enlc-20240930

Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

Form 10-Q

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

For the quarterly period ended September 30, 2024

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

For the transition period from to

Commission file number: 001-36336

ENLINK MIDSTREAM, LLC

(Exact name of registrant as specified in its charter)


Delaware		46-4108528
(State of organization)		(I.R.S. Employer Identification No.)

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

(214) 953-9500

(Registrant’s telephone number, including area code)

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

Title of Each Class

Trading Symbol

Name of Exchange on which Registered

Common Units Representing Limited Liability Company Interests

ENLC

The New York Stock Exchange

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

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

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

Large accelerated filer

☒

Accelerated filer

☐

Non-accelerated filer

☐

Smaller reporting company

☐

Emerging growth company

☐

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

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

As of October 31, 2024, the Registrant had 457,073,081 common units outstanding.

Table of Contents

TABLE OF CONTENTS


Item	Description	Page

	Definitions	3
	PART I—FINANCIAL INFORMATION
1.	Financial Statements	5
	Consolidated Balance Sheets	5
	Consolidated Statements of Operations	6
	Consolidated Statements of Comprehensive Income	7
	Consolidated Statements of Changes in Members’ Equity	8
	Consolidated Statements of Cash Flows	12
	Notes to Consolidated Financial Statements	13
	Note 1—General	13
	Note 2—Significant Accounting Policies	14
	Note 3—Intangible Assets	15
	Note 4—Related Party Transactions	16
	Note 5—Long-Term Debt	17
	Note 6—Income Taxes	18
	Note 7—Certain Provisions of the ENLK Partnership Agreement	19
	Note 8—Members’ Equity	21


	Note 9—Derivatives	24
	Note 10—Fair Value Measurements	26
	Note 11—Segment Information	27
	Note 12—Other Information	32
	Note 13—Commitments and Contingencies	33

2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	34
	Overview	34
	Recent Developments Affecting Industry Conditions and Our Business	35
	Other Recent Developments	36
	Non-GAAP Financial Measures	38
	Results of Operations	43
	Critical Accounting Policies	53
	Liquidity and Capital Resources	53
	Indebtedness	57
	Inflation	57
	Recent Accounting Pronouncements	57
	Disclosure Regarding Forward-Looking Statements	58
3.	Quantitative and Qualitative Disclosures About Market Risk	59

4.	Controls and Procedures	61

	PART II—OTHER INFORMATION

1.	Legal Proceedings	62

1A.	Risk Factors	62

2.	Unregistered Sales of Equity Securities and Use of Proceeds	64

5.	Other Information	64

6.	Exhibits	65
	Signature	66

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DEFINITIONS

The following terms as defined are used in this document:


Defined Term						Definition
/d						Per day.

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.

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.
ASC						The FASB Accounting Standards Codification.



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 transmission pipeline that connects ENLK’s Riverside fractionator to Marathon Petroleum Corporation’s Garyville refinery.
ASU						The FASB Accounting Standards Update.


Bbl						Barrel.
Bbtu						Billion British thermal units.
Bcf						Billion cubic feet.


Board						The board of directors of the Managing Member.
CCS						Carbon capture, transportation, and sequestration.
Cedar Cove JV						Cedar Cove Midstream LLC, a joint venture in which we own a 30% 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.
Central Oklahoma Acquisition						On December 19, 2022, we acquired gathering and processing assets located in Central Oklahoma, including approximately 900 miles of lean and rich natural gas gathering pipeline and two processing plants with 280 MMcf/d of total processing capacity.


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 plants located in the Delaware Basin in Texas.


ENLC						EnLink Midstream, LLC together with its consolidated subsidiaries.

ENLK						EnLink Midstream Partners, LP or, when applicable, EnLink Midstream Partners, LP together with its consolidated subsidiaries.
Exchange Act						The Securities Exchange Act of 1934, as amended.

FASB						The Financial Accounting Standards Board.
FCDTCs						Futures and Cleared Derivatives Transactions Customer Agreements.
Federal Reserve						The Board of Governors of the Federal Reserve System of the United States.
GAAP						Generally accepted accounting principles in the United States of America.
Gal						Gallon.
GCF						Gulf Coast Fractionators, a joint venture in which we own a 38.75% interest. GCF owns an NGL fractionator in Mont Belvieu, Texas. The GCF assets were idled to reduce operating expenses in 2021 but are expected to resume operations in the fourth quarter of 2024.
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.
GIP/ONEOK Transaction						On October 15, 2024, GIP closed a transaction to sell all of GIP’s equity interests in (i) ENLC and (ii) the Managing Member to ONEOK.

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ISDAs						International Swaps and Derivatives Association Agreements.
LIBOR						U.S. Dollar London Interbank Offered Rate.
LNG						Liquified natural gas.
Managing Member						EnLink Midstream Manager, LLC, the managing member of ENLC.
Matterhorn JV						Matterhorn JV, a joint venture in which we own a 15% interest. The Matterhorn JV is constructing 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.


Midland Basin						A large sedimentary basin in West Texas.
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.

NYMEX						New York Mercantile Exchange.
ONEOK						ONEOK, Inc.
Operating Partnership						EnLink Midstream Operating, LP, a Delaware limited partnership and wholly owned subsidiary of ENLK.
OPIS						Oil Price Information Service.
ORV						ENLK’s Ohio River Valley crude oil, condensate stabilization, natural gas compression, and brine disposal assets in the Utica and Marcellus shales, which were divested in November 2023.
OTC						Over-the-counter.
Permian Basin						A large sedimentary basin that includes the Midland and Delaware Basins primarily in West Texas and New Mexico.
PIK Distribution						A quarterly distribution in-kind of Series B Preferred Units. We agreed with the holders of the Series B Preferred Units to make a PIK Distribution until the quarterly distribution in respect of the earlier of (x) any quarter in which the holders of the Series B Preferred Units give notice to the General Partner of their election to terminate such PIK Distribution right and (y) the quarter ending June 30, 2024.


Revolving Credit Facility						A $1.40 billion unsecured revolving credit facility entered into by ENLC, 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.
SPV						EnLink Midstream Funding, LLC, a bankruptcy-remote special purpose entity that is an indirect subsidiary of ENLC.
STACK						Sooner Trend Anadarko Basin Canadian and Kingfisher Counties in Oklahoma.

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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)


	September 30, 2024		December 31, 2023
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	10.4	$	28.7
Accounts receivable:
Trade receivables (1)	58.4		85.9
Accrued revenue and other	491.8		581.4

Fair value of derivative assets	40.3		76.9
Other current assets	127.1		65.4
Total current assets	728.0		838.3
Property and equipment, net of accumulated depreciation of $5,453.3 and $5,137.2, respectively	6,168.2		6,407.0
Intangible assets, net of accumulated amortization of $1,146.8 and $1,051.2, respectively	698.0		793.6

Investment in unconsolidated affiliates	156.5		150.5
Fair value of derivative assets	13.9		27.0
Other assets, net	119.2		112.2
Total assets	$	7,883.8	$	8,328.6
LIABILITIES AND MEMBERS’ EQUITY
Current liabilities:
Accounts payable and drafts payable	$	76.9	$	126.5

Accrued natural gas, NGLs, condensate, and crude oil purchases	339.9		428.0
Fair value of derivative liabilities	32.5		62.7
Current maturities of long-term debt	681.3		97.9
Other current liabilities	605.7		278.5
Total current liabilities	1,736.3		993.6
Long-term debt, net of unamortized issuance cost	4,150.2		4,471.0

Other long-term liabilities	78.0		98.0
Deferred tax liability, net	103.8		104.2
Fair value of derivative liabilities	13.7		26.7

Members’ equity:
Members’ equity (458,619,945 and 451,614,086 units issued and outstanding, respectively)	946.9		1,000.5
Accumulated other comprehensive income (loss)	(1.1)		0.7
Non-controlling interest	856.0		1,633.9
Total members’ equity	1,801.8		2,635.1
Commitments and contingencies (Note 13)
Total liabilities and members’ equity	$	7,883.8	$	8,328.6

____________________________

(1)There was no allowance for bad debt at September 30, 2024 and December 31, 2023.

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 September 30,				Nine Months Ended September 30,
	2024		2023		2024		2023
	(Unaudited)
Revenues:
Product sales	$	1,292.3	$	1,488.1	$	3,975.9	$	4,203.7
Midstream services	294.3		280.1		839.5		838.9
Gain (loss) on derivative activity	21.8		(22.0)		(8.0)		1.2
Total revenues	1,608.4		1,746.2		4,807.4		5,043.8
Operating costs and expenses:
Cost of sales, exclusive of operating expenses and depreciation and amortization	1,067.6		1,244.7		3,280.6		3,535.6
Operating expenses	134.0		143.3		441.8		412.5
Depreciation and amortization	186.1		163.8		514.0		489.5
Impairments	71.0		20.7		85.2		20.7
(Gain) loss on disposition of assets	0.7		(0.6)		(0.1)		(1.8)
General and administrative	30.0		30.4		115.4		87.8

Total operating costs and expenses	1,489.4		1,602.3		4,436.9		4,544.3
Operating income	119.0		143.9		370.5		499.5
Other income (expense):
Interest expense, net of interest income	(67.7)		(67.9)		(199.8)		(205.2)
Gain on extinguishment of debt	9.5		—		9.5		—
Income (loss) from unconsolidated affiliate investments	(11.6)		1.0		(12.1)		(3.7)
Other income (expense)	0.9		(0.6)		5.2		(0.2)
Total other expense	(68.9)		(67.5)		(197.2)		(209.1)
Income before non-controlling interest and income taxes	50.1		76.4		173.3		290.4
Income tax expense	(7.0)		(10.6)		(13.2)		(40.5)
Net income	43.1		65.8		160.1		249.9
Net income attributable to non-controlling interest	29.1		36.3		93.5		107.9
Net income attributable to ENLC	$	14.0	$	29.5	$	66.6	$	142.0
Net income attributable to ENLC per unit:
Basic common unit	$	(0.03)	$	0.06	$	0.08	$	0.31
Diluted common unit	$	(0.03)	$	0.06	$	0.08	$	0.30

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 September 30,				Nine Months Ended September 30,
	2024		2023		2024		2023
	(Unaudited)
Net income	$	43.1	$	65.8	$	160.1	$	249.9
Unrealized gain (loss) on designated cash flow hedge (1)	(4.9)		1.7		(1.8)		6.2
Comprehensive income	38.2		67.5		158.3		256.1
Comprehensive income attributable to non-controlling interest	29.1		36.3		93.5		107.9
Comprehensive income attributable to ENLC	$	9.1	$	31.2	$	64.8	$	148.2

____________________________

(1)Includes tax benefit of $1.7 million and $0.6 million for the three and nine months ended September 30, 2024, respectively, and tax expense of $0.5 million and $1.9 million for the three and nine months ended September 30, 2023, 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 Income (Loss)		Non-Controlling Interest		Total
	$		Units	$		$		$
	(Unaudited)
























Balance, June 30, 2024	$	914.2	452.1	$	3.8	$	1,540.3	$	2,458.3
Conversion of unit-based awards for common units, net of units withheld for taxes	(0.8)		0.2	—		—		(0.8)
Unit-based compensation	5.7		—	—		—		5.7
Contributions from non-controlling interests	—		—	—		10.9		10.9
Distributions	(61.4)		—	—		(40.5)		(101.9)
Unrealized loss on designated cash flow hedge (1)	—		—	(4.9)		—		(4.9)
Exchange of Series B Preferred Units (2)	127.6		10.0	—		(127.6)		—
Repurchase of Series B Preferred Units (2)	(9.5)		—	—		(190.5)		(200.0)
Tax impact of exchange and repurchase of Series B Preferred Units	6.3		—	—		—		6.3
Redemption of Series C Preferred Units (2)	(3.8)		—	—		(360.7)		(364.5)
Repurchase of Series C Preferred Units (2)	—		—	—		(5.0)		(5.0)
Common units repurchased	(47.9)		(3.7)	—		—		(47.9)
Accrued common unit repurchase (3)	2.5		—	—		—		2.5
Net income	14.0		—	—		29.1		43.1
Balance, September 30, 2024	$	946.9	458.6	$	(1.1)	$	856.0	$	1,801.8

____________________________

(1)Includes tax benefit of $1.7 million for the three months ended September 30, 2024.

(2)For more information regarding the exchange and repurchase of the Series B Preferred Units and the repurchase and redemption of the Series C Preferred Units, see “Note 7—Certain Provisions of the ENLK Partnership Agreement.”

(3)Relates to the change in the repurchase accrual of ENLC common units held by GIP, which were contractually subject to repurchase by ENLC at the end of each quarter and settled in the subsequent quarter. For additional information, see “Note 8—Members’ Equity.”

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 Income (Loss)		Non-Controlling Interest		Total
	$		Units	$		$		$
	(Unaudited)




















Balance, June 30, 2023	$	1,156.1	462.0	$	4.5	$	1,613.6	$	2,774.2
Conversion of unit-based awards for common units, net of units withheld for taxes	(2.4)		0.3	—		—		(2.4)
Unit-based compensation	5.7		—	—		—		5.7
Contributions from non-controlling interests	—		—	—		29.4		29.4
Distributions	(58.4)		—	—		(49.7)		(108.1)
Unrealized gain on designated cash flow hedge (1)	—		—	1.7		—		1.7


Common units repurchased	(54.9)		(5.0)	—		—		(54.9)
Accrued common unit repurchase (2)	4.5		—	—		—		4.5
Net income	29.5		—	—		36.3		65.8
Balance, September 30, 2023	$	1,080.1	457.3	$	6.2	$	1,629.6	$	2,715.9

____________________________

(1)Includes tax expense of $0.5 million for the three months ended September 30, 2023.

(2)Relates to the change in the repurchase accrual of ENLC common units held by GIP, which were contractually subject to repurchase by ENLC at the end of each quarter and settled in the subsequent quarter. For additional information, see “Note 8—Members’ Equity.”

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 Income (Loss)		Non-Controlling Interest		Total
	$		Units	$		$		$
	(Unaudited)
Balance, December 31, 2023	$	1,000.5	451.6	$	0.7	$	1,633.9	$	2,635.1
Conversion of unit-based awards for common units, net of units withheld for taxes	(17.9)		3.0	—		—		(17.9)
Unit-based compensation	16.5		—	—		—		16.5
Contributions from non-controlling interests	—		—	—		24.7		24.7
Distributions	(183.9)		—	—		(122.4)		(306.3)
Unrealized loss on designated cash flow hedge (1)	—		—	(1.8)		—		(1.8)
Exchange of Series B Preferred Units (2)	217.5		17.0	—		(217.5)		—
Repurchase of Series B Preferred Units (2)	(9.5)		—	—		(190.5)		(200.0)
Tax impact of exchange and repurchase of Series B Preferred Units	6.3		—	—		—		6.3
Redemption of Series C Preferred Units (2)	(3.8)		—	—		(360.7)		(364.5)
Repurchase of Series C Preferred Units (2)	—		—	—		(5.0)		(5.0)
Common units repurchased (3)	(125.0)		(13.0)	—		—		(125.0)
Accrued common unit repurchase (4)	(20.4)		—	—		—		(20.4)
Net income	66.6		—	—		93.5		160.1
Balance, September 30, 2024	$	946.9	458.6	$	(1.1)	$	856.0	$	1,801.8

____________________________

(1)Includes tax benefit of $0.6 million for the nine months ended September 30, 2024.

(3)Excludes the $41.5 million repurchase of ENLC common units held by GIP on February 19, 2024, which was accrued at December 31, 2023.

(4)Relates to the repurchase of ENLC common units held by GIP, which were contractually subject to repurchase by ENLC at the end of each quarter and settled in the subsequent quarter. For additional information, see “Note 8—Members’ Equity.”

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 Income (Loss)		Non-Controlling Interest		Total
	$		Units	$		$		$
	(Unaudited)










Balance, December 31, 2022	$	1,306.4	469.0	$	—	$	1,606.3	$	2,912.7
Conversion of unit-based awards for common units, net of units withheld for taxes	(19.3)		2.9	—		—		(19.3)
Unit-based compensation	14.2		—	—		—		14.2
Contributions from non-controlling interests	—		—	—		51.5		51.5
Distributions	(178.6)		—	—		(132.2)		(310.8)
Unrealized gain on designated cash flow hedge (1)	—		—	6.2		—		6.2
Adjustment related to the redemption of the mandatorily redeemable non-controlling interest (2)	0.8		—	—		—		0.8

Repurchase of Series C Preferred Units	—		—	—		(3.9)		(3.9)
Common units repurchased	(162.4)		(14.6)	—		—		(162.4)
Accrued common unit repurchase (3)	(23.0)		—	—		—		(23.0)
Net income	142.0		—	—		107.9		249.9
Balance, September 30, 2023	$	1,080.1	457.3	$	6.2	$	1,629.6	$	2,715.9

____________________________

(1)Includes tax expense of $1.9 million for the nine months ended September 30, 2023.

(2)Relates to book-to-tax differences recorded upon the settlement of the mandatorily redeemable non-controlling interest.

(3)Relates to the repurchase of ENLC common units held by GIP, which were contractually subject to repurchase by ENLC at the end of each quarter and settled in the subsequent quarter. For additional information, see “Note 8—Members’ Equity.”

See accompanying notes to consolidated financial statements.

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Consolidated Statements of Cash Flows

(In millions)


	Nine Months Ended September 30,
	2024		2023
	(Unaudited)
Cash flows from operating activities:
Net income	$	160.1	$	249.9
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	514.0		489.5
Gain on disposition of assets	(0.1)		(1.8)
Non-cash unit-based compensation	16.5		14.2
Non-cash loss on derivatives recognized in net income	4.1		19.0
Gain on extinguishment of debt	(9.5)		—
Amortization of debt issuance costs and net discount of senior unsecured notes	4.6		4.9
Deferred income tax expense	12.0		39.0
Loss from unconsolidated affiliate investments	12.1		3.7
Impairments	85.2		20.7
Other operating activities	(2.5)		2.8
Changes in assets and liabilities, net of the effects of acquisitions:
Accounts receivable, accrued revenue, and other	117.7		33.3
Product inventory, prepaid expenses, and other	(65.7)		59.5
Accounts payable, accrued product purchases, and other accrued liabilities	(132.5)		(72.7)
Net cash provided by operating activities	716.0		862.0
Cash flows from investing activities:
Additions to property and equipment	(293.9)		(320.9)


Contributions to unconsolidated affiliate investments	(25.4)		(58.4)
Other investing activities	(5.8)		5.9
Net cash used in investing activities	(325.1)		(373.4)
Cash flows from financing activities:
Proceeds from borrowings	2,736.3		2,538.4
Repayments on borrowings	(2,465.2)		(2,544.4)

Distributions to members	(183.9)		(178.6)
Distributions to non-controlling interests	(122.4)		(132.2)
Payment to redeem mandatorily redeemable non-controlling interest	—		(10.5)
Repurchase of Series B Preferred Units	(200.0)		—
Repurchase of Series C Preferred Units	(5.0)		(3.9)

Contributions from non-controlling interests	24.7		51.5
Common unit repurchases	(166.5)		(162.4)
Payment of taxes related to the conversion of unit-based awards for common units	(17.9)		(19.3)
Other financing activities	(9.3)		(1.7)
Net cash used in financing activities	(409.2)		(463.1)
Net increase (decrease) in cash and cash equivalents	(18.3)		25.5
Cash and cash equivalents, beginning of period	28.7		22.6
Cash and cash equivalents, end of period	$	10.4	$	48.1

Supplemental disclosures of cash flow information:
Cash paid for interest	$	223.0	$	222.8
Cash paid for income taxes	$	1.1	$	1.5
Non-cash investing activities:

Right-of-use assets obtained in exchange for operating lease liabilities	$	40.3	$	13.3
Non-cash accrual of property and equipment	$	(29.2)	$	34.4
Non-cash financing activities:
Issuance of ENLC common units from Series B Preferred Units exchange	$	234.9	$	—
Redemption of Series B Preferred Units from Series B Preferred Units exchange	$	(217.5)	$	—

See accompanying notes to consolidated financial statements.

Table of Contents

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements

September 30, 2024

(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.” As of September 30, 2024, and prior to the GIP/ONEOK Transaction, GIP, through GIP III Stetson I, L.P. (“GIP Stetson I”) and GIP III Stetson II, L.P. (“GIP Stetson II”), owned 44.0% of the outstanding limited liability company interests in ENLC. In addition to GIP’s equity interests in ENLC, GIP Stetson I maintained control over the Managing Member through its ownership of all of the equity interests in the Managing Member.

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.

GIP/ONEOK Transaction

On October 15, 2024, GIP and ONEOK closed a transaction pursuant to which ONEOK acquired (i) 43.8% of the outstanding ENLC common units, consisting of 97,207,538 ENLC common units from GIP Stetson I and 103,133,215 ENLC common units from GIP Stetson II, in exchange for consideration equal to $14.90 in cash per common unit and (ii) all of the outstanding limited liability company interests in the Managing Member from GIP Stetson I in exchange for $300.0 million in cash, for a total cash consideration of approximately $3.285 billion. As a result of the GIP/ONEOK Transaction, ONEOK acquired control of the operations of ENLC and its subsidiaries.

b.Nature of Business

We primarily focus on owning, operating, investing in, and developing midstream energy infrastructure assets to provide midstream energy services, including:

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

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

•gathering, transporting, storing, trans-loading, and selling crude oil and condensate.

As of September 30, 2024, our midstream infrastructure network includes approximately 13,600 miles of pipelines, 25 natural gas processing plants with approximately 5.9 Bcf/d of processing capacity, seven fractionators with approximately 316,300 Bbls/d of fractionation capacity, barge and rail terminals, product storage facilities, purchasing and marketing capabilities, and equity investments in certain joint ventures. Our operations are based in the United States, and our sales are derived primarily from domestic customers.

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

(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 statement 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, 2023 filed with the Commission on February 21, 2024. 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 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. These fees do not represent the shortfall amounts we expect to collect under our MVC and firm transportation contracts, as we generally do not expect volume shortfalls to equal the full amount of the contractual MVCs and firm transportation contracts during these periods.


Contractually Committed Fees	Commitments
2024 (remaining)	$	45.0
2025	158.8
2026	142.2
2027	112.1
2028	107.7
Thereafter	547.0
Total	$	1,112.8

c.Property and Equipment

In accordance with ASC 360, Property, Plant, and Equipment, we evaluate long-lived assets of identifiable business activities for potential impairment whenever events or changes in circumstances, or triggering events, indicate that their carrying value may not be recoverable. When the carrying amount of a long-lived asset is not recoverable, an impairment is recognized equal to the excess of the asset’s carrying value over its fair value, which is based on inputs that are not observable in the market, and thus represent Level 3 inputs.

In the third quarter of 2024, we identified changes in our outlook for future cash flows and the anticipated use of certain non-core assets in our Louisiana segment. We determined that the carrying amounts of these assets exceeded their fair values and are not recoverable. For the three months ended September 30, 2024, we recorded $71.0 million of impairment expense in our Louisiana segment related to our decision to idle the Pelican processing plant and cancel certain projects. For the nine months ended September 30, 2024, we recorded $85.2 million of impairment expense, of which $14.2 million was recorded in the first quarter of 2024 and related to changes in our outlook for future cash flows and the anticipated use of certain non-core assets in our North Texas segment.

During the third quarter of 2023, we identified changes in our outlook for future cash flows and the anticipated use of certain ORV crude assets in our Louisiana segment, which warranted an interim impairment test. We determined that the carrying amounts of these assets exceeded their fair values, based on market inputs and certain assumptions, and recorded an impairment expense of $20.7 million for the three months ended September 30, 2023.

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

d.Non-controlling Interests

Our non-controlling interests are 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 50.0% share of the Ascension JV. Certain of our joint venture arrangements provide us or our joint venture partners with the right, under certain circumstances, to cause a purchase or sale of interest in the joint venture or to seek to sell the entire joint venture. At any time after June 30, 2025, NGP has the right to arrange a sale of the Delaware Basin JV for the best available price; provided that, if NGP exercises this right, we are permitted, but not required, to purchase NGP’s interest at a certain call price.

e.Recent Accounting Pronouncements

On November 27, 2023, the FASB issued ASU No. 2023-07, “Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures.” (“ASU 2023-07”). ASU 2023-07 amends reportable segment disclosure requirements, primarily through enhanced disclosures about significant segment expenses. This ASU is effective for annual periods beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024. The impact of ASU 2023-07 would be limited to the disclosures within the footnotes of the consolidated financial statements.

On December 14, 2023, the FASB issued ASU No. 2023-09, “Income Taxes (Topic 740): Improvements to Income Tax Disclosures.” (“ASU 2023-09”). ASU 2023-09 is intended to improve the transparency of income tax disclosures by requiring (i) consistent categories and greater disaggregation of information in the rate reconciliation and (ii) income taxes paid disaggregated by jurisdiction. ASU 2023-09 will become effective for annual periods beginning after December 15, 2024, with early adoption permitted. Management is currently evaluating ASU 2023-09 to determine its impact on the Company’s annual disclosures.

On March 6, 2024, the Commission adopted a new set of rules that require a wide range of climate-related disclosures, including material climate-related risks, information on any climate-related targets or goals that are material to the registrant’s business, results of operations, or financial condition, Scope 1 and Scope 2 GHG emissions on a phased-in basis by certain larger registrants when those emissions are material and the filing of an attestation report covering the same, and disclosure of the financial statement effects of severe weather events and other natural conditions including costs and losses. Compliance dates under the final rule are phased in by registrant category. Multiple lawsuits have been filed challenging the Commission’s new climate rules, which have been consolidated and will be heard in the U.S. Court of Appeals for the Eighth Circuit. On April 4, 2024, the Commission issued an order staying the final rules until judicial review is complete.

(3) Intangible Assets

Intangible assets associated with customer relationships are amortized on a straight-line basis over the expected period of benefits of the customer relationships, which ranged from 10 to 20 years at the time the intangible assets were originally recorded. The weighted average amortization period for intangible assets is 14.9 years.

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


	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount
Nine Months Ended September 30, 2024
Customer relationships, beginning of period	$	1,844.8	$	(1,051.2)	$	793.6
Amortization expense	—		(95.6)		(95.6)

Customer relationships, end of period	$	1,844.8	$	(1,146.8)	$	698.0

Amortization expense was $31.9 million for each of the three months ended September 30, 2024 and 2023 and $95.6 million and $95.7 million for the nine months ended September 30, 2024 and 2023, respectively.

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

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


2024 (remaining)	$	32.0
2025	110.2
2026	106.3
2027	106.3
2028	106.3
Thereafter	236.9

Total	$	698.0

(4) Related Party Transactions

(a) Transactions with the Cedar Cove JV

We process natural gas and purchase the related residue natural gas and NGLs from the Cedar Cove JV. Our transactions with the Cedar Cove JV for all periods presented were not material.

(b) Transactions with GIP

GIP Repurchase Agreement. On January 16, 2024, we entered into a new repurchase agreement with GIP with terms substantially similar to the repurchase agreement with GIP for 2023 entered into on December 20, 2022, which repurchase agreement terminated on December 31, 2023 in accordance with its terms. The current repurchase agreement will renew for successive one-year terms (each, a “Renewal Year”) on January 1 of each Renewal Year, with the first Renewal Year beginning on January 1, 2025, unless either the Company or the GIP Entities elects to terminate the Repurchase Agreement prior to the start of any Renewal Year, during a two-week period in December preceding the applicable Renewal Year.

On September 16, 2024, in connection with the GIP/ONEOK Transaction, we gave notice to GIP of our election to terminate the repurchase agreement entered into on January 16 , 2024, in accordance with the terms of the repurchase agreement. The termination of the repurchase agreement was effective as of October 2, 2024, upon which date we repurchased the applicable number of common units representing GIP’s pro rata share of the aggregate number of common units repurchased by us during the three months ended September 30, 2024.

See “Note 8—Members’ Equity” for additional information on the activity related to the GIP repurchase agreement.

Transactions with Companies Affiliated with GIP. We may engage in various transactions with GIP’s affiliated entities, including GIP’s portfolio companies. Our transactions with GIP’s affiliated entities for all periods presented were not material.

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

(5) Long-Term Debt

As of September 30, 2024 and December 31, 2023, long-term debt consisted of the following (in millions):


	September 30, 2024						December 31, 2023
	Outstanding Principal		Premium (Discount)		Long-Term Debt		Outstanding Principal		Premium (Discount)		Long-Term Debt

Revolving Credit Facility due 2027	$	—	$	—	$	—	$	—	$	—	$	—
AR Facility due 2025 (1)	260.0		—		260.0		300.0		—		300.0
ENLK’s 4.40% Senior unsecured notes due 2024	—		—		—		97.9		—		97.9
ENLK’s 4.15% Senior unsecured notes due 2025	421.6		—		421.6		421.6		—		421.6
ENLK’s 4.85% Senior unsecured notes due 2026	491.0		(0.1)		490.9		491.0		(0.2)		490.8
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	498.7		—		498.7		498.7		—		498.7
ENLC’s 6.50% Senior unsecured notes due 2030	1,000.0		(2.4)		997.6		1,000.0		(2.7)		997.3
ENLC’s 5.650% Senior unsecured notes due 2034	500.0		(1.9)		498.1		—		—		—
ENLK’s 5.60% Senior unsecured notes due 2044	340.0		(0.2)		339.8		350.0		(0.2)		349.8
ENLK’s 5.05% Senior unsecured notes due 2045	413.4		(4.4)		409.0		450.0		(5.0)		445.0
ENLK’s 5.45% Senior unsecured notes due 2047	448.2		(0.1)		448.1		500.0		(0.1)		499.9
Debt classified as long-term, including current maturities of long-term debt	$	4,872.9	$	(9.1)	4,863.8		$	4,609.2	$	(8.2)	4,601.0
Debt issuance cost (2)					(32.3)						(32.1)
Less: Current maturities of long-term debt (3)(4)(5)					(681.3)						(97.9)
Long-term debt, net of unamortized issuance cost					$	4,150.2					$	4,471.0

____________________________

(1)The effective interest rate was 5.9% and 6.4% at September 30, 2024 and December 31, 2023, respectively.

(2)Net of accumulated amortization of $23.8 million and $20.0 million at September 30, 2024 and December 31, 2023, respectively.

(3)The outstanding balance, net of debt issuance costs, of ENLK’s 4.40% senior unsecured notes due 2024 are classified as “Current maturities of long-term debt” in the consolidated balance sheet as of December 31, 2023 as these notes matured on April 1, 2024.

(4)The outstanding balance, net of debt issuance costs, of ENLK’s 4.15% senior unsecured notes are classified as “Current maturities of long-term debt” in the consolidated balance sheet as of September 30, 2024 as these notes mature on June 1, 2025.

(5)The AR Facility is classified as “Current maturities of long-term debt” in the consolidated balance sheet as of September 30, 2024 as the AR Facility is scheduled to terminate on August 1, 2025.

Revolving Credit Facility

The Revolving Credit Facility permits ENLC to borrow up to $1.4 billion on a revolving credit basis and includes a $500.0 million letter of credit subfacility. There were no outstanding borrowings under the Revolving Credit Facility and $14.6 million in outstanding letters of credit as of September 30, 2024.

On September 12, 2024, we amended the change of control provisions of the Revolving Credit Facility to, among other things, designate ONEOK as Qualifying Owners (as defined in the Revolving Credit Facility), such that the GIP/ONEOK Transaction did not result in a change of control under the Revolving Credit Agreement.At September 30, 2024, we were in compliance with the financial covenants of the Revolving Credit Facility.

AR Facility

On October 21, 2020, the SPV entered into the AR Facility. We are the primary beneficiary of the SPV, and we consolidate its assets and liabilities, which consist primarily of billed and unbilled accounts receivable of $496.4 million as of September 30, 2024. As of September 30, 2024, the AR Facility had a borrowing base of $383.3 million and there were $260.0 million in outstanding borrowings under the AR Facility.

Table of Contents

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

The amount available for borrowings at any one time under the AR Facility is limited to a borrowing base amount calculated based on the outstanding balance of eligible receivables held as collateral, subject to certain reserves, concentration limits, and other limitations. Depending on our operational needs, we may not borrow the total amount available for borrowings. At September 30, 2024, we were in compliance with the financial covenants of the AR Facility.

Senior Unsecured Notes

On August 15, 2024, ENLC completed the sale of $500.0 million in aggregate principal amount of ENLC’s 5.650% senior unsecured notes due September 1, 2034 (the “2034 Notes”) at 99.618% of their face value. Interest on the 2034 Notes is payable on March 1 and September 1 of each year beginning on March 1, 2025. ENLC used the net proceeds for general limited liability company purposes, including to repay the borrowings under the Revolving Credit Facility and a portion of the borrowings under the AR Facility. A portion of these borrowings were incurred to purchase outstanding Series B Preferred Units on August 5, 2024. The 2034 Notes are fully and unconditionally guaranteed by ENLK.

Additionally, for the three and nine months ended September 30, 2024, we repurchased a portion of ENLK’s 5.60% senior unsecured notes due 2044 (the “2044 Notes”), ENLK’s 5.05% senior unsecured notes due 2045 (the “2045 Notes”), and ENLK’s 5.45% senior unsecured notes due 2047 (the “2047 Notes”) in open market transactions. As a result, we recognized a $9.5 million gain on extinguishment of debt, which is included in the consolidated statements of operations for the three and nine months ended September 30, 2024. We did not repurchase any senior unsecured notes in open market transactions during the three and nine months ended September 30, 2023.

(6) Income Taxes

The components of our income tax expense are as follows (in millions):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2024		2023		2024		2023
Current income tax expense	$	(0.8)	$	(1.2)	$	(1.2)	$	(1.5)
Deferred income tax expense	(6.2)		(9.4)		(12.0)		(39.0)
Income tax expense	$	(7.0)	$	(10.6)	$	(13.2)	$	(40.5)

The following schedule reconciles income tax 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 September 30,				Nine Months Ended September 30,
	2024		2023		2024		2023
Expected income tax expense based on federal statutory tax rate	$	(6.3)	$	(8.4)	$	(16.8)	$	(38.3)
State income tax expense, net of federal benefit	(0.9)		(1.1)		(2.4)		(4.9)
Unit-based compensation (1)	0.1		0.9		7.8		7.5



Other	0.1		(2.0)		(1.8)		(4.8)
Income tax expense	$	(7.0)	$	(10.6)	$	(13.2)	$	(40.5)

____________________________

(1)Related to book-to-tax differences recorded upon the vesting of unit-based awards.

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.

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

As of September 30, 2024, we had $767.1 million of deferred tax assets, net of a $1.2 million valuation allowance, and $870.9 million of deferred tax liabilities for net deferred tax liabilities of $103.8 million. In September 2024, we recorded a deferred tax asset of $6.3 million resulting from the step-up in basis allowed under Section 743(b) of the Internal Revenue Code related to the exchanges and repurchase of the Series B Preferred Units during the nine months ended September 30, 2024, which is expected to be amortized over the useful lives of the underlying assets. Refer to “Note 7—Certain Provisions of the ENLK Partnership Agreement” for more information on our exchanges and repurchase of the Series B Preferred Units.

As of December 31, 2023, we had $758.3 million of deferred tax assets, net of a $1.2 million valuation allowance, and $862.5 million of deferred tax liabilities for net deferred tax liabilities of $104.2 million.

As of September 30, 2024, 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) Certain Provisions of the ENLK Partnership Agreement

a.Series B Preferred Units

As of September 30, 2024 and December 31, 2023, there were 27,365,971 and 54,575,638 Series B Preferred Units issued and outstanding, respectively.

Conversion

Series B Preferred Units are exchangeable for ENLC common units in an amount equal to the number of applicable Series B Preferred Units multiplied by the exchange ratio of 1.15, subject to certain adjustments. The exchange is subject to ENLK’s option to pay cash instead of ENLC issuing additional ENLC common units, and can occur in whole or in part at the option of the holder of the Series B Preferred Units at any time, or in whole at our option, provided the daily volume-weighted average closing price of the ENLC common units for the 30 trading days ending two trading days prior to the exchange is greater than 150% of the $15.00 per Series B Preferred Unit issue price divided by the conversion ratio of 1.15.

A summary of the exchange activity by the holders of the Series B Preferred Units during the nine months ended September 30, 2024 is provided below (in millions, except per unit amounts):


	Series B Preferred Units Canceled	Series B Preferred Units Exchanged				ENLC Common Units Issued			Loss on Exchange of Series B Preferred Units
Transaction date	Units	Units		$		Units	$		$

April 2024	2,604,046	2,608,696	(1)	$	38.3	3,000,000	$	41.2	$	(2.9)
May 2024	3,478,262	3,478,262		$	51.6	4,000,000	$	53.9	$	(2.3)
July 2024	8,695,654	8,695,654		$	127.6	10,000,000	$	139.8	$	(12.2)

____________________________

(1)Includes 4,650 accrued and unpaid Series B Preferred Units that holders were entitled to receive in a PIK Distribution in respect of the first quarter of 2024 as of the date of the exchange of such Series B Preferred Units.

As a result of these exchanges, we recorded a $12.2 million and $17.4 million loss attributable to common units for the three and nine months ended September 30, 2024, respectively.

Repurchase

In August 2024, we repurchased 12,698,414 Series B Preferred Units for $200.0 million plus accrued distributions. The repurchase price represented 105% of the preferred units’ par value.

As a result of this repurchase, we recorded a $9.5 million loss attributable to common units for the three and nine months ended September 30, 2024.

Table of Contents

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

Income and Distributions

Income is allocated to the Series B Preferred Units in an amount equal to the quarterly distribution with respect to the period earned. A summary of the distribution activity relating to the Series B Preferred Units during the nine months ended September 30, 2024 and 2023 is provided below:


Declaration period	PIK Distribution	Cash distribution (in millions)		Date paid/payable
2024
Fourth Quarter of 2023	136,439	$	15.3	February 9, 2024
First Quarter of 2024	130,270	$	14.7	May 14, 2024
Second Quarter of 2024 (1)	—	$	12.8	August 14, 2024
Third Quarter of 2024	—	$	8.7	November 14, 2024


2023
Fourth Quarter of 2022	—	$	17.3	February 13, 2023
First Quarter of 2023	135,421	$	15.2	May 12, 2023
Second Quarter of 2023	135,759	$	15.3	August 11, 2023
Third Quarter of 2023	136,099	$	15.3	November 10, 2023

____________________________

(1)On September 8, 2023, we amended and restated the limited partnership agreement of ENLK (the “ENLK LPA”) to terminate the rights of the holders of the Series B Preferred Units to receive PIK distributions beginning with the quarter ending June 30, 2024, and in connection with such termination of PIK distributions, increase the cash distribution per Series B Preferred Unit from $0.28125 to $0.31875, in addition to the continued payment of the Series B Excess Cash Payment Amount (as defined in the ENLK LPA).

b.Series C Preferred Units

As of September 30, 2024 and December 31, 2023, there were 361,500 and 366,500 Series C Preferred Units issued and outstanding, respectively.

Repurchase

In August 2024, we repurchased 5,000 Series C Preferred Units for total consideration of $5.0 million plus accrued distributions. The repurchase price represented 100% of the preferred units’ par value.

Redemption

On September 17, 2024, ENLK gave notice to redeem all of its outstanding Series C Preferred Units on October 17, 2024 (the “Redemption Date”). The redemption amount was set at $1,000 per Series C Preferred Unit, plus $8.28 per Series C Preferred Unit of unpaid distributions. We paid the redemption amount to the holders of the Series C Preferred Units on the Redemption Date, upon which time the Series C Preferred Units ceased to be outstanding. As of September 30, 2024, $364.5 million is classified as “Other current liabilities” on the consolidated balance sheets related to the redemption of the Series C Preferred Units.

As a result of this redemption, we recorded a $3.8 million loss attributable to common units for the three and nine months ended September 30, 2024.

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

Distributions

Income is allocated to the Series C Preferred Units in an amount equal to the earned distribution for the respective reporting period. A summary of the distribution activity relating to the Series C Preferred Units is provided below:


Declaration period (1)	Distribution rate (2)		Cash distribution (in millions)		Date paid/payable
2024
December 15, 2023 – March 14, 2024	9.749	%	$	9.0	March 15, 2024
March 15, 2024 – June 14, 2024	9.701	%	$	9.1	June 17, 2024
June 15, 2024 – September 14, 2024	9.716	%	$	9.0	September 16, 2024


2023
December 15, 2022 – March 14, 2023	8.846	%	$	8.4	March 15, 2023
March 15, 2023 – June 14, 2023	9.051	%	$	8.7	June 15, 2023
June 15, 2023 – September 14, 2023	9.618	%	$	9.3	September 15, 2023
September 15, 2023 - December 14, 2023	9.782	%	$	9.3	December 15, 2023

____________________________

(1)Distributions on the Series C Preferred Units accrue quarterly in arrears on the 15th day of March, June, September, and December of each year, in each case, if and when declared by the General Partner out of legally available funds for such purpose.

(2)Distributions on the Series C Preferred Units accumulate for each distribution period at a percentage of the $1,000 liquidation preference per unit equal to the floating rate of the three-month LIBOR plus a spread of 4.11%. Starting on September 15, 2023, distributions on the Series C Preferred Units are based on the forward-looking term rate based on SOFR (“Term SOFR”), plus a Term SOFR spread adjustment of 0.26161%, plus a spread of 4.11%.

(8) Members’ Equity

a.Common Unit Repurchase Program

The table below provides a summary of the Board’s authorizations of the 2023 and 2024 common unit repurchase programs.


Date	Board Action	Authorized Amount (in millions)(1)
December 2022	Reauthorization of common unit repurchase program and set amount available for repurchases for 2023	$	200
November 2023	Increase in 2023 common unit repurchase program	$	50
December 2023	Reauthorization of common unit repurchase program and set amount available for repurchases for 2024	$	200
July 2024	Increase in 2024 common unit repurchase program	$	50

____________________________

(1)The authorized amount includes repurchases of common units held by GIP. Refer to “Note 4—Related Party Transactions” for more information on our ENLC common unit repurchase agreement with GIP.

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.

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

The following table summarizes our ENLC common unit repurchase activity for the periods presented (in millions, except for unit amounts):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2024		2023		2024		2023
Publicly held ENLC common units	1,906,780		2,253,012		6,108,742		7,690,821
ENLC common units held by GIP (1)	1,718,847		2,763,581		6,862,179		6,911,568
Total ENLC common units	3,625,627		5,016,593		12,970,921		14,602,389

Aggregate cost for publicly held ENLC common units	$	25.0	$	26.9	$	79.0	$	85.9
Aggregate cost for ENLC common units held by GIP	22.9		27.5		87.5		75.3
Excise tax on net common unit repurchases	—		0.5		—		1.2
Total aggregate cost for ENLC common units	$	47.9	$	54.9	$	166.5	$	162.4

Average price paid per publicly held ENLC common unit (2)	$	13.09	$	11.93	$	12.93	$	11.16
Average price paid per ENLC common unit held by GIP (2)(3)	$	13.31	$	9.94	$	12.75	$	10.89

____________________________

(1)The units repurchased in each quarter represent GIP’s pro rata share of the aggregate number of common units repurchased by us under our common unit repurchase program during the prior quarter.

(2)The average price paid per common unit excludes excise tax on common unit repurchases.

(3)The per unit price we paid to GIP in each quarter was the average per unit price paid by us for publicly held ENLC common units repurchased in the prior quarter, less broker commissions.

Additionally, on October 2, 2024, we repurchased 1,562,279 ENLC common units held by GIP at an aggregate cost of $20.4 million, or an average of $13.07 per common unit. These units represented GIP’s pro rata share of the aggregate number of common units repurchased by us during the three months ended September 30, 2024. 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 commissions, which were not paid with respect to the ENLC common units held by GIP. As of September 30, 2024, $20.4 million is classified as “Other current liabilities” in the consolidated balance sheets related to our obligation to repurchase our common units from GIP. See “Note 4—Related Party Transactions” for additional information relating to the GIP repurchase agreement.

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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 September 30,				Nine Months Ended September 30,
	2024		2023		2024		2023
Distributed earnings allocated to:
Common units (1)	$	60.8	$	57.6	$	180.4	$	174.0
Unvested unit-based awards (1)	0.7		1.0		2.2		2.9
Total distributed earnings	$	61.5	$	58.6	$	182.6	$	176.9
Distribution in excess of earnings:
Common units	$	(72.1)	$	(28.6)	$	(144.9)	$	(34.3)
Unvested unit-based awards	(0.9)		(0.5)		(1.8)		(0.6)
Total distribution in excess of earnings	$	(73.0)	$	(29.1)	$	(146.7)	$	(34.9)
Net income (loss) attributable to ENLC allocated to:
Common units (2)	$	(11.3)	$	29.0	$	35.5	$	139.7
Unvested unit-based awards (2)	(0.2)		0.5		0.4		2.3
Total net income (loss) attributable to ENLC (2)	$	(11.5)	$	29.5	$	35.9	$	142.0
Net income (loss) attributable to ENLC per unit:
Basic (2)	$	(0.03)	$	0.06	$	0.08	$	0.31
Diluted (2)	$	(0.03)	$	0.06	$	0.08	$	0.30

____________________________

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

(2)Includes losses related to the exchanges and repurchase of the Series B Preferred Units and the redemption of the Series C Preferred Units. Refer to “Note 7—Certain Provisions of the ENLK Partnership Agreement” for additional information on these losses.

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


	Three Months Ended September 30,		Nine Months Ended September 30,
	2024	2023	2024	2023
Basic weighted average units outstanding:
Weighted average common units outstanding	458.6	459.3	453.8	464.1
Diluted weighted average units outstanding:
Weighted average basic common units outstanding	458.6	459.3	453.8	464.1
Dilutive effect of unvested restricted units (1)	—	4.6	2.6	4.3

Total weighted average diluted common units outstanding	458.6	463.9	456.4	468.4

____________________________

(1)All common unit equivalents were antidilutive for the three months ended September 30, 2024 since a net loss attributable to ENLC common units, including losses related to the exchange and repurchase of the Series B Preferred Units and the redemption of the Series C Preferred Units, existed for 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.

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

c.Distributions

A summary of our distribution activity related to the ENLC common units for the nine months ended September 30, 2024 and 2023, respectively, is provided below:


Declaration period	Distribution/unit		Date paid/payable
2024
Fourth Quarter of 2023	$	0.1325	February 9, 2024
First Quarter of 2024	$	0.1325	May 14, 2024
Second Quarter of 2024	$	0.1325	August 14, 2024
Third Quarter of 2024	$	0.1325	November 14, 2024


2023
Fourth Quarter of 2022	$	0.1250	February 13, 2023
First Quarter of 2023	$	0.1250	May 12, 2023
Second Quarter of 2023	$	0.1250	August 11, 2023
Third Quarter of 2023	$	0.1250	November 10, 2023

(9) Derivatives

Interest Rate Swap

In January 2023, we entered into a $400.0 million interest rate swap to manage the interest rate risk associated with our floating-rate, SOFR-based borrowings, including borrowings on the Revolving Credit Facility and the AR Facility. Under this arrangement, we pay a fixed interest rate of 3.8565% in exchange for SOFR-based variable interest through February 2026. Assets or liabilities related to this interest rate swap contract are included in the fair value of derivative assets and liabilities on the consolidated balance sheets, and the change in fair value of this contract is recorded net as a gain or loss on designated cash flow hedges on the consolidated statements of comprehensive income. Monthly, upon settlement, we reclassify the gain or loss associated with the interest rate swap into interest expense from accumulated other comprehensive income (loss). We designated our interest rate swap as a cash flow hedge in accordance with ASC 815, Derivatives and Hedging. There is no ineffectiveness related to our hedge.

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2024		2023		2024		2023
Change in fair value of interest rate swap	$	(6.6)	$	2.2	$	(2.4)	$	8.1
Tax benefit (expense)	1.7		(0.5)		0.6		(1.9)
Unrealized gain (loss) on designated cash flow hedge	$	(4.9)	$	1.7	$	(1.8)	$	6.2

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

The fair value of derivative assets and liabilities related to the interest rate swap are as follows (in millions):


	September 30, 2024		December 31, 2023
Fair value of derivative assets—current	$	—	$	3.3

Fair value of derivative liabilities—current	(0.2)		—
Fair value of derivative liabilities—long-term	(1.3)		(2.4)
Net fair value of interest rate swap	$	(1.5)	$	0.9

Interest income is recognized from accumulated other comprehensive income (loss) from the monthly settlement of our interest rate swap and was included in our consolidated statements of operations as follows (in millions):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2024		2023		2024		2023
Interest income	$	1.5	$	1.4	$	4.5	$	3.0

We expect to recognize an additional $0.2 million of interest expense out of accumulated other comprehensive income (loss) over the next twelve months.

Commodity Derivatives

We manage our exposure to changes in commodity prices by hedging the impact of market fluctuations by utilizing various over-the-counter and exchange-traded commodity financial instrument contracts. Commodity swaps and futures 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 crude, condensate, natural gas, and NGLs. We do not designate commodity swaps or futures as cash flow or fair value hedges for hedge accounting treatment under ASC 815, Derivatives and Hedging. Therefore, changes in the fair value of our derivatives are recorded in revenue in the period incurred. In addition, our commodity risk management policy does not allow us to take speculative positions with our derivative contracts.

We commonly enter into index (float-for-float) or fixed-for-float swaps in order to mitigate our cash flow exposure to fluctuations in the future prices of natural gas, NGLs, and crude oil. For natural gas, index swaps are used to protect against the price exposure of daily priced natural gas versus first-of-month priced natural gas. For condensate, crude oil, and natural gas, index swaps are also used to hedge the basis location price risk resulting from supply and markets being priced on different indices. Similarly, we use futures in order to mitigate our cash flow exposure to fluctuations in the future prices of natural gas, crude, and condensate. For natural gas, NGLs, condensate, and crude oil, fixed-for-float swaps and futures are used to protect cash flows against price fluctuations: (1) where we receive a percentage of liquids as a fee for processing third-party natural gas or where we receive a portion of the proceeds of the sales of natural gas and liquids as a fee, (2) in the natural gas processing and fractionation components of our business and (3) where we are mitigating the price risk for product held in inventory or storage.

Assets and liabilities related to our derivative contracts are included in the fair value of derivative assets and liabilities, and the change in fair value of these contracts is recorded net as a gain (loss) on derivative activity on the consolidated statements of operations. We estimate the fair value of all of our derivative contracts based upon actively-quoted prices of the underlying commodities.

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2024		2023		2024		2023
Change in fair value of derivatives	$	18.0	$	(22.9)	$	(4.1)	$	(19.0)
Realized gain (loss) on derivatives	3.8		0.9		(3.9)		20.2
Gain (loss) on derivative activity	$	21.8	$	(22.0)	$	(8.0)	$	1.2

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

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


	September 30, 2024		December 31, 2023
Fair value of derivative assets—current	$	40.3	$	73.6
Fair value of derivative assets—long-term	13.9		27.0
Fair value of derivative liabilities—current	(32.3)		(62.7)
Fair value of derivative liabilities—long-term	(12.4)		(24.3)
Net fair value of commodity derivatives	$	9.5	$	13.6

Set forth below are the summarized notional volumes and fair values of all instruments related to commodity derivatives that we held for price risk management purposes and the related physical offsets at September 30, 2024 (in millions, except volumes). The remaining term of the contracts extend no later than January 2029.

Commodity

Instruments

Unit

Volume

Net Fair Value

NGL (short contracts)

Swaps

MMgals

(88.8)

(1.0)

NGL (long contracts)

Swaps

MMgals

31.5

2.6

Natural gas (short contracts)

Swaps and futures

Bbtu

(105.8)

41.5

Natural gas (long contracts)

Swaps and futures

Bbtu

94.6

(35.8)

Crude and condensate (short contracts)

Swaps and futures

MMbbls

(5.3)

6.3

Crude and condensate (long contracts)

Swaps and futures

MMbbls

0.9

(4.1)

Total fair value of commodity derivatives

9.5

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. Additionally, we have entered into FCDTCs that allow for netting of futures contract receivables and payables in the event of default by either party. If our counterparties failed to perform under existing commodity swap and futures contracts, the maximum loss on our gross receivable position of $54.2 million as of September 30, 2024 would be reduced to $10.5 million due to the offsetting of gross fair value payables against gross fair value receivables as allowed by the ISDAs and the FCDTCs.

(10) Fair Value Measurements

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


	Level 2
	September 30, 2024		December 31, 2023
Interest rate swap (1)	$	(1.5)	$	0.9
Commodity derivatives (2)	$	9.5	$	13.6

____________________________

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

(2)The fair values of commodity derivatives 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.

Table of Contents

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

Long-term debt, including current maturities of long-term debt. The carrying value and estimated fair value of our outstanding debt balances are disclosed below (in millions):


	September 30, 2024				December 31, 2023
	Carrying Value		Fair Value		Carrying Value		Fair Value
Long-term debt, including current maturities of long-term debt (1)	$	4,831.5	$	4,909.9	$	4,568.9	$	4,427.0

____________________________

(1)The carrying value of long-term debt, including current maturities of long-term debt, is reduced by debt issuance cost, net of accumulated amortization, of $32.3 million and $32.1 million as of September 30, 2024 and December 31, 2023, respectively. The respective fair values do not factor in debt issuance costs.

The fair values of all senior unsecured notes as of September 30, 2024 and December 31, 2023 were based on Level 2 inputs from third-party market quotations.

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.

(11) Segment Information

We manage and report our operations primarily according to the geography and the nature of the activity. We have five reportable segments:

•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 transmission pipelines, natural gas processing plants, natural gas and NGL storage facilities, and fractionation facilities located in Louisiana and, prior to its sale in November 2023, 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 Cana-Woodford, Arkoma-Woodford, northern Oklahoma Woodford, STACK, and adjacent areas;

•North Texas Segment. The North Texas segment includes our natural gas gathering, processing, fractionation, 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, as well as our corporate assets and expenses.

Table of Contents

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

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


	Permian		Louisiana		Oklahoma		North Texas		Corporate		Totals
Three Months Ended September 30, 2024
Natural gas sales	$	6.6	$	100.8	$	23.3	$	41.5	$	—	$	172.2
NGL sales	(9.7)		672.4		0.5		(5.1)		—		658.1
Crude oil and condensate sales	429.5		—		31.6		—		—		461.1
Other	—		—		—		0.9		—		0.9
Product sales	426.4		773.2		55.4		37.3		—		1,292.3
Natural gas sales—related parties	—		—		0.4		—		(0.4)		—
NGL sales—related parties	227.3		10.0		103.9		69.0		(410.2)		—
Crude oil and condensate sales—related parties	—		—		—		2.7		(2.7)		—
Product sales—related parties	227.3		10.0		104.3		71.7		(413.3)		—
Gathering and transportation	50.8		28.7		70.5		42.5		—		192.5
Processing	14.2		0.5		36.1		23.8		—		74.6
NGL services	—		15.7		—		0.1		—		15.8
Crude services	6.7		—		3.1		0.2		—		10.0
Other services	1.2		—		0.1		0.1		—		1.4
Midstream services	72.9		44.9		109.8		66.7		—		294.3


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


Midstream services—related parties	—		—		—		1.5		(1.5)		—
Revenue from contracts with customers	726.6		828.1		269.5		177.2		(414.8)		1,586.6
Realized gain (loss) on derivatives	3.4		(1.9)		0.1		2.2		—		3.8
Change in fair value of derivatives	2.6		11.3		3.0		1.1		—		18.0
Total revenues	732.6		837.5		272.6		180.5		(414.8)		1,608.4
Cost of sales, exclusive of operating expenses and depreciation and amortization	(533.7)		(709.8)		(140.1)		(98.8)		414.8		(1,067.6)

Operating expenses	(56.0)		(28.0)		(27.1)		(22.9)		—		(134.0)
Segment profit	$	142.9	$	99.7	$	105.4	$	58.8	$	—	$	406.8










Capital expenditures	$	29.7	$	15.7	$	20.5	$	8.4	$	0.8	$	75.1

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)


	Permian		Louisiana		Oklahoma		North Texas		Corporate		Totals
Three Months Ended September 30, 2023
Natural gas sales	$	132.9	$	101.8	$	42.3	$	22.7	$	—	$	299.7
NGL sales	(4.8)		746.6		(2.0)		0.7		—		740.5
Crude oil and condensate sales	345.2		78.0		24.7		—		—		447.9

Product sales	473.3		926.4		65.0		23.4		—		1,488.1

NGL sales—related parties	247.4		5.3		126.0		78.7		(457.4)		—
Crude oil and condensate sales—related parties	—		—		—		2.3		(2.3)		—
Product sales—related parties	247.4		5.3		126.0		81.0		(459.7)		—
Gathering and transportation	30.5		19.5		60.5		49.8		—		160.3
Processing	15.3		0.5		36.2		29.9		—		81.9
NGL services	—		20.5		—		0.1		—		20.6
Crude services	5.6		5.7		3.7		0.1		—		15.1
Other services	1.7		0.2		0.1		0.2		—		2.2
Midstream services	53.1		46.4		100.5		80.1		—		280.1


NGL services—related parties	—		—		—		1.2		(1.2)		—


Midstream services—related parties	—		—		—		1.2		(1.2)		—
Revenue from contracts with customers	773.8		978.1		291.5		185.7		(460.9)		1,768.2
Realized gain (loss) on derivatives	(4.4)		—		0.9		4.4		—		0.9
Change in fair value of derivatives	(7.4)		(6.0)		(4.1)		(5.4)		—		(22.9)
Total revenues	762.0		972.1		288.3		184.7		(460.9)		1,746.2
Cost of sales, exclusive of operating expenses and depreciation and amortization	(604.3)		(850.0)		(157.1)		(94.2)		460.9		(1,244.7)

Operating expenses	(55.0)		(35.0)		(26.6)		(26.7)		—		(143.3)
Segment profit	$	102.7	$	87.1	$	104.6	$	63.8	$	—	$	358.2











Capital expenditures	$	82.9	$	23.1	$	11.5	$	17.0	$	2.0	$	136.5

Table of Contents

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)


	Permian		Louisiana		Oklahoma		North Texas		Corporate		Totals
Nine Months Ended September 30, 2024
Natural gas sales	$	126.1	$	331.3	$	76.0	$	97.8	$	—	$	631.2
NGL sales	(22.5)		2,106.0		(1.1)		(13.5)		—		2,068.9
Crude oil and condensate sales	1,176.5		—		97.2		—		—		1,273.7
Other	—		—		—		2.1		—		2.1
Product sales	1,280.1		2,437.3		172.1		86.4		—		3,975.9
Natural gas sales—related parties	—		0.1		0.4		—		(0.5)		—
NGL sales—related parties	722.5		28.5		318.2		208.1		(1,277.3)		—
Crude oil and condensate sales—related parties	—		—		—		9.6		(9.6)		—
Product sales—related parties	722.5		28.6		318.6		217.7		(1,287.4)		—
Gathering and transportation	132.1		81.0		191.0		129.1		—		533.2
Processing	45.7		1.7		105.1		73.3		—		225.8
NGL services	—		46.9		—		0.2		—		47.1
Crude services	16.7		0.1		10.0		0.6		—		27.4
Other services	4.8		0.2		0.4		0.6		—		6.0
Midstream services	199.3		129.9		306.5		203.8		—		839.5


NGL services—related parties	—		—		—		3.0		(3.0)		—


Midstream services—related parties	—		—		—		3.0		(3.0)		—
Revenue from contracts with customers	2,201.9		2,595.8		797.2		510.9		(1,290.4)		4,815.4
Realized gain (loss) on derivatives	(1.0)		(2.8)		(1.9)		1.8		—		(3.9)
Change in fair value of derivatives	(1.1)		(2.6)		(0.3)		(0.1)		—		(4.1)
Total revenues	2,199.8		2,590.4		795.0		512.6		(1,290.4)		4,807.4
Cost of sales, exclusive of operating expenses and depreciation and amortization	(1,668.4)		(2,210.1)		(423.4)		(269.1)		1,290.4		(3,280.6)

Operating expenses	(206.4)		(85.9)		(77.0)		(72.5)		—		(441.8)
Segment profit	$	325.0	$	294.4	$	294.6	$	171.0	$	—	$	1,085.0










Capital expenditures	$	109.9	$	68.6	$	57.3	$	26.0	$	2.9	$	264.7

Table of Contents

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)


	Permian		Louisiana		Oklahoma		North Texas		Corporate		Totals
Nine Months Ended September 30, 2023
Natural gas sales	$	338.6	$	326.1	$	142.0	$	53.9	$	—	$	860.6
NGL sales	(4.4)		2,253.1		7.0		(2.2)		—		2,253.5
Crude oil and condensate sales	826.3		187.2		76.1		—		—		1,089.6

Product sales	1,160.5		2,766.4		225.1		51.7		—		4,203.7

NGL sales—related parties	689.0		15.0		346.3		224.4		(1,274.7)		—
Crude oil and condensate sales—related parties	—		—		—		7.8		(7.8)		—
Product sales—related parties	689.0		15.0		346.3		232.2		(1,282.5)		—
Gathering and transportation	83.1		58.2		175.8		153.8		—		470.9
Processing	43.8		0.9		107.9		92.5		—		245.1
NGL services	—		65.7		—		0.2		—		65.9
Crude services	18.6		17.8		13.1		0.5		—		50.0
Other services	5.0		0.9		0.4		0.7		—		7.0
Midstream services	150.5		143.5		297.2		247.7		—		838.9


NGL services—related parties	—		—		—		2.6		(2.6)		—


Midstream services—related parties	—		—		—		2.6		(2.6)		—
Revenue from contracts with customers	2,000.0		2,924.9		868.6		534.2		(1,285.1)		5,042.6
Realized gain (loss) on derivatives	(3.0)		(0.6)		4.8		19.0		—		20.2
Change in fair value of derivatives	(9.0)		3.2		(3.5)		(9.7)		—		(19.0)
Total revenues	1,988.0		2,927.5		869.9		543.5		(1,285.1)		5,043.8
Cost of sales, exclusive of operating expenses and depreciation and amortization	(1,541.3)		(2,538.9)		(481.6)		(258.9)		1,285.1		(3,535.6)

Operating expenses	(156.2)		(100.6)		(78.3)		(77.4)		—		(412.5)
Segment profit	$	290.5	$	288.0	$	310.0	$	207.2	$	—	$	1,095.7











Capital expenditures	$	191.2	$	53.1	$	59.3	$	46.9	$	4.8	$	355.3

The following table reconciles segment profit to income before non-controlling interest and income taxes in the consolidated statements of operations:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2024		2023		2024		2023
Segment profit	$	406.8	$	358.2	$	1,085.0	$	1,095.7
Depreciation and amortization	(186.1)		(163.8)		(514.0)		(489.5)
Impairments	(71.0)		(20.7)		(85.2)		(20.7)
Gain (loss) on disposition of assets	(0.7)		0.6		0.1		1.8
General and administrative	(30.0)		(30.4)		(115.4)		(87.8)
Interest expense, net of interest income	(67.7)		(67.9)		(199.8)		(205.2)
Gain on extinguishment of debt	9.5		—		9.5		—
Income (loss) from unconsolidated affiliate investments	(11.6)		1.0		(12.1)		(3.7)
Other income (expense)	0.9		(0.6)		5.2		(0.2)
Income before non-controlling interest and income taxes	$	50.1	$	76.4	$	173.3	$	290.4

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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 September 30, 2024 and December 31, 2023 (in millions):


Segment Identifiable Assets:	September 30, 2024		December 31, 2023
Permian	$	2,749.7	$	2,813.6
Louisiana	1,888.4		2,031.8
Oklahoma	2,121.5		2,275.8
North Texas	927.6		1,017.7
Corporate (1)	196.6		189.7
Total identifiable assets	$	7,883.8	$	8,328.6

____________________________

(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.

(12) Other Information

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


Other current assets:	September 30, 2024		December 31, 2023
Product inventory	$	101.2	$	46.4
Prepaid expenses and other	25.9		19.0
Other current assets	$	127.1	$	65.4


Other current liabilities:	September 30, 2024		December 31, 2023
Accrued interest	$	42.8	$	63.4
Accrued wages and benefits, including taxes	25.9		23.2
Accrued ad valorem taxes	36.2		33.3
Redemption of Series C Preferred Units	364.5		—
Capital expenditure accruals	37.7		64.6
Short-term lease liability	40.0		28.2
Operating expense accruals	15.4		21.5
Accrued common unit repurchase	20.4		41.5
Other	22.8		2.8
Other current liabilities	$	605.7	$	278.5

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

(13) 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 natural gas during the storm, including one that resulted in litigation. The litigation was between one of our subsidiaries, EnLink Gas Marketing, LP (“EnLink Gas”), and Koch Energy Services, LLC in the 162nd District Court in Dallas County, Texas. In April 2024, we settled this matter and all claims related to this dispute have been dismissed.

One of our subsidiaries, EnLink Energy GP, LLC (“EnLink Energy”), was involved in industry-wide multi-district litigation arising out of Winter Storm Uri, pending in Harris County, Texas, in which multiple individual plaintiffs asserted personal injury and property damage claims arising out of Winter Storm Uri against an aggregate of over 350 power generators, transmission/distribution utility, retail electric provider, and natural gas defendants across over 150 filed cases. On January 26, 2023, the court dismissed the claims against the pipeline and other natural gas-related defendants in the multi-district litigation, including EnLink Energy. The court’s order was not appealed and the case is continuing without EnLink Energy and the other natural gas-related defendants. Subsequently, several suits were filed in February 2023 by individual plaintiffs (including one matter in which the plaintiffs seek to certify a class of Texas residents affected by Winter Storm Uri) and the alleged assignee of the claims of individual plaintiffs against approximately 90 natural gas producers, pipelines, marketers, sellers, and traders, including EnLink Gas. The plaintiffs asserted claims of tortious interference, nuisance, and unjust enrichment against all defendants and are seeking economic and punitive damages and disgorgement of profits. EnLink Gas believes it has substantial defenses to these claims and intends to vigorously dispute these allegations and 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.

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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.

Our revenues and adjusted gross margins are generated from six 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; 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 nine months ended September 30, 2024 or 2023. No other customers represented greater than 10% of our consolidated revenues during the periods presented.


	Three Months Ended September 30,				Nine Months Ended September 30,
	2024		2023		2024		2023

The Dow Chemical Company (1)	10.5	%	9.3	%	10.6	%	10.7	%
Marathon Petroleum Corporation (2)	22.1	%	15.5	%	21.8	%	18.3	%
ExxonMobil Corporation (3)	11.4	%	5.0	%	7.7	%	3.7	%

____________________________

(1)The Dow Chemical Company together with its consolidated subsidiaries.

(2)Marathon Petroleum Corporation together with its consolidated subsidiaries.

(3)ExxonMobil Corporation together with its consolidated subsidiaries.

CCS Business

We are continuing to work on building a carbon transportation business in support of CCS activity along the Gulf Coast, including the Mississippi River corridor in Louisiana, one of the highest CO2 emitting regions in the United States. We believe that CCS remains an important solution to address carbon emissions by industrial emitters and that our existing asset footprint, including our extensive network of natural gas pipelines in Louisiana, our operating expertise, including our current operation of CCS pipelines in North Texas, and our customer relationships, provide us with an advantage in building a carbon transportation business and becoming a transporter of choice in the regions in which we operate.

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Recent Developments Affecting Industry Conditions and Our Business

Current Market Environment

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. The table below presents selected average index prices for crude oil, NGL, and natural gas for the periods indicated.


	Crude oil		NGL		Natural gas
	$/Bbl (1)(2)		$/Gal (1)(3)		$/MMbtu (1)(4)
2024 by quarter:
1st Quarter	$	76.91	$	0.55	$	2.10
2nd Quarter	$	80.66	$	0.52	$	2.32
3rd Quarter	$	75.27	$	0.52	$	2.23

2024 Averages	$	77.61	$	0.53	$	2.22

2023 by quarter:
1st Quarter	$	75.99	$	0.61	$	2.74
2nd Quarter	$	73.56	$	0.43	$	2.33
3rd Quarter	$	82.22	$	0.50	$	2.66

2023 Averages	$	77.28	$	0.51	$	2.58

____________________________

(1)The average closing price was computed by taking the sum of the closing prices of each trading day divided by the number of trading days during the period presented.

(2)Crude oil closing prices based on the NYMEX futures daily close prices.

(3)Weighted average NGL closing prices based on the OPIS Napoleonville daily average spot liquids prices.

(4)Natural gas closing prices based on Henry Hub Natural Gas Daily closing prices.

Competition for crude oil, condensate, natural gas, and NGL supplies and any decrease in the availability of such commodities, volatile prices, and market demand for crude oil, condensate, natural gas, and NGLs that are beyond our control could each adversely affect our financial condition, results of operation, or cash flows. For more information, see “Item 1A—Risk Factors—Business and Industry Risks” in our Annual Report on Form 10-K for the year ended December 31, 2023 filed with the Commission on February 21, 2024.

Inflation

In recent years, U.S. inflation has increased significantly. In order to reduce the inflation rate, the Federal Reserve increased its target for the federal funds rate (the benchmark for most interest rates) several times in 2023. Inflation has moderated in 2023 and throughout 2024. In September 2024, the Federal Reserve cut the federal funds rate by 50 basis points and indicated the possibility of further rate cuts before the end of 2024.

To the extent that a rising cost environment impacts our results, there are typically offsetting benefits either inherent in our business or that result from other steps we take proactively to reduce the impact of inflation on our net operating results. These benefits include: (1) provisions included in our long-term fee-based revenue contracts that offset cost increases in the form of rate escalations based on positive changes in the U.S. Consumer Price Index, Producer Price Index for Finished Goods, or other factors; (2) provisions in our contracts that enable us to pass through higher costs to customers; and (3) higher commodity prices, which generally enhance our results in the form of increased volumetric throughput and demand for our services. For these reasons, the increased cost environment, caused in part by inflation, has not had a material impact on our historical results of operations for the periods presented in this report. However, a significant or prolonged period of high inflation could adversely impact our results if costs were to increase at a rate greater than the increase in the revenues we receive.

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, 2023 filed with the Commission on February 21, 2024.

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Regulatory Developments

In accordance with the requirements of the Inflation Reduction Act of 2022, on January 26, 2024, the U.S. Environmental Protection Agency (the “EPA”) published its proposed rule regarding the Waste Emissions Charge, applicable to excess methane emissions at certain crude oil and natural gas facilities. Further, On March 8, 2024, the EPA published its final rules imposing new, stricter requirements for methane monitoring, reporting, and emissions control at certain crude oil and natural gas facilities. Finally, on April 10, 2024, the U.S. Bureau of Land Management published its final Waste Prevention Rule, which requires operators of crude oil and natural gas leases to take reasonable steps to avoid natural gas waste, as well as develop leak detection, repair, and waste minimization plans.

Any regulatory changes could 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 Item 1A—Risk Factors—“Environmental, Legal Compliance, and Regulatory Risk” in our Annual Report on Form 10-K for the year ended December 31, 2023 filed with the Commission on February 21, 2024.

Other Recent Developments

GIP/ONEOK Transaction

Organic Growth

Henry Hub to the River Project. In 2024, we plan to expand the natural gas transmission capacity of the Bridgeline pipeline from the Henry Hub to the Mississippi River Corridor by 210 MMcf/d through additional compression. We expect to complete the project in the fourth quarter of 2025.

Jefferson Island Storage Facility Expansion. We plan to expand the Jefferson Island storage facility by approximately 8 Bcf, which will increase the estimated working gas storage capacity from 2 Bcf to 10 Bcf. We expect to complete the Jefferson Island storage facility expansion in 2028.

Tiger II Processing Plant. In April 2023, we began moving equipment and facilities associated with the non-operational Cowtown processing plant in North Texas to our Delaware Basin JV operations in the Permian to operate as the Tiger II processing plant. The move has been completed and the Tiger II processing plant began operations in May 2024, which increased our Permian Basin processing capacity by 150 MMcf/d.

GCF Operations. In January 2023, we and our partners started the process to restart the GCF assets. We expect the assets to become operational in the fourth quarter of 2024.

Matterhorn JV. We own a 15% interest in the Matterhorn JV. The Matterhorn JV is constructing 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”). The Matterhorn Express Pipeline began in-service operations in the third quarter of 2024.

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Exxon Mobil 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 southeastern Louisiana at Pecan Island in Vermilion Parish. In February 2024, we and ExxonMobil agreed to reassess the Pecan Island project’s near-term role with the expectation that other joint CCS opportunities along the Gulf Coast might be prioritized ahead of the Pecan Island Project. Since that time, we and ExxonMobil have been unable to identify alternative CO2 transportation projects for EnLink. We are now pursuing a financial arrangement for the value to EnLink of the Pecan Island transportation agreement. There can be no assurance that we would recover the value to EnLink of the Pecan Island transportation agreement in any financial arrangement or when such arrangement would be realized.

Debt

Senior Unsecured Notes

Additionally, for the three and nine months ended September 30, 2024, we repurchased a portion of the 2044 Notes, the 2045 Notes, and the 2047 Notes in open market transactions. As a result, we recognized a $9.5 million gain on extinguishment of debt, which is included in the consolidated statements of operations for the three and nine months ended September 30, 2024. We did not repurchase any senior unsecured notes in open market transactions during the three and nine months ended September 30, 2023.

Equity

Preferred Unit Activity

In July 2024, the holders of the Series B Preferred Units exchanged 8,695,654 Series B Preferred Units for 10,000,000 ENLC common units.

In August 2024, we repurchased 12,698,414 Series B Preferred Units for $200.0 million plus accrued distributions. The repurchase price represented 105% of the preferred units’ par value.

On October 17, 2024, we redeemed all of the outstanding Series C Preferred units for $1,000 per Series C Preferred Unit, plus $8.28 per Series C Preferred Unit of unpaid distributions.

See “Item 1. Financial Statements—Note 7” for more information regarding the exchanges and repurchase of the Series B Preferred Units and the repurchase and redemption of the Series C Preferred Units.

Common Unit Repurchase Program. During the three months ended September 30, 2024, we repurchased 1,906,780 outstanding common units in open market purchases, for an aggregate cost, including commissions, of $25.0 million, or an average of $13.09 per common unit. For the nine months ended September 30, 2024, we repurchased 6,108,742 outstanding common units in open market purchases, for an aggregate cost, including commissions, of $79.0 million, or an average of $12.93 per common unit.

GIP Repurchase Agreement. During the three months ended September 30, 2024, we repurchased 1,718,847 ENLC common units held by GIP for an aggregate cost of $22.9 million, or an average of $13.31 per common unit. For the nine months ended September 30, 2024, we repurchased 6,862,179 ENLC common units held by GIP for an aggregate cost of $87.5 million, or an average of $12.75 per common unit.

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See “Item 1. Financial Statements—Note 8” for more information regarding our common unit repurchase activity.

Rate Reset

Beginning March 2024, certain legacy contracts in the Oklahoma and North Texas segments experienced a one-time rate reset. The rate reset was negotiated in 2018 in exchange for adding an additional five years of term to these contracts. The rate reset is a one-time adjustment down to a pre-negotiated rate (which partially reverses recent annual inflation cost escalation adjustments). These contracts are set to expire between 2029 and 2033 and continue to have cost escalation provisions that allow for rate increases from the reset rate based on future changes in inflation.

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.

Adjusted Gross Margin

We define adjusted gross margin as revenues less cost of sales, exclusive of operating expenses and depreciation and amortization. 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 September 30,				Nine Months Ended September 30,
	2024		2023		2024		2023
Total revenues	$	1,608.4	$	1,746.2	$	4,807.4	$	5,043.8
Cost of sales, exclusive of operating expenses and depreciation and amortization	(1,067.6)		(1,244.7)		(3,280.6)		(3,535.6)
Operating expenses	(134.0)		(143.3)		(441.8)		(412.5)
Depreciation and amortization	(186.1)		(163.8)		(514.0)		(489.5)
Gross margin	220.7		194.4		571.0		606.2
Operating expenses	134.0		143.3		441.8		412.5
Depreciation and amortization	186.1		163.8		514.0		489.5
Adjusted gross margin	$	540.8	$	501.5	$	1,526.8	$	1,508.2

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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; (gain) loss on litigation settlement; unit-based compensation; income tax expense (benefit); unrealized (gain) loss on commodity derivatives; 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 September 30,				Nine Months Ended September 30,
	2024		2023		2024		2023
Net income	$	43.1	$	65.8	$	160.1	$	249.9
Interest expense, net of interest income	67.7		67.9		199.8		205.2
Depreciation and amortization	186.1		163.8		514.0		489.5
Impairments	71.0		20.7		85.2		20.7
(Income) loss from unconsolidated affiliate investments	11.6		(1.0)		12.1		3.7
Distributions from unconsolidated affiliate investments	—		0.1		—		2.4
(Gain) loss on disposition of assets	0.7		(0.6)		(0.1)		(1.8)
Gain on extinguishment of debt	(9.5)		—		(9.5)		—
Loss on litigation settlement (1)	—		—		23.0		—
Unit-based compensation	5.7		5.7		16.5		14.2
Income tax expense	7.0		10.6		13.2		40.5
Unrealized (gain) loss on commodity derivatives	(18.0)		22.9		4.1		19.0
Costs associated with the relocation of processing facilities (2)	2.1		2.9		28.3		5.0
Other (3)	0.1		0.1		1.6		0.6
Adjusted EBITDA before non-controlling interest	367.6		358.9		1,048.3		1,048.9
Non-controlling interest share of adjusted EBITDA from joint ventures (4)	(22.6)		(17.0)		(59.6)		(49.7)
Adjusted EBITDA, net to ENLC	$	345.0	$	341.9	$	988.7	$	999.2

____________________________

(1)Relates to the loss incurred to settle litigation that arose from Winter Storm Uri and is not part of our ongoing operations.

(2)Represents cost incurred to execute discrete, project-based strategic initiatives aimed at realigning available processing capacity from our Oklahoma and North Texas segments to the Permian segment. These costs are not part of our ongoing operations.

(3)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.

(4)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); (cash distributions earned by the Series B Preferred Units and the Series C Preferred Units); (payment to redeem mandatorily redeemable non-controlling interest); (costs associated with the relocation of processing facilities, excluding costs that were contributed by other entities and relate to the non-controlling interest share of our consolidated entities); non-cash interest (income)/expense; (contributions to investment in unconsolidated affiliates); (payments to terminate interest rate swaps); (current income taxes); (earnout payments related to the Amarillo Rattler Acquisition and the Central Oklahoma Acquisition); (non-cash gain associated with a lease modification); and proceeds from the sale of equipment and land.

Free cash flow after distributions is the principal cash flow metric used by the Company. 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, processing assets, or CCS initiatives, 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 September 30,				Nine Months Ended September 30,
	2024		2023		2024		2023
Net cash provided by operating activities	$	260.1	$	274.2	$	716.0	$	862.0
Interest expense (1)	66.1		66.3		195.2		200.3
Costs associated with the relocation of processing facilities (2)	2.1		2.9		28.3		5.0
Loss on litigation settlement (3)	—		—		23.0		—
Other (4)	1.3		0.9		5.3		1.7
Changes in operating assets and liabilities which (provided) used cash:
Accounts receivable, accrued revenues, inventories, and other	(63.5)		156.9		(52.0)		(92.8)
Accounts payable, accrued product purchases, and other accrued liabilities	101.5		(142.3)		132.5		72.7
Adjusted EBITDA before non-controlling interest	367.6		358.9		1,048.3		1,048.9
Non-controlling interest share of adjusted EBITDA from joint ventures (5)	(22.6)		(17.0)		(59.6)		(49.7)
Adjusted EBITDA, net to ENLC	345.0		341.9		988.7		999.2
Growth capital expenditures, net to ENLC (6)	(48.9)		(97.4)		(192.3)		(264.7)
Maintenance capital expenditures, net to ENLC (6)	(21.6)		(18.3)		(55.9)		(52.5)
Interest expense, net of interest income	(67.7)		(67.9)		(199.8)		(205.2)
Distributions declared on common units	(62.4)		(57.5)		(183.0)		(174.3)
ENLK preferred unit cash distributions earned (7)	(13.7)		(24.6)		(61.9)		(72.2)

Payment to redeem mandatorily redeemable non-controlling interest (8)	—		—		—		(10.5)
Costs associated with the relocation of processing facilities, net to ENLC (2)(6)	(1.9)		(1.7)		(17.7)		5.0
Contributions to investment in unconsolidated affiliates	(5.3)		(8.7)		(25.4)		(58.4)
Other (9)	(1.1)		0.4		(3.0)		1.2
Free cash flow after distributions	$	122.4	$	66.2	$	249.7	$	167.6

____________________________

(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.

(3)Relates to the loss incurred to settle litigation that arose from Winter Storm Uri and is not part of our ongoing operations.

(4)Includes utility credits redeemed, distributions from unconsolidated affiliate investments in excess of earnings, transaction costs, current income tax expense, and non-cash rent, which relates to lease incentives pro-rated over the lease term.

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

(6)Excludes capital expenditures and costs associated with the relocation of processing facilities that were contributed by other entities and relate to the non-controlling interest share of our consolidated entities.

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

(8)In January 2023, we settled the redemption of the mandatorily redeemable non-controlling interest in one of our non-wholly owned subsidiaries.

(9)Includes current income tax expense, earnout payments related to the Amarillo Rattler Acquisition and the Central Oklahoma Acquisition, a reduction for non-cash gain associated with a lease modification, 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
Three Months Ended September 30, 2024
Total revenues	$	732.6	$	837.5	$	272.6	$	180.5	$	(414.8)	$	1,608.4
Cost of sales, exclusive of operating expenses and depreciation and amortization	(533.7)		(709.8)		(140.1)		(98.8)		414.8		(1,067.6)
Adjusted gross margin	198.9		127.7		132.5		81.7		—		540.8
Operating expenses	(56.0)		(28.0)		(27.1)		(22.9)		—		(134.0)
Segment profit	142.9		99.7		105.4		58.8		—		406.8
Depreciation and amortization	(46.7)		(31.3)		(80.7)		(25.9)		(1.5)		(186.1)
Gross margin	$	96.2	$	68.4	$	24.7	$	32.9	$	(1.5)	$	220.7

	Permian		Louisiana		Oklahoma		North Texas		Corporate		Totals
Three Months Ended September 30, 2023
Total revenues	$	762.0	$	972.1	$	288.3	$	184.7	$	(460.9)	$	1,746.2
Cost of sales, exclusive of operating expenses and depreciation and amortization	(604.3)		(850.0)		(157.1)		(94.2)		460.9		(1,244.7)
Adjusted gross margin	157.7		122.1		131.2		90.5		—		501.5
Operating expenses	(55.0)		(35.0)		(26.6)		(26.7)		—		(143.3)
Segment profit	102.7		87.1		104.6		63.8		—		358.2
Depreciation and amortization	(42.1)		(36.3)		(54.6)		(29.3)		(1.5)		(163.8)
Gross margin	$	60.6	$	50.8	$	50.0	$	34.5	$	(1.5)	$	194.4

	Permian		Louisiana		Oklahoma		North Texas		Corporate		Totals
Nine Months Ended September 30, 2024
Total revenues	$	2,199.8	$	2,590.4	$	795.0	$	512.6	$	(1,290.4)	$	4,807.4
Cost of sales, exclusive of operating expenses and depreciation and amortization	(1,668.4)		(2,210.1)		(423.4)		(269.1)		1,290.4		(3,280.6)
Adjusted gross margin	531.4		380.3		371.6		243.5		—		1,526.8
Operating expenses	(206.4)		(85.9)		(77.0)		(72.5)		—		(441.8)
Segment profit	325.0		294.4		294.6		171.0		—		1,085.0
Depreciation and amortization	(136.1)		(97.8)		(193.2)		(82.3)		(4.6)		(514.0)
Gross margin	$	188.9	$	196.6	$	101.4	$	88.7	$	(4.6)	$	571.0

	Permian		Louisiana		Oklahoma		North Texas		Corporate		Totals
Nine Months Ended September 30, 2023
Total revenues	$	1,988.0	$	2,927.5	$	869.9	$	543.5	$	(1,285.1)	$	5,043.8
Cost of sales, exclusive of operating expenses and depreciation and amortization	(1,541.3)		(2,538.9)		(481.6)		(258.9)		1,285.1		(3,535.6)
Adjusted gross margin	446.7		388.6		388.3		284.6		—		1,508.2
Operating expenses	(156.2)		(100.6)		(78.3)		(77.4)		—		(412.5)
Segment profit	290.5		288.0		310.0		207.2		—		1,095.7
Depreciation and amortization	(123.6)		(111.5)		(163.1)		(87.1)		(4.2)		(489.5)
Gross margin	$	166.9	$	176.5	$	146.9	$	120.1	$	(4.2)	$	606.2

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	Three Months Ended September 30,		Nine Months Ended September 30,
	2024	2023	2024	2023
Midstream Volumes:
Consolidated
Gathering and Transportation (MMbtu/d)	7,350,500	7,095,800	7,380,800	7,064,400
Processing (MMbtu/d)	3,762,700	3,606,900	3,656,600	3,546,700
Crude Oil Handling (Bbls/d)	213,200	216,600	202,500	201,200
NGL Fractionation (Bbls/d)	164,400	180,800	174,400	181,000
Brine Disposal (Bbls/d)	—	3,400	—	3,000
Permian Segment
Gathering and Transportation (MMbtu/d)	2,029,700	1,840,800	1,987,600	1,752,800
Processing (MMbtu/d)	1,864,700	1,699,700	1,820,300	1,626,500
Crude Oil Handling (Bbls/d)	195,500	176,100	183,800	158,100
Louisiana Segment
Gathering and Transportation (MMbtu/d)	2,561,500	2,468,900	2,711,100	2,501,900
Crude Oil Handling (Bbls/d)	—	18,600	—	17,800
NGL Fractionation (Bbls/d)	164,400	180,800	174,400	181,000
Brine Disposal (Bbls/d)	—	3,400	—	3,000
Oklahoma Segment
Gathering and Transportation (MMbtu/d)	1,242,900	1,223,000	1,202,200	1,218,600
Processing (MMbtu/d)	1,192,700	1,178,200	1,152,400	1,182,400
Crude Oil Handling (Bbls/d)	17,700	21,900	18,700	25,300
North Texas Segment
Gathering and Transportation (MMbtu/d)	1,516,400	1,563,100	1,479,900	1,591,100
Processing (MMbtu/d)	705,300	729,000	683,900	737,800

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Three Months Ended September 30, 2024 Compared to Three Months Ended September 30, 2023

Revenues and Cost of Sales, Exclusive of Operating Expenses and Depreciation and Amortization.

Our consolidated and segment revenues and cost of sales, exclusive of operating expenses and depreciation and amortization, are from natural gas, NGL, crude oil, and condensate product sales and purchases, midstream services that we perform with respect to those commodities, and derivative activity. Fluctuations in our consolidated and segment revenues and cost of sales, exclusive of operating expenses and depreciation and amortization, reflect in large part changes in commodity prices and volumes. Our adjusted gross margin is not directly affected by the commodity price environment because the commodities that we buy and sell are generally based on the same pricing indices. Both consolidated and segment product sales revenues and cost of sales, exclusive of operating expenses and depreciation and amortization, will fluctuate with market prices; however, the adjusted gross margin related to those sales and purchases will not necessarily have a corresponding increase or decrease. Additionally, fluctuations in these measures from changes in commodity prices may be offset by gains or losses from derivative instruments that we use to manage our exposure to commodity price risk associated with such sales and purchases.

Total revenues and cost of sales, exclusive of operating expenses and depreciation and amortization, decreased $137.8 million and $177.1 million, respectively, for the three months ended September 30, 2024 compared to the three months ended September 30, 2023 due to the following:

•Product sales revenues decreased $195.8 million for the three months ended September 30, 2024 compared to the three months ended September 30, 2023 primarily due to:

◦A $127.5 million decrease in natural gas sales primarily driven by lower natural gas prices; and

◦An $82.4 million decrease in NGL sales primarily driven by lower NGL volumes.

These decreases were partially offset by a $13.2 million increase in crude oil and condensate sales primarily driven by an $84.3 million increase in our Permian segment, which was primarily driven by higher volumes, and was partially offset by a $78.0 million decrease in our Louisiana segment, driven by the divestiture of our ORV crude assets in November 2023.

•The changes in natural gas, NGL, and crude oil prices also had a corresponding impact to cost of sales, exclusive of operating expenses and depreciation and amortization, contributing to the $177.1 million decrease for the three months ended September 30, 2024 compared to the three months ended September 30, 2023.

•Revenues from midstream services increased $14.2 million for the three months ended September 30, 2024 compared to the three months ended September 30, 2023 primarily due to a $32.2 million increase in gathering and transportation revenues primarily driven by higher gathering and transportation volumes in our Permian segment.

This increase was partially offset by:

◦A $7.3 million decrease in processing revenues primarily due to a $6.1 million decrease in our North Texas segment, which was driven by a one-time rate reset to a lower fee on certain existing contracts;

◦A $4.8 million decrease in NGL service revenues primarily driven by lower NGL service volumes; and

◦A $5.1 million decrease in crude services revenues primarily driven by the divestiture of our ORV crude assets.

•Derivative gains increased $43.8 million for the three months ended September 30, 2024 compared to the three months ended September 30, 2023 due to $2.9 million of increased realized gains and $40.9 million of increased unrealized gains.

Operating Expenses. Operating expenses decreased $9.3 million for the three months ended September 30, 2024 compared to the three months ended September 30, 2023 primarily due to a $7.0 million decrease in our Louisiana segment, driven by the divestiture of our ORV assets in November 2023.

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Depreciation and Amortization. Depreciation and amortization increased $22.3 million for the three months ended September 30, 2024 compared to the three months ended September 30, 2023 primarily due to a $25.8 million increase related to changes in estimated useful lives of certain assets and a $5.3 million increase resulting from additional assets being placed in service. These increases were partially offset by a $6.1 million decrease related to assets reaching the end of their depreciable lives and a $2.9 million decrease due to the divestiture of our ORV assets in November 2023.

Impairments. For the three months ended September 30, 2024 and 2023, we recognized impairment expense related to property and equipment. Impairment expense is composed of the following amounts (in millions):


	Three Months Ended September 30,
	2024		2023
Impairments (1)	$	71.0	$	20.7

____________________________

(1)See “Item 1. Financial Statements—Note 2” for more information regarding the property and equipment impairments.

Interest Expense, Net of Interest Income. Interest expense, net of interest income, was $67.7 million for the three months ended September 30, 2024 compared to $67.9 million for the three months ended September 30, 2023, a decrease of $0.2 million. Interest expense, net of interest income, consisted of the following (in millions):


	Three Months Ended September 30,
	2024		2023
ENLK and ENLC senior notes	$	60.6	$	58.8
Revolving Credit Facility	2.8		4.0
AR Facility	5.8		5.2
Amortization of debt issuance costs and net discount of senior unsecured notes	1.6		1.6
Interest rate swap – realized	(1.5)		(1.4)
Treasury lock agreement	(1.1)		—
Other	(0.5)		(0.3)
Interest expense, net of interest income	$	67.7	$	67.9

Gain on Extinguishment of Debt. Gain on extinguishment of debt was $9.5 million for the three months ended September 30, 2024 related to the partial repurchase of the 2044 Notes, 2045 Notes, and 2047 Notes. There were no debt extinguishments for the three months ended September 30, 2023.

Income (Loss) from Unconsolidated Affiliate Investments. Loss from unconsolidated affiliate investments was $11.6 million for the three months ended September 30, 2024 compared to income of $1.0 million for the three months ended September 30, 2023, an increase in loss of $12.6 million. Income (loss) from unconsolidated affiliate investments consisted of the following (in millions):


	Three Months Ended September 30,
	2024		2023
GCF	$	(2.3)	$	0.3
Cedar Cove JV	—		(0.6)
Matterhorn JV	(9.3)		1.3
Income (loss) from unconsolidated affiliate investments	$	(11.6)	$	1.0

Income Tax Expense. Income tax expense was $7.0 million for the three months ended September 30, 2024 compared to an income tax expense of $10.6 million for the three months ended September 30, 2023, a decrease in income tax expense of $3.6 million. The decrease in income tax expense was primarily attributable to the decrease in income between periods. See “Item 1. Financial Statements—Note 6” for additional information.

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Net Income Attributable to Non-Controlling Interest. Net income attributable to non-controlling interest was $29.1 million for the three months ended September 30, 2024 compared to net income of $36.3 million for the three months ended September 30, 2023, a decrease of $7.2 million. Net income attributable to non-controlling interest consisted of the following (in millions):


	Three Months Ended September 30,
	2024		2023
NGP’s 49.9% share of the Delaware Basin JV	$	14.9	$	8.5
Marathon Petroleum Corporation’s 50% share of the Ascension JV	0.4		1.5
Series B Preferred Units	6.2		17.0
Series C Preferred Units	7.6		9.3
Net income attributable to non-controlling interest	$	29.1	$	36.3

Analysis of Operating Segments

We manage and report our operations primarily according to the geography and the nature of the activity. We have five reportable segments: Permian segment, Louisiana segment, Oklahoma segment, North Texas segment, and Corporate segment. We evaluate the performance of our operating segments based on segment profit and adjusted gross margin. The GAAP measure most directly comparable to segment profit and adjusted gross margin is gross margin. We believe that investors benefit from having access to the same financial measures that our management uses to evaluate segment results.

See below for our discussion of segment results for the three months ended September 30, 2024 compared to the three months ended September 30, 2023.

•Permian Segment.

◦Revenues and cost of sales, exclusive of operating expenses and depreciation and amortization, decreased $29.4 million and $70.6 million, respectively, resulting in an increase in adjusted gross margin in the Permian segment of $41.2 million, due to:

•A $39.4 million increase in adjusted gross margin associated with our Permian natural gas assets. Adjusted gross margin, excluding derivative activity, increased $27.1 million, which was primarily due to higher volumes from existing customers. Derivative activity associated with our Permian natural gas assets increased adjusted gross margin by $12.3 million, which included $2.3 million from increased realized gains and $10.0 million from increased unrealized gains; and

•A $1.8 million increase in adjusted gross margin associated with our Permian crude assets. Adjusted gross margin, excluding derivative activity, decreased $3.7 million, which was primarily due to lower commodity prices. Derivative activity associated with our Permian crude assets increased adjusted gross margin by $5.5 million from increased realized gains.

◦Operating expenses in the Permian segment increased $1.0 million due to an increase in operating activity.

◦Depreciation and amortization in the Permian segment increased $4.6 million primarily due to additional assets being placed in service.

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•Louisiana Segment.

◦Revenues and cost of sales, exclusive of operating expenses and depreciation and amortization, decreased $134.6 million and $140.2 million, respectively, resulting in an increase in adjusted gross margin in the Louisiana segment of $5.6 million, due to:

•A $0.8 million increase in adjusted gross margin associated with our Louisiana NGL transmission and fractionation assets. Adjusted gross margin, excluding derivative activity, decreased $6.7 million, which was primarily due to lower seasonal fees for delivery of normal butane. Derivative activity associated with our Louisiana NGL transmission and fractionation assets increased adjusted gross margin by $7.5 million, which included $2.6 million from increased realized losses and $10.1 million from increased unrealized gains;

•A $15.7 million increase in adjusted gross margin associated with our Louisiana natural gas assets. Adjusted gross margin, excluding derivative activity, increased $8.6 million, which was primarily due to higher volumes from existing customers. Derivative activity associated with our Louisiana natural gas assets increased adjusted gross margin by $7.1 million, which included $0.1 million from increased realized losses and $7.2 million from increased unrealized gains; and

•A $10.9 million decrease in adjusted gross margin associated with our ORV crude assets, due to their divestiture in November 2023.

◦Operating expenses in the Louisiana segment decreased $7.0 million primarily due to the divestiture of our ORV assets in November 2023.

◦Depreciation and amortization in the Louisiana segment decreased $5.0 million primarily due to a $2.9 million decrease due to the divestiture of our ORV assets in November 2023 and a $1.7 million decrease resulting from assets reaching the end of their depreciable lives.

•Oklahoma Segment.

◦Revenues and cost of sales, exclusive of operating expenses and depreciation amortization, decreased $15.7 million and $17.0 million, respectively, resulting in an increase in adjusted gross margin in the Oklahoma segment of $1.3 million, due to:

•A $2.0 million increase in adjusted gross margin associated with our Oklahoma natural gas assets. Adjusted gross margin, excluding derivative activity, decreased $3.9 million, which was primarily due to a one-time rate reset to a lower fee on certain existing contracts. For additional information on the one-time rate reset, see “Other Recent Developments.” Derivative activity associated with our Oklahoma natural gas assets increased adjusted gross margin by $5.9 million, which included $1.2 million from increased realized losses and $7.1 million from increased unrealized gains; and

•A $0.7 million decrease in adjusted gross margin associated with our Oklahoma crude assets. Adjusted gross margin, excluding derivative activity, decreased $1.1 million, which was primarily due to lower volumes from existing customers. Derivative activity associated with our Oklahoma crude assets increased adjusted gross margin by $0.4 million from increased realized gains.

◦Operating expenses in the Oklahoma segment increased $0.5 million primarily due to an increase in operating activity.

◦Depreciation and amortization in the Oklahoma segment increased $26.1 million primarily due to a $25.8 million increase related to changes in estimated useful lives of certain assets.

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•North Texas Segment.

◦Revenues decreased $4.2 million and cost of sales, exclusive of operating expenses and depreciation and amortization, increased $4.6 million, resulting in a decrease in adjusted gross margin in the North Texas segment of $8.8 million. Adjusted gross margin, excluding derivative activity, decreased $13.1 million, which was primarily due to a one-time rate reset to a lower fee on certain existing contracts. For additional information on the one-time rate reset, see “Other Recent Developments.” Derivative activity associated with our North Texas segment increased adjusted gross margin by $4.3 million, which included $2.2 million from decreased realized gains and $6.5 million from increased unrealized gains.

◦Operating expenses in the North Texas segment decreased $3.8 million primarily due to a decrease in operating activity.

◦Depreciation and amortization in the North Texas segment decreased $3.4 million primarily due to assets reaching the end of their depreciable lives.

•Corporate Segment.

◦Revenues and cost of sales, exclusive of operating expenses and depreciation and amortization, each increased $46.1 million. The corporate segment includes offsetting eliminations related to intercompany revenues and cost of sales, exclusive of operating expenses and depreciation and amortization.

Nine Months Ended September 30, 2024 Compared to Nine Months Ended September 30, 2023

Revenues and Cost of Sales, Exclusive of Operating Expenses and Depreciation and Amortization.

Total revenues and cost of sales, exclusive of operating expenses and depreciation and amortization, decreased $236.4 million and $255.0 million, respectively, for the nine months ended September 30, 2024 compared to the nine months ended September 30, 2023 due to the following:

•Product sales revenues decreased $227.8 million for the nine months ended September 30, 2024 compared to the nine months ended September 30, 2023 primarily due to:

◦A $229.4 million decrease in natural gas sales primarily driven by lower natural gas prices; and

◦A $184.6 million decrease in NGL sales primarily driven by lower NGL volumes.

These decreases were partially offset by a $184.1 million increase in crude oil and condensate sales primarily driven by a $350.2 million increase in our Permian segment, which was primarily driven by higher volumes, and was partially offset by a $187.2 million decrease in our Louisiana segment, driven by the divestiture of our ORV crude assets in November 2023.

•The changes in natural gas, NGL, and crude oil prices also had a corresponding impact to cost of sales, exclusive of operating expenses and depreciation and amortization, contributing to the $255.0 million decrease for the nine months ended September 30, 2024 compared to the nine months ended September 30, 2023.

•Revenues from midstream services increased $0.6 million for the nine months ended September 30, 2024 compared to the nine months ended September 30, 2023 primarily due to a $62.3 million increase in gathering and transportation revenues primarily driven by higher gathering and transportation volumes in our Permian segment.

This increase was partially offset by:

◦A $19.3 million decrease in processing revenues primarily due to a $19.2 million decrease in our North Texas segment, which was driven by a one-time rate reset to a lower fee on certain existing contracts;

◦A $18.8 million decrease in NGL service revenues primarily driven by lower NGL service volumes; and

◦A $22.6 million decrease in crude services revenues primarily driven by the divestiture of our ORV crude assets.

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•Derivative losses increased $9.2 million for the nine months ended September 30, 2024 compared to the nine months ended September 30, 2023 due to $24.1 million of increased realized losses and $14.9 million of decreased unrealized losses.

Operating Expenses. Operating expenses increased $29.3 million for the nine months ended September 30, 2024 compared to the nine months ended September 30, 2023 primarily due to a $20.6 million increase in construction fees and services resulting from the relocation of the Tiger II processing plant and a $12.3 million increase in compressor rentals, principally due to an increase in operating activity. These increases were partially offset by a $4.7 million decrease in vehicle expenses, driven by the divestiture of our ORV assets in November 2023.

Depreciation and Amortization. Depreciation and amortization increased $24.5 million for the nine months ended September 30, 2024 compared to the nine months ended September 30, 2023 primarily due to a $31.5 million increase related to changes in estimated useful lives of certain assets and a $16.8 million increase resulting from additional assets being placed in service. These increases were partially offset by a $15.6 million decrease related to assets reaching the end of their depreciable lives and an $8.2 million decrease due to the divestitures of our ORV assets in November 2023.

Impairments. For the nine months ended September 30, 2024 and 2023, we recognized impairment expense related to property and equipment. Impairment expense is composed of the following amounts (in millions):


	Nine Months Ended September 30,
	2024		2023
Impairments (1)	$	85.2	$	20.7

____________________________

(1)See “Item 1. Financial Statements—Note 2” for more information regarding the property and equipment impairments.

General and Administrative Expenses. General and administrative expenses were $115.4 million for the nine months ended September 30, 2024 compared to $87.8 million for the nine months ended September 30, 2023, an increase of $27.6 million, which was primarily due to an increase in legal settlements and related to the loss incurred to settle litigation that arose from Winter Storm Uri.

Interest Expense. Interest expense was $199.8 million for the nine months ended September 30, 2024 compared to $205.2 million for the nine months ended September 30, 2023, a decrease of $5.4 million. Interest expense consisted of the following (in millions):


	Nine Months Ended September 30,
	2024		2023
ENLK and ENLC senior notes	$	177.1	$	171.4
Revolving Credit Facility	8.0		15.8
AR Facility	17.2		16.9
Amortization of debt issuance costs and net discount of senior unsecured notes	4.6		4.9
Interest rate swap – realized	(4.5)		(3.0)
Treasury lock agreement	(1.1)		—
Other	(1.5)		(0.8)
Interest expense, net of interest income	$	199.8	$	205.2

Gain on Extinguishment of Debt. Gain on extinguishment of debt was $9.5 million for the nine months ended September 30, 2024 related to the partial repurchase of the 2044 Notes, 2045 Notes, and 2047 Notes. There were no debt extinguishments for the nine months ended September 30, 2023.

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Income (Loss) from Unconsolidated Affiliate Investments. Loss from unconsolidated affiliate investments was $12.1 million for the nine months ended September 30, 2024 compared to a loss of $3.7 million for the nine months ended September 30, 2023, an increase in loss of $8.4 million. Loss from unconsolidated affiliate investments consisted of the following (in millions):


	Nine Months Ended September 30,
	2024		2023
GCF	$	(6.7)	$	(2.5)
Cedar Cove JV	7.3		(1.7)
Matterhorn JV	(12.7)		0.5
Loss from unconsolidated affiliate investments	$	(12.1)	$	(3.7)

Income Tax Expense. Income tax expense was $13.2 million for the nine months ended September 30, 2024 compared to an income tax expense of $40.5 million for the nine months ended September 30, 2023, a decrease in income tax expense of $27.3 million. The decrease in income tax expense was primarily attributable to the decrease in income between periods. See “Item 1. Financial Statements—Note 6” for additional information.

Net Income Attributable to Non-Controlling Interest. Net income attributable to non-controlling interest was $93.5 million for the nine months ended September 30, 2024 compared to net income of $107.9 million for the nine months ended September 30, 2023, a decrease of $14.4 million. Net income attributable to non-controlling interest consisted of the following (in millions):


	Nine Months Ended September 30,
	2024		2023
NGP’s 49.9% share of the Delaware Basin JV	$	27.6	$	27.3
Marathon Petroleum Corporation’s 50% share of the Ascension JV	2.1		3.8
Series B Preferred Units	38.2		50.4
Series C Preferred Units	25.6		26.4
Net income attributable to non-controlling interest	$	93.5	$	107.9

Analysis of Operating Segments

See below for our discussion of segment results for the nine months ended September 30, 2024 compared to the nine months ended September 30, 2023.

•Permian Segment.

◦Revenues and cost of sales, exclusive of operating expenses and depreciation and amortization, increased $211.8 million and $127.1 million, respectively, resulting in an increase in adjusted gross margin in the Permian segment of $84.7 million, due to:

•A $77.5 million increase in adjusted gross margin associated with our Permian natural gas assets. Adjusted gross margin, excluding derivative activity, increased $75.0 million, which was primarily due to higher volumes from existing customers. Derivative activity associated with our Permian natural gas assets increased adjusted gross margin by $2.5 million, which included $7.8 million from increased realized losses and $10.3 million from decreased unrealized losses; and

•A $7.2 million increase in adjusted gross margin associated with our Permian crude assets. Adjusted gross margin, excluding derivative activity, decreased $0.2 million, which was primarily due to lower commodity prices. Derivative activity associated with our Permian crude assets increased adjusted gross margin by $7.4 million, which included $9.8 million from increased realized gains and $2.4 million from decreased unrealized gains.

◦Operating expenses in the Permian segment increased $50.2 million, which was due to a $30.2 million increase primarily from an increase in operating activity, in addition to a $20.0 million increase in construction fees and services primarily due to the relocation of the Tiger II processing plant.

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◦Depreciation and amortization in the Permian segment increased $12.5 million primarily due to additional assets being placed in service.

•Louisiana Segment.

◦Revenues and cost of sales, exclusive of operating expenses and depreciation and amortization, decreased $337.1 million and $328.8 million, respectively, resulting in a decrease in adjusted gross margin in the Louisiana segment of $8.3 million, due to:

•A $21.0 million decrease in adjusted gross margin associated with our Louisiana NGL transmission and fractionation assets. Adjusted gross margin, excluding derivative activity, decreased $14.3 million, which was primarily due to lower seasonal fees for delivery of normal butane. Derivative activity associated with our Louisiana NGL transmission and fractionation assets decreased adjusted gross margin by $6.7 million, which included $8.6 million from increased realized losses and $1.9 million from increased unrealized gains;

•A $44.1 million increase in adjusted gross margin associated with our Louisiana natural gas assets. Adjusted gross margin, excluding derivative activity, increased $45.0 million, which was primarily due to a $51.8 million increase primarily from higher volumes from existing customers, partially offset by a settlement payment resulting from a customer account dispute in the amount of $6.8 million received in the second quarter of 2023. Derivative activity associated with our Louisiana natural gas assets decreased adjusted gross margin by $0.9 million, which included $6.8 million from increased realized gains and $7.7 million from increased unrealized losses; and

•A $31.4 million decrease in adjusted gross margin associated with our ORV crude assets, which was due to the divestiture of our ORV assets in our Louisiana segment in November 2023.

◦Operating expenses in the Louisiana segment decreased $14.7 million primarily due to the divestiture of our ORV assets in November 2023.

◦Depreciation and amortization in the Louisiana segment decreased $13.7 million primarily due an $8.2 million decrease due to the divestiture of our ORV assets in November 2023 and a $7.8 million decrease resulting from assets reaching the end of their depreciable lives. These decreases were partially offset by a $2.4 million increase related to changes in estimated useful lives of certain assets.

•Oklahoma Segment.

◦Revenues and cost of sales, exclusive of operating expenses and depreciation and amortization, decreased $74.9 million and $58.2 million, respectively, resulting in a decrease in adjusted gross margin in the Oklahoma segment of $16.7 million, due to:

•A $13.3 million decrease in adjusted gross margin associated with our Oklahoma natural gas assets. Adjusted gross margin, excluding derivative activity, decreased $9.9 million, which was primarily due to a one-time rate reset to a lower fee on certain existing contracts. For additional information on the one-time rate reset, see “Other Recent Developments.” Derivative activity associated with our Oklahoma natural gas assets decreased adjusted gross margin by $3.4 million, which included $6.6 million from increased realized losses and $3.2 million from decreased unrealized losses; and

•A $3.4 million decrease in adjusted gross margin associated with our Oklahoma crude assets. Adjusted gross margin, excluding derivative activity, decreased $3.3 million, which was primarily due to lower volumes from existing customers. Derivative activity associated with our Oklahoma crude assets decreased adjusted gross margin by $0.1 million from decreased realized gains.

◦Operating expenses in the Oklahoma segment decreased $1.3 million primarily due to a decrease in operating activity.

◦Depreciation and amortization in the Oklahoma segment increased $30.1 million primarily due to a $29.0 million increase related to changes in estimated useful lives of certain assets and a $1.1 million increase due to additional assets being placed in service.

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•North Texas Segment.

◦Revenues decreased $30.9 million and cost of sales, exclusive of operating expenses and depreciation and amortization, increased $10.2 million, resulting in a decrease in adjusted gross margin in the North Texas segment of $41.1 million. Adjusted gross margin, excluding derivative activity, decreased $33.5 million, which was primarily due to a one-time rate reset to a lower fee on certain existing contracts. For additional information on the one-time rate reset, see “Other Recent Developments.” Derivative activity associated with our North Texas segment decreased adjusted gross margin by $7.6 million, which included $17.2 million from decreased realized gains and $9.6 million from decreased unrealized losses.

◦Operating expenses in the North Texas segment decreased $4.9 million primarily due to a decrease in operating activity.

◦Depreciation and amortization in the North Texas segment decreased $4.8 million primarily due to a $7.8 million decrease due to assets reaching the end of their depreciable lives, partially offset by a $2.9 million increase due to additional assets being placed in service.

•Corporate Segment.

◦Revenues and cost of sales, exclusive of operating expenses and depreciation and amortization, each decreased $5.3 million. The corporate segment includes offsetting eliminations related to intercompany revenues and cost of sales, exclusive of operating expenses and depreciation and amortization.

◦Depreciation and amortization in the Corporate segment increased $0.4 million due to additional assets being placed in service.

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, 2023 filed with the Commission on February 21, 2024.

Liquidity and Capital Resources

Cash Flows from Operating Activities. Net cash provided by operating activities was $716.0 million for the nine months ended September 30, 2024 compared to $862.0 million for the nine months ended September 30, 2023. Net cash provided by operating activities decreased $146.0 million primarily due to the following:

•Gross margin, excluding depreciation and amortization, non-cash commodity derivative activity, utility credits redeemed, and unit-based compensation, decreased $27.1 million. The decrease in gross margin is due to a $30.8 million increase in operating expenses, excluding utility credits redeemed or earned and unit-based compensation, and was partially offset by a $3.7 million increase in adjusted gross margin, excluding non-cash commodity derivative activity. For more information regarding the changes in gross margin for the nine months ended September 30, 2024 compared to the nine months ended September 30, 2023, see “Results of Operations.”

•General and administrative expenses, excluding unit-based compensation, increased $25.3 million.

•Changes in working capital decreased net cash provided by operating activities by $100.6 million 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 purchases.

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Cash Flows from Investing Activities. Net cash used in investing activities was $325.1 million for the nine months ended September 30, 2024 compared to $373.4 million for the nine months ended September 30, 2023. Our primary investing activities consisted of the following (in millions):


	Nine Months Ended September 30,
	2024		2023
Additions to property and equipment (1)	$	(293.9)	$	(320.9)
Contributions to unconsolidated affiliate investments (2)	(25.4)		(58.4)

____________________________

(1)The decrease in capital expenditures was due to the timing of our capital projects.

(2)Represents contributions to the Matterhorn JV and GCF.

Cash Flows from Financing Activities. Net cash used in financing activities was $409.2 million for the nine months ended September 30, 2024 compared to $463.1 million for the nine months ended September 30, 2023. Our primary financing activities consisted of the following (in millions):


	Nine Months Ended September 30,
	2024		2023
Net repayments on the AR Facility (1)	$	(40.0)	$	(208.0)
Net repayments on the Revolving Credit Facility (1)	—		(95.0)
Net borrowings on ENLC’s senior unsecured notes (1)	498.1		297.0
Net repayments of ENLK’s senior unsecured notes (1)	(187.0)		—
Distributions to members	(183.9)		(178.6)
Distributions to the holders of the Series B Preferred Units (2)	(43.0)		(47.8)
Distributions to the holders of the Series C Preferred Units (2)	(27.2)		(26.4)
Distributions to joint venture partners (3)	(52.2)		(58.0)
Repurchase of Series B Preferred Units (2)	(200.0)		—
Repurchase of Series C Preferred Units (2)	(5.0)		(3.9)

Contributions from non-controlling interests (4)	24.7		51.5
Common unit repurchases (5)	(166.5)		(162.4)
Conversion of unit-based awards for common units, net of units withheld for taxes	(17.9)		(19.3)

____________________________

(1)See “Item 1. Financial Statements—Note 5” for more information regarding our long-term debt.

(2)See “Item 1. Financial Statements—Note 7” for information on distributions to holders of the Series B Preferred Units and Series C Preferred Units and repurchases of the Series B Preferred Units and Series C Preferred Units.

(3)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.

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

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

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Capital Requirements

As of September 30, 2024, the following table summarizes our expected remaining capital requirements for 2024 (in millions):


Capital expenditures, net to ENLC (1)	$	138

____________________________

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

Our primary remaining capital projects for 2024 include the continued development of our existing systems through well connects and other low-cost development projects. We expect to fund our remaining 2024 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, to make contributions to unconsolidated affiliate investments, and to make acquisitions will depend upon our future operating performance, which will be affected by prevailing economic conditions in the industry, financial, business, and other factors, some of which are beyond our control.

Off-Balance Sheet Arrangements. We had no off-balance sheet arrangements as of September 30, 2024.

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Total Contractual Cash Obligations. A summary of our total contractual cash obligations as of September 30, 2024 is as follows (in millions):


	Payments Due by Period
	Total		Remainder 2024		2025		2026		2027		2028		Thereafter
ENLC’s & ENLK’s senior unsecured notes	$	4,612.9	$	—	$	421.6	$	491.0	$	—	$	500.0	$	3,200.3
AR Facility (1)	260.0		—		260.0		—		—		—		—
Revolving Credit Facility (1)	—		—		—		—		—		—		—
Interest payable on fixed long-term debt obligations (1)	2,332.3		34.4		246.3		236.3		212.5		198.5		1,404.3
Acquisition contingent consideration (2)	5.5		—		4.1		1.0		0.4		—		—
Repurchase of ENLC common units held by GIP (3)	20.4		20.4		—		—		—		—		—
Redemption of Series C Preferred Units (4)	364.5		364.5		—		—		—		—		—
Operating lease obligations	125.3		11.2		41.2		25.9		9.5		5.9		31.6
Purchase obligations	10.0		10.0		—		—		—		—		—
Pipeline and trucking capacity and deficiency agreements (5)	866.7		27.6		115.6		101.7		88.3		84.9		448.6
Total contractual cash obligations	$	8,597.6	$	468.1	$	1,088.8	$	855.9	$	310.7	$	789.3	$	5,084.8

____________________________

(1)The interest payable related to the Revolving Credit Facility and the AR Facility is not reflected in the 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. See “Item 1. Financial Statements—Note 5” for more information regarding the Revolving Credit Facility and the AR Facility.

(2)The estimated fair value of the contingent consideration for the Amarillo Rattler Acquisition and the Central Oklahoma Acquisition 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.

(3)Relates to the repurchase of ENLC common units held by GIP on October 2, 2024. See “Item 1. Financial Statements—Note 8” for more information.

(4)See “Item 1. Financial Statements—Note 7” for more information regarding the redemption of the Series C Preferred Units.

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

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.

Our contractual cash obligations for the next twelve months are expected to be funded from cash flows generated from our operations and the available capacity under the Revolving Credit Facility or other debt sources.

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Indebtedness

Revolving Credit Facility. As of September 30, 2024, there were no outstanding borrowings and $14.6 million in outstanding letters of credit under the Revolving Credit Facility.

AR Facility. As of September 30, 2024, the AR Facility had a borrowing base of $383.3 million and there were $260.0 million in outstanding borrowings under the AR Facility, which is scheduled to terminate on August 1, 2025 and is classified as “Current maturities of long-term debt” in the consolidated balance sheet. In connection with the AR Facility, certain subsidiaries of ENLC sold and contributed, and will continue to sell or contribute, their accounts receivable to the SPV to be held as collateral for borrowings under the AR Facility. The SPV’s assets are not available to satisfy the obligations of ENLC or any of its affiliates.

Senior Unsecured Notes. As of September 30, 2024, we had $4.6 billion in aggregate principal amount of outstanding senior unsecured notes maturing from 2025 to 2047, of which $421.6 million relates to the 2025 Notes that mature on June 1, 2025 and is classified as “Current maturities of long-term debt” in the consolidated balance sheet.

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 September 30, 2024, 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” for more information on our outstanding debt.

Inflation

See “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Recent Developments Affecting Industry Conditions and Our Business—Inflation” for more information.

Recent Accounting Pronouncements

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

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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 on Form 10-Q constitute forward-looking statements, including, but not limited to, statements identified by the words “forecast,” “may,” “believe,” “will,” “shall,” “should,” “plan,” “predict,” “anticipate,” “intend,” “estimate,” “expect,” “continue,” and similar expressions. Such forward-looking statements include, but are not limited to, statements about ONEOK’s pursuit of a Public Unit Transaction (as defined herein), future results and growth of our CCS business, potential financial arrangements with CCS counterparties, expected financial and operational results associated with certain projects, acquisitions, or growth capital expenditures, timing for completion of construction or expansion projects, results in certain basins, profitability, financial or leverage metrics, cost savings or operational, environmental and climate change initiatives, repurchases of common or preferred units. our future capital structure and credit ratings, objectives, strategies, expectations, and intentions, 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) potential conflicts of interest of ONEOK with us and the potential for ONEOK to favor ONEOK’s own interests to the detriment of our other unitholders, (b) ONEOK’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, (c) impacts from the announcement that ONEOK intends to acquire the publicly held interests of ENLC, (d) the dependence on key customers for a substantial portion of the natural gas and crude that we gather, process, and transport, (e) developments that materially and adversely affect our key customers or other customers, (f) adverse developments in the midstream business that may reduce our ability to make distributions, (g) competition for crude oil, condensate, natural gas, and NGL supplies and any decrease in the availability of such commodities, (h) decreases in the volumes that we gather, process, fractionate, or transport, (i) increasing scrutiny and changing expectations from stakeholders with respect to our environment, social, and governance practices, (j) our ability to receive or renew required permits and other approvals, (k) 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, (l) climate change legislation and regulatory initiatives resulting in increased operating costs and reduced demand for the natural gas and NGL services we provide, (m) changes in the availability and cost of capital, (n) volatile prices and market demand for crude oil, condensate, natural gas, and NGLs that are beyond our control, (o) debt levels that could limit our flexibility and adversely affect our financial health or limit our flexibility to obtain financing and to pursue other business opportunities, (p) operating hazards, natural disasters, weather-related issues or delays, casualty losses, and other matters beyond our control, (q) reductions in demand for NGL products by the petrochemical, refining, or other industries or by the fuel markets, (r) impairments to goodwill, long-lived assets and equity method investments, (s) construction risks in our major development projects, (t) challenges we may face in connection with our strategy to build a CCS transportation business and to enter into other new lines of business related to the energy transition, including entry into the CCS business, (u) our ability to effectively integrate and manage assets we acquire through acquisitions, (v) the effects of existing and future laws and governmental regulations, including environmental and climate change requirements and other uncertainties, and (w) whether ONEOK is able to consummate its publicly announced intention to pursue an acquisition of the remaining ENLC common units not held by it (a “Public Unit Transaction”). 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 “Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2023, filed with the Commission on February 21, 2024, 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 and equity.

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 nine months ended September 30, 2024 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 natural gas processing component of our business. For more information regarding our main types of contractual arrangements, see “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” of our Annual Report on Form 10-K for the year ended December 31, 2023 filed with the Commission on February 21, 2024.

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.

Commodity derivatives 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, crude, and condensate.

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The following table sets forth information related to derivative instruments outstanding at September 30, 2024.

Period

Underlying

Notional Volume
(Net Position)

Reference Price

Price Range

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

October 2024 - December 2025

Ethane

(6.7) MMgals

OPIS Mt Belvieu

$0.21 - $0.26/Gal

0.1

October 2024 - June 2025

Propane

(61.2) MMgals

OPIS Mt Belvieu

$0.68 - $0.85/Gal

(0.1)

October 2024 - June 2025

Normal Butane

(8.8) MMgals

OPIS Mt Belvieu

$0.77 - $1.00/Gal

(1.0)

October 2024 - February 2025

Natural Gasoline

(0.8) MMgals

NYMEX WTI Average

$1.55 - $1.79/Gal

0.1

October 2024 - December 2024

Natural Gasoline and Condensate

20.2 MMgals

OPIS Mt Belvieu and NYMEX WTI Average differential

($0.31) - ($0.29)/Gal

2.5

October 2024 - January 2029

Natural Gas

(7.4) Bbtu

NYMEX Henry Hub

$2.03 - $5.30/MMbtu

6.0

October 2024 - December 2025

Natural Gas

1.2 Bbtu

Waha basis differential

($1.49) - ($0.09)/MMbtu

(0.7)

October 2024 - October 2024

Natural Gas

(1.4) Bbtu

Henry Hub Natural Gas Daily

$2.58 - $2.61/MMbtu

—

October 2024 - October 2024

Natural Gas

(0.6) Bbtu

NGPL TEXOK Natural Gas Daily

$2.21 - $2.22/MMbtu

—

October 2024 - December 2024

Natural Gas

(2.8) Bbtu

NGPL TEXOK basis differential

($0.25) - ($0.25)/MMbtu

0.4

March 2025 - March 2025

Natural Gas

(0.2) Bbtu

IFHSC Basis Differential

($0.46) - ($0.46)/MMbtu

—

November 2024 - March 2025

Crude and Condensate

(0.2) MMbbls

NYMEX WTI

$67.70 - $80.66/Bbl

1.8

October 2024 - December 2024

Crude and Condensate

0.0 MMbbls

OPIS Mt Belvieu

$67.20 - $67.20/Bbl

(0.2)

October 2024 - December 2024

Crude and Condensate

0.0 MMbbls

NYMEX WTI Average

$80.20 - $80.20/Bbl

0.4

November 2024 - December 2025

Crude and Condensate

(4.2) MMbbls

WTI-Houston and Midland basis differential

$0.70 - $0.90/Bbl

0.2

Total fair value of commodity derivatives

9.5

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

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

As of September 30, 2024, our outstanding commodity derivative instruments had a net fair value asset of $9.5 million. The aggregate effect of a hypothetical 10% change, increase or decrease, in natural gas, crude and condensate, and NGL prices would result in a change of approximately $13.1 million in the net fair value of these contracts as of September 30, 2024.

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 September 30, 2024, we had no outstanding borrowings under the Revolving Credit Facility and $260.0 million in outstanding borrowings under the AR Facility.

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In January 2023, we entered into a $400.0 million interest rate swap to reduce the variability of cash outflows associated with our floating rate, SOFR-based borrowings, including borrowings on the Revolving Credit Facility and the AR Facility. This swap has been designated as a cash flow hedge. See “Item 1. Financial Statements—Note 9” for more information on our outstanding derivatives.

A 1.0% increase or decrease in interest rates would change our annualized interest expense by approximately $2.6 million for the AR Facility, based on our outstanding borrowings at September 30, 2024. This change in interest expense would be offset by a $4.0 million change in the opposite direction due to our open interest rate swap hedge.

We are not exposed to changes in interest rates with respect to ENLK’s senior unsecured notes due in 2025, 2026, 2044, 2045, or 2047 or our senior unsecured notes due in 2028, 2029, 2030, and 2034 as these are fixed-rate obligations. As of September 30, 2024, the estimated fair value of the senior unsecured notes was approximately $4,649.9 million, based on the market prices of ENLK’s and our publicly traded debt at September 30, 2024. 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 $254.5 million decrease in fair value of the senior unsecured notes at September 30, 2024. See “Item 1. Financial Statements—Note 5” for more information on our outstanding indebtedness.

Item 4. Controls and Procedures

a.Evaluation of Disclosure Controls and Procedures

Management of the Managing Member is responsible for establishing and maintaining adequate internal control over financial reporting and for the assessment of the effectiveness of internal control over financial reporting for us. We carried out an evaluation, under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer of the Managing Member, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report pursuant to Exchange Act Rules 13a-15 and 15d-15. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of the period covered by this report (September 30, 2024), our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed by us in the reports we file or submit under the Exchange Act is recorded, processed, summarized, and reported within the time period specified in the applicable rules and forms, and that such information is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding disclosure.

b.Changes in Internal Control Over Financial Reporting

There has been no change in our internal control over financial reporting that occurred in the three months ended September 30, 2024 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 13, “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

In addition to the information set forth in this report, you should carefully consider the factors discussed in Part I, “Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2023 filed with the Commission on February 21, 2024. The risks described in this report and our Annual Report on Form 10-K are not our only risks. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also could materially adversely affect our business, financial condition, or operating results.

We have added the following risk factors related to the GIP/ONEOK Transaction, which could have a material adverse effect on our business.

ONEOK owns 43.8% of ENLC’s outstanding common units as of October 15, 2024 and controls the Managing Member, which has sole responsibility for conducting our business and managing our operations. Our Managing Member and its affiliates, including ONEOK, have conflicts of interest with us and limited duties to us and may favor their own interests to your detriment.

ONEOK owns and controls the Managing Member and appoints all of the directors of the Managing Member. Some of the directors of the Managing Member, including directors with a majority of voting power, are also directors and/or officers of ONEOK. Although the Managing Member has a duty to manage us in a manner it subjectively believes to be in, or not opposed to, our best interests, the directors and officers of the Managing Member also have a duty to manage the Managing Member in a manner that is in the best interests of ONEOK, in its capacity as the sole member of the Managing Member. Conflicts of interest may arise between ONEOK and its affiliates, including the Managing Member, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, the Managing Member may favor its own interests and the interests of its affiliates over the interests of our unitholders. These conflicts include, among others, the following situations:

•neither our operating agreement nor any other agreement requires ONEOK to pursue a business strategy that favors us or to enter into any commercial or business arrangement with us. ONEOK’s directors and officers have a fiduciary duty to make decisions in the best interests of the stockholders of ONEOK, which may be contrary to our interests;

•ONEOK may be constrained by the terms of its debt instruments from taking actions, or refraining from taking actions, that may be in our best interests;

•the Managing Member determines the amount and timing of asset purchases and sales, borrowings, issuance of additional membership interests and reserves, each of which can affect the amount of cash that is available to be distributed to unitholders;

•the Managing Member determines which costs incurred by it are reimbursable by us;

•the Managing Member is allowed to take into account the interests of parties other than us in exercising certain rights under our operating agreement;

•our operating agreement limits the liability of, and eliminates and replaces the fiduciary duties that would otherwise be owed by, the Managing Member and also restricts the remedies available to our unitholders for actions that, without the provisions of the operating agreement, might constitute breaches of fiduciary duty;

•any future contracts between us, on the one hand, and ONEOK or its subsidiaries, on the other, may not be the result of arm’s-length negotiations;

•except in limited circumstances, the Managing Member has the power and authority to conduct our business without unitholder approval;

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•the Managing Member may exercise its right to call and purchase all of ENLC’s outstanding common units not owned by it and its affiliates if it and its affiliates own more than 90% of ENLC’s outstanding common units;

•the Managing Member controls the enforcement of obligations owed to us by the Managing Member and its affiliates, including commercial agreements; and

•the Managing Member decides whether to retain separate counsel, accountants, or others to perform services for us.

ONEOK is not limited in its ability to compete with us and is not obligated to offer us the opportunity to acquire additional assets or businesses, which could limit our ability to grow and could adversely affect our results of operations and cash available for distribution to our unitholders.

ONEOK is a midstream operator that provides gathering, processing, fractionation, transportation, and storage services, with significant resources and experience in the midstream industry. ONEOK is not prohibited from owning assets or interests in entities, or engaging in businesses, that compete directly or indirectly with us. In addition, ONEOK and its subsidiaries may acquire, construct, or dispose of additional midstream or other assets and may be presented with new business opportunities, without any obligation to offer us the opportunity to purchase or construct such assets or to engage in such business opportunities.

Pursuant to the terms of our operating agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to the Managing Member, or any of its affiliates, including ONEOK and its officers. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any unitholder for breach of any duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself.

ONEOK has stated that it intends to pursue an acquisition of the remaining ENLC common units not held by it (a “Public Unit Transaction”). There is no assurance that ONEOK’s pursuit of a Public Unit Transaction will result in a definitive agreement or, if a definitive agreement is executed, that a Public Unit Transaction will be consummated.

As disclosed in the Schedule 13D with respect to ENLC filed by ONEOK with the Commission on October 15, 2024 upon the consummation of the GIP/ONEOK Transaction, ONEOK intends to pursue the acquisition of the remaining publicly held ENLC common units in a tax-free transaction and expects to discuss the terms of such potential transaction with the conflicts committee of the Board. There is no assurance that ONEOK’s pursuit of a Public Unit Transaction will result in a definitive agreement with respect thereto or, if a definitive agreement is executed, that a Public Unit Transaction will be consummated.

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

During the three months ended September 30, 2024, we re-acquired ENLC common units from certain employees in order to satisfy the employees’ tax liability in connection with the vesting of unit-based awards 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)
July 1, 2024 to July 31, 2024	685,879	$	13.94	677,765	$	140.6
August 1, 2024 to August 31, 2024	1,263,518	12.65		1,229,015	$	125.1
September 1, 2024 to September 30, 2024 (3)	1,575,818	13.09		1,562,279	$	104.6
Total	3,525,215	$	13.10	3,469,059

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(1)The total number of units purchased shown in the table includes 56,156 ENLC common units received by us from employees for the payment of personal income tax withholding on vesting transactions.

(2)In December 2023, the Board reauthorized our common unit repurchase program for 2024 and set the amount available for repurchases of outstanding common units at up to $200.0 million. In July 2024, the Board authorized an increase in the 2024 common unit repurchase program by $50.0 million to $250.0 million. On September 16, 2024, we notified GIP of our decision to terminate the repurchase agreement. The termination became effective on October 2, 2024. 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.”

(3)Includes the ENLC common units repurchased from GIP pursuant to the GIP repurchase agreement, which settled on October 2, 2024. These units represented GIP’s pro rata share of the aggregate number of common units repurchased by us during the three months ended September 30, 2024. See “Item 1. Financial Statements—Note 4 and Note 8” for additional information on the GIP repurchase agreement.

Item 5. Other Information

Insider Trading Plans

During the three months ended September 30, 2024, no director or officer of the Company adopted a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement” as each term is defined in Item 408(a) of Regulation S-K.

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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		—	Third Amended and Restated Limited Liability Company Agreement of EnLink Midstream Manager, LLC, dated as of October 15, 2024 (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K dated October 15, 2024, filed with the Commission on October 15, 2024, 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		—	Eleventh Amended and Restated Agreement of Limited Partnership of EnLink Midstream Partners, LP, dated as of September 8, 2023 (incorporated by reference to Exhibit 3.14 to our Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2023, filed with the Commission on November 1, 2023, file No. 001-36336).






















4.1		—	Indenture, dated as of August 15, 2024, 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 EnLink Midstream, LLC’s Current Report on Form 8-K, dated August 15, 2024, filed with the Commission on August 15, 2024, file No. 001-36336).
4.2		—	F irst Supplemental Indenture, dated as of August 15, 2024, 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 4.2 to EnLink Midstream, LLC’s Current Report on Form 8-K dated August 15, 2024, filed with the Commission on August 15, 2024, file No. 001-36336).
10.1		—	First Amendment to Amended and Restated Credit Agreement, dated as of September 12, 2024, among EnLink Midstream, LLC, Bank of America, N.A., as Administrative Agent, and the lenders party thereto (incorporated by reference to Exhibit 10 .1 to our Current Report on Form 8-K dated September 12, 2024 , filed with the Commission on September 16, 2024 , file No. 001-36336).
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 September 30, 2024, formatted in iXBRL (Inline eXtensible Business Reporting Language): (i) Consolidated Balance Sheets as of September 30, 2024 and December 31, 2023, (ii) Consolidated Statements of Operations for the three and nine months ended September 30, 2024 and 2023, (iii) Consolidated Statements of Changes in Members’ Equity for the three and nine months ended September 30, 2024 and 2023, (iv) Consolidated Statements of Cash Flows for the nine months ended September 30, 2024 and 2023, and (v) the Notes to Consolidated Financial Statements.
104	*	—	Cover Page Interactive Data File (formatted as Inline iXBRL and included in Exhibit 101).

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* Filed herewith.

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SIGNATURE

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


	EnLink Midstream, LLC

	By:	EnLink Midstream Manager, LLC, its managing member

	By:	/s/ J. PHILIPP ROSSBACH
		J. Philipp Rossbach
		Vice President and Chief Accounting Officer
		(Principal Accounting Officer)
November 7, 2024