liabilities	90.2		93.9
Deferred tax liability, net	Deferred tax liability, net	138.7		137.5		Deferred tax liability, net	153.6		137.5
Fair value of derivative liabilities	Fair value of derivative liabilities	1.2		2.2		Fair value of derivative liabilities	0.8		2.2

Members’ equity:	Members’ equity:					Members’ equity:
Members’ equity (479,825,804 and 484,277,258 units issued and outstanding, respectively)		1,293.3		1,325.8
Members’ equity (474,566,135 and 484,277,258 units issued and outstanding, respectively)						Members’ equity (474,566,135 and 484,277,258 units issued and outstanding, respectively)	1,259.2		1,325.8
Accumulated other comprehensive loss	Accumulated other comprehensive loss	(1.3)		(1.4)		Accumulated other comprehensive loss	(1.3)		(1.4)
Non-controlling interest	Non-controlling interest	1,614.0		1,662.6		Non-controlling interest	1,616.1		1,662.6
Total members’ equity	Total members’ equity	2,906.0		2,987.0		Total members’ equity	2,874.0		2,987.0
Commitments and contingencies (Note 15)		0		0
Commitments and contingencies (Note 16)						Commitments and contingencies (Note 16)
Total liabilities and members’ equity	Total liabilities and members’ equity	$	8,678.8	$	8,483.2	Total liabilities and members’ equity	$	8,813.3	$	8,483.2

____________________________

(1)Includes related party accounts payable balances of ~~$5.7~~$4.3 million and $1.6 million at ~~June~~September 30, 2022 and December 31, 2021, respectively.

See accompanying notes to consolidated financial statements.

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Consolidated Statements of Operations

(In millions, except per unit data)


		Three Months Ended June 30,				Six Months Ended June 30,					Three Months Ended September 30,				Nine Months Ended September 30,
		2022		2021		2022		2021			2022		2021		2022		2021
		(Unaudited)									(Unaudited)
Revenues:	Revenues:									Revenues:
Product sales	Product sales	$	2,370.5	$	1,235.6	$	4,414.4	$	2,358.5	Product sales	$	2,384.4	$	1,610.2	$	6,798.8	$	3,968.7

Midstream services	Midstream services	225.6		209.3		440.6		418.2		Midstream services	258.6		211.0		699.2		629.2

Gain (loss) on derivative activity	Gain (loss) on derivative activity	4.5		(38.2)		(26.7)		(121.6)		Gain (loss) on derivative activity	20.5		(33.6)		(6.2)		(155.2)
Total revenues	Total revenues	2,600.6		1,406.7		4,828.3		2,655.1		Total revenues	2,663.5		1,787.6		7,491.8		4,442.7
Operating costs and expenses:	Operating costs and expenses:									Operating costs and expenses:
Cost of sales, exclusive of operating expenses and depreciation and amortization (1)	Cost of sales, exclusive of operating expenses and depreciation and amortization (1)	2,105.1		1,055.1		3,899.6		1,989.8		Cost of sales, exclusive of operating expenses and depreciation and amortization (1)	2,131.1		1,400.8		6,030.7		3,390.6
Operating expenses	Operating expenses	128.9		96.8		249.8		153.1		Operating expenses	136.8		106.9		386.6		260.0
Depreciation and amortization	Depreciation and amortization	159.0		151.9		311.9		302.9		Depreciation and amortization	162.6		153.0		474.5		455.9

(Gain) loss on disposition of assets	(Gain) loss on disposition of assets	(0.4)		(0.3)		4.7		(0.3)		(Gain) loss on disposition of assets	(0.8)		(0.4)		3.9		(0.7)
General and administrative	General and administrative	28.4		26.1		57.4		52.1		General and administrative	34.5		28.2		91.9		80.3

Total operating costs and expenses	Total operating costs and expenses	2,421.0		1,329.6		4,523.4		2,497.6		Total operating costs and expenses	2,464.2		1,688.5		6,987.6		4,186.1
Operating income	Operating income	179.6		77.1		304.9		157.5		Operating income	199.3		99.1		504.2		256.6
Other income (expense):	Other income (expense):									Other income (expense):
Interest expense, net of interest income	Interest expense, net of interest income	(55.5)		(60.0)		(110.6)		(120.0)		Interest expense, net of interest income	(60.4)		(60.1)		(171.0)		(180.1)
Loss on extinguishment of debt	Loss on extinguishment of debt	(0.5)		—		(0.5)		—		Loss on extinguishment of debt	(5.7)		—		(6.2)		—
Loss from unconsolidated affiliate investments	Loss from unconsolidated affiliate investments	(1.2)		(1.3)		(2.3)		(7.6)		Loss from unconsolidated affiliate investments	(1.7)		(2.3)		(4.0)		(9.9)
Other income	Other income	0.2		0.2		0.3		0.1		Other income	0.3		—		0.6		0.1
Total other expense	Total other expense	(57.0)		(61.1)		(113.1)		(127.5)		Total other expense	(67.5)		(62.4)		(180.6)		(189.9)
Income before non-controlling interest and income taxes	Income before non-controlling interest and income taxes	122.6		16.0		191.8		30.0		Income before non-controlling interest and income taxes	131.8		36.7		323.6		66.7
Income tax benefit (expense)		1.3		(6.6)		(1.9)		(8.0)
Income tax expense										Income tax expense	(15.2)		(4.4)		(17.1)		(12.4)
Net income	Net income	123.9		9.4		189.9		22.0		Net income	116.6		32.3		306.5		54.3
Net income attributable to non-controlling interest	Net income attributable to non-controlling interest	38.6		31.0		69.4		56.3		Net income attributable to non-controlling interest	35.8		30.4		105.2		86.7
Net income (loss) attributable to ENLC	Net income (loss) attributable to ENLC	$	85.3	$	(21.6)	$	120.5	$	(34.3)	Net income (loss) attributable to ENLC	$	80.8	$	1.9	$	201.3	$	(32.4)
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	$	0.18	$	(0.04)	$	0.25	$	(0.07)	Basic common unit	$	0.17	$	—	$	0.42	$	(0.07)
Diluted common unit	Diluted common unit	$	0.17	$	(0.04)	$	0.25	$	(0.07)	Diluted common unit	$	0.17	$	—	$	0.41	$	(0.07)

____________________________

(1)Includes related party cost of sales of ~~$9.1~~$5.6 million and ~~$3.6~~$4.9 million for the three months ended ~~June~~September 30, 2022 and 2021, respectively, and ~~$19.7~~$25.3 million and ~~$6.8~~$11.7 million for the ~~six~~nine months ended ~~June~~September 30, 2022 and 2021, respectively.

See accompanying notes to consolidated financial statements.

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Consolidated Statements of Comprehensive Income

(In millions)


		Three Months Ended June 30,				Six Months Ended June 30,					Three Months Ended September 30,				Nine Months Ended September 30,
		2022		2021		2022		2021			2022		2021		2022		2021
		(Unaudited)									(Unaudited)
Net income	Net income	$	123.9	$	9.4	$	189.9	$	22.0	Net income	$	116.6	$	32.3	$	306.5	$	54.3
Unrealized gain on designated cash flow hedge (1)	Unrealized gain on designated cash flow hedge (1)	—		3.7		0.1		7.3		Unrealized gain on designated cash flow hedge (1)	—		3.8		0.1		11.1
Comprehensive income	Comprehensive income	123.9		13.1		190.0		29.3		Comprehensive income	116.6		36.1		306.6		65.4
Comprehensive income attributable to non-controlling interest	Comprehensive income attributable to non-controlling interest	38.6		31.0		69.4		56.3		Comprehensive income attributable to non-controlling interest	35.8		30.4		105.2		86.7
Comprehensive income (loss) attributable to ENLC	Comprehensive income (loss) attributable to ENLC	$	85.3	$	(17.9)	$	120.6	$	(27.0)	Comprehensive income (loss) attributable to ENLC	$	80.8	$	5.7	$	201.4	$	(21.3)

____________________________

(1)Includes tax expense of ~~$1.1~~$1.2 million and ~~$2.2~~$3.4 million for the three and ~~six~~nine months ended ~~June~~September 30, 2021, respectively.

See accompanying notes to consolidated financial statements.

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Consolidated Statements of Changes in Members’ Equity

(In millions)

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
Conversion of restricted units for common units, net of units withheld for taxes (0.2) — — — (0.2)
Unit-based compensation 5.7 — — — 5.7
Contributions from non-controlling interests — — — 2.0 2.0
Distributions (55.3) — — (42.2) (97.5)
Common units repurchased (33.7) (3.6) — — (33.7)
Net income 85.3 — — 38.6 123.9
Balance, June 30, 2022 $ 1,293.3 479.8 $ (1.3) $ 1,614.0 $ 2,906.0


	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 unit-based awards 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
Conversion of unit-based awards for common units, net of units withheld for taxes	(0.2)		—	—		—		(0.2)
Unit-based compensation	5.7		—	—		—		5.7
Contributions from non-controlling interests	—		—	—		2.0		2.0
Distributions	(55.3)		—	—		(42.2)		(97.5)

Common units repurchased	(33.7)		(3.6)	—		—		(33.7)
Net income	85.3		—	—		38.6		123.9
Balance, June 30, 2022	1,293.3		479.8	(1.3)		1,614.0		2,906.0
Conversion of unit-based awards for common units, net of units withheld for taxes	(8.1)		1.4	—		—		(8.1)
Unit-based compensation	11.4		—	—		—		11.4
Contributions from non-controlling interests	—		—	—		4.9		4.9
Distributions	(55.7)		—	—		(38.6)		(94.3)

Common units repurchased	(62.5)		(6.6)	—		—		(62.5)
Net income	80.8		—	—		35.8		116.6
Balance, September 30, 2022	$	1,259.2	474.6	$	(1.3)	$	1,616.1	$	2,874.0

See accompanying notes to consolidated financial statements.

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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, 2020	Balance, December 31, 2020	$	1,508.8	489.4	$	(15.3)	$	1,719.5	$	3,213.0	$	—	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)		—
Conversion of unit-based awards for common units, net of units withheld for taxes													Conversion of unit-based awards for common units, net of units withheld for taxes	(1.2)		0.7	—		—		(1.2)		—
Unit-based compensation	Unit-based compensation	6.5		—	—		—		6.5		—		Unit-based compensation	6.5		—	—		—		6.5		—
Contributions from non-controlling interests	Contributions from non-controlling interests	—		—	—		0.9		0.9		—		Contributions from non-controlling interests	—		—	—		0.9		0.9		—
Distributions	Distributions	(47.1)		—	—		(25.8)		(72.9)		(0.2)		Distributions	(47.1)		—	—		(25.8)		(72.9)		(0.2)
Unrealized gain on designated cash flow hedge (1)	Unrealized gain on designated cash flow hedge (1)	—		—	3.6		—		3.6		—		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	(0.1)		—	—		—		(0.1)		0.2		Fair value adjustment related to redeemable non-controlling interest	(0.1)		—	—		—		(0.1)		0.2

Net income (loss)	Net income (loss)	(12.7)		—	—		25.3		12.6		—		Net income (loss)	(12.7)		—	—		25.3		12.6		—
Balance, March 31, 2021	Balance, March 31, 2021	1,454.2		490.1	(11.7)		1,719.9		3,162.4		—		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)		—
Conversion of unit-based awards for common units, net of units withheld for taxes													Conversion of unit-based awards for common units, net of units withheld for taxes	(0.2)		0.1	—		—		(0.2)		—
Unit-based compensation	Unit-based compensation	6.4		—	—		—		6.4		—		Unit-based compensation	6.4		—	—		—		6.4		—
Contributions from non-controlling interests	Contributions from non-controlling interests	—		—	—		1.0		1.0		—		Contributions from non-controlling interests	—		—	—		1.0		1.0		—
Distributions	Distributions	(46.7)		—	—		(36.0)		(82.7)		—		Distributions	(46.7)		—	—		(36.0)		(82.7)		—
Unrealized gain on designated cash flow hedge (2)	Unrealized gain on designated cash flow hedge (2)	—		—	3.7		—		3.7		—		Unrealized gain on designated cash flow hedge (2)	—		—	3.7		—		3.7		—
Common units repurchased	Common units repurchased	(2.0)		(0.3)	—		—		(2.0)		—		Common units repurchased	(2.0)		(0.3)	—		—		(2.0)		—
Net income (loss)	Net income (loss)	(21.6)		—	—		31.0		9.4		—		Net income (loss)	(21.6)		—	—		31.0		9.4		—
Balance, June 30, 2021	Balance, June 30, 2021	$	1,390.1	489.9	$	(8.0)	$	1,715.9	$	3,098.0	$	—	Balance, June 30, 2021	1,390.1		489.9	(8.0)		1,715.9		3,098.0		—
Conversion of unit-based awards for common units, net of units withheld for taxes													Conversion of unit-based awards for common units, net of units withheld for taxes	(0.5)		0.2	—		—		(0.5)		—
Unit-based compensation													Unit-based compensation	6.4		—	—		—		6.4		—
Contributions from non-controlling interests													Contributions from non-controlling interests	—		—	—		0.5		0.5		—
Distributions													Distributions	(46.6)		—	—		(26.2)		(72.8)		—
Unrealized gain on designated cash flow hedge (3)													Unrealized gain on designated cash flow hedge (3)	—		—	3.8		—		3.8		—

Common units repurchased													Common units repurchased	(12.5)		(2.1)	—		—		(12.5)		—
Net income													Net income	1.9		—	—		30.4		32.3		—
Balance, September 30, 2021													Balance, September 30, 2021	$	1,338.8	488.0	$	(4.2)	$	1,720.6	$	3,055.2	$	—

____________________________

(1)Includes tax expense of $1.1 million.

(2)Includes tax expense of $1.1 million.

(3)

Includes tax expense of $1.2 million.

See accompanying notes to consolidated financial statements.

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Consolidated Statements of Cash Flows

(In millions)
Six Months Ended
June 30,
2022 2021
(Unaudited)
Cash flows from operating activities:
Net income $ 189.9 $ 22.0
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization 311.9 302.9
Utility credits redeemed (earned) 11.6 (43.8)
Deferred income tax expense 1.2 7.9
(Gain) Loss on disposition of assets 4.7 (0.3)
Non-cash unit-based compensation 12.3 12.9
Amortization of designated cash flow hedge 0.1 6.0
Payments to terminate interest rate swaps — (1.3)
Non-cash (gain) loss on derivatives recognized in net income (18.6) 34.2
Loss on extinguishment of debt 0.5 —
Amortization of debt issuance costs and net discount of senior unsecured notes 2.6 2.5
Loss from unconsolidated affiliate investments 2.3 7.6
Other operating activities (2.0) (2.5)
Changes in assets and liabilities:
Accounts receivable, accrued revenue, and other (226.7) (61.4)
Natural gas and NGLs inventory, prepaid expenses, and other (83.2) (47.8)
Accounts payable, accrued product purchases, and other accrued liabilities 276.0 163.3
Net cash provided by operating activities 482.6 402.2
Cash flows from investing activities:
Additions to property and equipment (124.1) (62.5)
Contributions to unconsolidated affiliate investments (26.6) —
Acquisitions, net of cash acquired — (55.0)
Distribution from unconsolidated affiliate investments in excess of earnings 0.4 3.7
Other investing activities 1.0 1.6
Net cash used in investing activities (149.3) (112.2)
Cash flows from financing activities:
Proceeds from borrowings 1,135.0 539.5
Repayments on borrowings (1,177.0) (679.5)
Distributions to members (111.7) (93.8)
Distributions to non-controlling interests (76.8) (62.0)
Payment of installment payable for the Amarillo Rattler Acquisition (10.0) —
Redemption of Series B Preferred Units (50.5) —
Contributions from non-controlling interests 9.3 1.9
Common unit repurchases (50.7) (2.0)
Other financing activities (9.0) (0.9)
Net cash used in financing activities (341.4) (296.8)
Net decrease in cash and cash equivalents (8.1) (6.8)
Cash and cash equivalents, beginning of period 26.2 39.6
Cash and cash equivalents, end of period $ 18.1 $ 32.8
Supplemental disclosures of cash flow information:
Cash paid for interest $ 107.8 $ 97.1
Cash paid for income taxes $ 0.8 $ 0.2
Non-cash investing activities:
Non-cash accrual of property and equipment $ (1.6) $ 6.9
Non-cash acquisitions $ — $ 16.5
Right-of-use assets obtained in exchange for operating lease liabilities $ 15.3 $ 10.7


	Nine Months Ended September 30,
	2022		2021
	(Unaudited)
Cash flows from operating activities:
Net income	$	306.5	$	54.3
Adjustments to reconcile net income to net cash provided by operating activities:

Depreciation and amortization	474.5		455.9
Utility credits redeemed (earned)	27.9		(38.2)
Deferred income tax expense	16.1		12.2
(Gain) Loss on disposition of assets	3.9		(0.7)
Non-cash unit-based compensation	23.7		19.3
Amortization of designated cash flow hedge	0.1		9.6
Non-cash (gain) loss on derivatives recognized in net income	(36.5)		37.5
Loss on extinguishment of debt	6.2		—
Amortization of debt issuance costs and net discount of senior unsecured notes	3.7		3.9


Loss from unconsolidated affiliate investments	4.0		9.9
Other operating activities	(4.7)		(4.2)
Changes in assets and liabilities:
Accounts receivable, accrued revenue, and other	(142.7)		(196.5)
Natural gas and NGLs inventory, prepaid expenses, and other	(112.9)		(80.3)
Accounts payable, accrued product purchases, and other accrued liabilities	256.1		316.5
Net cash provided by operating activities	825.9		599.2
Cash flows from investing activities:
Additions to property and equipment	(213.2)		(104.7)


Contributions to unconsolidated affiliate investments	(46.3)		—
Acquisitions, net of cash acquired	(289.5)		(56.7)
Other investing activities	2.0		6.0
Net cash used in investing activities	(547.0)		(155.4)
Cash flows from financing activities:
Proceeds from borrowings	3,431.5		829.5
Repayments on borrowings	(3,265.0)		(1,034.5)
Debt financing costs	(13.4)		(0.1)
Payment of installment payable for the Amarillo Rattler Acquisition	(10.0)		—
Payment of inactive easement commitment	(10.0)		—
Distributions to members	(167.4)		(140.4)
Distributions to non-controlling interests	(115.4)		(88.2)
Redemption of Series B Preferred Units	(50.5)		—
Contributions from non-controlling interests	14.2		2.4
Common unit repurchases	(113.2)		(14.5)
Conversion of unit-based awards for common units, net of units withheld for taxes	(12.5)		(1.9)
Other financing activities	6.6		0.4
Net cash used in financing activities	(305.1)		(447.3)
Net decrease in cash and cash equivalents	(26.2)		(3.5)
Cash and cash equivalents, beginning of period	26.2		39.6
Cash and cash equivalents, end of period	$	—	$	36.1

Supplemental disclosures of cash flow information:
Cash paid for interest	$	152.4	$	130.1
Cash paid for income taxes	$	0.7	$	0.2
Non-cash investing activities:
Non-cash accrual of property and equipment	$	2.5	$	5.1
Non-cash acquisitions	$	—	$	16.9
Right-of-use assets obtained in exchange for operating lease liabilities	$	22.0	$	10.7

See accompanying notes to consolidated financial statements.

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements

~~June~~September 30, 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.

As of ~~June~~September 30, 2022, our midstream energy asset network includes approximately ~~12,100~~12,500 miles of pipelines, 2225 natural gas processing plants with approximately ~~5.5~~5.9 Bcf/d of processing capacity, 7seven fractionators with approximately 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.

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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.

(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, 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. 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	Contractually Committed Fees	Commitments		Contractually Committed Fees	Commitments
2022 (remaining)	2022 (remaining)	$	69.6	2022 (remaining)	$	34.4
2023	2023	119.7		2023	126.2
2024	2024	99.9		2024	99.6
2025	2025	67.0		2025	67.1
2026	2026	59.9		2026	59.9
Thereafter	Thereafter	290.9		Thereafter	293.6
Total	Total	$	707.0	Total	$	680.8

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

(3) Acquisition

On July 1, 2022, we acquired all of the equity interest in the gathering and processing assets of Crestwood Equity Partners LP located in the Barnett Shale, for a cash purchase price of $275.0 million plus working capital of $14.5 million. These assets include approximately 400 miles of lean and rich gas gathering pipeline and three processing plants with 425 MMcf/d of total processing capacity. We completed this acquisition to increase the scale of our North Texas assets and realize efficiencies by redeploying redundant assets to our other segments, including the Permian segment in the near-term and the CCS business in the future.

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)	$	289.5

Purchase price allocation (1)
Assets acquired:
Current assets	$	17.3
Property and equipment	275.0
Liabilities assumed:
Current liabilities	(2.8)
Net assets acquired	$	289.5

____________________________

(1)The purchase price allocation was based on preliminary estimates and assumptions, which are subject to change within the measurement period (up to one year from the acquisition date), as we finalize the valuations of the assets acquired and liabilities assumed upon the closing of the acquisition.

We incurred $0.4 million of transaction costs for the three and nine months ended September 30, 2022. These costs are incurred in general and administrative costs in the accompanying consolidated statements of operations.

For the three months ended September 30, 2022, we recognized $20.6 million of revenue and $12.6 million of net income related to the assets acquired.

The following unaudited pro forma condensed consolidated financial information (in millions) for the three and nine months ended September 30, 2022 and 2021 gives effect to the July 1, 2022 acquisition of Barnett Shale assets from Crestwood Equity Partners LP as if it had occurred on January 1, 2021. The unaudited pro forma condensed consolidated financial information has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the transaction taken place on the dates indicated and is not intended to be a projection of future results.


	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
Pro forma total revenues	$	2,663.5	$	1,803.7	$	7,528.8	$	4,485.8
Pro forma net income	$	116.6	$	35.6	$	320.8	$	58.1

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

(4) 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.

~~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
Six Months Ended June 30, 2022
Nine Months Ended September 30, 2022								Nine Months Ended September 30, 2022
Customer relationships, beginning of period	Customer relationships, beginning of period	$	1,844.8	$	(795.1)	$	1,049.7	Customer relationships, beginning of period	$	1,844.8	$	(795.1)	$	1,049.7
Amortization expense	Amortization expense	—		(64.7)		(64.7)		Amortization expense	—		(96.6)		(96.6)

Customer relationships, end of period	Customer relationships, end of period	$	1,844.8	$	(859.8)	$	985.0	Customer relationships, end of period	$	1,844.8	$	(891.7)	$	953.1

Amortization expense was $31.9 million ~~and $31.6 million~~ for each of the three months ended ~~June~~September 30, 2022 and 2021, ~~respectively,~~ and ~~$64.7~~$96.6 million and ~~$62.5~~$94.4 million for the ~~six~~nine months ended ~~June~~September 30, 2022 and 2021, respectively.

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


2022 (remaining)	2022 (remaining)	$	63.7	2022 (remaining)	$	31.8
2023	2023	127.6		2023	127.6
2024	2024	127.6		2024	127.6
2025	2025	110.2		2025	110.2
2026	2026	106.3		2026	106.3
Thereafter	Thereafter	449.6		Thereafter	449.6

Total	Total	$	985.0	Total	$	953.1

~~(4)~~

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

(5) Related Party Transactions

(a) Transactions with Cedar Cove JV

For the three and ~~six~~nine months ended ~~June~~September 30, 2022, we recorded cost of sales of ~~$9.1~~$5.6 million and ~~$19.7~~$25.3 million, respectively, and for the three and ~~six~~nine months ended ~~June~~September 30, 2021, we recorded cost of sales of ~~$3.6~~$4.9 million and ~~$6.8~~$11.7 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 ~~$5.7~~$4.3 million and $1.6 million at ~~June~~September 30, 2022 and December 31, 2021, respectively.

(b) Transactions with GIP

General and Administrative Expenses. For the ~~three and six~~nine months ended ~~June~~September 30, 2021, we recorded general and administrative expenses of ~~$0.1 million and~~ $0.2 million ~~respectively,~~ related to personnel secondment services provided by GIP. We did not record any expenses related to transactions with GIP for the three ~~and six~~ months ended ~~June~~September 30, 2021 and for the three and nine months ended September 30, 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 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. See “Note 8—9—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.

1315

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

~~(5)~~(6) Long-Term Debt

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


		June 30, 2022						December 31, 2021							September 30, 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

Revolving Credit Facility due 2027 (1)	Revolving Credit Facility due 2027 (1)	$	—	$	—	$	—	$	15.0	$	—	$	15.0	Revolving Credit Facility due 2027 (1)	$	70.0	$	—	$	70.0	$	15.0	$	—	$	15.0
AR Facility due 2025 (2)	AR Facility due 2025 (2)	325.0		—		325.0		350.0		—		350.0		AR Facility due 2025 (2)	500.0		—		500.0		350.0		—		350.0
ENLK’s 4.40% Senior unsecured notes due 2024	ENLK’s 4.40% Senior unsecured notes due 2024	519.8		0.5		520.3		521.8		0.7		522.5		ENLK’s 4.40% Senior unsecured notes due 2024	97.9		—		97.9		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		(0.3)		720.5		720.8		(0.4)		720.4		ENLK’s 4.15% Senior unsecured notes due 2025	421.6		(0.2)		421.4		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		(0.3)		490.7		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
ENLC’s 6.50% Senior unsecured notes due 2030														ENLC’s 6.50% Senior unsecured notes due 2030	700.0		—		700.0		—		—		—
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		(5.3)		444.7		450.0		(5.5)		444.5		ENLK’s 5.05% Senior unsecured notes due 2045	450.0		(5.2)		444.8		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	$	4,355.3	$	(5.7)	4,349.6		$	4,397.3	$	(5.8)	4,391.5		Debt classified as long-term	$	4,579.2	$	(6.0)	4,573.2		$	4,397.3	$	(5.8)	4,391.5
Debt issuance cost (3)	Debt issuance cost (3)					(29.6)						(27.8)		Debt issuance cost (3)					(35.8)						(27.8)

Long-term debt, net of unamortized issuance cost	Long-term debt, net of unamortized issuance cost					$	4,320.0					$	4,363.7	Long-term debt, net of unamortized issuance cost					$	4,537.4					$	4,363.7

____________________________

(1)The effective interest rate was 6.9% and 3.9% at September 30, 2022 and December 31, ~~2021.~~2021, respectively.

(2)The effective interest rate was ~~2.8%~~4.0% and 1.2% at ~~June~~September 30, 2022 and December 31, 2021, respectively.

(3)Net of accumulated amortization of ~~$16.9~~$13.4 million and $18.4 million at ~~June~~September 30, 2022 and December 31, 2021, respectively.

Revolving Credit Facility

On June 3, 2022, we amended and restated our prior revolving credit facility by entering into the Revolving Credit Facility. As a result, we recognized a $0.5 million loss on extinguishment of debt. The Revolving Credit Facility amended our prior revolving credit facility by, among other things, (i) decreasing the lenders’ commitments under the Revolving Credit Facility from $1.75 billion to $1.40 billion, (ii) modifying the leverage ratio financial covenant calculation to net from the funded indebtedness numerator the lesser of (a) consolidated unrestricted cash of ENLC and (b) $50.0 million, (iii) removing the consolidated interest coverage ratio financial covenant, (iv) extending the maturity date from January 25, 2024 to June 3, 2027, (v) replacing the ability of ENLC to elect that borrowings accrue interest at LIBOR, plus a margin, with the ability of ENLC to elect that borrowings accrue interest at a forward-looking term rate based on SOFR (“Term SOFR”), plus a margin and a Term SOFR spread adjustment, (vi) increasing the size of a permitted receivables financing to $500.0 million from $350.0 million, and (vii) permitting, but not requiring, the establishment by ENLC (subject to approval by Bank of America, N.A., as administrative agent, and lenders holding a majority of the revolving commitments) of specified key performance indicators with respect to environmental, social, and/or governance targets that may result in a pricing increase or decrease under the Revolving Credit Facility of up to 0.05% per annum for the margin on borrowings and letters of credit and 0.02% per annum for the commitment fees.

Borrowings under the Revolving Credit Facility bear interest at ENLC’s options at ~~the~~ Term SOFR plus a Term SOFR spread adjustment of 0.10% per annum (“Adjusted Term SOFR”) and an applicable margin (ranging from 1.125% to 2.00%) or the Base Rate (the highest of the federal funds rate plus 0.50%, ~~the~~Adjusted Term SOFR plus 1.0% or the administrative agent's prime rate) plus an applicable margin (ranging from 0.125% to 1.00%). The applicable margins vary depending on ENLC’s debt rating. Upon breach by ENLC of certain covenants governing the Revolving Credit Facility, amounts outstanding under the Revolving Credit Facility, if any, may become due and payable immediately.

There were no$70.0 million in outstanding borrowings and $46.6 million in outstanding letters of credit under the Revolving Credit Facility ~~and $44.6 million outstanding letters of credit~~ as of ~~June~~September 30, 2022.

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Notes to Consolidated Financial Statements (Continued)

(Unaudited)

At ~~June~~September 30, 2022, we were in compliance with and expect to be in compliance with the financial covenants of the Revolving Credit Facility for at least the next twelve months.

~~Table of Contents~~

~~ENLINK MIDSTREAM, LLC AND SUBSIDIARIES~~

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

~~(Unaudited)~~

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. We are the primary beneficiary of the SPV, and we consolidate its assets and liabilities, which consisted primarily of billed and unbilled accounts receivable of ~~$946.7~~$882.4 million as of ~~June~~September 30, 2022. ~~As of June 30, 2022, the AR Facility had a borrowing base of $350.0 million and there were $325.0 million in outstanding borrowings under the AR Facility.~~

~~At June 30, 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.~~

On August 1, 2022, we amended certain terms of the AR Facility to, among other things, increase the commitments thereunder from $350.0 million to $500.0 million and extend the scheduled termination date from September 24, 2024 to August 1, 2025. ~~See “Item 5. Other Information” for additional information.~~As of September 30, 2022, the AR Facility had a borrowing base of $500.0 million and there were $500.0 million in outstanding borrowings under the AR Facility.

~~Senior Unsecured Notes Repurchase~~At September 30, 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.

~~For~~Issuances and Repurchases of Senior Unsecured Notes

On August 31, 2022, ENLC completed the sale of $700.0 million in aggregate principal amount of ENLC’s 6.50% senior unsecured notes due September 1, 2030 (the “2030 Notes”) at 100% of their face value. Interest on the 2030 Notes will be payable on March 1 and September 1 of each year beginning on March 1, 2023, until their maturity on September 1, 2030. The 2030 Notes are fully and unconditionally guaranteed by ENLK. We used the net proceeds of approximately $693.0 million and available cash to settle ENLK’s debt tender offer to repurchase $700.0 million in aggregate principal amount of its senior unsecured notes. The repurchased notes consisted of $404.4 million of outstanding aggregate principal amount of ENLK’s 4.40% senior unsecured notes due 2024 (the “2024 Notes”) and $295.6 million of outstanding aggregate principal amount of ENLK’s 4.15% senior unsecured notes due 2025 (the “2025 Notes”). Total consideration for the repurchased 2024 Notes and the 2025 Notes was $715.8 million, including $21.0 million of debt tender premium.

Activity related to the repurchases of ENLK’s senior unsecured notes from the settled debt tender offer consisted of the following (in millions):


	Three and Nine Months Ended September 30, 2022
Debt repurchased	$	700.0
Aggregate payments	(715.8)
Net discount on repurchased debt	(1.0)
Accrued interest on repurchased debt	10.5
Loss on extinguishment of debt	$	(6.3)

Additionally, for the three and ~~six~~nine months ended ~~June~~September 30, 2022, we repurchased ~~$2.0 million~~a portion of ~~ENLK’s~~the outstanding ~~senior unsecured notes due~~ 2024 Notes and 2025 Notes in open market transactions. We did not repurchase any senior unsecured notes in open market transactions during the three and ~~six~~nine months ended ~~June~~September 30, 2021.

Activity related to the repurchases of ENLK’s senior unsecured notes in open market transactions consisted of the following (in millions):

~~(6)~~


	Three Months Ended September 30, 2022		Nine Months Ended September 30, 2022
Debt repurchased	$	21.1	$	23.1
Aggregate payments	(20.7)		(22.7)

Accrued interest on repurchased debt	0.2		0.2
Gain on extinguishment of debt	$	0.6	$	0.6

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

(7) Income Taxes

The components of our ~~total~~ income tax ~~benefit (expense)~~expense are as follows (in millions):
Three Months Ended
June 30, Six Months Ended
June 30,
2022 2021 2022 2021
Current income tax expense $ (0.5) $ — $ (0.7) $ (0.1)
Deferred income tax benefit (expense) 1.8 (6.6) (1.2) (7.9)
Total income tax benefit (expense) $ 1.3 $ (6.6) $ (1.9) $ (8.0)


	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
Current income tax expense	$	(0.3)	$	(0.1)	$	(1.0)	$	(0.2)
Deferred income tax expense	(14.9)		(4.3)		(16.1)		(12.2)
Income tax expense	$	(15.2)	$	(4.4)	$	(17.1)	$	(12.4)

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 before non-controlling interest and income taxes (in millions):


		Three Months Ended June 30,				Six Months Ended June 30,					Three Months Ended September 30,				Nine Months Ended September 30,
		2022		2021		2022		2021			2022		2021		2022		2021
Expected income tax benefit (expense) based on federal statutory rate	Expected income tax benefit (expense) based on federal statutory rate	$	(17.8)	$	3.8	$	(25.9)	$	6.2	Expected income tax benefit (expense) based on federal statutory rate	$	(20.0)	$	(2.0)	$	(45.9)	$	4.2
State income tax benefit (expense), net of federal benefit	State income tax benefit (expense), net of federal benefit	(2.5)		0.6		(3.6)		0.8		State income tax benefit (expense), net of federal benefit	(2.6)		(0.3)		(6.2)		0.5
Unit-based compensation (1)	Unit-based compensation (1)	—		(0.4)		(2.0)		(2.9)		Unit-based compensation (1)	1.4		(0.2)		(0.6)		(3.1)

Change in valuation allowance	Change in valuation allowance	21.0		(1.0)		28.1		(2.2)		Change in valuation allowance	10.9		(1.6)		39.0		(3.8)
Oklahoma statutory rate change (2)	Oklahoma statutory rate change (2)	—		(7.6)		—		(7.6)		Oklahoma statutory rate change (2)	—		—		—		(7.6)
Other	Other	0.6		(2.0)		1.5		(2.3)		Other	(4.9)		(0.3)		(3.4)		(2.6)
Total income tax benefit (expense)		$	1.3	$	(6.6)	$	(1.9)	$	(8.0)
Income tax expense										Income tax expense	$	(15.2)	$	(4.4)	$	(17.1)	$	(12.4)

____________________________

(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%. Accordingly, we recorded deferred tax expense in the amount of $7.6 million for the ~~three and six~~nine months ended ~~June~~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 ~~June~~September 30, 2022, we had ~~$138.7~~$153.6 million of deferred tax liabilities, net of ~~$511.9~~$553.2 million of deferred tax assets, which included a ~~$123.5~~$112.6 million valuation

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~~ENLINK MIDSTREAM, LLC AND SUBSIDIARIES~~

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

~~(Unaudited)~~

allowance. As of December 31, 2021, we had $137.5 million of deferred tax liabilities, net of $481.6 million of deferred tax assets, which included a $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 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. As of ~~June~~September 30, 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.

~~(7)~~

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

(8) Certain Provisions of the ENLK Partnership Agreement

a.Series B Preferred Units

As of ~~June~~September 30, 2022 and December 31, 2021, there were 54,168,359 and 57,501,693 Series B Preferred Units issued and outstanding, respectively.

In January 2022, we 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 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 that we will pay cash in lieu of making a quarterly PIK distribution through the distribution declared for the fourth quarter of 2022.

A summary of the distribution activity relating to the Series B Preferred Units during the ~~six~~nine months ended ~~June~~September 30, 2022 and 2021 is provided below:


Declaration period	Declaration period	Distribution paid as additional Series B Preferred Units	Cash distribution (in millions)		Date paid/payable	Declaration period	Distribution paid as additional Series B Preferred Units	Cash distribution (in millions)		Date paid/payable
2022	2022					2022
Fourth Quarter of 2021	Fourth Quarter of 2021	—	$	19.2	February 11, 2022 (1)	Fourth Quarter of 2021	—	$	19.2	February 11, 2022 (1)
First Quarter of 2022	First Quarter of 2022	—	$	17.5	May 13, 2022 (2)	First Quarter of 2022	—	$	17.5	May 13, 2022 (2)
Second Quarter of 2022	Second Quarter of 2022	—	$	17.3	August 12, 2022	Second Quarter of 2022	—	$	17.3	August 12, 2022

Third Quarter of 2022						Third Quarter of 2022	—	$	17.3	November 14, 2022

2021	2021					2021
Fourth Quarter of 2020	Fourth Quarter of 2020	150,494	$	16.9	February 12, 2021	Fourth Quarter of 2020	150,494	$	16.9	February 12, 2021
First Quarter of 2021	First Quarter of 2021	150,871	$	17.0	May 14, 2021	First Quarter of 2021	150,871	$	17.0	May 14, 2021
Second Quarter of 2021	Second Quarter of 2021	151,248	$	17.0	August 13, 2021	Second Quarter of 2021	151,248	$	17.0	August 13, 2021

Third Quarter of 2021						Third Quarter of 2021	151,626	$	17.1	November 12, 2021

____________________________

(1)In December 2021 and January 2022, we paid $0.9 million and $1.0 million, respectively, of accrued distributions related to the fourth quarter of 2021 on ~~the~~redeemed Series B Preferred ~~Units redeemed.~~Units. The remaining distribution of $17.3 million related to the fourth quarter of 2021 was paid on February 11, 2022.

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

b.Series C Preferred Units

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

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

~~(8)~~(9) Members’ Equity

a.Common Unit Repurchase Program

In November 2020, the board of directors of the Managing Member (the “Board”) 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. In July 2022, the Board increased the amount available for repurchases to $200.0 million. 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 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 agreed to 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 preceding quarter from public unitholders under our common unit repurchase program. See “Note 4—5—Related Party Transactions” ~~above.~~for additional information on our ENLC common unit repurchase agreement with GIP.

The following table summarizes our ENLC common unit repurchase activity for the three and ~~six~~nine months ended ~~June~~September 30, 2022 and 2021 (in millions, except for unit amounts):

Three Months Ended June 30, Six Months Ended June 30,
2022 2021 2022 2021
Publicly held ENLC common units repurchased 2,921,370 317,751 5,015,212 317,751
ENLC common units held by GIP repurchased (1) 675,095 — 675,095 —
Total ENLC common units repurchased 3,596,465 317,751 5,690,307 317,751
Aggregate cost for publicly held ENLC common units repurchased $ 27.7 $ 2.0 $ 44.7 $ 2.0
Aggregate cost for ENLC common units held by GIP repurchased (3) 6.0 — 6.0 —
Total aggregate cost for ENLC common units repurchased $ 33.7 $ 2.0 $ 50.7 $ 2.0


	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
Publicly held ENLC common units	4,051,626		2,076,545		9,066,838		2,394,296
ENLC common units held by GIP (1)	2,530,507		—		3,205,602		—
Total ENLC common units	6,582,133		2,076,545		12,272,440		2,394,296

Aggregate cost for publicly held ENLC common units	$	38.5	$	12.5	$	83.2	$	14.5
Aggregate cost for ENLC common units held by GIP	24.0		—		30.0		—
Total aggregate cost for ENLC common units	$	62.5	$	12.5	$	113.2	$	14.5

Average price paid per publicly held ENLC common unit	$	9.49	$	6.02	$	9.18	$	6.05
Average price paid per ENLC common unit held by GIP (2)	$	9.47	$	—	$	9.35	$	—

____________________________

(1)~~The~~For the three and nine months ended September 30, 2022, the 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 third quarter and the period from February 15, 2022 (the date on which the Repurchase Agreement was signed) through ~~March 31, 2022.~~June 30, 2022, respectively.

(2)For the three and ~~six~~nine months ended ~~June~~September 30, 2022, the average price paid per common unit repurchased was $9.49 per common unit and $8.92 per common unit, respectively. For the three and six months ended June 30, 2021, the average price paid per common unit repurchased was $6.22 per common unit.

~~(3)For the three and six months ended June 30, 2022, the average price paid per common unit repurchased was $8.92. The~~ per unit price we paid to GIP was the average per unit price paid by us for publicly held ENLC common units repurchased during the third quarter and from February 15, 2022 (the date on which the Repurchase Agreement was signed) through ~~March 31, 2022.~~June 30, 2022, respectively, less broker commissions, which were not paid with respect to GIP units.

Additionally, on ~~August 2,~~October 31, 2022, we repurchased ~~2,530,507~~3,538,101 ENLC common units held by GIP at an aggregate cost of ~~$24.0~~$33.5 million, or an average of ~~$9.47~~$9.47 per common unit. These units represent GIP’s pro rata share of the aggregate number of common units repurchased by us during the three months ended ~~June~~September 30, 2022. The per unit price we paid to GIP was the same as the average per unit price paid by us for publicly held ENLC common units repurchased during the same period, less broker ~~commission,~~commissions, which were not paid with respect to the GIP units.

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

b.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 June 30,				Six Months Ended June 30,					Three Months Ended September 30,				Nine Months Ended September 30,
		2022		2021		2022		2021			2022		2021		2022		2021
Distributed earnings allocated to:	Distributed earnings allocated to:									Distributed earnings allocated to:
Common units (1)	Common units (1)	$	54.3	$	46.0	$	108.7	$	91.9	Common units (1)	$	53.7	$	45.8	$	162.4	$	137.7
Unvested restricted units (1)	Unvested restricted units (1)	1.4		1.1		2.5		2.2		Unvested restricted units (1)	1.4		1.0		3.9		3.2
Total distributed earnings	Total distributed earnings	$	55.7	$	47.1	$	111.2	$	94.1	Total distributed earnings	$	55.1	$	46.8	$	166.3	$	140.9
Undistributed income (loss) allocated to:	Undistributed income (loss) allocated to:									Undistributed income (loss) allocated to:
Common units	Common units	$	29.0	$	(67.1)	$	9.1	$	(125.4)	Common units	$	25.1	$	(43.9)	$	34.2	$	(169.3)
Unvested restricted units	Unvested restricted units	0.6		(1.6)		0.2		(3.0)		Unvested restricted units	0.6		(1.0)		0.8		(4.0)
Total undistributed income (loss)	Total undistributed income (loss)	$	29.6	$	(68.7)	$	9.3	$	(128.4)	Total undistributed income (loss)	$	25.7	$	(44.9)	$	35.0	$	(173.3)
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	$	83.3	$	(21.1)	$	117.8	$	(33.5)	Common units	$	78.8	$	1.9	$	196.6	$	(31.6)
Unvested restricted units	Unvested restricted units	2.0		(0.5)		2.7		(0.8)		Unvested restricted units	2.0		—		4.7		(0.8)
Total net income (loss) attributable to ENLC	Total net income (loss) attributable to ENLC	$	85.3	$	(21.6)	$	120.5	$	(34.3)	Total net income (loss) attributable to ENLC	$	80.8	$	1.9	$	201.3	$	(32.4)
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	$	0.18	$	(0.04)	$	0.25	$	(0.07)	Basic	$	0.17	$	—	$	0.42	$	(0.07)
Diluted	Diluted	$	0.17	$	(0.04)	$	0.25	$	(0.07)	Diluted	$	0.17	$	—	$	0.41	$	(0.07)

____________________________

(1)Represents distribution activity consistent with the distribution activity table below.

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 June 30,		Six Months Ended June 30,			Three Months Ended September 30,		Nine Months Ended September 30,
		2022	2021	2022	2021		2022	2021	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	482.0	490.0	483.0	490.0	Weighted average common units outstanding	477.2	488.6	481.0	489.6

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	482.0	490.0	483.0	490.0	Weighted average basic common units outstanding	477.2	488.6	481.0	489.6
Dilutive effect of non-vested restricted units (1)		7.0	—	6.7	—
Dilutive effect of unvested restricted units (1)						Dilutive effect of unvested restricted units (1)	7.2	6.2	6.9	—

Total weighted average diluted common units outstanding	Total weighted average diluted common units outstanding	489.0	490.0	489.7	490.0	Total weighted average diluted common units outstanding	484.4	494.8	487.9	489.6

____________________________

(1)All common unit equivalents were antidilutive for the ~~three and six~~nine months ended ~~June~~September 30, 2021, 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.

1821

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Notes to Consolidated Financial Statements (Continued)

(Unaudited)

c.Distributions

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


Declaration period	Distribution/unit		Date paid/payable
2022
Fourth Quarter of 2021	$	~~0.11250~~0.1125	February 11, 2022
First Quarter of 2022	$	~~0.11250~~0.1125	May 13, 2022
Second Quarter of 2022	$	~~0.11250~~0.1125	August 12, 2022
Third Quarter of 2022	$	0.1125		November 14, 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

1922

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

~~(9)~~(10) Investment in Unconsolidated Affiliates

On May 16, 2022, we formed a joint venture with WhiteWater Midstream, LLC, Devon Energy Corporation, and MPLX LP (the “Matterhorn JV”) to construct a pipeline designed to transport up to 2.5 Bcf/d of natural gas through approximately 490 miles of 42-inch pipeline from the Waha Hub in West Texas to Katy, Texas (the “Matterhorn Express Pipeline”).

As of ~~June~~September 30, 2022, our unconsolidated investments consisted of a 38.75% ownership in GCF, a 30% ownership in the Cedar Cove JV, and a 15% ownership in the Matterhorn JV. The following table shows the activity related to our investment in unconsolidated affiliates for the periods indicated (in millions):


		Three Months Ended June 30,				Six Months Ended June 30,					Three Months Ended September 30,				Nine Months Ended September 30,
		2022		2021		2022		2021			2022		2021		2022		2021
GCF	GCF									GCF
Contributions	Contributions	$	0.5	$	—	$	0.5	$	—	Contributions	$	0.9	$	—	$	1.4	$	—
Distributions	Distributions	$	—	$	—	$	—	$	(3.5)	Distributions	$	—	$	—	$	—	$	(3.5)
Equity in loss	Equity in loss	$	(0.9)	$	(0.7)	$	(1.6)	$	(6.4)	Equity in loss	$	(0.8)	$	(1.7)	$	(2.4)	$	(8.1)

Cedar Cove JV	Cedar Cove JV									Cedar Cove JV

Distributions	Distributions	$	(0.2)	$	(0.1)	$	(0.4)	$	(0.2)	Distributions	$	(0.2)	$	(0.1)	$	(0.6)	$	(0.3)
Equity in loss	Equity in loss	$	(0.3)	$	(0.6)	$	(0.7)	$	(1.2)	Equity in loss	$	(0.6)	$	(0.6)	$	(1.3)	$	(1.8)

Matterhorn JV	Matterhorn JV									Matterhorn JV
Contributions	Contributions	$	26.1	$	—	$	26.1	$	—	Contributions	$	18.8	$	—	$	44.9	$	—

Equity in loss										Equity in loss	$	(0.3)	$	—	$	(0.3)	$	—

Total	Total									Total
Contributions	Contributions	$	26.6	$	—	$	26.6	$	—	Contributions	$	19.7	$	—	$	46.3	$	—
Distributions	Distributions	$	(0.2)	$	(0.1)	$	(0.4)	$	(3.7)	Distributions	$	(0.2)	$	(0.1)	$	(0.6)	$	(3.8)
Equity in loss	Equity in loss	$	(1.2)	$	(1.3)	$	(2.3)	$	(7.6)	Equity in loss	$	(1.7)	$	(2.3)	$	(4.0)	$	(9.9)

The following table shows the balances related to our investment in unconsolidated affiliates as of ~~June~~September 30, 2022 and December 31, 2021 (in millions):


		June 30, 2022		December 31, 2021			September 30, 2022		December 31, 2021
GCF	GCF	$	26.9	$	28.0	GCF	$	27.0	$	28.0
Cedar Cove JV (1)	Cedar Cove JV (1)	(2.9)		(1.8)		Cedar Cove JV (1)	(3.7)		(1.8)
Matterhorn JV	Matterhorn JV	26.1		—		Matterhorn JV	44.6		—
Total investment in unconsolidated affiliates	Total investment in unconsolidated affiliates	$	50.1	$	26.2	Total investment in unconsolidated affiliates	$	67.9	$	26.2

____________________________

(1)As of ~~June~~September 30, 2022 and December 31, 2021, our investment in the Cedar Cove JV is classified as “Other long-term liabilities” on the consolidated balance sheets.

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Notes to Consolidated Financial Statements (Continued)

(Unaudited)

~~(10)~~(11) Employee Incentive Plans

a.Long-Term Incentive Plans

We account for unit-based compensation in accordance with ASC 718, which requires that compensation related to all unit-based awards be recognized in the consolidated financial statements. Unit-based compensation cost is valued at fair value at the date of grant, and that grant date fair value is recognized as expense over each award’s requisite service period with a corresponding increase to equity or liability based on the terms of each award and the appropriate accounting treatment under ASC 718.

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


		Three Months Ended June 30,				Six Months Ended June 30,					Three Months Ended September 30,				Nine Months Ended September 30,
		2022		2021		2022		2021			2022		2021		2022		2021
Cost of unit-based compensation charged to operating expense	Cost of unit-based compensation charged to operating expense	$	1.2	$	1.7	$	2.8	$	3.4	Cost of unit-based compensation charged to operating expense	$	1.3	$	1.5	$	4.1	$	4.9
Cost of unit-based compensation charged to general and administrative expense	Cost of unit-based compensation charged to general and administrative expense	4.5		4.7		9.5		9.5		Cost of unit-based compensation charged to general and administrative expense	10.1		4.9		19.6		14.4
Total unit-based compensation expense	Total unit-based compensation expense	$	5.7	$	6.4	$	12.3	$	12.9	Total unit-based compensation expense	$	11.4	$	6.4	$	23.7	$	19.3
Amount of related income tax benefit recognized in net income (1)	Amount of related income tax benefit recognized in net income (1)	$	1.3	$	1.5	$	2.9	$	3.0	Amount of related income tax benefit recognized in net income (1)	$	2.7	$	1.5	$	5.6	$	4.5

____________________________

(1)For the ~~six~~three and nine months ended ~~June~~September 30, 2022, the amount of related income tax benefit recognized in net income excluded ~~$2.0~~$1.4 million of income tax benefit and $0.6 million 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 ~~June 30, 2022, there was no income tax expense related to book-to-tax differences recorded upon the vesting of units. For the three and six months ended June~~September 30, 2021, the amount of related income tax benefit recognized in net income excluded ~~$0.4~~$0.2 million and ~~$2.9~~$3.1 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 ~~six~~nine months ended ~~June~~September 30, 2022 is provided below:


		Six Months Ended June 30, 2022					Nine Months Ended September 30, 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	7,507,471		$	5.46	Non-vested, beginning of period	7,507,471		$	5.46
Granted (1)	Granted (1)	2,386,493		8.81		Granted (1)	2,461,950		8.83
Vested (1)(2)	Vested (1)(2)	(1,100,302)		10.22		Vested (1)(2)	(2,198,511)		7.88
Forfeited	Forfeited	(131,415)		5.91		Forfeited	(348,431)		7.13
Non-vested, end of period	Non-vested, end of period	8,662,247		$	5.77	Non-vested, end of period	7,422,479		$	5.78
Aggregate intrinsic value, end of period (in millions)	Aggregate intrinsic value, end of period (in millions)	$	73.6			Aggregate intrinsic value, end of period (in millions)	$	66.0

____________________________

(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 ~~296,453~~709,189 ENLC common units withheld for payroll taxes paid on behalf of employees.

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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 ~~six~~nine months ended ~~June~~September 30, 2022 and 2021 is provided below (in millions):


		Three Months Ended June 30,				Six Months Ended June 30,					Three Months Ended September 30,				Nine Months Ended September 30,
ENLC Restricted Incentive Units:	ENLC Restricted Incentive Units:	2022		2021		2022		2021		ENLC Restricted Incentive Units:	2022		2021		2022		2021
Aggregate intrinsic value of units vested	Aggregate intrinsic value of units vested	$	0.6	$	0.9	$	8.2	$	3.9	Aggregate intrinsic value of units vested	$	11.1	$	1.5	$	19.3	$	5.4
Fair value of units vested	Fair value of units vested	$	0.5	$	2.3	$	11.2	$	12.5	Fair value of units vested	$	6.1	$	3.6	$	17.3	$	16.1

As of ~~June~~September 30, 2022, there were ~~$25.7~~$20.5 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 ~~2.0~~1.8 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:


		Six Months Ended June 30, 2022					Nine Months Ended September 30, 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	3,574,827		$	6.40	Non-vested, beginning of period	3,574,827		$	6.40
Granted	Granted	1,204,882		11.60		Granted	1,204,882		11.60
Vested (1)	Vested (1)	(708,361)		15.57		Vested (1)	(1,265,207)		10.94

Forfeited						Forfeited	(147,232)		11.90
Non-vested, end of period	Non-vested, end of period	4,071,348		$	6.34	Non-vested, end of period	3,367,270		$	6.31
Aggregate intrinsic value, end of period (in millions)	Aggregate intrinsic value, end of period (in millions)	$	34.6			Aggregate intrinsic value, end of period (in millions)	$	29.9

____________________________

(1)Vested units included ~~273,357~~676,156 ENLC common 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 ~~six~~nine months ended ~~June~~September 30, 2022 and 2021 is provided below (in millions).


		Six Months Ended June 30,					Three Months Ended September 30,				Nine Months Ended September 30,
ENLC Performance Units:	ENLC Performance Units:		2022		2021			ENLC Performance Units:	2022		2021		2022		2021
Aggregate intrinsic value of units vested	Aggregate intrinsic value of units vested		$	5.6	$	0.6		Aggregate intrinsic value of units vested	$	10.2	$	—	$	15.8	$	0.6
Fair value of units vested	Fair value of units vested		$	11.0	$	4.4		Fair value of units vested	$	4.5	$	—	$	15.5	$	4.4

As of ~~June~~September 30, 2022, there were ~~$20.3~~$12.9 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 2.0 years.

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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:	June 2022			March 2022 (1)			January 2021
Grant-date fair value	$	11.71		$	11.90		$	4.70
Beginning TSR price	$	8.54		$	8.83		$	3.71
Risk-free interest rate	3.35		%	2.15		%	0.17		%
Volatility factor	76.00		%	75.00		%	71.00		%

____________________________

(1)Excludes certain 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~~are scheduled to vest in February 2023.

~~(11)~~(12) Derivatives

Interest Rate Swaps

The components of the unrealized gain 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 June 30,				Six Months Ended June 30,					Three Months Ended September 30,				Nine Months Ended September 30,
		2022		2021		2022		2021			2022		2021		2022		2021
Change in fair value of interest rate swaps	Change in fair value of interest rate swaps	$	—	$	4.8	$	0.1	$	9.5	Change in fair value of interest rate swaps	$	—	$	5.0	$	0.1	$	14.5
Tax expense	Tax expense	—		(1.1)		—		(2.2)		Tax expense	—		(1.2)		—		(3.4)
Unrealized gain on designated cash flow hedge	Unrealized gain on designated cash flow hedge	$	—	$	3.7	$	0.1	$	7.3	Unrealized gain on designated cash flow hedge	$	—	$	3.8	$	0.1	$	11.1

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
June 30, Six Months Ended
June 30,
2022 2021 2022 2021
Interest expense $ — $ 4.8 $ 0.1 $ 9.6


	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
Interest expense	$	—	$	5.0	$	0.1	$	14.6

We expect to recognize an additional $0.1 million of interest expense out of accumulated other comprehensive loss over the next twelve months.

Commodity Swaps

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


		Three Months Ended June 30,				Six Months Ended June 30,					Three Months Ended September 30,				Nine Months Ended September 30,
		2022		2021		2022		2021			2022		2021		2022		2021
Change in fair value of derivatives	Change in fair value of derivatives	$	35.3	$	(23.8)	$	20.2	$	(31.7)	Change in fair value of derivatives	$	18.2	$	(1.2)	$	38.4	$	(32.9)
Realized loss on derivatives		(30.8)		(14.4)		(46.9)		(89.9)
Realized gain (loss) on derivatives										Realized gain (loss) on derivatives	2.3		(32.4)		(44.6)		(122.3)
Gain (loss) on derivative activity	Gain (loss) on derivative activity	$	4.5	$	(38.2)	$	(26.7)	$	(121.6)	Gain (loss) on derivative activity	$	20.5	$	(33.6)	$	(6.2)	$	(155.2)

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Notes to Consolidated Financial Statements (Continued)

(Unaudited)

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


		June 30, 2022		December 31, 2021			September 30, 2022		December 31, 2021
Fair value of derivative assets—current	Fair value of derivative assets—current	$	95.6	$	22.4	Fair value of derivative assets—current	$	76.2	$	22.4
Fair value of derivative assets—long-term	Fair value of derivative assets—long-term	—		0.2		Fair value of derivative assets—long-term	0.7		0.2
Fair value of derivative liabilities—current	Fair value of derivative liabilities—current	(88.7)		(34.9)		Fair value of derivative liabilities—current	(52.2)		(34.9)
Fair value of derivative liabilities—long-term	Fair value of derivative liabilities—long-term	(1.2)		(2.2)		Fair value of derivative liabilities—long-term	(0.8)		(2.2)
Net fair value of commodity swaps	Net fair value of commodity swaps	$	5.7	$	(14.5)	Net fair value of commodity swaps	$	23.9	$	(14.5)

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 ~~June~~September 30, 2022 (in ~~millions)~~millions, except volumes). The remaining term of the contracts extend no later than ~~July 2023.~~January 2024.

June 30, 2022

September 30, 2022

Commodity

Instruments

Unit

Volume

Net Fair Value

Commodity

Instruments

Unit

Volume

Net Fair Value

NGL (short contracts)

Swaps

Gals

(122.0)

(4.1)

NGL (short contracts)

Swaps

MMgals

(113.0)

24.7

NGL (long contracts)

Swaps

MMgals

7.8

(0.3)

Natural gas (short contracts)

Swaps

MMbtu

(19.7)

26.8

Natural gas (short contracts)

Swaps

MMbtu

(25.5)

9.4

Natural gas (long contracts)

Swaps

MMbtu

11.7

(19.5)

Natural gas (long contracts)

Swaps

MMbtu

20.6

(14.4)

Crude and condensate (short contracts)

Swaps

MMbbls

(3.2)

(55.4)

Crude and condensate (short contracts)

Swaps

MMbbls

(2.5)

11.1

Crude and condensate (long contracts)

Swaps

MMbbls

2.8

57.9

Crude and condensate (long contracts)

Swaps

MMbbls

2.2

(6.6)

Total fair value of commodity swaps

5.7

Total fair value of commodity swaps

23.9

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 ~~$95.6~~$76.9 million as of ~~June~~September 30, 2022 would be reduced to ~~$9.6~~$30.3 million due to the offsetting of gross fair value payables against gross fair value receivables as allowed by the ISDAs.

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Notes to Consolidated Financial Statements (Continued)

(Unaudited)

~~(12)~~(13) Fair Value Measurements

Assets and liabilities measured at fair value on a recurring basis are summarized below (in millions):
Level 2
June 30, 2022 December 31, 2021
Commodity swaps (1) $ 5.7 $ (14.5)


	Level 2
	September 30, 2022		December 31, 2021

Commodity swaps (1)	$	23.9	$	(14.5)

____________________________

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

Fair Value of Financial Instruments

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


		June 30, 2022				December 31, 2021					September 30, 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)	$	4,320.0	$	3,750.6	$	4,363.7	$	4,520.0	Long-term debt (1)	$	4,537.4	$	4,072.5	$	4,363.7	$	4,520.0
Installment payable (2)	Installment payable (2)	$	—	$	—	$	10.0	$	10.0	Installment payable (2)	$	—	$	—	$	10.0	$	10.0
Contingent consideration (2)	Contingent consideration (2)	$	7.2	$	7.2	$	6.9	$	6.9	Contingent consideration (2)	$	4.4	$	4.4	$	6.9	$	6.9

____________________________

(1)The carrying value of long-term debt is reduced by debt issuance cost, net of accumulated amortization, of ~~$29.6~~$35.8 million and $27.8 million as of ~~June~~September 30, 2022 and December 31, 2021, respectively. The respective fair values do not factor in debt issuance costs.

(2)Consideration for the Amarillo Rattler Acquisition included a $10.0 million installment payable, which was paid on April 30, 2022, and a contingent component capped at $15.0 million and payable, if at all, between 2024 and 2026 based on Diamondback 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.

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 ~~June~~September 30, 2022 and December 31, 2021 were based on Level 2 inputs from third-party market quotations.

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Notes to Consolidated Financial Statements (Continued)

(Unaudited)

~~(13)~~(14) Segment Information

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. 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, GCF in South Texas, and the Matterhorn JV in West Texas and our corporate assets and expenses.

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Notes to Consolidated Financial Statements (Continued)

(Unaudited)

We evaluate the performance of our operating segments based on segment 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 June 30, 2022
Three Months Ended September 30, 2022														Three Months Ended September 30, 2022
Natural gas sales	Natural gas sales	$	323.0	$	272.9	$	87.1	$	37.9	$	—	$	720.9	Natural gas sales	$	361.6	$	383.8	$	114.5	$	42.8	$	—	$	902.7
NGL sales	NGL sales	—		1,163.7		3.6		0.1		—		1,167.4		NGL sales	0.2		1,067.4		1.7		1.4		—		1,070.7
Crude oil and condensate sales	Crude oil and condensate sales	331.6		110.0		40.6		—		—		482.2		Crude oil and condensate sales	280.7		97.0		33.3		—		—		411.0

Product sales	Product sales	654.6		1,546.6		131.3		38.0		—		2,370.5		Product sales	642.5		1,548.2		149.5		44.2		—		2,384.4

NGL sales—related parties	NGL sales—related parties	427.5		43.1		242.6		165.8		(879.0)		—		NGL sales—related parties	380.3		46.3		203.2		139.7		(769.5)		—
Crude oil and condensate sales—related parties	Crude oil and condensate sales—related parties	—		—		—		4.0		(4.0)		—		Crude oil and condensate sales—related parties	—		—		—		2.6		(2.6)		—
Product sales—related parties	Product sales—related parties	427.5		43.1		242.6		169.8		(883.0)		—		Product sales—related parties	380.3		46.3		203.2		142.3		(772.1)		—
Gathering and transportation	Gathering and transportation	19.9		15.7		44.7		40.6		—		120.9		Gathering and transportation	20.9		22.1		45.9		49.9		—		138.8
Processing	Processing	9.9		0.3		28.6		27.9		—		66.7		Processing	11.1		0.4		31.4		39.5		—		82.4
NGL services	NGL services	—		18.4		—		0.1		—		18.5		NGL services	—		19.5		—		0.1		—		19.6
Crude services	Crude services	6.0		9.2		3.2		0.2		—		18.6		Crude services	5.7		8.1		3.0		0.1		—		16.9
Other services	Other services	0.2		0.4		0.1		0.2		—		0.9		Other services	0.2		0.4		0.2		0.1		—		0.9
Midstream services	Midstream services	36.0		44.0		76.6		69.0		—		225.6		Midstream services	37.9		50.5		80.5		89.7		—		258.6

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

Other services—related parties														Other services—related parties	—		0.1		—		—		(0.1)		—
Midstream services—related parties	Midstream services—related parties	—		—		0.1		—		(0.1)		—		Midstream services—related parties	—		0.1		—		—		(0.1)		—
Revenue from contracts with customers	Revenue from contracts with customers	1,118.1		1,633.7		450.6		276.8		(883.1)		2,596.1		Revenue from contracts with customers	1,060.7		1,645.1		433.2		276.2		(772.2)		2,643.0
Cost of sales, exclusive of operating expenses and depreciation and amortization (1)	Cost of sales, exclusive of operating expenses and depreciation and amortization (1)	(958.0)		(1,519.2)		(321.3)		(189.7)		883.1		(2,105.1)		Cost of sales, exclusive of operating expenses and depreciation and amortization (1)	(903.3)		(1,517.8)		(315.3)		(166.9)		772.2		(2,131.1)
Realized loss on derivatives		(10.2)		(2.5)		(15.8)		(2.3)		—		(30.8)
Realized gain (loss) on derivatives														Realized gain (loss) on derivatives	1.3		3.3		0.6		(2.9)		—		2.3
Change in fair value of derivatives	Change in fair value of derivatives	12.5		11.8		8.2		2.8		—		35.3		Change in fair value of derivatives	2.4		4.0		9.5		2.3		—		18.2
Adjusted gross margin	Adjusted gross margin	162.4		123.8		121.7		87.6		—		495.5		Adjusted gross margin	161.1		134.6		128.0		108.7		—		532.4
Operating expenses	Operating expenses	(50.3)		(34.8)		(23.1)		(20.7)		—		(128.9)		Operating expenses	(49.7)		(37.6)		(23.5)		(26.0)		—		(136.8)
Segment profit	Segment profit	112.1		89.0		98.6		66.9		—		366.6		Segment profit	111.4		97.0		104.5		82.7		—		395.6
Depreciation and amortization	Depreciation and amortization	(37.1)		(39.4)		(52.3)		(28.7)		(1.5)		(159.0)		Depreciation and amortization	(36.8)		(39.7)		(51.5)		(33.4)		(1.2)		(162.6)

Gain on disposition of assets	Gain on disposition of assets	—		—		0.2		0.2		—		0.4		Gain on disposition of assets	—		0.1		0.1		0.6		—		0.8
General and administrative	General and administrative	—		—		—		—		(28.4)		(28.4)		General and administrative	—		—		—		—		(34.5)		(34.5)
Interest expense, net of interest income	Interest expense, net of interest income	—		—		—		—		(55.5)		(55.5)		Interest expense, net of interest income	—		—		—		—		(60.4)		(60.4)
Loss on extinguishment of debt	Loss on extinguishment of debt	—		—		—		—		(0.5)		(0.5)		Loss on extinguishment of debt	—		—		—		—		(5.7)		(5.7)
Loss from unconsolidated affiliate investments	Loss from unconsolidated affiliate investments	—		—		—		—		(1.2)		(1.2)		Loss from unconsolidated affiliate investments	—		—		—		—		(1.7)		(1.7)
Other income	Other income	—		—		—		—		0.2		0.2		Other income	—		—		—		—		0.3		0.3
Income (loss) before non-controlling interest and income taxes	Income (loss) before non-controlling interest and income taxes	$	75.0	$	49.6	$	46.5	$	38.4	$	(86.9)	$	122.6	Income (loss) before non-controlling interest and income taxes	$	74.6	$	57.4	$	53.1	$	49.9	$	(103.2)	$	131.8
Capital expenditures	Capital expenditures	$	34.7	$	6.3	$	11.5	$	8.1	$	1.9	$	62.5	Capital expenditures	$	61.7	$	6.5	$	18.2	$	6.5	$	1.6	$	94.5

____________________________

(1)Includes related party cost of sales of ~~$9.1~~$5.6 million for the three months ended ~~June~~September 30, 2022.

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(Unaudited)


		Permian		Louisiana		Oklahoma		North Texas		Corporate		Totals			Permian		Louisiana		Oklahoma		North Texas		Corporate		Totals
Three Months Ended June 30, 2021
Three Months Ended September 30, 2021														Three Months Ended September 30, 2021
Natural gas sales	Natural gas sales	$	97.4	$	122.0	$	45.6	$	26.2	$	—	$	291.2	Natural gas sales	$	159.3	$	183.2	$	58.2	$	32.2	$	—	$	432.9
NGL sales	NGL sales	0.5		706.6		0.4		(0.1)		—		707.4		NGL sales	0.4		898.6		0.3		(0.1)		—		899.2
Crude oil and condensate sales	Crude oil and condensate sales	170.4		50.9		15.7		—		—		237.0		Crude oil and condensate sales	194.4		62.5		21.2		—		—		278.1

Product sales	Product sales	268.3		879.5		61.7		26.1		—		1,235.6		Product sales	354.1		1,144.3		79.7		32.1		—		1,610.2

NGL sales—related parties	NGL sales—related parties	195.5		30.2		137.1		94.3		(457.1)		—		NGL sales—related parties	301.4		39.5		180.2		131.2		(652.3)		—
Crude oil and condensate sales—related parties	Crude oil and condensate sales—related parties	—		—		0.1		2.1		(2.2)		—		Crude oil and condensate sales—related parties	—		—		—		1.5		(1.5)		—
Product sales—related parties	Product sales—related parties	195.5		30.2		137.2		96.4		(459.3)		—		Product sales—related parties	301.4		39.5		180.2		132.7		(653.8)		—
Gathering and transportation	Gathering and transportation	11.8		16.4		45.9		38.2		—		112.3		Gathering and transportation	12.8		16.3		44.6		39.0		—		112.7
Processing	Processing	6.0		0.5		28.1		27.0		—		61.6		Processing	7.5		0.9		26.5		27.0		—		61.9
NGL services	NGL services	—		17.1		—		0.1		—		17.2		NGL services	—		16.9		—		—		—		16.9
Crude services	Crude services	4.0		9.6		3.4		0.2		—		17.2		Crude services	5.5		10.3		2.8		0.1		—		18.7
Other services	Other services	0.2		0.4		0.2		0.2		—		1.0		Other services	0.2		0.4		0.1		0.1		—		0.8
Midstream services	Midstream services	22.0		44.0		77.6		65.7		—		209.3		Midstream services	26.0		44.8		74.0		66.2		—		211.0

Crude services—related parties														Crude services—related parties	—		—		0.1		—		(0.1)		—
Other services—related parties														Other services—related parties	—		0.1		—		—		(0.1)		—
Midstream services—related parties														Midstream services—related parties	—		0.1		0.1		—		(0.2)		—
Revenue from contracts with customers	Revenue from contracts with customers	485.8		953.7		276.5		188.2		(459.3)		1,444.9		Revenue from contracts with customers	681.5		1,228.7		334.0		231.0		(654.0)		1,821.2
Cost of sales, exclusive of operating expenses and depreciation and amortization (1)	Cost of sales, exclusive of operating expenses and depreciation and amortization (1)	(402.3)		(838.9)		(164.9)		(108.3)		459.3		(1,055.1)		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)
Realized loss on derivatives	Realized loss on derivatives	(4.2)		(6.4)		(2.9)		(0.9)		—		(14.4)		Realized loss on derivatives	(8.7)		(14.9)		(6.8)		(2.0)		—		(32.4)
Change in fair value of derivatives	Change in fair value of derivatives	(7.9)		(9.4)		(5.3)		(1.2)		—		(23.8)		Change in fair value of derivatives	10.2		(8.8)		(2.3)		(0.3)		—		(1.2)
Adjusted gross margin	Adjusted gross margin	71.4		99.0		103.4		77.8		—		351.6		Adjusted gross margin	106.4		94.2		106.9		79.3		—		386.8
Operating expenses	Operating expenses	(27.4)		(31.7)		(17.8)		(19.9)		—		(96.8)		Operating expenses	(37.3)		(30.5)		(19.8)		(19.3)		—		(106.9)
Segment profit	Segment profit	44.0		67.3		85.6		57.9		—		254.8		Segment profit	69.1		63.7		87.1		60.0		—		279.9
Depreciation and amortization	Depreciation and amortization	(34.6)		(36.1)		(50.6)		(28.8)		(1.8)		(151.9)		Depreciation and amortization	(35.4)		(34.6)		(52.3)		(28.5)		(2.2)		(153.0)

Gain on disposition of assets	Gain on disposition of assets	—		0.2		—		0.1		—		0.3		Gain on disposition of assets	0.1		0.2		—		0.1		—		0.4
General and administrative	General and administrative	—		—		—		—		(26.1)		(26.1)		General and administrative	—		—		—		—		(28.2)		(28.2)
Interest expense, net of interest income	Interest expense, net of interest income	—		—		—		—		(60.0)		(60.0)		Interest expense, net of interest income	—		—		—		—		(60.1)		(60.1)

Loss from unconsolidated affiliate investments	Loss from unconsolidated affiliate investments	—		—		—		—		(1.3)		(1.3)		Loss from unconsolidated affiliate investments	—		—		—		—		(2.3)		(2.3)
Other income		—		—		—		—		0.2		0.2

Income (loss) before non-controlling interest and income taxes	Income (loss) before non-controlling interest and income taxes	$	9.4	$	31.4	$	35.0	$	29.2	$	(89.0)	$	16.0	Income (loss) before non-controlling interest and income taxes	$	33.8	$	29.3	$	34.8	$	31.6	$	(92.8)	$	36.7

Capital expenditures	Capital expenditures	$	39.5	$	2.2	$	4.9	$	1.9	$	0.1	$	48.6	Capital expenditures	$	25.8	$	0.4	$	10.3	$	3.3	$	0.6	$	40.4

____________________________

(1)Includes related party cost of sales of ~~$3.6~~$4.9 million for the three months ended ~~June~~September 30, 2021.

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(Unaudited)


		Permian		Louisiana		Oklahoma		North Texas		Corporate		Totals			Permian		Louisiana		Oklahoma		North Texas		Corporate		Totals
Six Months Ended June 30, 2022
Nine Months Ended September 30, 2022														Nine Months Ended September 30, 2022
Natural gas sales	Natural gas sales	$	518.6	$	484.4	$	163.4	$	63.3	$	—	$	1,229.7	Natural gas sales	$	880.2	$	868.2	$	277.9	$	106.1	$	—	$	2,132.4
NGL sales	NGL sales	—		2,315.2		6.7		—		—		2,321.9		NGL sales	0.2		3,382.6		8.4		1.4		—		3,392.6
Crude oil and condensate sales	Crude oil and condensate sales	603.6		183.9		75.3		—		—		862.8		Crude oil and condensate sales	884.3		280.9		108.6		—		—		1,273.8

Product sales	Product sales	1,122.2		2,983.5		245.4		63.3		—		4,414.4		Product sales	1,764.7		4,531.7		394.9		107.5		—		6,798.8

NGL sales—related parties	NGL sales—related parties	827.3		80.0		450.7		312.7		(1,670.7)		—		NGL sales—related parties	1,207.6		126.3		653.9		452.4		(2,440.2)		—
Crude oil and condensate sales—related parties	Crude oil and condensate sales—related parties	—		—		0.3		7.0		(7.3)		—		Crude oil and condensate sales—related parties	—		—		0.3		9.6		(9.9)		—
Product sales—related parties	Product sales—related parties	827.3		80.0		451.0		319.7		(1,678.0)		—		Product sales—related parties	1,207.6		126.3		654.2		462.0		(2,450.1)		—
Gathering and transportation	Gathering and transportation	33.5		32.0		87.4		79.4		—		232.3		Gathering and transportation	54.4		54.1		133.3		129.3		—		371.1
Processing	Processing	17.7		0.8		54.0		55.5		—		128.0		Processing	28.8		1.2		85.4		95.0		—		210.4
NGL services	NGL services	—		42.3		—		0.1		—		42.4		NGL services	—		61.8		—		0.2		—		62.0
Crude services	Crude services	10.3		18.6		6.9		0.4		—		36.2		Crude services	16.0		26.7		9.9		0.5		—		53.1
Other services	Other services	0.4		0.8		0.2		0.3		—		1.7		Other services	0.6		1.2		0.4		0.4		—		2.6
Midstream services	Midstream services	61.9		94.5		148.5		135.7		—		440.6		Midstream services	99.8		145.0		229.0		225.4		—		699.2

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	—		0.1		—		—		(0.1)		—		Other services—related parties	—		0.2		—		—		(0.2)		—
Midstream services—related parties	Midstream services—related parties	—		0.1		0.1		—		(0.2)		—		Midstream services—related parties	—		0.2		0.1		—		(0.3)		—
Revenue from contracts with customers	Revenue from contracts with customers	2,011.4		3,158.1		845.0		518.7		(1,678.2)		4,855.0		Revenue from contracts with customers	3,072.1		4,803.2		1,278.2		794.9		(2,450.4)		7,498.0
Cost of sales, exclusive of operating expenses and depreciation and amortization (1)	Cost of sales, exclusive of operating expenses and depreciation and amortization (1)	(1,724.7)		(2,907.9)		(598.1)		(347.1)		1,678.2		(3,899.6)		Cost of sales, exclusive of operating expenses and depreciation and amortization (1)	(2,628.0)		(4,425.7)		(913.4)		(514.0)		2,450.4		(6,030.7)
Realized loss on derivatives	Realized loss on derivatives	(12.6)		(9.1)		(19.5)		(5.7)		—		(46.9)		Realized loss on derivatives	(11.3)		(5.8)		(18.9)		(8.6)		—		(44.6)
Change in fair value of derivatives	Change in fair value of derivatives	6.6		6.2		1.1		6.3		—		20.2		Change in fair value of derivatives	9.0		10.2		10.6		8.6		—		38.4
Adjusted gross margin	Adjusted gross margin	280.7		247.3		228.5		172.2		—		928.7		Adjusted gross margin	441.8		381.9		356.5		280.9		—		1,461.1
Operating expenses	Operating expenses	(95.6)		(67.8)		(44.1)		(42.3)		—		(249.8)		Operating expenses	(145.3)		(105.4)		(67.6)		(68.3)		—		(386.6)
Segment profit	Segment profit	185.1		179.5		184.4		129.9		—		678.9		Segment profit	296.5		276.5		288.9		212.6		—		1,074.5
Depreciation and amortization	Depreciation and amortization	(73.8)		(74.9)		(103.2)		(57.1)		(2.9)		(311.9)		Depreciation and amortization	(110.6)		(114.6)		(154.7)		(90.5)		(4.1)		(474.5)

Gain (loss) on disposition of assets	Gain (loss) on disposition of assets	—		0.2		0.4		(5.3)		—		(4.7)		Gain (loss) on disposition of assets	—		0.3		0.5		(4.7)		—		(3.9)
General and administrative	General and administrative	—		—		—		—		(57.4)		(57.4)		General and administrative	—		—		—		—		(91.9)		(91.9)
Interest expense, net of interest income	Interest expense, net of interest income	—		—		—		—		(110.6)		(110.6)		Interest expense, net of interest income	—		—		—		—		(171.0)		(171.0)
Loss on extinguishment of debt	Loss on extinguishment of debt	—		—		—		—		(0.5)		(0.5)		Loss on extinguishment of debt	—		—		—		—		(6.2)		(6.2)
Loss from unconsolidated affiliate investments	Loss from unconsolidated affiliate investments	—		—		—		—		(2.3)		(2.3)		Loss from unconsolidated affiliate investments	—		—		—		—		(4.0)		(4.0)
Other income	Other income	—		—		—		—		0.3		0.3		Other income	—		—		—		—		0.6		0.6
Income (loss) before non-controlling interest and income taxes	Income (loss) before non-controlling interest and income taxes	$	111.3	$	104.8	$	81.6	$	67.5	$	(173.4)	$	191.8	Income (loss) before non-controlling interest and income taxes	$	185.9	$	162.2	$	134.7	$	117.4	$	(276.6)	$	323.6
Capital expenditures	Capital expenditures	$	68.9	$	12.0	$	26.9	$	11.2	$	3.5	$	122.5	Capital expenditures	$	130.6	$	18.5	$	45.1	$	17.7	$	5.1	$	217.0

____________________________

(1)Includes related party cost of sales of ~~$19.7~~$25.3 million for the ~~six~~nine months ended ~~June~~September 30, 2022.

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Notes to Consolidated Financial Statements (Continued)

(Unaudited)


		Permian		Louisiana		Oklahoma		North Texas		Corporate		Totals			Permian		Louisiana		Oklahoma		North Texas		Corporate		Totals
Six Months Ended June 30, 2021
Nine Months Ended September 30, 2021														Nine Months Ended September 30, 2021
Natural gas sales	Natural gas sales	$	222.4	$	243.2	$	81.5	$	77.2	$	—	$	624.3	Natural gas sales	$	381.7	$	426.4	$	139.7	$	109.4	$	—	$	1,057.2
NGL sales	NGL sales	0.5		1,332.6		1.0		1.1		—		1,335.2		NGL sales	0.9		2,231.2		1.3		1.0		—		2,234.4
Crude oil and condensate sales	Crude oil and condensate sales	277.7		92.0		29.3		—		—		399.0		Crude oil and condensate sales	472.1		154.5		50.5		—		—		677.1

Product sales	Product sales	500.6		1,667.8		111.8		78.3		—		2,358.5		Product sales	854.7		2,812.1		191.5		110.4		—		3,968.7

NGL sales—related parties	NGL sales—related parties	360.4		53.8		250.2		175.2		(839.6)		—		NGL sales—related parties	661.8		93.3		430.4		306.4		(1,491.9)		—
Crude oil and condensate sales—related parties	Crude oil and condensate sales—related parties	—		—		0.1		3.6		(3.7)		—		Crude oil and condensate sales—related parties	—		—		0.1		5.1		(5.2)		—
Product sales—related parties	Product sales—related parties	360.4		53.8		250.3		178.8		(843.3)		—		Product sales—related parties	661.8		93.3		430.5		311.5		(1,497.1)		—
Gathering and transportation	Gathering and transportation	21.5		32.2		97.2		78.6		—		229.5		Gathering and transportation	34.3		48.5		141.8		117.6		—		342.2
Processing	Processing	14.2		1.0		44.0		54.1		—		113.3		Processing	21.7		1.9		70.5		81.1		—		175.2
NGL services	NGL services	—		39.1		—		0.2		—		39.3		NGL services	—		56.0		—		0.2		—		56.2
Crude services	Crude services	7.5		19.5		6.7		0.4		—		34.1		Crude services	13.0		29.8		9.5		0.5		—		52.8
Other services	Other services	0.4		0.9		0.4		0.3		—		2.0		Other services	0.6		1.3		0.5		0.4		—		2.8
Midstream services	Midstream services	43.6		92.7		148.3		133.6		—		418.2		Midstream services	69.6		137.5		222.3		199.8		—		629.2

Crude services—related parties	Crude services—related parties	—		—		0.1		—		(0.1)		—		Crude services—related parties	—		—		0.2		—		(0.2)		—
Other services—related parties	Other services—related parties	—		2.3		—		—		(2.3)		—		Other services—related parties	—		2.4		—		—		(2.4)		—
Midstream services—related parties	Midstream services—related parties	—		2.3		0.1		—		(2.4)		—		Midstream services—related parties	—		2.4		0.2		—		(2.6)		—
Revenue from contracts with customers	Revenue from contracts with customers	904.6		1,816.6		510.5		390.7		(845.7)		2,776.7		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)	Cost of sales, exclusive of operating expenses and depreciation and amortization (1)	(727.9)		(1,579.3)		(315.9)		(212.4)		845.7		(1,989.8)		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	Realized loss on derivatives	(61.1)		(17.1)		(8.9)		(2.8)		—		(89.9)		Realized loss on derivatives	(69.8)		(32.0)		(15.7)		(4.8)		—		(122.3)
Change in fair value of derivatives	Change in fair value of derivatives	(13.2)		(9.8)		(7.1)		(1.6)		—		(31.7)		Change in fair value of derivatives	(3.0)		(18.6)		(9.4)		(1.9)		—		(32.9)
Adjusted gross margin	Adjusted gross margin	102.4		210.4		178.6		173.9		—		665.3		Adjusted gross margin	208.8		304.6		285.5		253.2		—		1,052.1
Operating expenses	Operating expenses	(15.6)		(60.9)		(37.5)		(39.1)		—		(153.1)		Operating expenses	(52.9)		(91.4)		(57.3)		(58.4)		—		(260.0)
Segment profit	Segment profit	86.8		149.5		141.1		134.8		—		512.2		Segment profit	155.9		213.2		228.2		194.8		—		792.1
Depreciation and amortization	Depreciation and amortization	(68.1)		(72.2)		(101.3)		(57.5)		(3.8)		(302.9)		Depreciation and amortization	(103.5)		(106.8)		(153.6)		(86.0)		(6.0)		(455.9)

Gain on disposition of assets	Gain on disposition of assets	0.1		0.1		—		0.1		—		0.3		Gain on disposition of assets	0.2		0.3		—		0.2		—		0.7
General and administrative	General and administrative	—		—		—		—		(52.1)		(52.1)		General and administrative	—		—		—		—		(80.3)		(80.3)
Interest expense, net of interest income	Interest expense, net of interest income	—		—		—		—		(120.0)		(120.0)		Interest expense, net of interest income	—		—		—		—		(180.1)		(180.1)

Loss from unconsolidated affiliate investments	Loss from unconsolidated affiliate investments	—		—		—		—		(7.6)		(7.6)		Loss from unconsolidated affiliate investments	—		—		—		—		(9.9)		(9.9)
Other income	Other income	—		—		—		—		0.1		0.1		Other income	—		—		—		—		0.1		0.1
Income (loss) before non-controlling interest and income taxes	Income (loss) before non-controlling interest and income taxes	$	18.8	$	77.4	$	39.8	$	77.4	$	(183.4)	$	30.0	Income (loss) before non-controlling interest and income taxes	$	52.6	$	106.7	$	74.6	$	109.0	$	(276.2)	$	66.7

Capital expenditures	Capital expenditures	$	52.8	$	5.0	$	6.8	$	4.3	$	0.5	$	69.4	Capital expenditures	$	78.6	$	5.4	$	17.1	$	7.6	$	1.1	$	109.8

____________________________

(1)Includes related party cost of sales of ~~$6.8~~$11.7 million for the ~~six~~nine months ended ~~June~~September 30, 2021.

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

The table below represents information about segment assets as of ~~June~~September 30, 2022 and December 31, 2021 (in millions):


Segment Identifiable Assets:	Segment Identifiable Assets:	June 30, 2022		December 31, 2021		Segment Identifiable Assets:	September 30, 2022		December 31, 2021
Permian	Permian	$	2,525.8	$	2,358.6	Permian	$	2,553.8	$	2,358.6
Louisiana	Louisiana	2,574.8		2,428.6		Louisiana	2,487.0		2,428.6
Oklahoma	Oklahoma	2,581.1		2,619.5		Oklahoma	2,533.3		2,619.5
North Texas	North Texas	869.3		896.8		North Texas	1,130.2		896.8
Corporate (1)	Corporate (1)	127.8		179.7		Corporate (1)	109.0		179.7
Total identifiable assets	Total identifiable assets	$	8,678.8	$	8,483.2	Total identifiable assets	$	8,813.3	$	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)~~(15) 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:	June 30, 2022		December 31, 2021		Other current assets:	September 30, 2022		December 31, 2021
Natural gas and NGLs inventory	Natural gas and NGLs inventory	$	124.9	$	49.4	Natural gas and NGLs inventory	$	149.8	$	49.4
Prepaid expenses and other	Prepaid expenses and other	34.8		34.2		Prepaid expenses and other	25.2		34.2
Other current assets	Other current assets	$	159.7	$	83.6	Other current assets	$	175.0	$	83.6


Other current liabilities:	Other current liabilities:	June 30, 2022		December 31, 2021		Other current liabilities:	September 30, 2022		December 31, 2021
Accrued interest	Accrued interest	$	47.2	$	47.2	Accrued interest	$	62.1	$	47.2
Accrued wages and benefits, including taxes	Accrued wages and benefits, including taxes	22.2		33.1		Accrued wages and benefits, including taxes	30.5		33.1
Accrued ad valorem taxes	Accrued ad valorem taxes	24.3		28.3		Accrued ad valorem taxes	38.9		28.3
Capital expenditure accruals	Capital expenditure accruals	19.3		23.2		Capital expenditure accruals	22.1		23.2

Short-term lease liability	Short-term lease liability	21.2		18.1		Short-term lease liability	22.9		18.1
Installment payable (1)	Installment payable (1)	—		10.0		Installment payable (1)	—		10.0
Inactive easement commitment (2)	Inactive easement commitment (2)	10.0		9.8		Inactive easement commitment (2)	—		9.8
Operating expense accruals	Operating expense accruals	14.2		9.6		Operating expense accruals	15.8		9.6
Other	Other	25.7		23.6		Other	26.0		23.6
Other current liabilities	Other current liabilities	$	184.1	$	202.9	Other current liabilities	$	218.3	$	202.9

____________________________

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

(2)Amount related to an inactive ~~easements~~easement commitment, which was paid ~~as utilized by us with the balance due~~ in August ~~2022 if not utilized.~~2022.

~~(15)~~

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

(16) 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 encountered customer billing disputes related to the delivery of gas during the storm, including one that 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 intend to vigorously defend against Koch’s claims.

Another of our subsidiaries, EnLink Energy GP, LLC, is also involved in 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,

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~~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 claims against our subsidiary lack merit and we intend to vigorously defend against such claims.

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

~~(16) Subsequent Event~~

~~Acquisition of Barnett Shale Assets from Crestwood Equity Partners LP.~~ On May 19, 2022, we entered into an agreement to acquire the North Texas gathering and processing assets of Crestwood Equity Partners LP located in the Barnett Shale, for an upfront cash purchase price of approximately $275.0 million, plus an amount equal to the estimated working capital of approximately $14.5 million, subject to customary adjustments. These assets include approximately 500 miles of lean and rich gas gathering pipeline and 3 processing plants with 425 MMcf/d of total processing capacity. The acquisition closed on July 1, 2022. The initial accounting for this acquisition is not complete and therefore we cannot provide an estimated purchase price allocation as of the date of this report.

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

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

Overview

ENLC is a Delaware limited liability company formed in October 2013. ENLC’s 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.

As of ~~June~~September 30, 2022, our midstream energy asset network includes approximately ~~12,100~~12,500 miles of pipelines, 2225 natural gas processing plants with approximately ~~5.5~~5.9 Bcf/d of processing capacity, seven fractionators with approximately 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 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 90% of our

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adjusted gross margin was derived from fee-based contractual arrangements with minimal direct commodity price exposure for the ~~six~~nine months ended ~~June~~September 30, 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 individually represented greater than 10% of our consolidated revenues for the three and ~~six~~nine months ended ~~June~~September 30, 2022 and 2021. The loss of 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 June 30,				Six Months Ended June 30,					Three Months Ended September 30,				Nine Months Ended September 30,
		2022		2021		2022		2021			2022		2021		2022		2021

Dow Hydrocarbons and Resources LLC	Dow Hydrocarbons and Resources LLC	14.8	%	15.2	%	14.4	%	14.9	%	Dow Hydrocarbons and Resources LLC	14.5	%	14.0	%	14.4	%	14.5	%
Marathon Petroleum Corporation	Marathon Petroleum Corporation	15.5	%	12.8	%	15.8	%	13.8	%	Marathon Petroleum Corporation	11.8	%	12.2	%	14.4	%	13.1	%

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 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

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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. 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. However, oil and natural gas prices continue to remain volatile. Oil and natural gas prices rose during 2021 and ~~have risen very~~rose especially rapidly in the first half of 2022 due to various factors, including a rebound in demand from economic activity after COVID-19 shutdowns, supply issues, and geopolitical events, including Russia’s invasion of Ukraine. ~~As of the date of this report, while~~Since that time, both oil and natural gas prices have moderated from their peaks earlier in the year, although as of the date of this report, the market price for both oil and natural gas are at higher levels than either has traded in recent 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 negatively 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, 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 by the COVID-19 pandemic, which reduced demand 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 begun to rise, although global capital investments by oil and natural gas producers remain below historical levels and producers continue to remain 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 Basin, because of the availability of higher investment returns. Currently, a large percentage of all drilling rigs operating in the

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United States are operating in the Permian Basin. We continue to experience a robust increase in volumes in our Permian

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segment as our operations in that basin are in a favorable position relative to producer activity. 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 investment and declines in volumes produced. However, the rise in commodity prices during 2022 has led to renewed producer interest in both Oklahoma and North Texas and we expect activity to increase in both areas for the remainder of 2022 and during 2023.

Our Louisiana segment, while subject to commodity 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 throughout 2021 and through the first ~~half~~three quarters of 2022, supported by regional industrial activity and export markets. Our activities and, in turn, our financial performance in the Louisiana segment is 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 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, particularly those who may operate on public lands. While none of these initiatives to date have ~~adversely~~materially affected our operations or those of our customers, the Biden Administration could seek, in the future, to put into place 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 are expected to represent only approximately 6% of our total segment profit, net to EnLink, during 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 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~~

On August 16, 2022, the U.S. government enacted the Inflation Reduction Act of 2022 (the "IRA") into law. The enhancements to the 45Q carbon sequestration tax credits provided by the IRA should expand and support the development of our CCS business, while the other provisions are not expected to have a material impact to our business.

Any regulatory changes 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 16, 2022.

Other Recent Developments

Organic Growth and Acquisition

Acquisition of Barnett Shale ~~Assets from Crestwood Equity Partners LP.~~ Assets.On ~~May 19,~~July 1, 2022, we ~~entered into an agreement to acquire~~acquired all of the ~~North Texas~~equity interest in the gathering and processing assets of Crestwood Equity Partners LP located in the Barnett Shale, for ~~an upfront~~a cash purchase price of ~~approximately~~ $275.0 million plus ~~an amount equal to the estimated~~ working capital of ~~approximately~~ $14.5 ~~million, subject to customary adjustments.~~million. These assets include approximately ~~500~~400 miles of lean and rich gas gathering pipeline and three processing plants with 425 MMcf/d of total processing capacity. ~~The acquisition closed on July 1, 2022.~~See “Item 1. Financial Statements—Note 3” for more information regarding this acquisition.

Matterhorn Express Pipeline Joint Venture. On May 16, 2022, we entered into an agreement with WhiteWater Midstream, LLC, Devon Energy Corporation, and MPLX LP to construct a pipeline designed to transport up to 2.5 Bcf/d of natural gas through approximately 490 miles of 42-inch pipeline from Waha Hub in West Texas to Katy, Texas. Supply for the Matterhorn JV will be sourced from multiple upstream connections in the Permian Basin, including direct connections to processing facilities in the Midland Basin through an approximately 75-mile lateral, as well as a direct connection to the 3.2 Bcf/d Agua ~~Blanca Pipeline.~~

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Blanca Pipeline. The Matterhorn Express Pipeline is expected to be in service in the third quarter of 2024, pending the receipt of customary regulatory and other approvals.

Phantom Processing Plant. In November 2021, we began moving equipment and facilities associated with the Thunderbird processing plant in Central Oklahoma to the Midland Basin. ~~This~~We completed the relocation of the Phantom processing plant ~~relocation is expected to increase the processing capacity of~~in October 2022, which increased our Permian Basin processing ~~facilities~~capacity by ~~approximately 200~~235 MMcf/d. ~~We expect to complete the relocation in the fourth quarter of 2022.~~

CCS Business

ExxonMobil Agreement. In October 2022, we entered into a transportation services agreement with a subsidiary of ExxonMobil in connection with the development of a CCS project in the Mississippi River corridor in southeastern Louisiana. Under this agreement, we will deliver CO2 from the Mississippi River corridor to ExxonMobil’s storage location in Vermilion Parish. The reserved capacity available under this agreement is up to 10 million metric tonnes per year, with initial reserved capacity of 3.2 million metric tonnes per year, beginning in early 2025.

BKV Agreement. In June 2022, we entered into an agreement with BKV to develop a CCS project in the Barnett Shale. Under this agreement, we will separate CO2 from lean gas in our North Texas gathering systems and from rich gas delivered to our natural gas processing plant in Bridgeport, Texas. The CO2 waste stream will then be captured, compressed, transported, and sequestered by ~~BKV.~~BKV, beginning in late 2023.

Debt and Equity

Amended AR Facility ~~Agreement.~~ Agreement. On August 1, 2022, we amended certain terms of the AR Facility to, among other things, increase the commitments thereunder from $350.0 million to $500.0 million and extend the scheduled termination date from September 24, 2024 to August 1, 2025. See “Item ~~5. Other Information”~~1. Financial Statements—Note 6” for ~~additional~~more information.

Amended and Restated Revolving Credit ~~Agreement.~~ Agreement. On June 3, 2022, we amended and restated our prior revolving credit facility by entering into the Revolving Credit Facility. See “Item 1. Financial Statements—Note 5”6” for more information.

Senior Unsecured Notes ~~Repurchase.~~ Issuance and Repurchases~~For~~. On August 31, 2022, ENLC completed the sale of $700.0 million in aggregate principal amount of ENLC’s 6.50% senior unsecured notes due September 1, 2030. We used the net proceeds from the sale to settle ENLK’s debt tender offer to repurchase $700.0 million in aggregate principal amount of its senior unsecured notes, consisting of the 2024 Notes and 2025 Notes. Additionally, for the three and ~~six~~nine months ended ~~June~~September 30, 2022, we repurchased ~~approximately $2.0 million~~a portion of ~~ENLK’s~~the outstanding ~~senior unsecured notes due~~ 2024 Notes and 2025 Notes in open market transactions. See “Item 1. Financial Statements—Note 5”6” for more information regarding the activity related to our senior unsecured ~~note repurchase.~~notes.

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. In July 2022, the Board increased the amount available for repurchase to $200.0 million. See “Item 1. Financial Statements—Note 8”9” for more information regarding our common unit repurchase program.

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. See “Item 1. Financial Statements—Note 8”9” for more information regarding repurchases of ENLC common units held by GIP.

Redemption of Series B Preferred Units. In January 2022, we 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 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 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”8” for more information regarding distributions with respect to the Series B Preferred Units.

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Non-GAAP Financial Measures

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

~~Table of Contents~~

Adjusted Gross Margin

We define adjusted gross margin as revenues less cost of sales, exclusive of operating expenses and depreciation and 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 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 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.

The following table reconciles total revenues and gross margin to adjusted gross margin (in millions):


		Three Months Ended June 30,				Six Months Ended June 30,					Three Months Ended September 30,				Nine Months Ended September 30,
		2022		2021		2022		2021			2022		2021		2022		2021
Total revenues	Total revenues	$	2,600.6	$	1,406.7	$	4,828.3	$	2,655.1	Total revenues	$	2,663.5	$	1,787.6	$	7,491.8	$	4,442.7
Cost of sales, exclusive of operating expenses and depreciation and amortization	Cost of sales, exclusive of operating expenses and depreciation and amortization	(2,105.1)		(1,055.1)		(3,899.6)		(1,989.8)		Cost of sales, exclusive of operating expenses and depreciation and amortization	(2,131.1)		(1,400.8)		(6,030.7)		(3,390.6)
Operating expenses	Operating expenses	(128.9)		(96.8)		(249.8)		(153.1)		Operating expenses	(136.8)		(106.9)		(386.6)		(260.0)
Depreciation and amortization	Depreciation and amortization	(159.0)		(151.9)		(311.9)		(302.9)		Depreciation and amortization	(162.6)		(153.0)		(474.5)		(455.9)
Gross margin	Gross margin	207.6		102.9		367.0		209.3		Gross margin	233.0		126.9		600.0		336.2
Operating expenses	Operating expenses	128.9		96.8		249.8		153.1		Operating expenses	136.8		106.9		386.6		260.0
Depreciation and amortization	Depreciation and amortization	159.0		151.9		311.9		302.9		Depreciation and amortization	162.6		153.0		474.5		455.9
Adjusted gross margin	Adjusted gross margin	$	495.5	$	351.6	$	928.7	$	665.3	Adjusted gross margin	$	532.4	$	386.8	$	1,461.1	$	1,052.1

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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 expense related to changes in the fair value of contingent consideration; (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.

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


		Three Months Ended June 30,				Six Months Ended June 30,					Three Months Ended September 30,				Nine Months Ended September 30,
		2022		2021		2022		2021			2022		2021		2022		2021
Net income	Net income	$	123.9	$	9.4	$	189.9	$	22.0	Net income	$	116.6	$	32.3	$	306.5	$	54.3
Interest expense, net of interest income	Interest expense, net of interest income	55.5		60.0		110.6		120.0		Interest expense, net of interest income	60.4		60.1		171.0		180.1
Depreciation and amortization	Depreciation and amortization	159.0		151.9		311.9		302.9		Depreciation and amortization	162.6		153.0		474.5		455.9

Loss from unconsolidated affiliate investments	Loss from unconsolidated affiliate investments	1.2		1.3		2.3		7.6		Loss from unconsolidated affiliate investments	1.7		2.3		4.0		9.9
Distributions from unconsolidated affiliate investments	Distributions from unconsolidated affiliate investments	0.2		0.1		0.4		3.7		Distributions from unconsolidated affiliate investments	0.2		0.1		0.6		3.8
(Gain) loss on disposition of assets	(Gain) loss on disposition of assets	(0.4)		(0.3)		4.7		(0.3)		(Gain) loss on disposition of assets	(0.8)		(0.4)		3.9		(0.7)
Loss on extinguishment of debt	Loss on extinguishment of debt	0.5		—		0.5		—		Loss on extinguishment of debt	5.7		—		6.2		—
Unit-based compensation	Unit-based compensation	5.7		6.4		12.3		12.9		Unit-based compensation	11.4		6.4		23.7		19.3
Income tax expense (benefit)		(1.3)		6.6		1.9		8.0
Income tax expense										Income tax expense	15.2		4.4		17.1		12.4
Unrealized (gain) loss on commodity swaps	Unrealized (gain) loss on commodity swaps	(35.3)		23.8		(20.2)		31.7		Unrealized (gain) loss on commodity swaps	(18.2)		1.2		(38.4)		32.9
Costs associated with the relocation of processing facilities (1)	Costs associated with the relocation of processing facilities (1)	11.1		10.2		22.4		17.8		Costs associated with the relocation of processing facilities (1)	9.7		8.8		32.1		26.6
Other (2)	Other (2)	0.4		0.4		0.7		—		Other (2)	(3.1)		(0.2)		(2.4)		(0.2)
Adjusted EBITDA before non-controlling interest	Adjusted EBITDA before non-controlling interest	320.5		269.8		637.4		526.3		Adjusted EBITDA before non-controlling interest	361.4		268.0		998.8		794.3
Non-controlling interest share of adjusted EBITDA from joint ventures (3)	Non-controlling interest share of adjusted EBITDA from joint ventures (3)	(20.8)		(12.3)		(33.4)		(19.4)		Non-controlling interest share of adjusted EBITDA from joint ventures (3)	(18.0)		(11.6)		(51.4)		(31.0)
Adjusted EBITDA, net to ENLC	Adjusted EBITDA, net to ENLC	$	299.7	$	257.5	$	604.0	$	506.9	Adjusted EBITDA, net to ENLC	$	343.4	$	256.4	$	947.4	$	763.3

____________________________

(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 was completed in the third quarter of 2021 and we ~~expect to complete~~completed the relocation of equipment and facilities from the Thunderbird processing plant in ~~the fourth quarter of~~October 2022.

(2)Includes transaction costs, non-cash expense related to changes in the fair value of contingent consideration, accretion expense associated with asset retirement 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.

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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; (contributions to investment in unconsolidated affiliates); (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. 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.

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


		Three Months Ended June 30,				Six Months Ended June 30,					Three Months Ended September 30,				Nine Months Ended September 30,
		2022		2021		2022		2021			2022		2021		2022		2021
Net cash provided by operating activities	Net cash provided by operating activities	$	174.9	$	176.4	$	482.6	$	402.2	Net cash provided by operating activities	$	343.3	$	197.0	$	825.9	$	599.2
Interest expense (1)	Interest expense (1)	54.2		55.6		107.9		111.5		Interest expense (1)	59.3		55.1		167.2		166.6
Utility credits (redeemed) earned (2)	Utility credits (redeemed) earned (2)	(6.0)		3.4		(11.6)		43.8		Utility credits (redeemed) earned (2)	(16.3)		(5.6)		(27.9)		38.2
Payments to terminate interest rate swaps (3)	Payments to terminate interest rate swaps (3)	—		1.3		—		1.3		Payments to terminate interest rate swaps (3)	—		0.5		—		1.8
Accruals for settled commodity swap transactions	Accruals for settled commodity swap transactions	0.6		(2.6)		(1.6)		(2.5)		Accruals for settled commodity swap transactions	(0.3)		(2.1)		(1.9)		(4.6)
Distributions from unconsolidated affiliate investment in excess of earnings	Distributions from unconsolidated affiliate investment in excess of earnings	0.2		0.1		0.4		3.7		Distributions from unconsolidated affiliate investment in excess of earnings	0.2		0.1		0.6		3.8
Costs associated with the relocation of processing facilities (4)	Costs associated with the relocation of processing facilities (4)	11.1		10.2		22.4		17.8		Costs associated with the relocation of processing facilities (4)	9.7		8.8		32.1		26.6
Other (5)	Other (5)	1.7		1.4		3.4		2.6		Other (5)	(0.1)		(0.2)		3.3		2.4
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	137.2		91.7		309.9		109.2		Accounts receivable, accrued revenues, inventories, and other	(54.3)		167.6		255.6		276.8
Accounts payable, accrued product purchases, and other accrued liabilities	Accounts payable, accrued product purchases, and other accrued liabilities	(53.4)		(67.7)		(276.0)		(163.3)		Accounts payable, accrued product purchases, and other accrued liabilities	19.9		(153.2)		(256.1)		(316.5)
Adjusted EBITDA before non-controlling interest	Adjusted EBITDA before non-controlling interest	320.5		269.8		637.4		526.3		Adjusted EBITDA before non-controlling interest	361.4		268.0		998.8		794.3
Non-controlling interest share of adjusted EBITDA from joint ventures (6)	Non-controlling interest share of adjusted EBITDA from joint ventures (6)	(20.8)		(12.3)		(33.4)		(19.4)		Non-controlling interest share of adjusted EBITDA from joint ventures (6)	(18.0)		(11.6)		(51.4)		(31.0)
Adjusted EBITDA, net to ENLC	Adjusted EBITDA, net to ENLC	299.7		257.5		604.0		506.9		Adjusted EBITDA, net to ENLC	343.4		256.4		947.4		763.3
Growth capital expenditures, net to ENLC (7)	Growth capital expenditures, net to ENLC (7)	(49.9)		(40.0)		(90.4)		(55.9)		Growth capital expenditures, net to ENLC (7)	(82.7)		(33.2)		(173.1)		(89.1)
Maintenance capital expenditures, net to ENLC (7)	Maintenance capital expenditures, net to ENLC (7)	(11.1)		(7.5)		(25.0)		(12.2)		Maintenance capital expenditures, net to ENLC (7)	(8.7)		(6.9)		(33.7)		(19.1)
Interest expense, net of interest income	Interest expense, net of interest income	(55.5)		(60.0)		(110.6)		(120.0)		Interest expense, net of interest income	(60.4)		(60.1)		(171.0)		(180.1)
Distributions declared on common units	Distributions declared on common units	(54.6)		(46.7)		(110.1)		(93.4)		Distributions declared on common units	(54.8)		(46.6)		(164.9)		(140.0)
ENLK preferred unit accrued cash distributions (8)	ENLK preferred unit accrued cash distributions (8)	(23.3)		(23.0)		(46.8)		(46.0)		ENLK preferred unit accrued cash distributions (8)	(23.3)		(23.0)		(70.1)		(69.0)
Costs associated with the relocation of processing facilities (4)	Costs associated with the relocation of processing facilities (4)	(11.1)		(10.2)		(22.4)		(17.8)		Costs associated with the relocation of processing facilities (4)	(9.7)		(8.8)		(32.1)		(26.6)
Contribution to investment in unconsolidated affiliates	Contribution to investment in unconsolidated affiliates	(26.6)		—		(26.6)		—		Contribution to investment in unconsolidated affiliates	(19.7)		—		(46.3)		—
Payments to terminate interest rate swaps	Payments to terminate interest rate swaps	—		(1.3)		—		(1.3)		Payments to terminate interest rate swaps	—		(0.5)		—		(1.8)
Non-cash interest expense	Non-cash interest expense	—		2.4		—		4.6		Non-cash interest expense	—		2.7		—		7.3
Other (9)	Other (9)	(0.1)		0.3		0.3		0.8		Other (9)	0.8		0.5		1.1		1.3
Free cash flow after distributions	Free cash flow after distributions	$	67.5	$	71.5	$	172.4	$	165.7	Free cash flow after distributions	$	84.9	$	80.5	$	257.3	$	246.2

____________________________

(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 termination of ~~$100.0 million of~~ our interest rate swaps due to the partial repayment of the Term Loan in May 2021 and September 2021.”

(4)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 was completed in the third quarter of 2021 and we ~~expect to complete~~completed the relocation of equipment and facilities from the Thunderbird processing plant in ~~the fourth quarter of~~October 2022.

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

(6)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.

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

(8)Represents the cash distributions earned by the Series B Preferred Units and Series C Preferred Units. See “Item 1. Financial Statements—Note 78” 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)Includes current income tax expense and proceeds from the sale of surplus or unused equipment and land, which occurred in the normal operation of our business.

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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 June 30, 2022
Three Months Ended September 30, 2022														Three Months Ended September 30, 2022
Gross margin	Gross margin	$	75.0	$	49.6	$	46.3	$	38.2	$	(1.5)	$	207.6	Gross margin	$	74.6	$	57.3	$	53.0	$	49.3	$	(1.2)	$	233.0
Depreciation and amortization	Depreciation and amortization	37.1		39.4		52.3		28.7		1.5		159.0		Depreciation and amortization	36.8		39.7		51.5		33.4		1.2		162.6
Segment profit	Segment profit	112.1		89.0		98.6		66.9		—		366.6		Segment profit	111.4		97.0		104.5		82.7		—		395.6
Operating expenses	Operating expenses	50.3		34.8		23.1		20.7		—		128.9		Operating expenses	49.7		37.6		23.5		26.0		—		136.8
Adjusted gross margin	Adjusted gross margin	$	162.4	$	123.8	$	121.7	$	87.6	$	—	$	495.5	Adjusted gross margin	$	161.1	$	134.6	$	128.0	$	108.7	$	—	$	532.4

Three Months Ended June 30, 2021
Three Months Ended September 30, 2021														Three Months Ended September 30, 2021
Gross margin	Gross margin	$	9.4	$	31.2	$	35.0	$	29.1	$	(1.8)	$	102.9	Gross margin	$	33.7	$	29.1	$	34.8	$	31.5	$	(2.2)	$	126.9
Depreciation and amortization	Depreciation and amortization	34.6		36.1		50.6		28.8		1.8		151.9		Depreciation and amortization	35.4		34.6		52.3		28.5		2.2		153.0
Segment profit	Segment profit	44.0		67.3		85.6		57.9		—		254.8		Segment profit	69.1		63.7		87.1		60.0		—		279.9
Operating expenses	Operating expenses	27.4		31.7		17.8		19.9		—		96.8		Operating expenses	37.3		30.5		19.8		19.3		—		106.9
Adjusted gross margin	Adjusted gross margin	$	71.4	$	99.0	$	103.4	$	77.8	$	—	$	351.6	Adjusted gross margin	$	106.4	$	94.2	$	106.9	$	79.3	$	—	$	386.8


		Permian		Louisiana		Oklahoma		North Texas		Corporate		Totals			Permian		Louisiana		Oklahoma		North Texas		Corporate		Totals
Six Months Ended June 30, 2022
Nine Months Ended September 30, 2022														Nine Months Ended September 30, 2022
Gross margin	Gross margin	$	111.3	$	104.6	$	81.2	$	72.8	$	(2.9)	$	367.0	Gross margin	$	185.9	$	161.9	$	134.2	$	122.1	$	(4.1)	$	600.0
Depreciation and amortization	Depreciation and amortization	73.8		74.9		103.2		57.1		2.9		311.9		Depreciation and amortization	110.6		114.6		154.7		90.5		4.1		474.5
Segment profit	Segment profit	185.1		179.5		184.4		129.9		—		678.9		Segment profit	296.5		276.5		288.9		212.6		—		1,074.5
Operating expenses	Operating expenses	95.6		67.8		44.1		42.3		—		249.8		Operating expenses	145.3		105.4		67.6		68.3		—		386.6
Adjusted gross margin	Adjusted gross margin	$	280.7	$	247.3	$	228.5	$	172.2	$	—	$	928.7	Adjusted gross margin	$	441.8	$	381.9	$	356.5	$	280.9	$	—	$	1,461.1

Six Months Ended June 30, 2021
Nine Months Ended September 30, 2021														Nine Months Ended September 30, 2021
Gross margin	Gross margin	$	18.7	$	77.3	$	39.8	$	77.3	$	(3.8)	$	209.3	Gross margin	$	52.4	$	106.4	$	74.6	$	108.8	$	(6.0)	$	336.2
Depreciation and amortization	Depreciation and amortization	68.1		72.2		101.3		57.5		3.8		302.9		Depreciation and amortization	103.5		106.8		153.6		86.0		6.0		455.9
Segment profit	Segment profit	86.8		149.5		141.1		134.8		—		512.2		Segment profit	155.9		213.2		228.2		194.8		—		792.1
Operating expenses	Operating expenses	15.6		60.9		37.5		39.1		—		153.1		Operating expenses	52.9		91.4		57.3		58.4		—		260.0
Adjusted gross margin	Adjusted gross margin	$	102.4	$	210.4	$	178.6	$	173.9	$	—	$	665.3	Adjusted gross margin	$	208.8	$	304.6	$	285.5	$	253.2	$	—	$	1,052.1

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		Three Months Ended June 30,		Six Months Ended June 30,			Three Months Ended September 30,		Nine Months Ended September 30,
		2022	2021	2022	2021		2022	2021	2022	2021
Midstream Volumes:	Midstream Volumes:					Midstream Volumes:
Permian Segment	Permian Segment					Permian Segment
Gathering and Transportation (MMbtu/d)	Gathering and Transportation (MMbtu/d)	1,494,400	1,025,900	1,421,200	976,000	Gathering and Transportation (MMbtu/d)	1,596,400	1,111,800	1,480,200	1,021,800
Processing (MMbtu/d)	Processing (MMbtu/d)	1,432,200	958,400	1,344,700	917,500	Processing (MMbtu/d)	1,520,800	1,062,800	1,404,100	966,500
Crude Oil Handling (Bbls/d)	Crude Oil Handling (Bbls/d)	175,000	121,900	162,900	115,100	Crude Oil Handling (Bbls/d)	157,700	157,500	161,200	129,400
Louisiana Segment	Louisiana Segment					Louisiana Segment
Gathering and Transportation (MMbtu/d)	Gathering and Transportation (MMbtu/d)	2,696,500	2,139,300	2,597,700	2,145,300	Gathering and Transportation (MMbtu/d)	2,996,100	2,013,900	2,731,900	2,101,000

Crude Oil Handling (Bbls/d)	Crude Oil Handling (Bbls/d)	17,700	15,200	16,800	15,100	Crude Oil Handling (Bbls/d)	18,500	17,600	17,400	16,000
NGL Fractionation (Gals/d)	NGL Fractionation (Gals/d)	7,896,900	7,729,300	7,965,000	7,419,500	NGL Fractionation (Gals/d)	7,930,200	7,050,500	7,953,300	7,295,100
Brine Disposal (Bbls/d)	Brine Disposal (Bbls/d)	3,200	2,900	3,100	2,200	Brine Disposal (Bbls/d)	3,000	3,300	3,100	2,500
Oklahoma Segment	Oklahoma Segment					Oklahoma Segment
Gathering and Transportation (MMbtu/d)	Gathering and Transportation (MMbtu/d)	1,016,100	1,016,200	1,008,100	977,000	Gathering and Transportation (MMbtu/d)	1,036,400	996,900	1,017,600	983,700
Processing (MMbtu/d)	Processing (MMbtu/d)	1,047,600	1,040,000	1,038,600	997,900	Processing (MMbtu/d)	1,067,600	1,004,400	1,048,400	999,900
Crude Oil Handling (Bbls/d)	Crude Oil Handling (Bbls/d)	21,400	23,800	22,600	20,700	Crude Oil Handling (Bbls/d)	21,500	20,000	22,200	20,400
North Texas Segment	North Texas Segment					North Texas Segment
Gathering and Transportation (MMbtu/d)	Gathering and Transportation (MMbtu/d)	1,429,900	1,377,400	1,397,100	1,367,200	Gathering and Transportation (MMbtu/d)	1,687,100	1,377,600	1,494,800	1,370,700
Processing (MMbtu/d)	Processing (MMbtu/d)	661,900	627,600	638,300	626,100	Processing (MMbtu/d)	776,700	627,900	684,900	626,700

Three Months Ended ~~June~~September 30, 2022 Compared to Three Months Ended ~~June~~September 30, 2021

Gross Margin. Gross margin was ~~$207.6~~$233.0 million for the three months ended ~~June~~September 30, 2022 compared to ~~$102.9~~$126.9 million for the three months ended ~~June~~September 30, 2021, an increase of ~~$104.7~~$106.1 million. The primary contributors to the increase were as follows:

•Permian Segment. Gross margin was ~~$75.0~~$74.6 million for the three months ended ~~June~~September 30, 2022 compared to ~~$9.4~~$33.7 million for the three months ended ~~June~~September 30, 2021, an increase of ~~$65.6~~$40.9 million primarily due to the following:

◦Adjusted gross margin in the Permian segment increased ~~$91.0~~$54.7 million, which was primarily driven by:

•A ~~$95.9~~$50.9 million increase to adjusted gross margin associated with our Permian gas assets. Adjusted gross margin, excluding derivative activity, increased ~~$75.6~~$50.8 million, which was primarily due to higher volumes from increased producer activity and higher commodity prices. Derivative activity associated with our Permian gas assets increased margin by ~~$20.3~~$0.1 million, which included ~~$3.9~~$7.7 million from ~~increased~~decreased realized losses and ~~$24.2~~$7.6 million from ~~increased~~decreased unrealized gains.

•A ~~$4.9~~$3.8 million ~~decrease~~increase to adjusted gross margin associated with our Permian crude assets. Adjusted gross margin, excluding derivative activity, increased ~~$1.0~~$1.7 million, which was primarily due to higher ~~volumes from increased producer activity.~~commodity prices. Derivative activity associated with our Permian crude assets ~~decreased~~increased margin by ~~$5.9~~$2.1 million, which included ~~$2.1~~$2.3 million from increased realized ~~losses~~gains and ~~$3.8~~$0.2 million from ~~decreased~~increased unrealized ~~gains.~~losses.

◦Operating expenses in the Permian segment increased ~~$22.9 million. During the three months ended June 30, 2021, our Permian operating expenses were reduced by $8.1~~$12.4 million ~~due to electricity credits earned during Winter Storm Uri in February 2021 that were not available during the same quarter of 2022. Operating expenses also increased~~ due to higher construction fees and services, labor and benefits costs, materials and supplies expense, utility costs, and compressor rentals due to an increase in operating ~~activity.~~activity and the transfer of equipment to the Phantom processing facilities in 2022.

◦Depreciation and amortization in the Permian segment increased ~~$2.5~~$1.4 million primarily due to new assets placed into ~~service, including gathering and processing assets associated with the Amarillo Rattler Acquisition in April 2021.~~service.

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•Louisiana Segment. Gross margin was ~~$49.6~~$57.3 million for the three months ended ~~June~~September 30, 2022 compared to ~~$31.2~~$29.1 million for the three months ended ~~June~~September 30, 2021, an increase of ~~$18.4~~$28.2 million primarily due to the following:

◦Adjusted gross margin in the Louisiana segment increased ~~$24.8~~$40.4 million, resulting from:

•An ~~$18.2~~$15.1 million increase to adjusted gross margin associated with our Louisiana NGL transmission and fractionation assets. Adjusted gross margin, excluding derivative activity, ~~increased $1.3~~decreased $7.3 million, which was primarily due to ~~higher volumes from existing customers.~~fluctuations in market prices. Derivative activity associated with our Louisiana NGL transmission and fractionation assets increased margin by ~~$16.9~~$22.4 million, which included ~~$5.2~~$18.0 million from increased realized gains and ~~$11.7~~$4.4 million from increased unrealized gains.

•A ~~$7.6~~$25.8 million increase to adjusted gross margin associated with our Louisiana gas assets. Adjusted gross margin, excluding derivative activity, ~~decreased $2.2~~increased $18.0 million, which was primarily due to ~~unfavorable imbalance activity on our gas storage assets.~~higher volumes from existing customers and higher commodity prices. Derivative activity associated with our Louisiana gas assets increased margin by ~~$9.8~~$7.8 million, which included ~~$0.8~~$0.6 million from increased realized losses and ~~$10.6~~$8.4 million from ~~increased~~decreased unrealized ~~gains.~~losses.

•A ~~$1.0~~$0.5 million decrease to adjusted gross margin associated with our ORV crude assets. Adjusted gross margin, excluding derivative activity, ~~increased $0.6~~decreased $1.3 million, which was primarily due to ~~higher volumes from existing customers.~~fluctuation in market prices. Derivative activity associated with our ORV crude assets ~~decreased~~increased margin by ~~$1.6 million, which included $0.5~~$0.8 million from increased realized ~~losses and $1.1 million from decreased unrealized~~ gains.

◦Operating expenses in the Louisiana segment increased ~~$3.1~~$7.1 million primarily due to increases in materials and supplies expense, utility costs, construction fees and services, ~~and~~ vehicle expenses, and ad valorem taxes due to an increase in operating activity.

◦Depreciation and amortization in the Louisiana segment increased ~~$3.3~~$5.1 million primarily due to changes in estimated useful lives of certain non-core assets.

•Oklahoma Segment. Gross margin was ~~$46.3~~$53.0 million for the three months ended ~~June~~September 30, 2022 compared to ~~$35.0~~$34.8 million for the three months ended ~~June~~September 30, 2021, an increase of ~~$11.3~~$18.2 million primarily due to the following:

◦Adjusted gross margin in the Oklahoma segment increased ~~$18.3~~$21.1 million, resulting from:

•A ~~$22.4~~$21.7 million increase to adjusted gross margin associated with our Oklahoma gas assets. Adjusted gross margin, excluding derivative activity, increased ~~$17.9~~$2.8 million, which was primarily due to higher ~~commodity prices.~~volumes from existing customers. Derivative activity associated with our Oklahoma gas assets increased margin by ~~$4.5~~$18.9 million, which included ~~$11.9~~$7.1 million from increased realized ~~losses~~gains and ~~$16.4~~$11.8 million from increased unrealized gains.

•A ~~$4.1~~$0.6 million decrease to adjusted gross margin associated with our Oklahoma crude assets. Adjusted gross margin, excluding derivative activity, decreased ~~$0.2~~$0.9 million, which was primarily due to ~~lower volumes from existing customers as a result of declining production.~~fluctuation in market prices. Derivative activity associated with our Oklahoma crude assets ~~decreased~~increased margin by ~~$3.9 million, which includes $1.0~~$0.3 million from increased realized ~~losses and $2.9 million from decreased unrealized~~ gains.

◦Operating expenses in the Oklahoma segment increased ~~$5.3~~$3.7 million primarily due to increases in materials and supplies expense and construction fees and services ~~and ad valorem taxes~~ due to an increase in operating activity. Operating expenses also increased due to the transfer of equipment related to the Phantom processing facility.

◦Depreciation and amortization in the Oklahoma segment ~~increased $1.7~~decreased $0.8 million due to ~~additional assets placed in service, partially offset by~~ the transfer of equipment to the Phantom and Warhorse processing ~~facilities.~~facilities, which was partially offset by additional assets placed into service.

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•North Texas Segment. Gross margin was ~~$38.2~~$49.3 million for the three months ended ~~June~~September 30, 2022 compared to ~~$29.1~~$31.5 million for the three months ended ~~June~~September 30, 2021, an increase of ~~$9.1~~$17.8 million primarily due to the following:

◦Adjusted gross margin in the North Texas segment increased ~~$9.8~~$29.4 million. Adjusted gross margin, excluding derivative activity, increased ~~$7.2~~$27.7 million, which was primarily due to the acquisition of Barnett Shale gathering and processing assets on July 1, 2022 and higher volumes from existing customers. Derivative activity associated with our North Texas segment increased margin by ~~$2.6~~$1.7 million, which included ~~$1.4~~$0.9 million from increased realized losses and ~~$4.0~~$2.6 million from increased unrealized gains.

◦Operating expenses in the North Texas segment increased ~~$0.8~~$6.7 million primarily due to increases in materials and supplies expense and ~~compressor rentals~~ad valorem taxes due to an increase in operating ~~activity.~~activity and the acquisition of Barnett Shale gathering and processing assets on July 1, 2022.

◦Depreciation and amortization in the North Texas segment ~~decreased $0.1~~increased $4.9 million primarily due to the acquisition of Barnett Shale gathering and processing assets ~~reaching the end of their depreciable lives.~~on July 1, 2022.

•Corporate Segment. Gross margin was negative ~~$1.5~~$1.2 million for the three months ended ~~June~~September 30, 2022 compared to negative ~~$1.8~~$2.2 million for the three months ended ~~June~~September 30, 2021. Corporate gross margin consists of depreciation and amortization of corporate assets.

General and Administrative Expenses. General and administrative expenses were ~~$28.4~~$34.5 million for the three months ended ~~June~~September 30, 2022 compared to ~~$26.1~~$28.2 million for the three months ended ~~June~~September 30, 2021, an increase of ~~$2.3~~$6.3 million. The increase was primarily due to an increase in ~~labor and benefits costs~~unit-based compensation and consulting fees and services. The increase was partially offset by a ~~reduction~~gain related to a decrease in ~~transaction and transition costs related to~~the estimated fair value of the Amarillo Rattler Acquisition ~~in April 2021.~~contingent consideration.

Interest Expense. Interest expense was ~~$55.5~~$60.4 million for the three months ended ~~June~~September 30, 2022 compared to ~~$60.0~~$60.1 million for the three months ended ~~June~~September 30, 2021, ~~a decrease~~an increase of ~~$4.5~~$0.3 million. Interest expense consisted of the following (in millions):


		Three Months Ended June 30,					Three Months Ended September 30,
		2022		2021			2022		2021
ENLK and ENLC Senior Notes	ENLK and ENLC Senior Notes	$	50.3	$	50.3	ENLK and ENLC Senior Notes	$	51.5	$	50.3
Term Loan	Term Loan	—		1.3		Term Loan	—		1.0
Revolving Credit Facility	Revolving Credit Facility	2.2		1.4		Revolving Credit Facility	4.4		1.3
AR Facility	AR Facility	1.7		0.8		AR Facility	3.6		1.0
Capitalized interest		—		(0.1)

Amortization of debt issuance costs and net discount of senior unsecured notes	Amortization of debt issuance costs and net discount of senior unsecured notes	1.3		1.3		Amortization of debt issuance costs and net discount of senior unsecured notes	1.1		1.4
Interest rate swaps - realized	Interest rate swaps - realized	—		4.8		Interest rate swaps - realized	—		5.0
Other	Other	—		0.2		Other	(0.2)		0.1
Total	Total	$	55.5	$	60.0	Total	$	60.4	$	60.1

Loss from Unconsolidated Affiliate Investments. Loss from unconsolidated affiliate investments was ~~$1.2~~$1.7 million for the three months ended ~~June~~September 30, 2022 compared to a loss of ~~$1.3~~$2.3 million for the three months ended ~~June~~September 30, 2021, a reduction in loss of ~~$0.1~~$0.6 million. The reduction in loss was primarily attributable to a reduction in loss of ~~$0.3~~$0.9 million from our ~~Cedar Cove JV~~GCF investment and was partially offset by an increase in loss of ~~$0.2~~$0.3 million from ~~our GCF investment, as a result of~~ the ~~GCF assets being idled beginning in January 2021.~~Matterhorn JV.

Income Tax ~~Benefit (Expense).~~Expense. Income tax ~~benefit~~expense was ~~$1.3~~$15.2 million for the three months ended ~~June~~September 30, 2022 compared to an income tax expense of ~~$6.6~~$4.4 million for the three months ended ~~June~~September 30, 2021. The increase in income tax ~~benefit~~expense was primarily attributable to ~~the changes in the valuation allowance and was partially offset by~~ the increase in income between periods. See “Item 1. Financial Statements—Note 6”7” for additional information.

Net Income Attributable to Non-Controlling Interest. Net income attributable to non-controlling interest was ~~$38.6~~$35.8 million for the three months ended ~~June~~September 30, 2022 compared to net income of ~~$31.0~~$30.4 million for the three months ended ~~June~~September 30, 2021, an increase of ~~$7.6~~$5.4 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. The increase in income was primarily due to a ~~$8.8~~$6.8 million increase attributable to NGP’s 49.9% share of the Delaware Basin JV and was partially offset by a ~~$0.5~~$0.6 million decrease attributable to Marathon Petroleum Corporation’s 50%

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share of the Ascension JV and a ~~$0.7~~$0.8 million decrease in income attributable to the Series B Preferred Units following the partial redemptions of the Series B Units in December 2021 and January 2022.

~~Table of Contents~~

~~Six~~Nine Months Ended ~~June~~September 30, 2022 Compared to ~~Six~~Nine Months Ended ~~June~~September 30, 2021

Gross Margin. Gross margin was ~~$367.0~~$600.0 million for the ~~six~~nine months ended ~~June~~September 30, 2022 compared to ~~$209.3~~$336.2 million for the ~~six~~nine months ended ~~June~~September 30, 2021, an increase of ~~$157.7~~$263.8 million. The primary contributors to the increase were as follows:

•Permian Segment. Gross margin was ~~$111.3~~$185.9 million for the ~~six~~nine months ended ~~June~~September 30, 2022 compared to ~~$18.7~~$52.4 million for the ~~six~~nine months ended ~~June~~September 30, 2021, an increase of ~~$92.6~~$133.5 million primarily due to the following:

◦Adjusted gross margin in the Permian segment increased ~~$178.3~~$233.0 million, which was primarily driven by:

•A ~~$167.4~~$218.3 million increase to adjusted gross margin associated with our Permian gas assets. Adjusted gross margin, excluding derivative activity, increased ~~$95.7~~$146.5 million, which was primarily due to higher volumes from increased producer activity and higher commodity prices. Derivative activity associated with our Permian gas assets increased margin by ~~$71.7~~$71.8 million, which included ~~$52.8~~$60.5 million from decreased realized losses and ~~$18.9~~$11.3 million from increased unrealized gains.

•A ~~$10.9~~$14.7 million increase to adjusted gross margin associated with our Permian crude assets. Adjusted gross margin, excluding derivative activity, increased ~~$14.3~~$16.0 million, which was primarily due to higher volumes from increased producer activity. Derivative activity associated with our Permian crude assets decreased margin by ~~$3.4~~$1.3 million, which included ~~$4.3~~$2.0 million from ~~increased~~decreased realized ~~losses~~gains and ~~$0.9~~$0.7 million from increased unrealized gains.

◦Operating expenses in the Permian segment increased ~~$80.0~~$92.4 million. During the ~~six~~nine months ended ~~June~~September 30, 2021, our Permian operating expenses were reduced by $48.1 million due to electricity credits earned during Winter Storm Uri in February 2021 that were not available during the same ~~quarter~~period of 2022. Operating expenses also increased due to higher construction fees and services, labor and benefits costs, materials and supplies expense, compressor rentals, and ad valorem and sales and use taxes due to an increase in operating ~~activity.~~activity and the transfer of equipment to the Warhorse and Phantom processing facilities in 2022.

◦Depreciation and amortization in the Permian segment increased ~~$5.7~~$7.1 million primarily due to new assets placed into service, including gathering and processing assets associated with the Amarillo Rattler Acquisition in April 2021.

•Louisiana Segment. Gross margin was ~~$104.6~~$161.9 million for the ~~six~~nine months ended ~~June~~September 30, 2022 compared to ~~$77.3~~$106.4 million for the ~~six~~nine months ended ~~June~~September 30, 2021, an increase of ~~$27.3~~$55.5 million primarily due to the following:

◦Adjusted gross margin in the Louisiana segment increased ~~$36.9~~$77.3 million, resulting from:

•A ~~$28.5~~$43.6 million increase to adjusted gross margin associated with our Louisiana NGL transmission and fractionation assets. Adjusted gross margin, excluding derivative activity, increased ~~$8.9~~$1.6 million, which was primarily due to higher volumes from existing customers. Derivative activity associated with our Louisiana NGL transmission and fractionation assets increased margin by ~~$19.6~~$42.0 million, which included ~~$12.2~~$30.2 million from ~~decreased~~increased realized ~~losses~~gains and ~~$7.4~~$11.8 million from increased unrealized gains.

•An ~~$8.5~~$34.3 million increase to adjusted gross margin associated with our Louisiana gas assets. Adjusted gross margin, excluding derivative activity, increased ~~$2.2~~$20.2 million, which was primarily due to higher volumes from existing customers. Derivative activity associated with our Louisiana gas assets increased margin by ~~$6.3~~$14.1 million, which included ~~$3.4~~$4.0 million from increased realized losses and ~~$9.7~~$18.1 million from increased unrealized gains.

•A ~~$0.1~~$0.6 million decrease to adjusted gross margin associated with our ORV crude assets. Adjusted gross margin, excluding derivative activity, increased ~~$1.8~~$0.5 million, which was primarily due to higher volumes from existing customers. Derivative activity associated with our ORV crude assets decreased margin by ~~$1.9 million, which included $0.8 million from increased realized losses and~~ $1.1 million from decreased unrealized gains.

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◦Operating expenses in the Louisiana segment increased ~~$6.9~~$14.0 million primarily due to increases in utility costs, construction fees and services, and compressor rentals due to an increase in operating activity. These increases were partially offset by decreases in consulting fees and services.

◦Depreciation and amortization in the Louisiana segment increased ~~$2.7~~$7.8 million primarily due to changes in estimated useful lives of certain non-core assets.

~~Table of Contents~~

•Oklahoma Segment. Gross margin was ~~$81.2~~$134.2 million for the ~~six~~nine months ended ~~June~~September 30, 2022 compared to ~~$39.8~~$74.6 million for the ~~six~~nine months ended ~~June~~September 30, 2021, an increase of ~~$41.4~~$59.6 million primarily due to the following:

◦Adjusted gross margin in the Oklahoma segment increased ~~$49.9~~$71.0 million, resulting from:

•A ~~$51.9~~$73.6 million increase to adjusted gross margin associated with our Oklahoma gas assets. Adjusted gross margin, excluding derivative activity, increased ~~$50.8~~$53.6 million, which was primarily due to higher volumes from existing customers, ~~and~~ higher commodity ~~prices.~~prices, and the negative effect in 2021 of weather disruptions from Winter Storm Uri. Derivative activity associated with our Oklahoma gas assets increased margin by ~~$1.1~~$20.0 million, which included ~~$9.6~~$2.5 million from increased realized losses and ~~$10.7~~$22.5 million from increased unrealized gains.

•A ~~$2.0~~$2.6 million decrease to adjusted gross margin associated with our Oklahoma crude assets. Adjusted gross margin, excluding derivative activity, increased ~~$1.5~~$0.6 million, which was primarily due to higher volumes from existing customers. Derivative activity associated with our Oklahoma crude assets decreased margin by ~~$3.5~~$3.2 million, which included ~~$1.0~~$0.7 million from increased realized losses and $2.5 million from decreased unrealized gains.

◦Operating expenses in the Oklahoma segment increased ~~$6.6~~$10.3 million primarily due to increases in materials and supplies expense and construction fees and services due to an increase in operating activity. Operating expenses also increased due to the transfer of equipment to the Phantom processing facility.

◦Depreciation and amortization in the Oklahoma segment increased ~~$1.9~~$1.1 million due to additional assets placed in service, partially offset by the transfer of equipment related to the Phantom and Warhorse processing facilities.

•North Texas Segment. Gross margin was ~~$72.8~~$122.1 million for the ~~six~~nine months ended ~~June~~September 30, 2022 compared to ~~$77.3~~$108.8 million for the ~~six~~nine months ended ~~June~~September 30, 2021, ~~a decrease~~an increase of ~~$4.5~~$13.3 million primarily due to the following:

◦Adjusted gross margin in the North Texas segment ~~decreased $1.7~~increased $27.7 million. Adjusted gross margin, excluding derivative activity, ~~decreased $6.7~~increased $21.0 million, which was primarily due to ~~favorable market pricing resulting from Winter Storm Uri in February 2021,~~the acquisition of Barnett Shale gathering and ~~was partially offset by higher volumes from existing customers in~~processing assets on July 1, 2022. Derivative activity associated with our North Texas segment increased margin by ~~$5.0~~$6.7 million, which included ~~$2.9~~$3.8 million from increased realized losses and ~~$7.9~~$10.5 million from increased unrealized gains.

◦Operating expenses in the North Texas segment increased ~~$3.2~~$9.9 million primarily due to increases in materials and supplies expense, ~~sales and use~~ad valorem taxes, and utility costs due to an increase in operating ~~activity.~~activity and the acquisition of Barnett Shale gathering and processing assets on July 1, 2022.

◦Depreciation and amortization in the North Texas segment ~~decreased $0.4~~increased $4.5 million primarily due to the acquisition of Barnett Shale gathering and processing assets on July 1, 2022, which was partially offset by assets reaching the end of their depreciable lives.

•Corporate Segment. Gross margin was negative ~~$2.9~~$4.1 million for the ~~six~~nine months ended ~~June~~September 30, 2022 compared to negative ~~$3.8~~$6.0 million for the ~~six~~nine months ended ~~June~~September 30, 2021. Corporate gross margin consists of depreciation and amortization of corporate assets.

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General and Administrative Expenses. General and administrative expenses were ~~$57.4~~$91.9 million for the ~~six~~nine months ended ~~June~~September 30, 2022 compared to ~~$52.1~~$80.3 million for the ~~six~~nine months ended ~~June~~September 30, 2021, an increase of ~~$5.3~~$11.6 million. The increase was primarily due to an increase in unit-based compensation, labor ~~and benefits~~ costs, and consulting fees and services. The increase was partially offset by a ~~reduction~~gain related to a decrease in ~~transaction and transition costs related to~~the estimated fair value of the Amarillo Rattler Acquisition ~~in April 2021.~~contingent consideration.

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Interest Expense. Interest expense was ~~$110.6~~$171.0 million for the ~~six~~nine months ended ~~June~~September 30, 2022 compared to ~~$120.0~~$180.1 million for the ~~six~~nine months ended ~~June~~September 30, 2021, a decrease of ~~$9.4~~$9.1 million. Interest expense consisted of the following (in millions):
Six Months Ended
June 30,
2022 2021
ENLK and ENLC Senior Notes $ 100.6 $ 100.6
Term Loan — 2.7
Revolving Credit Facility 4.5 2.7
AR Facility 2.8 2.0
Capitalized interest — (0.3)
Amortization of debt issuance costs and net discount of senior unsecured notes 2.6 2.5
Interest rate swaps - realized 0.1 9.6
Other — 0.2
Total $ 110.6 $ 120.0


	Nine Months Ended September 30,
	2022		2021
ENLK and ENLC Senior Notes	$	152.1	$	150.9
Term Loan	—		3.7
Revolving Credit Facility	8.9		4.0
AR Facility	6.4		3.0

Amortization of debt issuance costs and net discount of senior unsecured notes	3.7		3.9
Interest rate swaps - realized	0.1		14.6
Other	(0.2)		—
Total	$	171.0	$	180.1

Loss from Unconsolidated Affiliate Investments. Loss from unconsolidated affiliate investments was ~~$2.3~~$4.0 million for the ~~six~~nine months ended ~~June~~September 30, 2022 compared to a loss of ~~$7.6~~$9.9 million for the ~~six~~nine months ended ~~June~~September 30, 2021, a reduction in loss of ~~$5.3~~$5.9 million. The reduction in loss was primarily attributable to a reduction in loss of ~~$4.8~~$5.7 million from our GCF investment, as a result of the GCF assets being idled beginning in January 2021, and a reduction of loss of $0.5 million from ~~our~~the Cedar Cove JV. The reduction in loss was partially offset by an increase in loss of $0.3 million from the Matterhorn JV.

Income Tax ~~Benefit (Expense).~~Expense. Income tax expense was ~~$1.9~~$17.1 million for the ~~six~~nine months ended ~~June~~September 30, 2022 compared to an income tax expense of ~~$8.0~~$12.4 million for the ~~six~~nine months ended ~~June~~September 30, 2021. The ~~decrease~~increase in income tax expense was primarily attributable to the ~~changes~~increase in ~~the valuation allowance~~income between periods and was partially offset by the ~~increase~~changes in ~~income between periods.~~the valuation allowance. See “Item 1. Financial Statements—Note 6”7” for additional information.

Net Income Attributable to Non-Controlling Interest. Net income attributable to non-controlling interest was ~~$69.4~~$105.2 million for the ~~six~~nine months ended ~~June~~September 30, 2022 compared to net income of ~~$56.3~~$86.7 million for the ~~six~~nine months ended ~~June~~September 30, 2021, an increase of ~~$13.1~~$18.5 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. The increase in income was primarily due to a ~~$13.4~~$20.2 million increase attributable to NGP’s 49.9% share of the Delaware Basin JV and was partially offset by a ~~$0.5~~$0.1 million ~~increase~~decrease attributable to Marathon Petroleum Corporation’s 50% share of the Ascension JV and ~~was partially offset by~~ a ~~$0.8~~$1.6 million decrease 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 Condition and Results of Operations” of our Annual Report on Form 10-K for the year ended December 31, 2021 filed with the Commission on February 16, 2022.

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Liquidity and Capital Resources

Cash Flows from Operating Activities. Net cash provided by operating activities was ~~$482.6~~$825.9 million for the ~~six~~nine months ended ~~June~~September 30, 2022 compared to ~~$402.2~~$599.2 million for the ~~six~~nine months ended ~~June~~September 30, 2021. Operating cash flows before working capital and changes in working capital for the comparative periods were as follows (in millions):


		Six Months Ended June 30,					Nine Months Ended September 30,
		2022		2021			2022		2021
Operating cash flows before working capital	Operating cash flows before working capital	$	516.5	$	348.1	Operating cash flows before working capital	$	825.4	$	559.5
Changes in working capital	Changes in working capital	(33.9)		54.1		Changes in working capital	0.5		39.7

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Operating cash flows before changes in working capital increased ~~$168.4~~$265.9 million for the ~~six~~nine months ended ~~June~~September 30, 2022 compared to the ~~six~~nine months ended ~~June~~September 30, 2021. The primary contributor to the increase in operating cash flows was as follows:

•Gross margin, excluding depreciation and amortization, non-cash commodity swap activity, utility credits redeemed or earned, and unit-based compensation, increased ~~$168.7~~$273.7 million. The increase in gross margin is due to a ~~$210.6~~$335.0 million increase in adjusted gross margin, excluding non-cash commodity swap activity, which was partially offset by a ~~$41.9~~$61.3 million increase in operating expenses, excluding utility credits redeemed or earned and unit-based compensation. For more information regarding the changes in gross margin for the ~~six~~nine months ended ~~June~~September 30, 2022 compared to the ~~six~~nine months ended ~~June~~September 30, 2021, see “Results of Operations.”

The changes in working capital for the ~~six~~nine months ended ~~June~~September 30, 2022 compared to the ~~six~~nine months ended ~~June~~September 30, 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 ~~$149.3~~$547.0 million for the ~~six~~nine months ended ~~June~~September 30, 2022 compared to ~~$112.2~~$155.4 million for the ~~six~~nine months ended ~~June~~September 30, 2021. Our primary investing activities consisted of the following (in millions):


		Six Months Ended June 30,					Nine Months Ended September 30,
		2022		2021			2022		2021
Additions to property and equipment (1)	Additions to property and equipment (1)	$	(124.1)	$	(62.5)	Additions to property and equipment (1)	$	(213.2)	$	(104.7)
Contributions to unconsolidated affiliate investments (2)	Contributions to unconsolidated affiliate investments (2)	(26.6)		—		Contributions to unconsolidated affiliate investments (2)	(46.3)		—
Acquisitions, net of cash acquired (3)	Acquisitions, net of cash acquired (3)	—		(55.0)		Acquisitions, net of cash acquired (3)	(289.5)		(56.7)

____________________________

(1)The increase in capital expenditures was due to expansion projects to accommodate increased volumes on our systems.

(2)Represents contributions to the Matterhorn JV and GCF. See “Item 1. Financial Statements—Note 9”10” for more information regarding the contributions to unconsolidated affiliate investments.

(3)Represents cash paid for the acquisition of Barnett Shale assets in July 2022 and the Amarillo Rattler Acquisition in April 2021.

5053

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Cash Flows from Financing Activities. Net cash used in financing activities was ~~$341.4~~$305.1 million for the ~~six~~nine months ended ~~June~~September 30, 2022 compared to ~~$296.8~~$447.3 million for the ~~six~~nine months ended ~~June~~September 30, 2021. Our primary financing activities consisted of the following (in millions):
Six Months Ended
June 30,
2022 2021
Net repayments on the Term Loan $ — $ (100.0)
Net repayments on the AR Facility (1) (25.0) (40.0)
Net repayments on the Revolving Credit Facility (1) (15.0) —
Net repurchases of ENLK’s senior unsecured notes (1) (2.0) —
Contributions from non-controlling interests (2) 9.3 1.9
Distributions to members (111.7) (93.8)
Redemption of Series B Preferred Units (3) (50.5) —
Distributions to Series B Preferred Unitholders (3) (35.8) (33.9)
Distributions to Series C Preferred Unitholders (3) (12.0) (12.0)
Distributions to joint venture partners (4) (29.0) (16.1)
Common unit repurchases (5) (50.7) (2.0)
Payment of installment payable for Amarillo Rattler Acquisition (6) (10.0) —


	Nine Months Ended September 30,
	2022		2021
Net repayments on the Term Loan	$	—	$	(200.0)
Net borrowings (repayments) on the AR Facility (1)	150.0		(5.0)
Net borrowings on the Revolving Credit Facility (1)	55.0		—
Net borrowings on ENLC’s senior unsecured notes (1)	700.0		—
Net repurchases of ENLK’s senior unsecured notes (1)	(738.5)		—
Payment of installment payable for Amarillo Rattler Acquisition (2)	(10.0)		—
Payment of inactive easement commitment (3)	(10.0)		—
Contributions from non-controlling interests (4)	14.2		2.4
Distributions to members	(167.4)		(140.4)
Redemption of Series B Preferred Units (5)	(50.5)		—
Distributions to Series B Preferred Unitholders (5)	(53.1)		(50.9)
Distributions to Series C Preferred Unitholders (5)	(12.0)		(12.0)
Distributions to joint venture partners (6)	(50.3)		(25.3)
Common unit repurchases (7)	(113.2)		(14.5)

____________________________

(1)See “Item 1. Financial Statements—Note 5”6” for more information regarding the AR Facility, the Revolving Credit Facility, and the issuance of new senior unsecured notes by us and repurchases of ENLK’s senior unsecured notes.

(2)Consideration for the Amarillo Rattler Acquisition included an installment payable, which was paid on April 30, 2022.

(3)Amount related to an inactive easement commitment, which was paid in August 2022.

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

~~(3)~~(5)See “Item 1. Financial Statements—Note 7”8” for information on distributions to holders of the Series B Preferred Units and Series C Preferred Units and information on the partial redemption of the Series B Preferred Units.

~~(4)~~(6)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.

~~(5)~~(7)See “Item 1. Financial Statements—Note 8”9” for more information regarding the ENLC common unit repurchase program.

~~(6)Consideration for the Amarillo Rattler Acquisition included an installment payable, which was paid on April 30, 2022.~~

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Capital Requirements

~~The~~As of September 30, 2022, the following table summarizes our expected remaining capital requirements for 2022 (in millions):


Capital expenditures, net to ENLC (1)	$	~~185~~108
Operating expenses associated with the relocation of processing facilities (2)	2313
Contributions to unconsolidated affiliate investments (3)	4324
Total	$	~~251~~145

____________________________

(1)Excludes capital expenditures that ~~were~~are contributed by other entities and 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 the Permian segment. We ~~expect to complete~~completed the relocation of equipment and facilities from the Thunderbird processing plant in ~~the fourth quarter of~~October 2022.

(3)Includes contributions made to our GCF investment and the Matterhorn JV.

Our primary remaining capital projects for 2022 include the relocation of the Phantom processing plant, which was completed in October 2022, CCS-related initiatives, contributions to unconsolidated affiliate investments, continued development of our existing systems through well connects, and other low-cost development projects. We expect to fund our remaining 2022 capital requirements from operating cash 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.

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

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Total Contractual Cash Obligations. A summary of our total contractual cash obligations as of ~~June~~September 30, 2022 is as follows (in millions):


		Payments Due by Period															Payments Due by Period
		Total		Remainder 2022		2023		2024		2025		2026		Thereafter			Total		Remainder 2022		2023		2024		2025		2026		Thereafter
ENLC’s & ENLK’s senior unsecured notes	ENLC’s & ENLK’s senior unsecured notes	$	4,030.3	$	—	$	—	$	519.8	$	720.8	$	491.0	$	2,298.7	ENLC’s & ENLK’s senior unsecured notes	$	4,009.2	$	—	$	—	$	97.9	$	421.6	$	491.0	$	2,998.7
Revolving Credit Facility (1)	Revolving Credit Facility (1)	—		—		—		—		—		—		—		Revolving Credit Facility (1)	70.0		—		—		—		—		—		70.0
AR Facility (2)	AR Facility (2)	325.0		—		—		—		325.0		—		—		AR Facility (2)	500.0		—		—		—		500.0		—		—
Acquisition contingent consideration (3)	Acquisition contingent consideration (3)	7.2		—		—		0.7		3.3		3.2		—		Acquisition contingent consideration (3)	4.4		—		—		0.2		0.1		4.1		—
Interest payable on fixed long-term debt obligations	Interest payable on fixed long-term debt obligations	2,234.2		100.6		201.1		189.7		163.3		148.3		1,431.2		Interest payable on fixed long-term debt obligations	2,498.0		59.1		215.8		213.5		202.6		193.8		1,613.2
Operating lease obligations	Operating lease obligations	115.0		12.5		21.7		11.6		9.8		8.9		50.5		Operating lease obligations	115.1		6.7		24.3		13.8		10.8		8.9		50.6
Purchase obligations	Purchase obligations	5.9		5.9		—		—		—		—		—		Purchase obligations	8.3		8.3		—		—		—		—		—
Pipeline and trucking capacity and deficiency agreements (4)	Pipeline and trucking capacity and deficiency agreements (4)	286.2		26.5		55.7		44.2		39.4		30.9		89.5		Pipeline and trucking capacity and deficiency agreements (4)	283.9		14.6		60.6		47.8		40.5		30.9		89.5
Inactive easement commitment (5)		10.0		10.0		—		—		—		—		—
Total contractual obligations	Total contractual obligations	$	7,013.8	$	155.5	$	278.5	$	766.0	$	1,261.6	$	682.3	$	3,869.9	Total contractual obligations	$	7,488.9	$	88.7	$	300.7	$	373.2	$	1,175.6	$	728.7	$	4,822.0

____________________________

(1)The Revolving Credit Facility permits us to borrow up to $1.40 billion on a revolving credit basis and will mature on June 3, 2027. ~~As of June 30, 2022, there were no amounts outstanding under the Revolving Credit Facility.~~

(2)The AR Facility will terminate on August 1, 2025, unless extended or earlier terminated in accordance with its terms.

(3)The estimated fair value of the Amarillo Rattler ~~LLC~~Acquisition contingent consideration was calculated in accordance with the fair value guidance contained in ASC 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”~~13” for additional information.

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

~~(5)Amount related to inactive easements paid as utilized by us with the balance due in August 2022 if not utilized.~~

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

The interest payable related to the Revolving 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 Revolving Credit Facility and the AR Facility, which vary from time to time.

Our contractual cash obligations for the remainder of 2022 are expected to be funded from cash flows generated from our operations.

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Indebtedness

As of ~~June~~September 30, 2022, the AR Facility had a borrowing base of ~~$350.0~~$500.0 million and there were ~~$325.0~~$500.0 million in outstanding borrowings under the AR Facility. On August 1, 2022, we amended certain terms of the AR Facility to, among other things, increase the commitments thereunder from $350.0 million to $500.0 million and extend the scheduled termination date from September 24, 2024 to August 1, 2025. See “Item 5. Other Information” for additional information.

In addition, as of ~~June~~September 30, 2022, we have $4.0 billion in aggregate principal amount of outstanding unsecured senior notes maturing from 2024 to 2047. There were no$70.0 million in outstanding borrowings and $46.6 million in outstanding letters of credit under the Revolving Credit Facility ~~and $44.6 million outstanding letters of credit~~ as of ~~June~~September 30, 2022.

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Guarantees. The amounts outstanding on our senior unsecured notes and the Revolving Credit Facility are guaranteed in full by our subsidiary ENLK, including 105% of any letters of credit outstanding under the Revolving 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 and the Revolving Credit Facility. Liabilities under the guarantees rank equally in right of payment with all existing and future senior unsecured indebtedness of ENLK.

ENLC’s 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 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 ~~June~~September 30, 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.

See “Item 1. Financial Statements—Note 5”6” for more information on our outstanding debt.

Inflation

The annual U.S. inflation rate has increased significantly in the first ~~half~~three quarters of 2022. The Federal Reserve has already increased its target for the federal funds rate (the benchmark for most interest rates) several times this year. It is widely expected that this trend will continue for the remainder of 2022. Inflation will 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

We have reviewed recently issued accounting pronouncements that became effective during the three months ended ~~June~~September 30, 2022 and have determined that none would have a material impact to our consolidated financial statements.

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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 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 future results and growth of our CCS business, 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~~the impact of 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 operations, or cash flows, include, without limitation, (a) the impact of the ongoing coronavirus (COVID-19) pandemic (including the impact of any new variants of the virus) on our business, financial condition, and results of 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 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 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

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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, (t) construction risks in our major development projects, (u) challenges we may face in connection with our strategy to enter into new lines of business related to the energy transition, and (v) the effects of existing and future laws and governmental regulations, including environmental and climate change requirements and other uncertainties. In addition to the specific uncertainties, factors, and risks discussed above and elsewhere in this Quarterly Report on Form 10-Q, the risk factors set forth in Part I, “Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 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.

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

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Commodity Price Risk

We are also subject to direct risks due to fluctuations in commodity prices. While approximately 90% of our adjusted gross margin for the ~~six~~nine months ended ~~June~~September 30, 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.

2.Processing margin contracts. Under these contracts, we pay the producer for the full amount of inlet gas to the plant, and we make a margin based on the difference between the value of liquids recovered from the processed natural gas as compared to the value of the natural gas volumes lost and the cost of fuel used in processing. The shrink and fuel losses are referred to as plant thermal reduction, or PTR. Our margins from these contracts are high during periods of high liquids prices relative to natural gas prices and can be negative during periods of high natural gas prices relative to liquids prices. However, we mitigate our risk of processing natural gas when margins are negative primarily through

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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 ~~six~~nine months ended ~~June~~September 30, 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 ~~six~~nine months ended ~~June~~September 30, 2022, approximately 9%10% 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.

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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 ~~June~~September 30, 2022.

Period

Underlying

Notional Volume

We Pay

We Receive (1)

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

~~July~~October 2022 - ~~June~~September 2023

Ethane

~~575 (MMbbls)~~

~~$0.5410/Gal~~720 (Mbbls)

Index

$0.3930/Gal

~~(0.6)~~3.9

~~July~~October 2022 - ~~June~~September 2023

Propane

~~1,940 (MMbbls)~~1,680 (Mbbls)

Index

$~~1.1987/~~0.8613/Gal

~~(4.1)~~16.6

~~July~~October 2022 - ~~March~~June 2023

Normal butane

~~365 (MMbbls)~~355 (Mbbls)

Index

$~~1.4192/~~0.9710/Gal

~~0.5~~3.6

~~July~~October 2022 - ~~July~~October 2022

Natural gasoline

~~25 (MMbbls)~~120 (Mbbls)

Index

$~~1.9851/~~1.6891/Gal

~~0.1~~0.3

~~July~~October 2022 - ~~June~~September 2023

Natural gas

~~86,034~~126,379 (MMbtu/d)

Index

$~~5.5773/~~6.4518/MMbtu

~~7.3~~ (5.0)

~~July~~October 2022 - ~~July 2023~~January 2024

Crude and condensate

~~5,975 (MMbbls)~~4,650 (Mbbls)

Index

$~~97.17/~~76.61/Bbl

~~2.5~~4.5

~~5.7~~23.9

____________________________

(1)Weighted average.

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

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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 ~~June~~September 30, 2022, outstanding natural gas swap agreements, NGL swap agreements, swing swap agreements, storage swap agreements, and other derivative instruments had a net fair value asset of ~~$5.7~~$23.9 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 ~~$21.0~~$15.0 million in the net fair value of these contracts as of ~~June~~September 30, 2022.

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Interest Rate Risk

We are exposed to interest rate risk on the Revolving Credit Facility and the AR Facility. Amounts drawn on the Revolving Credit Facility and the AR Facility bear interest at rates based on SOFR. At ~~June~~September 30, 2022, we had no$70.0 million in outstanding borrowings under the Revolving Credit Facility and ~~$325.0~~$500.0 million in outstanding borrowings under the AR Facility. A 1.0% increase or decrease in interest rates would change our annualized interest expense by approximately ~~$3.3~~$0.7 million and $5.0 million for the Revolving Credit Facility and AR ~~Facility.~~Facility, respectively.

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, 2029, and ~~2029~~2030 as these are fixed-rate obligations. As of ~~June~~September 30, 2022, the estimated fair value of the senior unsecured notes was approximately ~~$3,425.6~~$3,502.5 million, based on the market prices of ENLK’s and our publicly traded debt at ~~June~~September 30, 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 ~~$178.8~~$209.8 million decrease in fair value of the senior unsecured notes at ~~June~~September 30, 2022. See “Item 1. Financial Statements—Note 5”6” 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 (or an alternative rate to be established) 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 ~~(June~~(September 30, 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 ~~June~~September 30, 2022 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II—OTHER INFORMATION

Item 1. Legal Proceedings

We are involved in various litigation and administrative proceedings arising in the normal course of business. For a discussion of certain litigation and similar proceedings, please refer to Note ~~15,~~16, “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, 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 ~~June~~September 30, 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 and we repurchased common units in open market transactions and from GIP 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)
April 1, 2022 to April 30, 2022 430,416 $ 9.92 418,440 $ 78.8
May 1, 2022 to May 31, 2022 1,656,301 9.53 1,650,690 $ 63.2
June 1, 2022 to June 30, 2022 1,527,335 9.08 1,527,335 $ 149.3
Total 3,614,052 $ 9.39 3,596,465


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, 2022 to July 31, 2022	904,782	$	8.60	901,800	$	141.5
August 1, 2022 to August 31, 2022	3,742,405	9.64		3,533,555	$	107.4
September 1, 2022 to September 30, 2022	2,750,481	9.69		2,146,778	$	86.8
Total	7,397,668	$	9.53	6,582,133

____________________________

(1)The total number of units purchased shown in the table includes ~~17,587~~815,535 ENLC common units received by us from employees for the payment of personal income tax withholding on vesting transactions.

(2)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. In July 2022, the Board increased the amount available for repurchase to $200.0 million. 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. For more information regarding common units repurchased from public unitholders and our repurchase of common units held by GIP, see “Item 1. Financial Statements—Note 8.9.”

~~Item 5. Other Information~~

Disclosure Pursuant to Item 1.01 of Form 8-K – Entry into a Material Definitive Agreement and Item 2.03 of Form 8-K – Creation of a Direct Financial Obligation or an Obligation under an Off-Balance Sheet Arrangement of a Registrant.

On August 1, 2022 (the “Amendment Date”), EnLink Midstream Funding, LLC, a bankruptcy-remote special purpose entity (the “SPV”) that is an indirect subsidiary of ENLC, entered into the Third Amendment to the Receivables Financing Agreement (the “Third Amendment”), which amended the AR Facility, in each case among the SPV, as borrower, the Operating Partnership, as initial servicer, PNC Bank, National Association, as administrative agent and lender, and PNC Capital Markets LLC, as structuring agent and sustainability agent.

Under the Third Amendment and related documentation, the SPV’s three-year committed accounts receivable securitization facility was amended to, among other things: (i) increase the facility limit and lender commitments under the AR Facility from $350.0 million to $500.0 million, (ii) extend the Scheduled Termination Date (as defined in the AR Facility) of the facility to August 1, 2025, and (iii) reduce the currently effective drawn fee to 90 bps from the previous 110 bps.

~~As of the Amendment Date, there were $350.0 million of borrowings by the SPV under the AR Facility and the borrowing base was $500.0 million.~~

The foregoing description of the Third Amendment does not purport to be complete and is qualified in its entirety by reference to the full text of the Third Amendment, a copy of which is filed as Exhibit 10.2 to this report and is incorporated herein by reference.

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Item 6. Exhibits

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


Number			Description

3.1		—	Certificate of 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).
4.1		—	Indenture, dated as of August 31, 2022, by and among EnLink Midstream, LLC, as issuer, EnLink Midstream Partners, LP, as guarantor, and Computershare Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K dated August 31, 2022, filed with the Commission on August 31, 2022, file No. 001-36336).

















10.1		—	Amended and Restated Revolving Credit Agreement, dated as of June 3, 2022, by and among EnLink Midstream, LLC, Bank of America, N.A., as Administrative Agent, Swing Line Lender and L/C Issuer, and each of the Lenders and other L/C Issuers party thereto (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K dated June 3, 2022, filed with the Commission on June 6, 2022, file No. 001-36336)
10.2*10.2		—	Third Amendment to the Receivables Financing Agreement, dated as of August 1, 2022, by and among EnLink Midstream Funding, LLC, as borrower, EnLink Midstream Operating, LP, as initial servicer, PNC Bank, National Association, as administrative agent and as lender and PNC Capital Markets LLC, as structuring agent and sustainability ~~agent.~~
~~22.1~~	—	~~Subsidiary Guarantors~~agent (incorporated by reference to Exhibit ~~22.1~~10.2 to our ~~Annual~~Quarterly Report on Form ~~10-K~~10-Q for the ~~year~~quarterly period ended ~~December 31, 2021,~~June 30, 2022, filed with the Commission on ~~February 16,~~August 4, 2022, file No. 001-36336).
10.3 *	†	—	EnLink Midstream, LLC 2023 Deferred Compensation Plan.
22.1 *		—	Subsidiary Guarantors.
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 ~~June~~September 30, 2022, formatted in iXBRL (Inline eXtensible Business Reporting Language): (i) Consolidated Balance Sheets as of ~~June~~September 30, 2022 and December 31, 2021, (ii) Consolidated Statements of Operations for the three and ~~six~~nine months ended ~~June~~September 30, 2022 and 2021, (iii) Consolidated Statements of Changes in Members’ Equity for the three months ended September 30, 2022 and 2021, June 30, 2022 and 2021, and March 31, 2022 and 2021, (iv) Consolidated Statements of Cash Flows for the ~~six~~nine months ended ~~June~~September 30, 2022 and 2021, and (v) the Notes to Consolidated Financial Statements.
104 *		—	Cover Page Interactive Data File (formatted as Inline iXBRL and included in Exhibit 101).

____________________________

* Filed herewith.

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

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SIGNATURES

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


	EnLink Midstream, 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)
~~August 4,~~November 2, 2022

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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	33	2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	36

3.	3.	Quantitative and Qualitative Disclosures About Market Risk	54	3.	Quantitative and Qualitative Disclosures About Market Risk	59

4.	4.	Controls and Procedures	56	4.	Controls and Procedures	62

		PART II—OTHER INFORMATION			PART II—OTHER INFORMATION

1.	1.	Legal Proceedings	57	1.	Legal Proceedings	63

1A.	1A.	Risk Factors	57	1A.	Risk Factors	63

2.	2.	Unregistered Sales of Equity Securities and Use of Proceeds	57	2.	Unregistered Sales of Equity Securities and Use of Proceeds	63

5.		Other Information	57

6.	6.	Exhibits	58	6.	Exhibits	64


	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
Publicly held ENLC common units repurchased	2,921,370		317,751		5,015,212		317,751
ENLC common units held by GIP repurchased (1)	675,095		—		675,095		—
Total ENLC common units repurchased	3,596,465		317,751		5,690,307		317,751

Aggregate cost for publicly held ENLC common units repurchased	$	27.7	$	2.0	$	44.7	$	2.0
Aggregate cost for ENLC common units held by GIP repurchased (3)	6.0		—		6.0		—
Total aggregate cost for ENLC common units repurchased	$	33.7	$	2.0	$	50.7	$	2.0