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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

Form 10-Q

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

For the quarterly period ended September 30, 20222023

OR

☐ 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)
Delaware46-4108528
(State of organization)(I.R.S. Employer Identification No.)
1722 Routh St., Suite 1300
Dallas,Texas75201
(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 ClassTrading SymbolName of Exchange on which Registered
Common Units Representing Limited Liability Company InterestsENLCThe 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 27, 2022,26, 2023, the Registrant had 473,596,120456,851,424 common units outstanding.

Table of Contents

TABLE OF CONTENTS
ItemItemDescriptionPageItemDescriptionPage
PART I—FINANCIAL INFORMATION
PART I—FINANCIAL INFORMATION
5
5
36
36
59
63
62
65
PART II—OTHER INFORMATION
PART II—OTHER INFORMATION
63
66
63
66
63
66
66
64
68

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DEFINITIONS
 
The following terms as defined are used in this document:
Defined TermDefinition
/dPer day.
2014 PlanENLC’s 2014 Long-Term Incentive Plan.
Adjusted gross marginRevenue less cost of sales, exclusive of operating expenses and depreciation and amortization. Adjusted gross margin is a non-GAAP financial measure. See “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures” for additional information.
Agua Blanca PipelineThe Agua Blanca Pipeline is a Delaware Basin intrastate natural gas pipeline servicing portions of Culberson, Loving, Pecos, Reeves, Ward, and Winkler counties and is owned by a joint venture between WhiteWater Midstream, LLC and MPLX LP.
Amarillo Rattler AcquisitionOn 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 FacilityAn accounts receivable securitization facility of up to $500 million entered into by EnLink Midstream Funding, LLC, a bankruptcy-remote special purpose entity and our indirect subsidiary, with PNC Bank, National Association, as administrative agent and lender, and PNC Capital Markets, LLC, as structuring agent and sustainability agent. The AR Facility is scheduled to terminate on August 1, 2025, unless extended or earlier terminated in accordance with its terms.
ASCThe Financial Accounting Standards Board Accounting Standards Codification.
ASC 718
ASC 718, Compensation—Stock Compensation.
ASC 815
ASC 815, Derivatives and Hedging.
ASC 820
ASC 820, Fair Value Measurements.
Ascension JVAscension Pipeline Company, LLC, a joint venture between a subsidiary of ENLK and a subsidiary of Marathon Petroleum Corporation in which ENLK owns a 50% interest and Marathon Petroleum Corporation owns a 50% interest. The Ascension JV, which began operations in April 2017, owns an NGL pipeline that connects ENLK’s Riverside fractionator to Marathon Petroleum Corporation’s Garyville refinery.
Barnett ShaleA natural gas producing shale reservoir located in North Texas.
Barnett Shale AcquisitionOn July 1, 2022, we acquired all of the equity interest in the gathering and processing assets of Crestwood Equity Partners LP located in the Barnett Shale.
BblBarrel.
BbtuBillion British thermal units.
BcfBillion cubic feet.
Beginning TSR PriceThe beginning total shareholder return (“TSR”) price, which is the closing unit price of ENLC on the grant date of the performance award agreement or the previous trading day if the grant date was not a trading day, is one of the assumptions used to calculate the grant-date fair value of performance award agreements.
BKVBKV Corporation.
CCSCarbon capture, transportation, and sequestration.
Cedar Cove JVCedar Cove Midstream LLC, a joint venture between a subsidiary of ENLK and a subsidiary of Kinder Morgan, Inc. in which ENLK owns a 30% interest and Kinder Morgan, Inc. owns a 70% interest. The Cedar Cove JV, which was formed in November 2016, owns gathering and compression assets in Blaine County, Oklahoma, located in the STACK play.
Central Oklahoma AcquisitionOn December 19, 2022, we acquired gathering and processing assets located in Central Oklahoma, including approximately 900 miles of lean and rich gas gathering pipeline and two processing plants with 280 MMcf/d of total processing capacity.
CFTCU.S. Commodity Futures Trading Commission.
CNOWCentral Northern Oklahoma Woodford Shale.
CO2
Carbon dioxide.
CommissionU.S. Securities and Exchange Commission.
Delaware BasinA large sedimentary basin in West Texas and New Mexico.
Delaware Basin JVDelaware G&P LLC, a joint venture between a subsidiary of ENLK and an affiliate of NGP in which ENLK owns a 50.1% interest and NGP owns a 49.9% interest. The Delaware Basin JV, which was formed in August 2016, owns the Lobo processing facilities and the Tiger processing plant located in the Delaware Basin in Texas.
ENLCEnLink Midstream, LLC.LLC together with its consolidated subsidiaries.
ENLC Class C Common UnitsA class of non-economic ENLC common units issued immediately prior to the Merger equal to the number of Series B Preferred Units held immediately prior to the effective time of the Merger, in order to provide certain voting rights with respect to ENLC to the holders of thesuch Series B Preferred Units with respect to ENLC.Units.
ENLKEnLink Midstream Partners, LP or, when applicable, EnLink Midstream Partners, LP together with its consolidated subsidiaries. Also referred to as the “Partnership.”
Exchange ActThe Securities Exchange Act of 1934, as amended.
ExxonMobilFCDTCsExxonMobil Corporation.Futures and Cleared Derivatives Transactions Customer Agreements.
Federal ReserveThe Board of Governors of the Federal Reserve System of the United States.
GAAPGenerally accepted accounting principles in the United States of America.
GalGallon.
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GalGallon.
GCFGulf Coast Fractionators, which owns an NGL fractionator in Mont Belvieu, Texas. ENLK ownsWe own 38.75% of GCF. The GCF assets have beenwere temporarily idled to reduce operating expenses.expenses in 2021 but are expected to resume operations in 2024.
General PartnerEnLink Midstream GP, LLC, the general partner of ENLK.
GIPGlobal 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.
ISDAsInternational Swaps and Derivatives Association Agreements.
LIBORU.S. Dollar London Interbank Offered Rate.
Managing MemberEnLink Midstream Manager, LLC, the managing member of ENLC.
MergerMatterhorn JVOn January 25, 2019, NOLA Merger Sub,A joint venture with WhiteWater Midstream, LLC, (previouslyDevon Energy Corporation, and MPLX LP. The Matterhorn JV is expected to construct a wholly-owned subsidiarypipeline designed to transport up to 2.5 Bcf/d of ENLC) merged with and into ENLK with ENLK continuing asnatural gas through approximately 490 miles of 42-inch pipeline from the surviving entity and a subsidiary of ENLC.Waha Hub in West Texas to Katy, Texas.
Midland BasinA large sedimentary basin in West Texas.
MbblsThousand barrels.
MMbblsMillion barrels.
MMbtuMillion British thermal units.
MMcfMillion cubic feet.
MMgalsMillion gallons.
MVCMinimum volume commitment.
NGLNatural gas liquid.
NGPNGP Natural Resources XI, LP.
NYMEXNew York Mercantile Exchange.
Operating PartnershipEnLink Midstream Operating, LP, a Delaware limited partnership and wholly owned subsidiary of ENLK.
OPISOil Price Information Service.
ORVENLK’s Ohio River Valley crude oil, condensate stabilization, natural gas compression, and brine disposal assets in the Utica and Marcellus shales.
OTCOver-the-counter.
Permian BasinA large sedimentary basin that includes the Midland and Delaware Basins primarily in West Texas and New Mexico.
POL contractsPercentage-of-liquids contracts.
POP contractsPercentage-of-proceeds contracts.
Revolving Credit FacilityA $1.40 billion unsecured revolving credit facility entered into by ENLC, that matures on June 3, 2027, which includes a $500.0 million letter of credit subfacility. The Revolving Credit Facility is guaranteed by ENLK.
Series B Preferred UnitENLK’s Series B Cumulative Convertible Preferred Unit.
Series C Preferred UnitENLK’s Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Unit.
SOFRSecured overnight financing rate.
SPVEnLink Midstream Funding, LLC, a bankruptcy-remote special purpose entity that is an indirect subsidiary of ENLC.
STACKSooner Trend Anadarko Basin Canadian and Kingfisher Counties in Oklahoma.
Term LoanA term loan originally in the amount of $850.0 million entered into by ENLK on December 11, 2018 with Bank of America, N.A., as Administrative Agent, Bank of Montreal and Royal Bank of Canada, as Co-Syndication Agents, Citibank, N.A. and Wells Fargo Bank, National Association, as Co-Documentation Agents, and the lenders party thereto, which ENLC assumed in connection with the Merger and the obligations of which ENLK guaranteed. The Term Loan was paid upon maturity on December 10, 2021.

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PART I—FINANCIAL INFORMATION
Item 1. Financial Statements
ENLINK MIDSTREAM, LLC AND SUBSIDIARIES
Consolidated Balance Sheets
(In millions, except unit data)
September 30, 2022December 31, 2021September 30, 2023December 31, 2022
(Unaudited)(Unaudited)
ASSETSASSETSASSETS
Current assets:Current assets:Current assets:
Cash and cash equivalentsCash and cash equivalents$— $26.2 Cash and cash equivalents$48.1 $22.6 
Accounts receivable:Accounts receivable:Accounts receivable:
Trade, net of allowance for bad debt of $0.1 and $0.3, respectively137.0 94.9 
Trade receivables (1)Trade receivables (1)108.6 89.2 
Accrued revenue and otherAccrued revenue and other810.6 693.3 Accrued revenue and other583.5 636.0 
Fair value of derivative assetsFair value of derivative assets76.2 22.4 Fair value of derivative assets68.0 68.4 
Other current assetsOther current assets175.0 83.6 Other current assets114.2 166.6 
Total current assetsTotal current assets1,198.8 920.4 Total current assets922.4 982.8 
Property and equipment, net of accumulated depreciation of $4,694.2 and $4,332.0, respectively6,497.7 6,388.3 
Intangible assets, net of accumulated amortization of $891.7 and $795.1, respectively953.1 1,049.7 
Property and equipment, net of accumulated depreciation of $5,154.8 and $4,774.5, respectivelyProperty and equipment, net of accumulated depreciation of $5,154.8 and $4,774.5, respectively6,486.6 6,556.0 
Intangible assets, net of accumulated amortization of $1,019.3 and $923.6, respectivelyIntangible assets, net of accumulated amortization of $1,019.3 and $923.6, respectively825.5 921.2 
Investment in unconsolidated affiliatesInvestment in unconsolidated affiliates71.6 28.0 Investment in unconsolidated affiliates144.6 90.2 
Fair value of derivative assetsFair value of derivative assets0.7 0.2 Fair value of derivative assets13.8 2.9 
Other assets, netOther assets, net91.4 96.6 Other assets, net97.6 97.9 
Total assetsTotal assets$8,813.3 $8,483.2 Total assets$8,490.5 $8,651.0 
LIABILITIES AND MEMBERS’ EQUITYLIABILITIES AND MEMBERS’ EQUITYLIABILITIES AND MEMBERS’ EQUITY
Current liabilities:Current liabilities:Current liabilities:
Accounts payable and drafts payableAccounts payable and drafts payable$208.7 $139.6 Accounts payable and drafts payable$121.9 $126.9 
Accrued gas, NGLs, condensate, and crude oil purchases (1)Accrued gas, NGLs, condensate, and crude oil purchases (1)678.1 521.5 Accrued gas, NGLs, condensate, and crude oil purchases (1)436.8 476.0 
Fair value of derivative liabilitiesFair value of derivative liabilities52.2 34.9 Fair value of derivative liabilities54.8 42.9 
Current maturities of long-term debtCurrent maturities of long-term debt97.9 — 
Other current liabilitiesOther current liabilities218.3 202.9 Other current liabilities256.5 229.6 
Total current liabilitiesTotal current liabilities1,157.3 898.9 Total current liabilities967.9 875.4 
Long-term debt, net of unamortized issuance costLong-term debt, net of unamortized issuance cost4,537.4 4,363.7 Long-term debt, net of unamortized issuance cost4,621.4 4,723.5 
Other long-term liabilitiesOther long-term liabilities90.2 93.9 Other long-term liabilities90.3 94.0 
Deferred tax liability, netDeferred tax liability, net153.6 137.5 Deferred tax liability, net82.8 42.7 
Fair value of derivative liabilitiesFair value of derivative liabilities0.8 2.2 Fair value of derivative liabilities12.2 2.7 
Members’ equity:Members’ equity:Members’ equity:
Members’ equity (474,566,135 and 484,277,258 units issued and outstanding, respectively)1,259.2 1,325.8 
Accumulated other comprehensive loss(1.3)(1.4)
Members’ equity (457,334,550 and 468,980,630 units issued and outstanding, respectively)Members’ equity (457,334,550 and 468,980,630 units issued and outstanding, respectively)1,080.1 1,306.4 
Accumulated other comprehensive incomeAccumulated other comprehensive income6.2 — 
Non-controlling interestNon-controlling interest1,616.1 1,662.6 Non-controlling interest1,629.6 1,606.3 
Total members’ equityTotal members’ equity2,874.0 2,987.0 Total members’ equity2,715.9 2,912.7 
Commitments and contingencies (Note 16)Commitments and contingencies (Note 16)Commitments and contingencies (Note 16)
Total liabilities and members’ equityTotal liabilities and members’ equity$8,813.3 $8,483.2 Total liabilities and members’ equity$8,490.5 $8,651.0 
____________________________
(1)Includes related party accounts payable balances of $4.3 million and $1.6 millionThere was no allowance for bad debt at September 30, 2022 and2023. Includes allowance for bad debt of $0.1 million at December 31, 2021, respectively.2022.



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,
2022202120222021
(Unaudited)
Revenues:
Product sales$2,384.4 $1,610.2 $6,798.8 $3,968.7 
Midstream services258.6 211.0 699.2 629.2 
Gain (loss) on derivative activity20.5 (33.6)(6.2)(155.2)
Total revenues2,663.5 1,787.6 7,491.8 4,442.7 
Operating costs and expenses:
Cost of sales, exclusive of operating expenses and depreciation and amortization (1)2,131.1 1,400.8 6,030.7 3,390.6 
Operating expenses136.8 106.9 386.6 260.0 
Depreciation and amortization162.6 153.0 474.5 455.9 
(Gain) loss on disposition of assets(0.8)(0.4)3.9 (0.7)
General and administrative34.5 28.2 91.9 80.3 
Total operating costs and expenses2,464.2 1,688.5 6,987.6 4,186.1 
Operating income199.3 99.1 504.2 256.6 
Other income (expense):
Interest expense, net of interest income(60.4)(60.1)(171.0)(180.1)
Loss on extinguishment of debt(5.7)— (6.2)— 
Loss from unconsolidated affiliate investments(1.7)(2.3)(4.0)(9.9)
Other income0.3 — 0.6 0.1 
Total other expense(67.5)(62.4)(180.6)(189.9)
Income before non-controlling interest and income taxes131.8 36.7 323.6 66.7 
Income tax expense(15.2)(4.4)(17.1)(12.4)
Net income116.6 32.3 306.5 54.3 
Net income attributable to non-controlling interest35.8 30.4 105.2 86.7 
Net income (loss) attributable to ENLC$80.8 $1.9 $201.3 $(32.4)
Net income (loss) attributable to ENLC per unit:
Basic common unit$0.17 $— $0.42 $(0.07)
Diluted common unit$0.17 $— $0.41 $(0.07)
____________________________
Three Months Ended
September 30,		Nine Months Ended
September 30,
2023202220232022
(Unaudited)
Revenues:
Product sales$1,488.1 $2,384.4 $4,203.7 $6,798.8 
Midstream services280.1 258.6 838.9 699.2 
Gain (loss) on derivative activity(22.0)20.5 1.2 (6.2)
Total revenues1,746.2 2,663.5 5,043.8 7,491.8 
Operating costs and expenses:
Cost of sales, exclusive of operating expenses and depreciation and amortization1,244.7 2,131.1 3,535.6 6,030.7 
Operating expenses143.3 136.8 412.5 386.6 
Depreciation and amortization163.8 162.6 489.5 474.5 
Impairments20.7 — 20.7 — 
(Gain) loss on disposition of assets(0.6)(0.8)(1.8)3.9 
General and administrative30.4 34.5 87.8 91.9 
Total operating costs and expenses1,602.3 2,464.2 4,544.3 6,987.6 
Operating income143.9 199.3 499.5 504.2 
Other income (expense):
Interest expense, net of interest income(67.9)(60.4)(205.2)(171.0)
Loss on extinguishment of debt— (5.7)— (6.2)
Income (loss) from unconsolidated affiliate investments1.0 (1.7)(3.7)(4.0)
Other income (expense)(0.6)0.3 (0.2)0.6 
Total other expense(67.5)(67.5)(209.1)(180.6)
Income before non-controlling interest and income taxes76.4 131.8 290.4 323.6 
Income tax expense(10.6)(15.2)(40.5)(17.1)
Net income65.8 116.6 249.9 306.5 
Net income attributable to non-controlling interest36.3 35.8 107.9 105.2 
Net income attributable to ENLC$29.5 $80.8 $142.0 $201.3 
Net income attributable to ENLC per unit:
Basic common unit$0.06 $0.17 $0.31 $0.42 
Diluted common unit$0.06 $0.17 $0.30 $0.41 
(1)Includes related party cost of sales of $5.6 million and $4.9 million for the three months ended September 30, 2022 and 2021, respectively, and $25.3 million and $11.7 million for the nine months endedSeptember 30, 2022and 2021, respectively.















See accompanying notes to consolidated financial statements.
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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES
Consolidated Statements of Comprehensive Income
(In millions)
Three Months Ended
September 30,		Nine Months Ended
September 30,		Three Months Ended
September 30,		Nine Months Ended
September 30,
20222021202220212023202220232022
(Unaudited)(Unaudited)
Net incomeNet income$116.6 $32.3 $306.5 $54.3 Net income$65.8 $116.6 $249.9 $306.5 
Unrealized gain on designated cash flow hedge (1)Unrealized gain on designated cash flow hedge (1)— 3.8 0.1 11.1 Unrealized gain on designated cash flow hedge (1)1.7 — 6.2 0.1 
Comprehensive incomeComprehensive income116.6 36.1 306.6 65.4 Comprehensive income67.5 116.6 256.1 306.6 
Comprehensive income attributable to non-controlling interestComprehensive income attributable to non-controlling interest35.8 30.4 105.2 86.7 Comprehensive income attributable to non-controlling interest36.3 35.8 107.9 105.2 
Comprehensive income (loss) attributable to ENLC$80.8 $5.7 $201.4 $(21.3)
Comprehensive income attributable to ENLCComprehensive income attributable to ENLC$31.2 $80.8 $148.2 $201.4 
____________________________
(1)Includes tax expense of $1.2$0.5 million and $3.4$1.9 million for the three and nine months ended September 30, 2021,2023, 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 UnitsAccumulated Other Comprehensive LossNon-Controlling InterestTotalCommon UnitsAccumulated Other Comprehensive Income (Loss)Non-Controlling InterestTotal
$Units$$$$Units$$$
(Unaudited)(Unaudited)
Balance, December 31, 2021$1,325.8 484.3 $(1.4)$1,662.6 $2,987.0 
Balance, December 31, 2022Balance, 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 taxesConversion of unit-based awards for common units, net of units withheld for taxes(4.2)1.2 — — (4.2)Conversion of unit-based awards for common units, net of units withheld for taxes(16.8)2.5 — — (16.8)
Unit-based compensationUnit-based compensation8.1 — — — 8.1 Unit-based compensation4.0 — — — 4.0 
Contributions from non-controlling interestsContributions from non-controlling interests— — — 7.3 7.3 Contributions from non-controlling interests— — — 8.4 8.4 
DistributionsDistributions(56.4)— — (34.6)(91.0)Distributions(61.7)— — (42.4)(104.1)
Unrealized gain on designated cash flow hedge— — 0.1 — 0.1 
Redemption of Series B Preferred Units— — — (50.5)(50.5)
Unrealized loss on designated cash flow hedge (1)Unrealized loss on designated cash flow hedge (1)— — (1.2)— (1.2)
Repurchase of Series C Preferred UnitsRepurchase of Series C Preferred Units— — — (3.9)(3.9)
Common units repurchasedCommon units repurchased(17.0)(2.1)— — (17.0)Common units repurchased(51.4)(4.4)— — (51.4)
Net incomeNet income35.2 — — 30.8 66.0 Net income58.2 — — 36.0 94.2 
Balance, March 31, 20221,291.5 483.4 (1.3)1,615.6 2,905.8 
Balance, March 31, 2023Balance, March 31, 20231,238.7 467.1 (1.2)1,604.4 2,841.9 
Conversion of unit-based awards for common units, net of units withheld for taxesConversion of unit-based awards for common units, net of units withheld for taxes(0.2)— — — (0.2)Conversion of unit-based awards for common units, net of units withheld for taxes(0.1)0.1 — — (0.1)
Unit-based compensationUnit-based compensation5.7 — — — 5.7 Unit-based compensation4.5 — — — 4.5 
Contributions from non-controlling interestsContributions from non-controlling interests— — — 2.0 2.0 Contributions from non-controlling interests— — — 13.7 13.7 
DistributionsDistributions(55.3)— — (42.2)(97.5)Distributions(58.5)— — (40.1)(98.6)
Unrealized gain on designated cash flow hedge (1)Unrealized gain on designated cash flow hedge (1)— — 5.7 — 5.7 
Adjustment related to the redemption of the mandatorily redeemable non-controlling interest (2)Adjustment related to the redemption of the mandatorily redeemable non-controlling interest (2)0.8 — — — 0.8 
Common units repurchasedCommon units repurchased(33.7)(3.6)— — (33.7)Common units repurchased(56.1)(5.2)— — (56.1)
Accrued common unit repurchase (3)Accrued common unit repurchase (3)(27.5)— — — (27.5)
Net incomeNet income85.3 — — 38.6 123.9 Net income54.3 — — 35.6 89.9 
Balance, June 30, 20221,293.3 479.8 (1.3)1,614.0 2,906.0 
Balance, June 30, 2023Balance, June 30, 20231,156.1 462.0 4.5 1,613.6 2,774.2 
Conversion of unit-based awards for common units, net of units withheld for taxesConversion of unit-based awards for common units, net of units withheld for taxes(8.1)1.4 — — (8.1)Conversion of unit-based awards for common units, net of units withheld for taxes(2.4)0.3 — — (2.4)
Unit-based compensationUnit-based compensation11.4 — — — 11.4 Unit-based compensation5.7 — — — 5.7 
Contributions from non-controlling interestsContributions from non-controlling interests— — — 4.9 4.9 Contributions from non-controlling interests— — — 29.4 29.4 
DistributionsDistributions(55.7)— — (38.6)(94.3)Distributions(58.4)— — (49.7)(108.1)
Unrealized gain on designated cash flow hedge (1)Unrealized gain on designated cash flow hedge (1)— — 1.7 — 1.7 
Common units repurchasedCommon units repurchased(62.5)(6.6)— — (62.5)Common units repurchased(54.9)(5.0)— — (54.9)
Accrued common unit repurchase (3)Accrued common unit repurchase (3)4.5 — — — 4.5 
Net incomeNet income80.8 — — 35.8 116.6 Net income29.5 — — 36.3 65.8 
Balance, September 30, 2022$1,259.2 474.6 $(1.3)$1,616.1 $2,874.0 
Balance, September 30, 2023Balance, September 30, 2023$1,080.1 457.3 $6.2 $1,629.6 $2,715.9 
____________________________

(1)Includes tax benefit of $0.4 million for the three months ended March 31, 2023, tax expense of $1.8 million for the three months ended June 30, 2023, and tax expense of $0.5 million for the three 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 are contractually subject to repurchase by ENLC at the end of each quarter and settled in the subsequent quarter. As of September 30, 2023, we accrued $23.0 million in connection with the repurchase of ENLC common units held by GIP. For additional information, see “Note 9—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 UnitsAccumulated Other Comprehensive LossNon-Controlling InterestTotalRedeemable Non-Controlling Interest (Temporary Equity)
$Units$$$$
(Unaudited)
Balance, December 31, 2020$1,508.8 489.4 $(15.3)$1,719.5 $3,213.0 $— 
Conversion of unit-based awards for common units, net of units withheld for taxes(1.2)0.7 — — (1.2)— 
Unit-based compensation6.5 — — — 6.5 — 
Contributions from non-controlling interests— — — 0.9 0.9 — 
Distributions(47.1)— — (25.8)(72.9)(0.2)
Unrealized gain on designated cash flow hedge (1)— — 3.6 — 3.6 — 
Fair value adjustment related to redeemable non-controlling interest(0.1)— — — (0.1)0.2 
Net income (loss)(12.7)— — 25.3 12.6 — 
Balance, March 31, 20211,454.2 490.1 (11.7)1,719.9 3,162.4 — 
Conversion of unit-based awards for common units, net of units withheld for taxes(0.2)0.1 — — (0.2)— 
Unit-based compensation6.4 — — — 6.4 — 
Contributions from non-controlling interests— — — 1.0 1.0 — 
Distributions(46.7)— — (36.0)(82.7)— 
Unrealized gain on designated cash flow hedge (2)— — 3.7 — 3.7 — 
Common units repurchased(2.0)(0.3)— — (2.0)— 
Net income (loss)(21.6)— — 31.0 9.4 — 
Balance, June 30, 20211,390.1 489.9 (8.0)1,715.9 3,098.0 — 
Conversion of unit-based awards for common units, net of units withheld for taxes(0.5)0.2 — — (0.5)— 
Unit-based compensation6.4 — — — 6.4 — 
Contributions from non-controlling interests— — — 0.5 0.5 — 
Distributions(46.6)— — (26.2)(72.8)— 
Unrealized gain on designated cash flow hedge (3)— — 3.8 — 3.8 — 
Common units repurchased(12.5)(2.1)— — (12.5)— 
Net income1.9 — — 30.4 32.3 — 
Balance, September 30, 2021$1,338.8 488.0 $(4.2)$1,720.6 $3,055.2 $— 
____________________________
Common UnitsAccumulated Other Comprehensive Income (Loss)Non-Controlling InterestTotal
$Units$$$
(Unaudited)
Balance, December 31, 2021$1,325.8 484.3 $(1.4)$1,662.6 $2,987.0 
Conversion of unit-based awards for common units, net of units withheld for taxes(4.2)1.2 — — (4.2)
Unit-based compensation8.1 — — — 8.1 
Contributions from non-controlling interests— — — 7.3 7.3 
Distributions(56.4)— — (34.6)(91.0)
Unrealized gain on designated cash flow hedge— — 0.1 — 0.1 
Redemption of Series B Preferred Units— — — (50.5)(50.5)
Common units repurchased(17.0)(2.1)— — (17.0)
Net income35.2 — — 30.8 66.0 
Balance, March 31, 20221,291.5 483.4 (1.3)1,615.6 2,905.8 
Conversion of unit-based awards for common units, net of units withheld for taxes(0.2)— — — (0.2)
Unit-based compensation5.7 — — — 5.7 
Contributions from non-controlling interests— — — 2.0 2.0 
Distributions(55.3)— — (42.2)(97.5)
Common units repurchased(33.7)(3.6)— — (33.7)
Net income85.3 — — 38.6 123.9 
Balance, June 30, 20221,293.3 479.8 (1.3)1,614.0 2,906.0 
Conversion of unit-based awards for common units, net of units withheld for taxes(8.1)1.4 — — (8.1)
Unit-based compensation11.4 — — — 11.4 
Contributions from non-controlling interests— — — 4.9 4.9 
Distributions(55.7)— — (38.6)(94.3)
Common units repurchased(62.5)(6.6)— — (62.5)
Net income80.8 — — 35.8 116.6 
Balance, September 30, 2022$1,259.2 474.6 $(1.3)$1,616.1 $2,874.0 
(1)Includes tax expense of $1.1 million.
(2)Includes tax expense of $1.1 million.
(3)
Includes tax expense of $1.2 million.













See accompanying notes to consolidated financial statements.
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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES
Consolidated Statements of Cash Flows
(In millions)
Nine Months Ended
September 30,		Nine Months Ended
September 30,
2022202120232022
(Unaudited)(Unaudited)
Cash flows from operating activities:Cash flows from operating activities:Cash flows from operating activities:
Net incomeNet income$306.5 $54.3 Net income$249.9 $306.5 
Adjustments to reconcile net income to net cash provided by operating activities:Adjustments to reconcile net income to net cash provided by operating activities:Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortizationDepreciation and amortization489.5 474.5 
Utility credits redeemedUtility credits redeemed1.5 27.9 
Deferred income tax expenseDeferred income tax expense39.0 16.1 
(Gain) loss on disposition of assets(Gain) loss on disposition of assets(1.8)3.9 
Non-cash unit-based compensationNon-cash unit-based compensation14.2 23.7 
Depreciation and amortization474.5 455.9 
Utility credits redeemed (earned)27.9 (38.2)
Deferred income tax expense16.1 12.2 
(Gain) Loss on disposition of assets3.9 (0.7)
Non-cash unit-based compensation23.7 19.3 
Amortization of designated cash flow hedge0.1 9.6 
Non-cash (gain) loss on derivatives recognized in net incomeNon-cash (gain) loss on derivatives recognized in net income(36.5)37.5 Non-cash (gain) loss on derivatives recognized in net income19.0 (36.5)
Loss on extinguishment of debt6.2 — 
Amortization of debt issuance costs and net discount of senior unsecured notesAmortization of debt issuance costs and net discount of senior unsecured notes3.7 3.9 Amortization of debt issuance costs and net discount of senior unsecured notes4.9 3.7 
Loss from unconsolidated affiliate investmentsLoss from unconsolidated affiliate investments4.0 9.9 Loss from unconsolidated affiliate investments3.7 4.0 
ImpairmentsImpairments20.7 — 
Other operating activitiesOther operating activities(4.7)(4.2)Other operating activities1.3 1.6 
Changes in assets and liabilities:Changes in assets and liabilities:Changes in assets and liabilities:
Accounts receivable, accrued revenue, and otherAccounts receivable, accrued revenue, and other(142.7)(196.5)Accounts receivable, accrued revenue, and other33.3 (142.7)
Natural gas and NGLs inventory, prepaid expenses, and other(112.9)(80.3)
Natural gas, NGLs, condensate, and crude oil inventory, prepaid expenses, and otherNatural gas, NGLs, condensate, and crude oil inventory, prepaid expenses, and other59.5 (112.9)
Accounts payable, accrued product purchases, and other accrued liabilitiesAccounts payable, accrued product purchases, and other accrued liabilities256.1 316.5 Accounts payable, accrued product purchases, and other accrued liabilities(72.7)256.1 
Net cash provided by operating activitiesNet cash provided by operating activities825.9 599.2 Net cash provided by operating activities862.0 825.9 
Cash flows from investing activities:Cash flows from investing activities:Cash flows from investing activities:
Additions to property and equipmentAdditions to property and equipment(213.2)(104.7)Additions to property and equipment(320.9)(213.2)
Contributions to unconsolidated affiliate investmentsContributions to unconsolidated affiliate investments(46.3)— Contributions to unconsolidated affiliate investments(58.4)(46.3)
Acquisitions, net of cash acquired(289.5)(56.7)
Acquisition, net of cash acquiredAcquisition, net of cash acquired— (289.5)
Other investing activitiesOther investing activities2.0 6.0 Other investing activities5.9 2.0 
Net cash used in investing activitiesNet cash used in investing activities(547.0)(155.4)Net cash used in investing activities(373.4)(547.0)
Cash flows from financing activities:Cash flows from financing activities:Cash flows from financing activities:
Proceeds from borrowingsProceeds from borrowings3,431.5 829.5 Proceeds from borrowings2,538.4 3,431.5 
Repayments on borrowingsRepayments on borrowings(3,265.0)(1,034.5)Repayments on borrowings(2,544.4)(3,265.0)
Debt financing costs(13.4)(0.1)
Payment of installment payable for the Amarillo Rattler AcquisitionPayment of installment payable for the Amarillo Rattler Acquisition(10.0)— Payment of installment payable for the Amarillo Rattler Acquisition— (10.0)
Payment of inactive easement commitmentPayment of inactive easement commitment(10.0)— Payment of inactive easement commitment— (10.0)
Distributions to membersDistributions to members(167.4)(140.4)Distributions to members(178.6)(167.4)
Distributions to non-controlling interestsDistributions to non-controlling interests(115.4)(88.2)Distributions to non-controlling interests(132.2)(115.4)
Payment to redeem mandatorily redeemable non-controlling interestPayment to redeem mandatorily redeemable non-controlling interest(10.5)— 
Redemption of Series B Preferred UnitsRedemption of Series B Preferred Units(50.5)— Redemption of Series B Preferred Units— (50.5)
Repurchase of Series C Preferred UnitsRepurchase of Series C Preferred Units(3.9)— 
Contributions from non-controlling interestsContributions from non-controlling interests14.2 2.4 Contributions from non-controlling interests51.5 14.2 
Common unit repurchasesCommon unit repurchases(113.2)(14.5)Common unit repurchases(162.4)(113.2)
Conversion of unit-based awards for common units, net of units withheld for taxesConversion of unit-based awards for common units, net of units withheld for taxes(12.5)(1.9)Conversion of unit-based awards for common units, net of units withheld for taxes(19.3)(12.5)
Other financing activitiesOther financing activities6.6 0.4 Other financing activities(1.7)(6.8)
Net cash used in financing activitiesNet cash used in financing activities(305.1)(447.3)Net cash used in financing activities(463.1)(305.1)
Net decrease in cash and cash equivalents(26.2)(3.5)
Net increase (decrease) in cash and cash equivalentsNet increase (decrease) in cash and cash equivalents25.5 (26.2)
Cash and cash equivalents, beginning of periodCash and cash equivalents, beginning of period26.2 39.6 Cash and cash equivalents, beginning of period22.6 26.2 
Cash and cash equivalents, end of periodCash and cash equivalents, end of period$— $36.1 Cash and cash equivalents, end of period$48.1 $— 
Supplemental disclosures of cash flow information:Supplemental disclosures of cash flow information:Supplemental disclosures of cash flow information:
Cash paid for interestCash paid for interest$152.4 $130.1 Cash paid for interest$222.8 $152.4 
Cash paid for income taxesCash paid for income taxes$0.7 $0.2 Cash paid for income taxes$1.5 $0.7 
Non-cash investing activities:Non-cash investing activities:Non-cash investing activities:
Right-of-use assets obtained in exchange for operating lease liabilitiesRight-of-use assets obtained in exchange for operating lease liabilities$13.3 $22.0 
Non-cash accrual of property and equipmentNon-cash accrual of property and equipment$2.5 $5.1 Non-cash accrual of property and equipment$34.4 $2.5 
Non-cash acquisitions$— $16.9 
Right-of-use assets obtained in exchange for operating lease liabilities$22.0 $10.7 

See accompanying notes to consolidated financial statements.
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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES
Notes to Consolidated Financial Statements
September 30, 20222023
(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, 2023, GIP, through GIP III Stetson I, L.P. and GIP III Stetson II, L.P, owns 46.1% of the outstanding limited liability company interests in ENLC. In addition to GIP’s equity interests in ENLC, GIP III Stetson I, L.P. maintains 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.

b.Nature of Business

We primarily focus on providing midstream energy services, including:

•gathering, compressing, treating, processing, transporting, storing, and selling natural gas;
•fractionating, transporting, storing, and selling NGLs; and
•gathering, transporting, stabilizing, storing, trans-loading, and selling crude oil and condensate, in addition to brine disposal services.

As of September 30, 2022,2023, our midstream energy asset network includes approximately 12,50013,600 miles of pipelines, 2526 natural gas processing plants with approximately 5.96.0 Bcf/d of processing capacity, seven fractionators with approximately 320,000 Bbls/d of fractionation capacity, barge and rail terminals, product storage facilities, purchasing and marketing capabilities, brine disposal wells, a crude oil trucking fleet, and equity investments in certain joint ventures. Our operations are based in the United States, and our sales are derived primarily from domestic customers.

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

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

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)
(Unaudited)

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

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)
(Unaudited)

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

(2) Significant Accounting Policies

a.Basis of Presentation

The accompanying consolidated financial statements have been prepared in accordance with the instructions to Form 10-Q, are unaudited, and do not include all the information and disclosures required by GAAP for complete financial statements. All adjustments that, in the opinion of management, are necessary for a fair presentation of the results of operations for the interim periods have been made and are of a recurring nature unless otherwise disclosed herein. The results of operations for such interim periods are not necessarily indicative of results of operations for a full year. These consolidated financial statements should be read in conjunction with the consolidated financial statements and accompanying notes included in our Annual Report on Form 10-K for the year ended December 31, 20212022 filed with the Commission on February 16, 2022.15, 2023. Certain reclassifications were made to the financial statements for the prior period to conform to current period presentation. The effect of these reclassifications had no impact on previously reported members’ equity or net income. All significant intercompany balances and transactions have been eliminated in consolidation.

b.Revenue Recognition

The following table summarizes the contractually committed fees (in millions) that we expect to recognize in our consolidated statements of operations, in either revenue or reductions to cost of sales, from MVC and firm transportation contractual provisions. Under these agreements, our customers or suppliers agree to transport or process a minimum volume of commodities on our system over an agreed period. If a customer or supplier fails to meet the minimum volume specified in such agreement, the customer or supplier is obligated to pay a contractually determined fee based upon the shortfall between actual volumes and the contractually stated volumes. All amounts in the table below are determined using the contractually-stated MVC or firm transportation volumes specified for each period multiplied by the relevant deficiency or reservation fee. Actual amounts could differ due to the timing of revenue recognition or reductions to cost of sales resulting from make-up right provisions included in our agreements, as well as due to nonpayment or nonperformance by our customers. We record revenue under MVC and firm transportation contracts during periods of shortfall when it is known that the customer cannot, or will not, make up the deficiency. These fees do not represent the shortfall amounts we expect to collect under our MVC and firm transportation contracts, as we generally do not expect volume shortfalls to equal the full amount of the contractual MVCs and firm transportation contracts during these periods.

Contractually Committed FeesCommitments
2022 (remaining)$34.4 
2023126.2 
202499.6 
202567.1 
202659.9 
Thereafter293.6 
Total$680.8 

Contractually Committed FeesCommitments
2023 (remaining)$40.6 
2024137.4 
2025117.3 
2026118.0 
2027100.4 
Thereafter1,121.2 
Total$1,634.9 

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)
(Unaudited)

c.Redeemable Non-Controlling Interest

During the first quarter of 2020, the non-controlling interest holder in one of our non-wholly owned subsidiaries exercised its option to require us to purchase its remaining interest. At the time of the exercise, we and the interest holder did not agree on the value of the interest and a lawsuit was filed by the interest holder. As part of a settlement effected with the interest holder in January 2023, we settled the redemption of the mandatorily redeemable non-controlling interest for $10.5 million.

d.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. Triggering events include, but are not limited to, significant changes in the use of the asset group, current operating results that are significantly less than forecasted results, and negative industry or economic trends, including changes in commodity prices, significant adverse changes in legal or regulatory factors, or an expectation that it is more likely than not that an asset group will be sold before the end of its useful life. The carrying amount of a long-lived asset is not recoverable when it exceeds the undiscounted sum of the future cash flows expected to result from the use and eventual disposition of the asset. Estimates of expected future cash flows represent management’s best estimate based on reasonable and supportable assumptions. When the carrying amount of a long-lived asset is not recoverable, an impairment is recognized equal to the excess of the asset’s carrying value over its fair value, which is based on inputs that are not observable in the market, and thus represent Level 3 inputs.

During 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.

(3) Acquisition

Central Oklahoma Acquisition

On July 1,December 19, 2022, we acquired all ofcompleted the equity interest in the gathering and processing assets of Crestwood Equity Partners LP located in the Barnett Shale, for a cash purchase price of $275.0 million plus working capital of $14.5 million. TheseCentral Oklahoma Acquisition. The acquired assets include approximately 400900 miles of lean and rich gas gathering pipeline and threetwo processing plants with 425280 MMcf/d of total processing capacity. We completed this acquisition to increase the scale and efficiency of our North Texas assets and realize efficiencies by redeploying redundant assets to our other segments, including the Permian segment in the near-term and the CCS business in the future.Central Oklahoma assets.

The following table presents the fair value of the identified assets received and liabilities assumed at the acquisition date (in millions):
Consideration
Cash (including working capital payment)$289.5100.9 
Contingent consideration1.3 
Total consideration$102.2 
Purchase price allocation (1)
Assets acquired:
Current assets$17.36.0 
Property and equipment275.097.1 
Other assets, net (1)0.9 
Liabilities assumed:
Current liabilities(2.8)(1.4)
Other long-term liabilities (1)(0.4)
Net assets acquired$289.5102.2 
____________________________
(1)The purchase price allocation was based on preliminary estimates“Other assets, net” and assumptions, which are subject to change within the measurement period (up to one year from the acquisition date), as we finalize the valuations“Other long-term liabilities” consist of the right-of-use assets acquired and lease liabilities, assumed uponrespectively, obtained through the closing of the acquisition.Central Oklahoma Acquisition.

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

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

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

Three Months Ended
September 30,		Nine Months Ended
September 30,
2022202120222021
Pro forma total revenues$2,663.5 $1,803.7 $7,528.8 $4,485.8 
Pro forma net income$116.6 $35.6 $320.8 $58.1 

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)
(Unaudited)

Contingent Consideration. The following table represents our change in carrying value of the Amarillo Rattler Acquisition and Central Oklahoma Acquisition contingent consideration liabilities for the periods presented (in millions):
Three Months Ended
September 30,		Nine Months Ended
September 30,
2023202220232022
Amarillo Rattler Acquisition contingent consideration
Contingent consideration liability, beginning of period (1)$4.6 $7.2 $4.2 $6.9 
Change in fair value0.4 (2.8)0.8 (2.5)
Contingent consideration liability, end of period$5.0 $4.4 $5.0 $4.4 
Central Oklahoma Acquisition contingent consideration
Contingent consideration liability, beginning of period (2)$1.8 $— $1.3 $— 
Change in fair value(0.1)— 0.4 — 
Contingent consideration liability, end of period$1.7 $— $1.7 $— 
Total contingent consideration
Contingent consideration liability, beginning of period (1)(2)$6.4 $7.2 $5.5 $6.9 
Change in fair value0.3 (2.8)1.2 (2.5)
Contingent consideration liability, end of period$6.7 $4.4 $6.7 $4.4 
____________________________
(1)The contingent consideration for the Amarillo Rattler Acquisition was recorded on April 30, 2021.
(2)The contingent consideration for the Central Oklahoma Acquisition was recorded on December 19, 2022.

Pro Forma of Acquisitions for the Three and Nine Months Ended September 30, 2022

The following unaudited pro forma condensed consolidated financial information (in millions) for the three and nine months ended September 30, 2022 gives effect to the Barnett Shale Acquisition on July 1, 2022 and the Central Oklahoma Acquisition on December 19, 2022 as if each of the acquisitions had occurred on January 1, 2022.

The unaudited pro forma condensed consolidated financial information has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the transactions taken place on the dates indicated and is not intended to be a projection of future results.
Three Months Ended
September 30, 2022		Nine Months Ended
September 30, 2022
Pro forma total revenues$2,677.2 $7,569.6 
Pro forma net income$121.8 $336.2 

(4) Intangible Assets

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

The following table represents our change in carrying value of intangible assets (in millions):
Gross Carrying AmountAccumulated AmortizationNet Carrying Amount
Nine Months Ended September 30, 2022
Customer relationships, beginning of period$1,844.8 $(795.1)$1,049.7 
Amortization expense— (96.6)(96.6)
Customer relationships, end of period$1,844.8 $(891.7)$953.1 

Amortization expense was $31.9 million for each of the three months ended September 30, 2022 and 2021, and $96.6 million and $94.4 million for the nine months ended September 30, 2022 and 2021, respectively.
The following table summarizes our estimated aggregate amortization expense for the next five years and thereafter (in millions):

2022 (remaining)$31.8 
2023127.6 
2024127.6 
2025110.2 
2026106.3 
Thereafter449.6 
Total$953.1 

Gross Carrying AmountAccumulated AmortizationNet Carrying Amount
Nine Months Ended September 30, 2023
Customer relationships, beginning of period$1,844.8 $(923.6)$921.2 
Amortization expense— (95.7)(95.7)
Customer relationships, end of period$1,844.8 $(1,019.3)$825.5 

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)
(Unaudited)

Amortization expense was $31.9 million for each of the three months ended September 30, 2023 and 2022, respectively, and $95.7 million and $96.6 million for the nine months ended September 30, 2023 and 2022, respectively.

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

2023 (remaining)$31.9 
2024127.6 
2025110.2 
2026106.3 
2027106.3 
Thereafter343.2 
Total$825.5 

(5) Related Party Transactions

(a)    Transactions with the Cedar Cove JV

ForWe process gas and purchase the three and nine months ended September 30, 2022, we recorded cost of sales of $5.6 million and $25.3 million, respectively, and for the three and nine months ended September 30, 2021, we recorded cost of sales of $4.9 million and $11.7 million, respectively, related to our purchase of residue gas and NGLs from the Cedar Cove JV subsequentJV. We recorded the following amounts (in millions) on our consolidated balance sheets related to processing at our Central Oklahoma processing facilities. Additionally, we had accounts payable balances related to transactions with the Cedar Cove JVJV:
September 30, 2023December 31, 2022
Accrued gas, NGLs, condensate, and crude oil purchases$0.5 $2.5 

We recorded the following amounts (in millions) on our consolidated statements of $4.3 million and $1.6 million at September 30, 2022 and December 31, 2021, respectively.operations related to our transactions with the Cedar Cove JV:

Three Months Ended
September 30,		Nine Months Ended
September 30,
2023202220232022
Midstream services revenue$0.7 $1.4 $2.0 $1.4 
Cost of sales(1.8)(5.6)(5.8)(25.3)

(b)    Transactions with GIP

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

GIP Repurchase Agreement. On February 15, 2022, we and GIP entered into an agreement with GIP pursuant to which we are repurchasing,agreed to repurchase, on a quarterly basis, a pro rata portion of the ENLC common units held by GIP, based upon the number of common units purchased by us during the applicable quarter from public unitholders under our common unit repurchase program. The number of ENLC common units held by GIP that we repurchase in any quarter is calculated such that GIP’s then-existing economic ownership percentage of our outstanding common units is maintained after our repurchases of common units from public unitholders are taken into account, and the per unit price we pay to GIP is the average per unit price paid by us for the common units repurchased from public unitholders.unitholders, less broker commissions, which are not paid with respect to the GIP units. See “Note 9—Members’ Equity” for additional information on the activity relating to the GIP repurchase agreement.

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

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)
(Unaudited)

(6) Long-Term Debt

As of September 30, 20222023 and December 31, 2021,2022, long-term debt consisted of the following (in millions):
September 30, 2022December 31, 2021September 30, 2023December 31, 2022
Outstanding PrincipalPremium (Discount)Long-Term DebtOutstanding PrincipalPremium (Discount)Long-Term DebtOutstanding PrincipalPremium (Discount)Long-Term DebtOutstanding PrincipalPremium (Discount)Long-Term Debt
Revolving Credit Facility due 2027 (1)Revolving Credit Facility due 2027 (1)$70.0 $— $70.0 $15.0 $— $15.0 Revolving Credit Facility due 2027 (1)$160.0 $— $160.0 $255.0 $— $255.0 
AR Facility due 2025 (2)AR Facility due 2025 (2)500.0 — 500.0 350.0 — 350.0 AR Facility due 2025 (2)292.0 — 292.0 500.0 — 500.0 
ENLK’s 4.40% Senior unsecured notes due 2024ENLK’s 4.40% Senior unsecured notes due 202497.9 — 97.9 521.8 0.7 522.5 ENLK’s 4.40% Senior unsecured notes due 202497.9 — 97.9 97.9 — 97.9 
ENLK’s 4.15% Senior unsecured notes due 2025ENLK’s 4.15% Senior unsecured notes due 2025421.6 (0.2)421.4 720.8 (0.4)720.4 ENLK’s 4.15% Senior unsecured notes due 2025421.6 — 421.6 421.6 (0.1)421.5 
ENLK’s 4.85% Senior unsecured notes due 2026ENLK’s 4.85% Senior unsecured notes due 2026491.0 (0.3)490.7 491.0 (0.3)490.7 ENLK’s 4.85% Senior unsecured notes due 2026491.0 (0.2)490.8 491.0 (0.2)490.8 
ENLC’s 5.625% Senior unsecured notes due 2028ENLC’s 5.625% Senior unsecured notes due 2028500.0 — 500.0 500.0 — 500.0 ENLC’s 5.625% Senior unsecured notes due 2028500.0 — 500.0 500.0 — 500.0 
ENLC’s 5.375% Senior unsecured notes due 2029ENLC’s 5.375% Senior unsecured notes due 2029498.7 — 498.7 498.7 — 498.7 ENLC’s 5.375% Senior unsecured notes due 2029498.7 — 498.7 498.7 — 498.7 
ENLC’s 6.50% Senior unsecured notes due 2030ENLC’s 6.50% Senior unsecured notes due 2030700.0 — 700.0 — — — ENLC’s 6.50% Senior unsecured notes due 20301,000.0 (2.8)997.2 700.0 — 700.0 
ENLK’s 5.60% Senior unsecured notes due 2044ENLK’s 5.60% Senior unsecured notes due 2044350.0 (0.2)349.8 350.0 (0.2)349.8 ENLK’s 5.60% Senior unsecured notes due 2044350.0 (0.2)349.8 350.0 (0.2)349.8 
ENLK’s 5.05% Senior unsecured notes due 2045ENLK’s 5.05% Senior unsecured notes due 2045450.0 (5.2)444.8 450.0 (5.5)444.5 ENLK’s 5.05% Senior unsecured notes due 2045450.0 (5.1)444.9 450.0 (5.2)444.8 
ENLK’s 5.45% Senior unsecured notes due 2047ENLK’s 5.45% Senior unsecured notes due 2047500.0 (0.1)499.9 500.0 (0.1)499.9 ENLK’s 5.45% Senior unsecured notes due 2047500.0 (0.1)499.9 500.0 (0.1)499.9 
Debt classified as long-term$4,579.2 $(6.0)4,573.2 $4,397.3 $(5.8)4,391.5 
Debt classified as long-term, including current maturities of long-term debtDebt classified as long-term, including current maturities of long-term debt$4,761.2 $(8.4)4,752.8 $4,764.2 $(5.8)4,758.4 
Debt issuance cost (3)Debt issuance cost (3)(35.8)(27.8)Debt issuance cost (3)(33.5)(34.9)
Less: Current maturities of long-term debt (4)Less: Current maturities of long-term debt (4)(97.9)— 
Long-term debt, net of unamortized issuance costLong-term debt, net of unamortized issuance cost$4,537.4 $4,363.7 Long-term debt, net of unamortized issuance cost$4,621.4 $4,723.5 
____________________________
(1)The effective interest rate was 6.9%7.0% and 3.9%6.5% at September 30, 20222023 and December 31, 2021,2022, respectively.
(2)The effective interest rate was 4.0%6.3% and 1.2%5.3% at September 30, 20222023 and December 31, 2021,2022, respectively.
(3)Net of accumulated amortization of $13.4$18.7 million and $18.4$15.1 million at September 30, 20222023 and December 31, 2021,2022, respectively.
(4)The outstanding balance, net of debt issuance costs, of ENLK’s 4.40% senior unsecured notes as of September 30, 2023 are classified as “Current maturities of long-term debt” on the consolidated balance sheet as these notes mature on April 1, 2024.

Revolving Credit Facility

On June 3, 2022, we amended and restated our prior revolving credit facility by entering into the Revolving Credit Facility. As a result, we recognized a $0.5 million loss on extinguishment of debt. The Revolving Credit Facility amended our priorpermits ENLC to borrow up to $1.40 billion on a revolving credit facility by, among other things, (i) decreasing the lenders’ commitmentsbasis and includes a $500.0 million letter of credit subfacility.There were $160.0 million in outstanding borrowings under the Revolving Credit Facility from $1.75 billion to $1.40 billion, (ii) modifying the leverage ratio financial covenant calculation to net from the funded indebtedness numerator the lesser of (a) consolidated unrestricted cash of ENLC and (b) $50.0 million, (iii) removing the consolidated interest coverage ratio financial covenant, (iv) extending the maturity date from January 25, 2024 to June 3, 2027, (v) replacing the ability of ENLC to elect that borrowings accrue interest at LIBOR, plus a margin, with the ability of ENLC to elect that borrowings accrue interest at a forward-looking term rate based on SOFR (“Term SOFR”), plus a margin and a Term SOFR spread adjustment, (vi) increasing the size of a permitted receivables financing to $500.0 million from $350.0 million, and (vii) permitting, but not requiring, the establishment by ENLC (subject to approval by Bank of America, N.A., as administrative agent, and lenders holding a majority of the revolving commitments) of specified key performance indicators with respect to environmental, social, and/or governance targets that may result in a pricing increase or decrease under the Revolving Credit Facility of up to 0.05% per annum for the margin on borrowings and letters of credit and 0.02% per annum for the commitment fees.

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

There were $70.0 million in outstanding borrowings and $46.6$29.6 million in outstanding letters of credit under the Revolving Credit Facility as of September 30, 2022.2023.

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Notes to Consolidated Financial Statements (Continued)
(Unaudited)

At September 30, 2022,2023, we were in compliance with and expect to be in compliance with the financial covenants of the Revolving Credit Facility for at least the next twelve months.

AR Facility

On October 21, 2020, EnLink Midstream Funding, LLC, a bankruptcy-remote special purpose entity that is an indirect subsidiary of ENLC (the “SPV”)the SPV entered into the AR Facility. We are the primary beneficiary of the SPV, and we consolidate its assets and liabilities, which consistedconsist primarily of billed and unbilled accounts receivable of $882.4$652.9 million as of September 30, 2022.

On August 1, 2022, we amended certain terms of the AR Facility to, among other things, increase the commitments thereunder from $350.0 million to $500.0 million and extend the scheduled termination date from September 24, 2024 to August 1, 2025.2023. As of September 30, 2022,2023, the AR Facility had a borrowing base of $500.0$443.4 million and there were $500.0$292.0 million in outstanding borrowings under the AR Facility.

At September 30, 2022,2023, we were in compliance with and expect to be in compliance with the financial covenants of the AR Facility for at least the next twelve months.

Issuances and Repurchases of Senior Unsecured Notes

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

Activity related to the repurchases of ENLK’s senior unsecured notes from the settled debt tender offer consisted of the following (in millions):
Three and Nine Months Ended September 30, 2022
Debt repurchased$700.0 
Aggregate payments(715.8)
Net discount on repurchased debt(1.0)
Accrued interest on repurchased debt10.5 
Loss on extinguishment of debt$(6.3)

Additionally, for the three and nine months ended September 30, 2022, we repurchased a portion of the outstanding 2024 Notes and 2025 Notes in open market transactions. We did not repurchase any senior unsecured notes in open market transactions during the three and nine months ended September 30, 2021.

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

Three Months Ended September 30, 2022Nine Months Ended September 30, 2022
Debt repurchased$21.1 $23.1 
Aggregate payments(20.7)(22.7)
Accrued interest on repurchased debt0.2 0.2 
Gain on extinguishment of debt$0.6 $0.6 
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Notes to Consolidated Financial Statements (Continued)
(Unaudited)

Senior Unsecured Notes

On April 3, 2023, we completed the sale of an additional $300.0 million aggregate principal amount of 6.50% senior unsecured notes due 2030 (the “Additional Notes”) at 99% of their face value. The Additional Notes were offered as an additional issuance of our existing 6.50% senior unsecured notes due 2030 that we issued on August 31, 2022 in an aggregate principal amount of $700.0 million. Net proceeds of approximately $294.5 million were used to repay a portion of the borrowings under the Revolving Credit Facility. The Additional Notes are fully and unconditionally guaranteed by ENLK.

(7) Income Taxes

The components of our income tax expense are as follows (in millions):
Three Months Ended
September 30,		Nine Months Ended
September 30,		Three Months Ended
September 30,		Nine Months Ended
September 30,
20222021202220212023202220232022
Current income tax expenseCurrent income tax expense$(0.3)$(0.1)$(1.0)$(0.2)Current income tax expense$(1.2)$(0.3)$(1.5)$(1.0)
Deferred income tax expenseDeferred income tax expense(14.9)(4.3)(16.1)(12.2)Deferred income tax expense(9.4)(14.9)(39.0)(16.1)
Income tax expenseIncome tax expense$(15.2)$(4.4)$(17.1)$(12.4)Income tax expense$(10.6)$(15.2)$(40.5)$(17.1)

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,		Three Months Ended
September 30,		Nine Months Ended
September 30,
20222021202220212023202220232022
Expected income tax benefit (expense) based on federal statutory rate$(20.0)$(2.0)$(45.9)$4.2 
State income tax benefit (expense), net of federal benefit(2.6)(0.3)(6.2)0.5 
Expected income tax expense based on federal statutory rateExpected income tax expense based on federal statutory rate$(8.4)$(20.0)$(38.3)$(45.9)
State income tax expense, net of federal benefitState income tax expense, net of federal benefit(1.1)(2.6)(4.9)(6.2)
Unit-based compensation (1)Unit-based compensation (1)1.4 (0.2)(0.6)(3.1)Unit-based compensation (1)0.9 1.4 7.5 (0.6)
Change in valuation allowanceChange in valuation allowance10.9 (1.6)39.0 (3.8)Change in valuation allowance— 10.9 — 39.0 
Oklahoma statutory rate change (2)— — — (7.6)
OtherOther(4.9)(0.3)(3.4)(2.6)Other(2.0)(4.9)(4.8)(3.4)
Income tax expenseIncome tax expense$(15.2)$(4.4)$(17.1)$(12.4)Income tax expense$(10.6)$(15.2)$(40.5)$(17.1)
____________________________
(1)Related to book-to-tax differences recorded upon the vesting of restricted incentive units.
(2)Oklahoma House Bill 2960 resulted in a change in the corporate income tax rate from 6% to 4%. Accordingly, we recorded deferred tax expense in the amount of $7.6 million for the nine months ended September 30, 2021 due to a remeasurement of deferred tax assets.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. As of September 30, 2022,2023, we had $153.6$774.1 million of deferred tax assets and $856.9 million of deferred tax liabilities for net deferred tax liabilities of $553.2$82.8 million. As of December 31, 2022, we had $714.1 million of deferred tax assets which included a $112.6 million valuation allowance. As of December 31, 2021, we had $137.5and $756.8 million of deferred tax liabilities for net of $481.6 million of deferred tax assets, which included a $151.6 million valuation allowance.liabilities of $42.7 million.

AWe provide a valuation allowance, is establishedif necessary, to reduce deferred tax assets, if all, or some portion, of such assets will more than likely not be realized. We have established a valuation allowance primarily related to federal and state tax operating loss carryforwards for which we do not believe a tax benefit is more likely than not to be realized. As of September 30, 2022,2023, we did not record a valuation allowance and management believes it is more likely than not that the Company will realize the benefits of the deferred tax assets, net of valuation allowance.assets.

Excise Tax on Common Unit Repurchases

In August 2022, the Inflation Reduction Act of 2022 was signed into law, which, among other things, imposed a 1.0% excise tax on net common unit repurchases made after December 31, 2022. As a result, we accrued $0.5 million and $1.2 million of excise tax in connection with our net common unit repurchases for the three and nine months ended September 30, 2023, respectively, which was recorded as an adjustment to the cost basis of common units repurchased in “Members’ equity” and “Other current liabilities” on the consolidated balance sheet as of September 30, 2023.

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Notes to Consolidated Financial Statements (Continued)
(Unaudited)

(8) Certain Provisions of the ENLK Partnership Agreement

a.Series B Preferred Units

As of September 30, 20222023 and December 31, 2021,2022, there were 54,168,35954,439,539 and 57,501,69354,168,359 Series B Preferred Units issued and outstanding, respectively.

Redemption

In January 2022, we redeemed 3,333,334 Series B Preferred Units for total consideration of $50.5 million plus accrued distributions. In addition, upon such redemption, a corresponding number of ENLC Class C Common Units were automatically cancelled. The redemption price representsrepresented 101% of the preferred units’ par value. In connection with the Series B Preferred Unit redemption, we have agreed with the holders of the Series B Preferred Units that we willto pay cash in lieu of making a quarterly PIK distribution in-kind of additional Series B Preferred Units (the “PIK Distribution”) through the distribution declared for the fourth quarter of 2022.

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, 20222023 and 20212022 is provided below:
Declaration periodDeclaration periodDistribution paid as additional Series B Preferred UnitsCash distribution (in millions)Date paid/payableDeclaration periodPIK DistributionCash distribution (in millions)Date paid/payable
20232023
Fourth Quarter of 2022Fourth Quarter of 2022— $17.3 February 13, 2023
First Quarter of 2023First Quarter of 2023135,421 $15.2 May 12, 2023
Second Quarter of 2023Second Quarter of 2023135,759 $15.3 August 11, 2023
Third Quarter of 2023Third Quarter of 2023136,099 $15.3 November 10, 2023
202220222022
Fourth Quarter of 2021Fourth Quarter of 2021— $19.2 February 11, 2022 (1)Fourth Quarter of 2021— $19.2 February 11, 2022 (1)
First Quarter of 2022First Quarter of 2022— $17.5 May 13, 2022 (2)First Quarter of 2022— $17.5 May 13, 2022 (2)
Second Quarter of 2022Second Quarter of 2022— $17.3 August 12, 2022Second Quarter of 2022— $17.3 August 12, 2022
Third Quarter of 2022Third Quarter of 2022— $17.3 November 14, 2022Third Quarter of 2022— $17.3 November 14, 2022
2021
Fourth Quarter of 2020150,494 $16.9 February 12, 2021
First Quarter of 2021150,871 $17.0 May 14, 2021
Second Quarter of 2021151,248 $17.0 August 13, 2021
Third Quarter of 2021151,626 $17.1 November 12, 2021
____________________________
(1)In December 2021 and January 2022, we paid $0.9 million and $1.0 million, respectively, of accrued distributions related to the fourth quarter of 2021 on redeemed Series B Preferred Units. The remaining distribution of $17.3 million related to the fourth quarter of 2021 was paid on February 11, 2022.
(2)In January 2022, we paid $0.3 million of accrued distributions related to the first quarter of 2022 on redeemed Series B Preferred Units. The remaining distribution of $17.2 million related to the first quarter of 2022 was paid on May 13, 2022.

b.ENLK’s Eleventh Amended and Restated Agreement of Limited Partnership

On September 8, 2023, in connection with ENLK’s qualification of the Series B Preferred Units to be eligible to be deposited through the Depository Trust Company, we amended and restated the limited partnership agreement of ENLK to, among other things, (i) reflect the cancellation of all outstanding ENLC Class C Common Units, which were non-economic equity interests previously held by the holders of the Series B Preferred Units and permitted such holders to participate in any vote of the holders of ENLC common units, (ii) provide for the termination of any rights of the holders of the Series B Preferred Units to PIK Distributions with respect to, and following, the earlier to occur of (x) any quarter in which the holders of the Series B Preferred Units give notice to the General Partner of its election to terminate such PIK Distribution right and (y) the quarter ending June 30, 2024, and (iii) 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 ENLK’s limited partnership agreement).

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Notes to Consolidated Financial Statements (Continued)
(Unaudited)

Taxable Income

For tax purposes, holders of Series B Preferred Units are allocated items of gross income from ENLK in respect of each Series B Preferred Unit until the cumulative amount of gross income so allocated equals the cumulative amount of distributions made in respect of such Series B Preferred Unit, but not in excess of such Series B Preferred Unit’s pro rata share of the net income of ENLK for the allocation year (the “Allocation Cap”). As of September 30, 2023, due to the application of the Allocation Cap, the cumulative amount of distributions made in respect of each Series B Preferred Unit exceeded the cumulative amount of gross income allocated to each Series B Preferred Unit by $6.52 per Series B Preferred Unit (the “Catch-Up Taxable Income Allocation”). As a result, holders of Series B Preferred Units will ultimately be allocated taxable income during future periods equal to the Catch-Up Taxable Income Allocation plus the amount of distributions received in respect of Series B Preferred Units, if ENLK generates positive net income.

a.Series C Preferred Units

As of September 30, 20222023 and December 31, 2021,2022, there were 400,000376,500 and 381,000 Series C Preferred Units issued and outstanding, respectively. ENLK distributed

Repurchase

In February 2023, we repurchased 4,500 Series C Preferred Units for total consideration of $3.9 million. The repurchase price represented 87% of the preferred units’ par value.
$12.0 million
Distributions

Income is allocated to holdersthe 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 during the nine months ended September 30, 2023 and 2022 and 2021, respectively. There was no distribution activity related tois provided below:
Declaration period (1)Distribution rate (2)Cash distribution (in millions)Date paid/payable
2023
December 15, 2022 – March 14, 20238.846 %$8.4 March 15, 2023
March 15, 2023 – June 14, 20239.051 %$8.7 June 15, 2023
June 15, 2023 – September 14, 20239.618 %$9.3 September 15, 2023
September 15, 2023 - December 14, 20239.782 %$9.3 December 15, 2023
2022
December 15, 2021 – June 14, 20226.000 %$12.0 June 15, 2022
June 15, 2022 – December 14, 20226.000 %$11.4 December 15, 2022
____________________________
(1)Distributions on the Series C Preferred Units duringaccrued and were cumulative from the three months ended September 30,date of original issue and payable semi-annually in arrears on the 15th day of June and December of each year through and including December 15, 2022 and, 2021.thereafter, 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)
The initial distribution rate for the Series C Preferred Units from the date of original issue through December 14, 2022 was 6.0% per year. Starting on December 15, 2022, 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%.

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Notes to Consolidated Financial Statements (Continued)
(Unaudited)

(9) Members’ Equity

a.Common Unit Repurchase Program

In November 2020,December 2022, the board of directors of the Managing Member (the “Board”) authorized areauthorized our common unit repurchase program for the repurchase of up to $100.0 million of outstanding ENLC common units2023 and reauthorized such program in April 2021. The Board reauthorized ENLC’s common unit repurchase program and resetset the amount available for repurchases of outstanding common units during 2023 at up to $100.0$200.0 million, effective January 1, 2022. In July 2022, the Board increased the amount available forincluding repurchases to $200.0 million.of common units held by 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.

On February 15, 2022, we and GIP entered into an agreement pursuant to which we agreed to repurchase, on a quarterly basis, a pro rata portion of the ENLC common units held by GIP, based upon the number of common units purchased by us during the preceding quarter from public unitholders under our common unit repurchase program. See “Note 5—Related Party Transactions” for additional information on our ENLC common unit repurchase agreement with GIP.

The following table summarizes our ENLC common unit repurchase activity for the three and nine months ended September 30, 2022 and 2021periods presented (in millions, except for unit amounts):
Three Months Ended September 30,Nine Months Ended September 30,Three Months Ended
September 30,		Nine Months Ended
September 30,
20222021202220212023202220232022
Publicly held ENLC common unitsPublicly held ENLC common units4,051,626 2,076,545 9,066,838 2,394,296 Publicly held ENLC common units2,253,012 4,051,626 7,690,821 9,066,838 
ENLC common units held by GIP (1)ENLC common units held by GIP (1)2,530,507 — 3,205,602 — ENLC common units held by GIP (1)2,763,581 2,530,507 6,911,568 3,205,602 
Total ENLC common unitsTotal ENLC common units6,582,133 2,076,545 12,272,440 2,394,296 Total ENLC common units5,016,593 6,582,133 14,602,389 12,272,440 
Aggregate cost for publicly held ENLC common unitsAggregate cost for publicly held ENLC common units$38.5 $12.5 $83.2 $14.5 Aggregate cost for publicly held ENLC common units$26.9 $38.5 $85.9 $83.2 
Aggregate cost for ENLC common units held by GIPAggregate cost for ENLC common units held by GIP24.0 — 30.0 — Aggregate cost for ENLC common units held by GIP27.5 24.0 75.3 30.0 
Excise tax on common unit repurchasesExcise tax on common unit repurchases0.5 — 1.2 — 
Total aggregate cost for ENLC common unitsTotal aggregate cost for ENLC common units$62.5 $12.5 $113.2 $14.5 Total aggregate cost for ENLC common units$54.9 $62.5 $162.4 $113.2 
Average price paid per publicly held ENLC common unit$9.49 $6.02 $9.18 $6.05 
Average price paid per ENLC common unit held by GIP (2)$9.47 $— $9.35 $— 
Average price paid per publicly held ENLC common unit (2)Average price paid per publicly held ENLC common unit (2)$11.93 $9.49 $11.16 $9.18 
Average price paid per ENLC common unit held by GIP (2)(3)Average price paid per ENLC common unit held by GIP (2)(3)$9.94 $9.47 $10.89 $9.35 
____________________________
(1)For the three and nine months ended September 30, 2022, theThe 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 third quarter and the period from February 15, 2022 (the date on which the Repurchase Agreement was signed) through June 30, 2022, respectively.prior quarter.
(2)For the three and nine months ended September 30, 2022, theThe 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 duringin the thirdprior quarter, and from February 15, 2022 (the date on which the Repurchase Agreement was signed) through June 30, 2022, respectively, less broker commissions, which were not paid with respect to GIP units.commissions.

Additionally, on October 31, 2022,30, 2023, we repurchased 3,538,1011,934,877 ENLC common units held by GIP at an aggregate cost of $33.5$23.0 million,, or an average of $9.47$11.91 per common unit. These units represent GIP’s pro rata share of the aggregate number of common units repurchased by us during the three months ended September 30, 2022.2023. 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 GIP units.

 As of September 30, 2023, $23.0 million is classified as “Other current liabilities” on the consolidated balance sheets related to our obligation to repurchase our common units from GIP. See “Note 5—Related Party Transactions” for additional information relating to the GIP repurchase agreement.
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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,
2022202120222021
Distributed earnings allocated to:
Common units (1)$53.7 $45.8 $162.4 $137.7 
Unvested restricted units (1)1.4 1.0 3.9 3.2 
Total distributed earnings$55.1 $46.8 $166.3 $140.9 
Undistributed income (loss) allocated to:
Common units$25.1 $(43.9)$34.2 $(169.3)
Unvested restricted units0.6 (1.0)0.8 (4.0)
Total undistributed income (loss)$25.7 $(44.9)$35.0 $(173.3)
Net income (loss) attributable to ENLC allocated to:
Common units$78.8 $1.9 $196.6 $(31.6)
Unvested restricted units2.0 — 4.7 (0.8)
Total net income (loss) attributable to ENLC$80.8 $1.9 $201.3 $(32.4)
Net income (loss) attributable to ENLC per unit:
Basic$0.17 $— $0.42 $(0.07)
Diluted$0.17 $— $0.41 $(0.07)
Three Months Ended
September 30,		Nine Months Ended
September 30,
2023202220232022
Distributed earnings allocated to:
Common units (1)$57.6 $53.7 $174.0 $162.4 
Unvested unit-based awards (1)1.0 1.4 2.9 3.9 
Total distributed earnings$58.6 $55.1 $176.9 $166.3 
Undistributed loss allocated to:
Common units$(28.6)$25.1 $(34.3)$34.2 
Unvested unit-based awards(0.5)0.6 (0.6)0.8 
Total undistributed loss$(29.1)$25.7 $(34.9)$35.0 
Net income attributable to ENLC allocated to:
Common units$29.0 $78.8 $139.7 $196.6 
Unvested unit-based awards0.5 2.0 2.3 4.7 
Total net income attributable to ENLC$29.5 $80.8 $142.0 $201.3 
Net income attributable to ENLC per unit:
Basic$0.06 $0.17 $0.31 $0.42 
Diluted$0.06 $0.17 $0.30 $0.41 
____________________________
(1)Represents distribution activity consistent with the distribution activity table below.

The following are the unit amounts used to compute the basic and diluted earnings per unit for the periods presented (in millions):
Three Months Ended
September 30,		Nine Months Ended
September 30,
2022202120222021
Basic weighted average units outstanding:
Weighted average common units outstanding477.2 488.6 481.0 489.6 
Diluted weighted average units outstanding:
Weighted average basic common units outstanding477.2 488.6 481.0 489.6 
Dilutive effect of unvested restricted units (1)7.2 6.2 6.9 — 
Total weighted average diluted common units outstanding484.4 494.8 487.9 489.6 
____________________________
(1)All common unit equivalents were antidilutive for the nine months ended September 30, 2021, since a net loss existed for that period.
Three Months Ended
September 30,		Nine Months Ended
September 30,
2023202220232022
Basic weighted average units outstanding:
Weighted average common units outstanding459.3 477.2 464.1 481.0 
Diluted weighted average units outstanding:
Weighted average basic common units outstanding459.3 477.2 464.1 481.0 
Dilutive effect of unvested unit-based awards4.6 7.2 4.3 6.9 
Total weighted average diluted common units outstanding463.9 484.4 468.4 487.9 

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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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, 20222023 and 2021,2022, respectively, is provided below:
Declaration periodDistribution/unitDate paid/payable
2023
Fourth Quarter of 2022$0.12500 February 13, 2023
First Quarter of 2023$0.12500 May 12, 2023
Second Quarter of 2023$0.12500 August 11, 2023
Third Quarter of 2023$0.12500 November 10, 2023
2022
Fourth Quarter of 2021$0.11250.11250 February 11, 2022
First Quarter of 2022$0.11250.11250 May 13, 2022
Second Quarter of 2022$0.11250.11250 August 12, 2022
Third Quarter of 2022$0.11250.11250 November 14, 2022
2021
Fourth Quarter of 2020$0.09375 February 12, 2021
First Quarter of 2021$0.09375 May 14, 2021
Second Quarter of 2021$0.09375 August 13, 2021
Third Quarter of 2021$0.09375 November 12, 2021

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Notes to Consolidated Financial Statements (Continued)
(Unaudited)

(10) Investment in Unconsolidated Affiliates

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

As of September 30, 2022,2023, our unconsolidated investments consisted of a 38.75% ownership in GCF, a 30% ownership in the Cedar Cove JV, and a 15% ownership in the Matterhorn JV. The following table shows the activity related to our investment in unconsolidated affiliates for the periods indicated (in millions):
Three Months Ended
September 30,		Nine Months Ended
September 30,		Three Months Ended
September 30,		Nine Months Ended
September 30,
20222021202220212023202220232022
GCFGCFGCF
ContributionsContributions$0.9 $— $1.4 $— Contributions$8.7 $0.9 $14.9 $1.4 
DistributionsDistributions$— $— $— $(3.5)Distributions$— $— $(2.0)$— 
Equity in loss$(0.8)$(1.7)$(2.4)$(8.1)
Equity in income (loss)Equity in income (loss)$0.3 $(0.8)$(2.5)$(2.4)
Cedar Cove JVCedar Cove JVCedar Cove JV
DistributionsDistributions$(0.2)$(0.1)$(0.6)$(0.3)Distributions$(0.1)$(0.2)$(0.4)$(0.6)
Equity in lossEquity in loss$(0.6)$(0.6)$(1.3)$(1.8)Equity in loss$(0.6)$(0.6)$(1.7)$(1.3)
Matterhorn JVMatterhorn JVMatterhorn JV
ContributionsContributions$18.8 $— $44.9 $— Contributions$— $18.8 $43.5 $44.9 
Equity in loss$(0.3)$— $(0.3)$— 
Equity in income (loss)Equity in income (loss)$1.3 $(0.3)$0.5 $(0.3)
TotalTotalTotal
ContributionsContributions$19.7 $— $46.3 $— Contributions$8.7 $19.7 $58.4 $46.3 
DistributionsDistributions$(0.2)$(0.1)$(0.6)$(3.8)Distributions$(0.1)$(0.2)$(2.4)$(0.6)
Equity in loss$(1.7)$(2.3)$(4.0)$(9.9)
Equity in income (loss)Equity in income (loss)$1.0 $(1.7)$(3.7)$(4.0)

The following table shows the balances related to our investment in unconsolidated affiliates as of September 30, 20222023 and December 31, 20212022 (in millions):
September 30, 2022December 31, 2021September 30, 2023December 31, 2022
GCFGCF$27.0 $28.0 GCF$36.7 $26.3 
Cedar Cove JV (1)Cedar Cove JV (1)(3.7)(1.8)Cedar Cove JV (1)(6.5)(4.4)
Matterhorn JVMatterhorn JV44.6 — Matterhorn JV107.9 63.9 
Total investment in unconsolidated affiliatesTotal investment in unconsolidated affiliates$67.9 $26.2 Total investment in unconsolidated affiliates$138.1 $85.8 
____________________________
(1)As of September 30, 20222023 and December 31, 2021,2022, our investment in the Cedar Cove JV is classified as “Other long-term liabilities” on the consolidated balance sheets.

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Notes to Consolidated Financial Statements (Continued)
(Unaudited)

(11) Employee Incentive Plans

a.Long-Term Incentive Plans

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

Amounts recognized on the consolidated financial statements with respect to these plans are as follows (in millions):
Three Months Ended
September 30,		Nine Months Ended
September 30,		Three Months Ended
September 30,		Nine Months Ended
September 30,
20222021202220212023202220232022
Cost of unit-based compensation charged to operating expenseCost of unit-based compensation charged to operating expense$1.3 $1.5 $4.1 $4.9 Cost of unit-based compensation charged to operating expense$1.1 $1.3 $2.7 $4.1 
Cost of unit-based compensation charged to general and administrative expenseCost of unit-based compensation charged to general and administrative expense10.1 4.9 19.6 14.4 Cost of unit-based compensation charged to general and administrative expense4.6 10.1 11.5 19.6 
Total unit-based compensation expenseTotal unit-based compensation expense$11.4 $6.4 $23.7 $19.3 Total unit-based compensation expense$5.7 $11.4 $14.2 $23.7 
Amount of related income tax benefit recognized in net income (1)Amount of related income tax benefit recognized in net income (1)$2.7 $1.5 $5.6 $4.5 Amount of related income tax benefit recognized in net income (1)$1.3 $2.7 $3.3 $5.6 
____________________________
(1)For the three and nine months ended September 30, 2022, theThe amount of related income tax benefit recognized in net income excluded $1.4 million of income tax benefit and $0.6 million of income tax expense, respectively, related to book-to-tax differences recorded upon the vesting of restricted units.unit-based awards. For the three and nine months ended September 30, 2021, the amount of related income tax benefit recognized in net income excluded $0.2 million and $3.1 million of income tax expense, respectively, related to book-to-tax differences recorded upon the vesting of restricted units.additional information, see “Note 7—Income Taxes.”

b.ENLC Restricted Incentive Units

ENLCThe restricted incentive units were valued at their fair value at the date of grant, which is equal to the market value of ENLC common units on such date. A summary of the restricted incentive unit activity for the nine months ended September 30, 20222023 is provided below:
Nine Months Ended
September 30, 2022		Nine Months Ended
September 30, 2023
ENLC Restricted Incentive Units:Number of UnitsWeighted Average Grant-Date Fair Value
Non-vested, beginning of period7,507,471 $5.46 
Restricted Incentive Units:Restricted Incentive Units:Number of UnitsWeighted Average Grant-Date Fair Value
Unvested, beginning of periodUnvested, beginning of period6,775,186 $5.89 
Granted (1)Granted (1)2,461,950 8.83 Granted (1)1,575,905 11.02 
Vested (2)(1)Vested (2)(1)(2,198,511)7.88 Vested (2)(1)(2,413,511)6.00 
ForfeitedForfeited(348,431)7.13 Forfeited(333,050)6.91 
Non-vested, end of period7,422,479 $5.78 
Unvested, end of periodUnvested, end of period5,604,530 $7.22 
Aggregate intrinsic value, end of period (in millions)Aggregate intrinsic value, end of period (in millions)$66.0  Aggregate intrinsic value, end of period (in millions)$68.5  
____________________________
(1)Restricted incentive units typically vest at the end of three years. In March 2022, ENLC granted 193,935 restricted incentive units with a fair value of $1.7 million. These restricted incentives units vested immediately and are included in the restricted incentive units granted and vested line items.
(2)Vested units included 709,189735,018 ENLC common units withheld for payroll taxes paid on behalf of employees.

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Notes to Consolidated Financial Statements (Continued)
(Unaudited)

A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for the three and nine months ended September 30, 20222023 and 20212022 is provided below (in millions):
Three Months Ended
September 30,		Nine Months Ended
September 30,		Three Months Ended
September 30,		Nine Months Ended
September 30,
ENLC Restricted Incentive Units:2022202120222021
Restricted Incentive Units:Restricted Incentive Units:2023202220232022
Aggregate intrinsic value of units vestedAggregate intrinsic value of units vested$11.1 $1.5 $19.3 $5.4 Aggregate intrinsic value of units vested$2.1 $11.1 $29.6 $19.3 
Fair value of units vestedFair value of units vested$6.1 $3.6 $17.3 $16.1 Fair value of units vested$1.0 $6.1 $14.5 $17.3 

As of September 30, 2022,2023, there were $20.5$20.8 million of unrecognized compensation costs that related to non-vested ENLC restricted incentive units. These costs are expected to be recognized over a weighted-average period of 1.81.9 years.

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Notes to Consolidated Financial Statements (Continued)
(Unaudited)

c.ENLC Performance Units

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

The following table presents a summary of the performance units:
Nine Months Ended
September 30, 2022		Nine Months Ended
September 30, 2023
ENLC Performance Units:Number of UnitsWeighted Average Grant-Date Fair Value
Performance Units:Performance Units:Number of UnitsWeighted Average Grant-Date Fair Value
Non-vested, beginning of periodNon-vested, beginning of period3,574,827 $6.40 Non-vested, beginning of period2,979,154 $6.44 
GrantedGranted1,204,882 11.60 Granted420,128 11.67 
Vested (1)Vested (1)(1,265,207)10.94 Vested (1)(1,091,523)8.30 
ForfeitedForfeited(147,232)11.90 Forfeited(81,827)11.06 
Non-vested, end of periodNon-vested, end of period3,367,270 $6.31 Non-vested, end of period2,225,932 $6.35 
Aggregate intrinsic value, end of period (in millions)Aggregate intrinsic value, end of period (in millions)$29.9 Aggregate intrinsic value, end of period (in millions)$27.2 
____________________________
(1)Vested units included 676,156811,114 ENLC common units withheld for payroll taxes paid on behalf of employees.

A summary of the performance units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for the nine months ended September 30, 20222023 and 20212022 is provided below (in millions).

Three Months Ended
September 30,		Nine Months Ended
September 30,		 Three Months Ended
September 30,		Nine Months Ended
September 30,
ENLC Performance Units:2022202120222021
Performance Units:Performance Units:2023202220232022
Aggregate intrinsic value of units vestedAggregate intrinsic value of units vested$10.2 $— $15.8 $0.6 Aggregate intrinsic value of units vested$4.1 $10.2 $26.1 $15.8 
Fair value of units vestedFair value of units vested$4.5 $— $15.5 $4.4 Fair value of units vested$1.0 $4.5 $9.1 $15.5 

As of September 30, 2022,2023, there were $12.9$10.0 million of unrecognized compensation costs that related to non-vested ENLC performance units. These costs are expected to be recognized over a weighted-average period of 2.01.6 years.

The following table presents a summary of the grant-date fair value assumptions by performance unit grant date:
Performance Units:March 2023
Grant-date fair value$11.67 
Beginning TSR Price$10.40 
Risk-free interest rate3.76 %
Volatility factor64.00 %

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Notes to Consolidated Financial Statements (Continued)
(Unaudited)

The following table presents a summary of the grant-date fair value assumptions by performance unit grant date:
ENLC Performance Units:June 2022March 2022 (1)January 2021
Grant-date fair value$11.71 $11.90 $4.70 
Beginning TSR price$8.54 $8.83 $3.71 
Risk-free interest rate3.35 %2.15 %0.17 %
Volatility factor76.00 %75.00 %71.00 %
____________________________
(1)Excludes certain ENLC performance units awarded March 1, 2022 with vesting conditions based on performance metrics. The 88,863 ENLC performance units have a grant-date fair value of $8.90 and are scheduled to vest in February 2023.

(12) Derivatives

Interest Rate Swaps

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. 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 this interest rate swap as a cash flow hedge in accordance with ASC 815. There is no ineffectiveness related to this hedge.

The components of the unrealized gain on designated cash flow hedge related to changes in the fair value of our interest rate swaps wereare as follows (in millions):
Three Months Ended
September 30,		Nine Months Ended
September 30,		Three Months Ended
September 30,		Nine Months Ended
September 30,
20222021202220212023202220232022
Change in fair value of interest rate swapsChange in fair value of interest rate swaps$— $5.0 $0.1 $14.5 Change in fair value of interest rate swaps$2.2 $— $8.1 $0.1 
Tax expenseTax expense— (1.2)— (3.4)Tax expense(0.5)— (1.9)— 
Unrealized gain on designated cash flow hedgeUnrealized gain on designated cash flow hedge$— $3.8 $0.1 $11.1 Unrealized gain on designated cash flow hedge$1.7 $— $6.2 $0.1 

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

September 30, 2023December 31, 2022
Fair value of derivative assets—current$5.7 $— 
Fair value of derivative assets—long-term2.4 — 
Net fair value of interest rate swaps$8.1 $— 

The interestInterest expense (income) is recognized from accumulated other comprehensive lossincome from the monthly settlement of our interest rate swaps and amortization of the termination payments,was included in our consolidated statements of operations were as follows (in millions):
Three Months Ended
September 30,		Nine Months Ended
September 30,
2022202120222021
Interest expense$— $5.0 $0.1 $14.6 
Three Months Ended
September 30,		Nine Months Ended
September 30,
2023202220232022
Interest expense, net of interest income$(1.4)$— $(3.0)$0.1 

We expect to recognize an additional $0.1$5.7 million of interest expenseincome out of accumulated other comprehensive lossincome (loss) over the next twelve months.

Commodity SwapsDerivatives

The components of gain (loss) on derivative activity in the consolidated statements of operations related to commodity swapsderivatives are as follows (in millions):
Three Months Ended
September 30,		Nine Months Ended
September 30,		Three Months Ended
September 30,		Nine Months Ended
September 30,
20222021202220212023202220232022
Change in fair value of derivativesChange in fair value of derivatives$18.2 $(1.2)$38.4 $(32.9)Change in fair value of derivatives$(22.9)$18.2 $(19.0)$38.4 
Realized gain (loss) on derivativesRealized gain (loss) on derivatives2.3 (32.4)(44.6)(122.3)Realized gain (loss) on derivatives0.9 2.3 20.2 (44.6)
Gain (loss) on derivative activityGain (loss) on derivative activity$20.5 $(33.6)$(6.2)$(155.2)Gain (loss) on derivative activity$(22.0)$20.5 $1.2 $(6.2)

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Notes to Consolidated Financial Statements (Continued)
(Unaudited)

The fair value of derivative assets and liabilities related to commodity swapsderivatives are as follows (in millions):
September 30, 2022December 31, 2021September 30, 2023December 31, 2022
Fair value of derivative assets—currentFair value of derivative assets—current$76.2 $22.4 Fair value of derivative assets—current$62.3 $68.4 
Fair value of derivative assets—long-termFair value of derivative assets—long-term0.7 0.2 Fair value of derivative assets—long-term11.4 2.9 
Fair value of derivative liabilities—currentFair value of derivative liabilities—current(52.2)(34.9)Fair value of derivative liabilities—current(54.8)(42.9)
Fair value of derivative liabilities—long-termFair value of derivative liabilities—long-term(0.8)(2.2)Fair value of derivative liabilities—long-term(12.2)(2.7)
Net fair value of commodity swaps$23.9 $(14.5)
Net fair value of commodity derivativesNet fair value of commodity derivatives$6.7 $25.7 

Set forth below are the summarized notional volumes and fair values of all instruments related to commodity swapsderivatives that we held for price risk management purposes and the related physical offsets at September 30, 20222023 (in millions, except volumes). The remaining term of the contracts extend no later than January 2024.2028.
September 30, 2022
CommodityCommodityInstrumentsUnitVolumeNet Fair ValueCommodityInstrumentsUnitVolumeNet Fair Value
NGL (short contracts)NGL (short contracts)SwapsMMgals(113.0)$24.7 NGL (short contracts)SwapsMMgals(114.5)$3.0 
NGL (long contracts)NGL (long contracts)SwapsMMgals7.8 (0.3)NGL (long contracts)SwapsMMgals71.2 (5.8)
Natural gas (short contracts)Natural gas (short contracts)SwapsMMbtu(25.5)9.4 Natural gas (short contracts)Swaps and futuresBbtu(124.6)28.8 
Natural gas (long contracts)Natural gas (long contracts)SwapsMMbtu20.6 (14.4)Natural gas (long contracts)Swaps and futuresBbtu111.8 (18.7)
Crude and condensate (short contracts)Crude and condensate (short contracts)SwapsMMbbls(2.5)11.1 Crude and condensate (short contracts)Swaps and futuresMMbbls(8.5)(8.5)
Crude and condensate (long contracts)Crude and condensate (long contracts)SwapsMMbbls2.2 (6.6)Crude and condensate (long contracts)Swaps and futuresMMbbls0.7 7.9 
Total fair value of commodity swaps$23.9 
Total fair value of commodity derivativesTotal fair value of commodity derivatives$6.7 

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 $76.9$73.7 million as of September 30, 20222023 would be reduced to $30.3$10.5 million due to the offsetting of gross fair value payables against gross fair value receivables as allowed by the ISDAs.ISDAs and the FCDTCs.

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Notes to Consolidated Financial Statements (Continued)
(Unaudited)

(13) Fair Value Measurements

AssetsDerivative assets and liabilities measured at fair value on a recurring basis are summarized below (in millions):
Level 2
September 30, 2022December 31, 2021
Commodity swaps (1)$23.9 $(14.5)
Level 2
September 30, 2023December 31, 2022
Interest rate swaps (1)$8.1 $— 
Commodity derivatives (2)$6.7 $25.7 
____________________________
(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 swapsderivatives represent the amount at which the instruments could be exchanged in a current arms-length transaction adjusted for our credit risk and/or the counterparty credit risk as required under ASC 820.

Fair Value of Financial Instruments

The estimated fair value of our financial instruments has been determined using available market information and valuation methodologies. Considerable judgment is required to develop the estimates of fair value; thus, the estimates provided below are not necessarily indicative of the amount we could realize upon the sale or refinancing of such financial instruments (in millions):
September 30, 2022December 31, 2021
Carrying ValueFair
Value		Carrying ValueFair
Value
Long-term debt (1)$4,537.4 $4,072.5 $4,363.7 $4,520.0 
Installment payable (2)$— $— $10.0 $10.0 
Contingent consideration (2)$4.4 $4.4 $6.9 $6.9 
September 30, 2023December 31, 2022
Carrying ValueFair
Value		Carrying ValueFair
Value
Long-term debt, including current maturities of long-term debt (1)$4,719.3 $4,331.2 $4,723.5 $4,385.9 
Contingent consideration (2)(3)$6.7 $6.7 $5.5 $5.5 
____________________________
(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 $35.8$33.5 million and $27.8$34.9 million as of September 30, 20222023 and December 31, 2021,2022, respectively. The respective fair values do not factor in debt issuance costs.
(2)Consideration for the Amarillo Rattler Acquisition included a $10.0 million installment payable, which was paid on April 30, 2022, and a contingent component capped at $15.0 million and payable, if at all, between 2024 and 2026 based on Diamondback E&P LLC’s drilling activity above historical levels. Estimated fair values were calculated using a discounted cash flow analysis that utilized Level 3 inputs.
(3)Consideration for the Central Oklahoma Acquisition included a contingent component, which is payable, if at all, between 2024 and 2027 based on fee revenue earned on certain contractually specified volumes for the annual periods beginning January 1, 2023 through December 31, 2026. Estimated fair values were calculated using a discounted cash flow analysis that utilized Level 3 inputs.

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

The fair values of all senior unsecured notes as of September 30, 20222023 and December 31, 20212022 were based on Level 2 inputs from third-party market quotations.

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Notes to Consolidated Financial Statements (Continued)
(Unaudited)

(14) Segment Information

We evaluatemanage and report our activities primarily according to the financial performancegeography and nature of our segments by including realized and unrealized gains and losses resulting from commodity swaps activity in the Permian, Louisiana, Oklahoma, and North Texas segments. Identification of the majority of our operating segments is based principally upon geographic regions served: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 pipelines, natural gas processing plants, natural gas and NGL storage facilities, and fractionation facilities located in Louisiana and our crude oil operations in ORV;

•Oklahoma Segment. The Oklahoma segment includes our natural gas gathering, processing, and transmission activities, and our crude oil operations in the Cana-Woodford, Arkoma-Woodford, northern Oklahoma Woodford, STACK, and CNOW shaleadjacent 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, andas well as our corporate assets and expenses.

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)
(Unaudited)

We evaluate the performance of our operating segments based on segment profit and adjusted gross margin. Adjusted gross margin is a non-GAAP financial measure. See “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures” for additional information. Summarized financial information for our reportable segments is shown in the following tables (in millions):
PermianLouisianaOklahomaNorth TexasCorporateTotals
Three Months Ended September 30, 2022
Natural gas sales$361.6 $383.8 $114.5 $42.8 $— $902.7 
NGL sales0.2 1,067.4 1.7 1.4 — 1,070.7 
Crude oil and condensate sales280.7 97.0 33.3 — — 411.0 
Product sales642.5 1,548.2 149.5 44.2 — 2,384.4 
NGL sales—related parties380.3 46.3 203.2 139.7 (769.5)— 
Crude oil and condensate sales—related parties— — — 2.6 (2.6)— 
Product sales—related parties380.3 46.3 203.2 142.3 (772.1)— 
Gathering and transportation20.9 22.1 45.9 49.9 — 138.8 
Processing11.1 0.4 31.4 39.5 — 82.4 
NGL services— 19.5 — 0.1 — 19.6 
Crude services5.7 8.1 3.0 0.1 — 16.9 
Other services0.2 0.4 0.2 0.1 — 0.9 
Midstream services37.9 50.5 80.5 89.7 — 258.6 
Other services—related parties— 0.1 — — (0.1)— 
Midstream services—related parties— 0.1 — — (0.1)— 
Revenue from contracts with customers1,060.7 1,645.1 433.2 276.2 (772.2)2,643.0 
Cost of sales, exclusive of operating expenses and depreciation and amortization (1)(903.3)(1,517.8)(315.3)(166.9)772.2 (2,131.1)
Realized gain (loss) on derivatives1.3 3.3 0.6 (2.9)— 2.3 
Change in fair value of derivatives2.4 4.0 9.5 2.3 — 18.2 
Adjusted gross margin161.1 134.6 128.0 108.7 — 532.4 
Operating expenses(49.7)(37.6)(23.5)(26.0)— (136.8)
Segment profit111.4 97.0 104.5 82.7 — 395.6 
Depreciation and amortization(36.8)(39.7)(51.5)(33.4)(1.2)(162.6)
Gain on disposition of assets— 0.1 0.1 0.6 — 0.8 
General and administrative— — — — (34.5)(34.5)
Interest expense, net of interest income— — — — (60.4)(60.4)
Loss on extinguishment of debt— — — — (5.7)(5.7)
Loss from unconsolidated affiliate investments— — — — (1.7)(1.7)
Other income— — — — 0.3 0.3 
Income (loss) before non-controlling interest and income taxes$74.6 $57.4 $53.1 $49.9 $(103.2)$131.8 
Capital expenditures$61.7 $6.5 $18.2 $6.5 $1.6 $94.5 
____________________________
(1)Includes related party cost of sales of $5.6 million for the three months ended September 30, 2022.
PermianLouisianaOklahomaNorth TexasCorporateTotals
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 sales345.2 78.0 24.7 — — 447.9 
Product sales473.3 926.4 65.0 23.4 — 1,488.1 
NGL sales—related parties247.4 5.3 126.0 78.7 (457.4)— 
Crude oil and condensate sales—related parties— — — 2.3 (2.3)— 
Product sales—related parties247.4 5.3 126.0 81.0 (459.7)— 
Gathering and transportation30.5 19.5 60.5 49.8 — 160.3 
Processing15.3 0.5 36.2 29.9 — 81.9 
NGL services— 20.5 — 0.1 — 20.6 
Crude services5.6 5.7 3.7 0.1 — 15.1 
Other services1.7 0.2 0.1 0.2 — 2.2 
Midstream services53.1 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 customers773.8 978.1 291.5 185.7 (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 revenues762.0 972.1 288.3 184.7 (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 margin157.7 122.1 131.2 90.5 — 501.5 
Operating expenses(55.0)(35.0)(26.6)(26.7)— (143.3)
Segment profit102.7 87.1 104.6 63.8 — 358.2 
Depreciation and amortization(42.1)(36.3)(54.6)(29.3)(1.5)(163.8)
Gross margin60.6 50.8 50.0 34.5 (1.5)194.4 
Impairments— (20.7)— — — (20.7)
Gain on disposition of assets— — 0.5 0.1 — 0.6 
General and administrative— — — — (30.4)(30.4)
Interest expense, net of interest income— — — — (67.9)(67.9)
Income from unconsolidated affiliate investments— — — — 1.0 1.0 
Other expense— — — — (0.6)(0.6)
Income (loss) before non-controlling interest and income taxes$60.6 $30.1 $50.5 $34.6 $(99.4)$76.4 
Capital expenditures$82.9 $23.1 $11.5 $17.0 $2.0 $136.5 

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)
(Unaudited)

PermianLouisianaOklahomaNorth TexasCorporateTotals
Three Months Ended September 30, 2021
Natural gas sales$159.3 $183.2 $58.2 $32.2 $— $432.9 
NGL sales0.4 898.6 0.3 (0.1)— 899.2 
Crude oil and condensate sales194.4 62.5 21.2 — — 278.1 
Product sales354.1 1,144.3 79.7 32.1 — 1,610.2 
NGL sales—related parties301.4 39.5 180.2 131.2 (652.3)— 
Crude oil and condensate sales—related parties— — — 1.5 (1.5)— 
Product sales—related parties301.4 39.5 180.2 132.7 (653.8)— 
Gathering and transportation12.8 16.3 44.6 39.0 — 112.7 
Processing7.5 0.9 26.5 27.0 — 61.9 
NGL services— 16.9 — — — 16.9 
Crude services5.5 10.3 2.8 0.1 — 18.7 
Other services0.2 0.4 0.1 0.1 — 0.8 
Midstream services26.0 44.8 74.0 66.2 — 211.0 
Crude services—related parties— — 0.1 — (0.1)— 
Other services—related parties— 0.1 — — (0.1)— 
Midstream services—related parties— 0.1 0.1 — (0.2)— 
Revenue from contracts with customers681.5 1,228.7 334.0 231.0 (654.0)1,821.2 
Cost of sales, exclusive of operating expenses and depreciation and amortization (1)(576.6)(1,110.8)(218.0)(149.4)654.0 (1,400.8)
Realized loss on derivatives(8.7)(14.9)(6.8)(2.0)— (32.4)
Change in fair value of derivatives10.2 (8.8)(2.3)(0.3)— (1.2)
Adjusted gross margin106.4 94.2 106.9 79.3 — 386.8 
Operating expenses(37.3)(30.5)(19.8)(19.3)— (106.9)
Segment profit69.1 63.7 87.1 60.0 — 279.9 
Depreciation and amortization(35.4)(34.6)(52.3)(28.5)(2.2)(153.0)
Gain on disposition of assets0.1 0.2 — 0.1 — 0.4 
General and administrative— — — — (28.2)(28.2)
Interest expense, net of interest income— — — — (60.1)(60.1)
Loss from unconsolidated affiliate investments— — — — (2.3)(2.3)
Income (loss) before non-controlling interest and income taxes$33.8 $29.3 $34.8 $31.6 $(92.8)$36.7 
Capital expenditures$25.8 $0.4 $10.3 $3.3 $0.6 $40.4 
____________________________
PermianLouisianaOklahomaNorth TexasCorporateTotals
Three Months Ended September 30, 2022
Natural gas sales$361.6 $383.8 $114.5 $42.8 $— $902.7 
NGL sales0.2 1,067.4 1.7 1.4 — 1,070.7 
Crude oil and condensate sales280.7 97.0 33.3 — — 411.0 
Product sales642.5 1,548.2 149.5 44.2 — 2,384.4 
NGL sales—related parties380.3 46.3 203.2 139.7 (769.5)— 
Crude oil and condensate sales—related parties— — — 2.6 (2.6)— 
Product sales—related parties380.3 46.3 203.2 142.3 (772.1)— 
Gathering and transportation20.9 22.1 45.9 49.9 — 138.8 
Processing11.1 0.4 31.4 39.5 — 82.4 
NGL services— 19.5 — 0.1 — 19.6 
Crude services5.7 8.1 3.0 0.1 — 16.9 
Other services0.2 0.4 0.2 0.1 — 0.9 
Midstream services37.9 50.5 80.5 89.7 — 258.6 
Other services—related parties— 0.1 — — (0.1)— 
Midstream services—related parties— 0.1 — — (0.1)— 
Revenue from contracts with customers1,060.7 1,645.1 433.2 276.2 (772.2)2,643.0 
Realized gain (loss) on derivatives1.3 3.3 0.6 (2.9)— 2.3 
Change in fair value of derivatives2.4 4.0 9.5 2.3 — 18.2 
Total revenues1,064.4 1,652.4 443.3 275.6 (772.2)2,663.5 
Cost of sales, exclusive of operating expenses and depreciation and amortization(903.3)(1,517.8)(315.3)(166.9)772.2 (2,131.1)
Adjusted gross margin161.1 134.6 128.0 108.7 — 532.4 
Operating expenses(49.7)(37.6)(23.5)(26.0)— (136.8)
Segment profit111.4 97.0 104.5 82.7 — 395.6 
Depreciation and amortization(36.8)(39.7)(51.5)(33.4)(1.2)(162.6)
Gross margin74.6 57.3 53.0 49.3 (1.2)233.0 
Gain on disposition of assets— 0.1 0.1 0.6 — 0.8 
General and administrative— — — — (34.5)(34.5)
Interest expense, net of interest income— — — — (60.4)(60.4)
Loss on extinguishment of debt— — — — (5.7)(5.7)
Loss from unconsolidated affiliate investments— — — — (1.7)(1.7)
Other income— — — — 0.3 0.3 
Income (loss) before non-controlling interest and income taxes$74.6 $57.4 $53.1 $49.9 $(103.2)$131.8 
Capital expenditures$61.7 $6.5 $18.2 $6.5 $1.6 $94.5 
(1)Includes related party cost of sales of $4.9 million for the three months ended September 30, 2021.

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)
(Unaudited)

PermianLouisianaOklahomaNorth TexasCorporateTotals
Nine Months Ended September 30, 2022
Natural gas sales$880.2 $868.2 $277.9 $106.1 $— $2,132.4 
NGL sales0.2 3,382.6 8.4 1.4 — 3,392.6 
Crude oil and condensate sales884.3 280.9 108.6 — — 1,273.8 
Product sales1,764.7 4,531.7 394.9 107.5 — 6,798.8 
NGL sales—related parties1,207.6 126.3 653.9 452.4 (2,440.2)— 
Crude oil and condensate sales—related parties— — 0.3 9.6 (9.9)— 
Product sales—related parties1,207.6 126.3 654.2 462.0 (2,450.1)— 
Gathering and transportation54.4 54.1 133.3 129.3 — 371.1 
Processing28.8 1.2 85.4 95.0 — 210.4 
NGL services— 61.8 — 0.2 — 62.0 
Crude services16.0 26.7 9.9 0.5 — 53.1 
Other services0.6 1.2 0.4 0.4 — 2.6 
Midstream services99.8 145.0 229.0 225.4 — 699.2 
Crude services—related parties— — 0.1 — (0.1)— 
Other services—related parties— 0.2 — — (0.2)— 
Midstream services—related parties— 0.2 0.1 — (0.3)— 
Revenue from contracts with customers3,072.1 4,803.2 1,278.2 794.9 (2,450.4)7,498.0 
Cost of sales, exclusive of operating expenses and depreciation and amortization (1)(2,628.0)(4,425.7)(913.4)(514.0)2,450.4 (6,030.7)
Realized loss on derivatives(11.3)(5.8)(18.9)(8.6)— (44.6)
Change in fair value of derivatives9.0 10.2 10.6 8.6 — 38.4 
Adjusted gross margin441.8 381.9 356.5 280.9 — 1,461.1 
Operating expenses(145.3)(105.4)(67.6)(68.3)— (386.6)
Segment profit296.5 276.5 288.9 212.6 — 1,074.5 
Depreciation and amortization(110.6)(114.6)(154.7)(90.5)(4.1)(474.5)
Gain (loss) on disposition of assets— 0.3 0.5 (4.7)— (3.9)
General and administrative— — — — (91.9)(91.9)
Interest expense, net of interest income— — — — (171.0)(171.0)
Loss on extinguishment of debt— — — — (6.2)(6.2)
Loss from unconsolidated affiliate investments— — — — (4.0)(4.0)
Other income— — — — 0.6 0.6 
Income (loss) before non-controlling interest and income taxes$185.9 $162.2 $134.7 $117.4 $(276.6)$323.6 
Capital expenditures$130.6 $18.5 $45.1 $17.7 $5.1 $217.0 
____________________________
(1)Includes related party cost of sales of $25.3 million for the nine months ended September 30, 2022.
PermianLouisianaOklahomaNorth TexasCorporateTotals
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 sales826.3 187.2 76.1 — — 1,089.6 
Product sales1,160.5 2,766.4 225.1 51.7 — 4,203.7 
NGL sales—related parties689.0 15.0 346.3 224.4 (1,274.7)— 
Crude oil and condensate sales—related parties— — — 7.8 (7.8)— 
Product sales—related parties689.0 15.0 346.3 232.2 (1,282.5)— 
Gathering and transportation83.1 58.2 175.8 153.8 — 470.9 
Processing43.8 0.9 107.9 92.5 — 245.1 
NGL services— 65.7 — 0.2 — 65.9 
Crude services18.6 17.8 13.1 0.5 — 50.0 
Other services5.0 0.9 0.4 0.7 — 7.0 
Midstream services150.5 143.5 297.2 247.7 — 838.9 
NGL services—related parties— — — 2.6 (2.6)— 
Midstream services—related parties— — — 2.6 (2.6)— 
Revenue from contracts with customers2,000.0 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 revenues1,988.0 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 margin446.7 388.6 388.3 284.6 — 1,508.2 
Operating expenses(156.2)(100.6)(78.3)(77.4)— (412.5)
Segment profit290.5 288.0 310.0 207.2 — 1,095.7 
Depreciation and amortization(123.6)(111.5)(163.1)(87.1)(4.2)(489.5)
Gross margin166.9 176.5 146.9 120.1 (4.2)606.2 
Impairments— (20.7)— — — (20.7)
Gain on disposition of assets0.1 0.2 0.8 0.7 — 1.8 
General and administrative— — — — (87.8)(87.8)
Interest expense, net of interest income— — — — (205.2)(205.2)
Loss from unconsolidated affiliate investments— — — — (3.7)(3.7)
Other expense— — — — (0.2)(0.2)
Income (loss) before non-controlling interest and income taxes$167.0 $156.0 $147.7 $120.8 $(301.1)$290.4 
Capital expenditures$191.2 $53.1 $59.3 $46.9 $4.8 $355.3 

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Notes to Consolidated Financial Statements (Continued)
(Unaudited)

PermianLouisianaOklahomaNorth TexasCorporateTotals
Nine Months Ended September 30, 2021
Natural gas sales$381.7 $426.4 $139.7 $109.4 $— $1,057.2 
NGL sales0.9 2,231.2 1.3 1.0 — 2,234.4 
Crude oil and condensate sales472.1 154.5 50.5 — — 677.1 
Product sales854.7 2,812.1 191.5 110.4 — 3,968.7 
NGL sales—related parties661.8 93.3 430.4 306.4 (1,491.9)— 
Crude oil and condensate sales—related parties— — 0.1 5.1 (5.2)— 
Product sales—related parties661.8 93.3 430.5 311.5 (1,497.1)— 
Gathering and transportation34.3 48.5 141.8 117.6 — 342.2 
Processing21.7 1.9 70.5 81.1 — 175.2 
NGL services— 56.0 — 0.2 — 56.2 
Crude services13.0 29.8 9.5 0.5 — 52.8 
Other services0.6 1.3 0.5 0.4 — 2.8 
Midstream services69.6 137.5 222.3 199.8 — 629.2 
Crude services—related parties— — 0.2 — (0.2)— 
Other services—related parties— 2.4 — — (2.4)— 
Midstream services—related parties— 2.4 0.2 — (2.6)— 
Revenue from contracts with customers1,586.1 3,045.3 844.5 621.7 (1,499.7)4,597.9 
Cost of sales, exclusive of operating expenses and depreciation and amortization (1)(1,304.5)(2,690.1)(533.9)(361.8)1,499.7 (3,390.6)
Realized loss on derivatives(69.8)(32.0)(15.7)(4.8)— (122.3)
Change in fair value of derivatives(3.0)(18.6)(9.4)(1.9)— (32.9)
Adjusted gross margin208.8 304.6 285.5 253.2 — 1,052.1 
Operating expenses(52.9)(91.4)(57.3)(58.4)— (260.0)
Segment profit155.9 213.2 228.2 194.8 — 792.1 
Depreciation and amortization(103.5)(106.8)(153.6)(86.0)(6.0)(455.9)
Gain on disposition of assets0.2 0.3 — 0.2 — 0.7 
General and administrative— — — — (80.3)(80.3)
Interest expense, net of interest income— — — — (180.1)(180.1)
Loss from unconsolidated affiliate investments— — — — (9.9)(9.9)
Other income— — — — 0.1 0.1 
Income (loss) before non-controlling interest and income taxes$52.6 $106.7 $74.6 $109.0 $(276.2)$66.7 
Capital expenditures$78.6 $5.4 $17.1 $7.6 $1.1 $109.8 
____________________________
(1)Includes related party cost of sales of $11.7 million for the nine months ended September 30, 2021.
PermianLouisianaOklahomaNorth TexasCorporateTotals
Nine Months Ended September 30, 2022
Natural gas sales$880.2 $868.2 $277.9 $106.1 $— $2,132.4 
NGL sales0.2 3,382.6 8.4 1.4 — 3,392.6 
Crude oil and condensate sales884.3 280.9 108.6 — — 1,273.8 
Product sales1,764.7 4,531.7 394.9 107.5 — 6,798.8 
NGL sales—related parties1,207.6 126.3 653.9 452.4 (2,440.2)— 
Crude oil and condensate sales—related parties— — 0.3 9.6 (9.9)— 
Product sales—related parties1,207.6 126.3 654.2 462.0 (2,450.1)— 
Gathering and transportation54.4 54.1 133.3 129.3 — 371.1 
Processing28.8 1.2 85.4 95.0 — 210.4 
NGL services— 61.8 — 0.2 — 62.0 
Crude services16.0 26.7 9.9 0.5 — 53.1 
Other services0.6 1.2 0.4 0.4 — 2.6 
Midstream services99.8 145.0 229.0 225.4 — 699.2 
Crude services—related parties— — 0.1 — (0.1)— 
Other services—related parties— 0.2 — — (0.2)— 
Midstream services—related parties— 0.2 0.1 — (0.3)— 
Revenue from contracts with customers3,072.1 4,803.2 1,278.2 794.9 (2,450.4)7,498.0 
Realized loss on derivatives(11.3)(5.8)(18.9)(8.6)— (44.6)
Change in fair value of derivatives9.0 10.2 10.6 8.6 — 38.4 
Total revenues3,069.8 4,807.6 1,269.9 794.9 (2,450.4)7,491.8 
Cost of sales, exclusive of operating expenses and depreciation and amortization(2,628.0)(4,425.7)(913.4)(514.0)2,450.4 (6,030.7)
Adjusted gross margin441.8 381.9 356.5 280.9 — 1,461.1 
Operating expenses(145.3)(105.4)(67.6)(68.3)— (386.6)
Segment profit296.5 276.5 288.9 212.6 — 1,074.5 
Depreciation and amortization(110.6)(114.6)(154.7)(90.5)(4.1)(474.5)
Gross margin185.9 161.9 134.2 122.1 (4.1)600.0 
Gain (loss) on disposition of assets— 0.3 0.5 (4.7)— (3.9)
General and administrative— — — — (91.9)(91.9)
Interest expense, net of interest income— — — — (171.0)(171.0)
Loss on extinguishment of debt— — — — (6.2)(6.2)
Loss from unconsolidated affiliate investments— — — — (4.0)(4.0)
Other income— — — — 0.6 0.6 
Income (loss) before non-controlling interest and income taxes$185.9 $162.2 $134.7 $117.4 $(276.6)$323.6 
Capital expenditures$130.6 $18.5 $45.1 $17.7 $5.1 $217.0 

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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, 20222023 and December 31, 20212022 (in millions):
Segment Identifiable Assets:Segment Identifiable Assets:September 30, 2022December 31, 2021Segment Identifiable Assets:September 30, 2023December 31, 2022
PermianPermian$2,553.8 $2,358.6 Permian$2,771.5 $2,661.4 
LouisianaLouisiana2,487.0 2,428.6 Louisiana2,164.0 2,310.7 
OklahomaOklahoma2,533.3 2,619.5 Oklahoma2,330.3 2,420.4 
North TexasNorth Texas1,130.2 896.8 North Texas1,025.5 1,094.6 
Corporate (1)Corporate (1)109.0 179.7 Corporate (1)199.2 163.9 
Total identifiable assetsTotal identifiable assets$8,813.3 $8,483.2 Total identifiable assets$8,490.5 $8,651.0 
____________________________
(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.

(15) Other Information

The following tables present additional detail for other current assets and other current liabilities, which consists of the following (in millions):
Other current assets:Other current assets:September 30, 2022December 31, 2021Other current assets:September 30, 2023December 31, 2022
Natural gas and NGLs inventory$149.8 $49.4 
Natural gas, NGLs, condensate, and crude oil inventoryNatural gas, NGLs, condensate, and crude oil inventory$91.2 $147.1 
Prepaid expenses and otherPrepaid expenses and other25.2 34.2 Prepaid expenses and other23.0 19.5 
Other current assetsOther current assets$175.0 $83.6 Other current assets$114.2 $166.6 

Other current liabilities:Other current liabilities:September 30, 2022December 31, 2021Other current liabilities:September 30, 2023December 31, 2022
Accrued interestAccrued interest$62.1 $47.2 Accrued interest$40.6 $57.6 
Accrued wages and benefits, including taxesAccrued wages and benefits, including taxes30.5 33.1 Accrued wages and benefits, including taxes23.6 38.1 
Accrued ad valorem taxesAccrued ad valorem taxes38.9 28.3 Accrued ad valorem taxes37.9 32.0 
Accrued settlement of mandatorily redeemable non-controlling interest (1)Accrued settlement of mandatorily redeemable non-controlling interest (1)— 10.5 
Capital expenditure accrualsCapital expenditure accruals22.1 23.2 Capital expenditure accruals59.8 23.4 
Short-term lease liabilityShort-term lease liability22.9 18.1 Short-term lease liability24.2 26.2 
Installment payable (1)— 10.0 
Inactive easement commitment (2)— 9.8 
Operating expense accrualsOperating expense accruals15.8 9.6 Operating expense accruals25.1 18.5 
OtherOther26.0 23.6 Other45.3 23.3 
Other current liabilitiesOther current liabilities$218.3 $202.9 Other current liabilities$256.5 $229.6 
____________________________
(1)Consideration forIn January 2023, we settled the Amarillo Rattler Acquisition included an installment payable, which was paid on April 30, 2022.
(2)Amount related to an inactive easement commitment, which was paidredemption of the mandatorily redeemable non-controlling interest in August 2022.one of our non-wholly owned subsidiaries.


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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)
(Unaudited)

(16) Commitments and Contingencies

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

AnotherOne of our subsidiaries, EnLink Energy GP, LLC is also(“EnLink Energy”), was involved in industry-wide multi-district litigation arising out of Winter Storm Uri. This matter is a multi-district litigation currentlyUri, pending in Harris County, Texas, in which multiple individual plaintiffs assertasserted 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. We believeOn January 26, 2023, the court dismissed the claims against our subsidiary lack meritthe pipeline and we intendother 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. 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.

(17) Subsequent Event

Divestitures. On November 1, 2023, we sold certain ORV crude assets in our Louisiana segment to a subsidiary of Ergon, Inc. in exchange for cash consideration of approximately $59.2 million, subject to post-closing purchase price adjustments, and a contingent payment of an additional $0.5 million subject to the buyer’s pursuit of certain commercial opportunities within three years after the acquisition date. For a further description of our ORV assets, see our Annual Report on Form 10-K for the year ended December 31, 2022 filed with the Commission on February 15, 2023.

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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.

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.

Overview

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

•gathering, compressing, treating, processing, transporting, storing, and selling natural gas;
•fractionating, transporting, storing, and selling NGLs; and
•gathering, transporting, stabilizing, storing, trans-loading, and selling crude oil and condensate, in addition to brine disposal services.

As of September 30, 2022,2023, our midstream energy asset network includes approximately 12,50013,600 miles of pipelines, 2526 natural gas processing plants with approximately 5.96.0 Bcf/d of processing capacity, seven fractionators with approximately 320,000 Bbls/d of fractionation capacity, barge and rail terminals, product storage facilities, purchasing and marketing capabilities, brine disposal wells, a crude oil trucking fleet, and equity investments in certain joint ventures. We manage and report our activities primarily according to the geography and nature of activity and geography.

activity. We evaluate the financial performance of our segments by including realized and unrealized gains and losses resulting from commodity swaps activity in the Permian, Louisiana, Oklahoma, and North Texas segments. Identification of the majority of our operating segments is based principally upon geographic regions served: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 pipelines, natural gas processing plants, natural gas and NGL storage facilities, and fractionation facilities located in Louisiana and our crude oil operations in ORV;

•Oklahoma Segment. The Oklahoma segment includes our natural gas gathering, processing, and transmission activities, and our crude oil operations in the Cana-Woodford, Arkoma-Woodford, northern Oklahoma Woodford, STACK, and CNOW shaleadjacent 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, andas well as our corporate assets and expenses.

We manage our consolidated operations by focusing on adjusted gross margin because our business is generally to gather, process, transport, or market natural gas, NGLs, crude oil, and condensate using our assets for a fee. We earn our fees through various fee-based contractual arrangements, which include stated fee-only contract arrangements or arrangements with fee-based components where we purchase and resell commodities in connection with providing the related service and earn a net margin as our fee. We earn our net margin under our purchase and resell contract arrangements primarily as a result of stated service-related fees that are deducted from the price of the commodity purchase. While our transactions vary in form, the essential element of most of our transactions is the use of our assets to transport a product or provide a processed product to an end-user or marketer at the tailgate of the plant, pipeline, or barge, truck, or rail terminal. Adjusted gross margin is a non-GAAP financial measure and is explained in greater detail under “Non-GAAP Financial Measures” below. Approximately 90% of our
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adjusted gross margin was derived from fee-based contractual arrangements with minimal direct commodity price exposure for the nine months ended September 30, 2022.2023.

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Our revenues and adjusted gross margins are generated from eight primary sources:

•gathering and transporting natural gas, NGLs, and crude oil on the pipeline systems we own;
•processing natural gas at our processing plants;
•fractionating and marketing recovered NGLs;
•providing compression services;
•providing crude oil and condensate transportation and terminal services;
•providing condensate stabilization services;
•providing brine disposal services; and
•providing natural gas, crude oil, and NGL storage.

The following customers individually represented greater than 10% of our consolidated revenues for the three and nine months ended September 30, 20222023 and 2021. The loss of these customers would have a material adverse impact on our results of operations because the revenues and adjusted gross margin received from transactions with these customers is material to us.2022. No other customers represented greater than 10% of our consolidated revenues during the periods presented.
Three Months Ended
September 30,		Nine Months Ended
September 30,		Three Months Ended
September 30,		Nine Months Ended
September 30,
20222021202220212023202220232022
Dow Hydrocarbons and Resources LLCDow Hydrocarbons and Resources LLC14.5 %14.0 %14.4 %14.5 %Dow Hydrocarbons and Resources LLC9.3 %14.5 %10.7 %14.4 %
Marathon Petroleum CorporationMarathon Petroleum Corporation11.8 %12.2 %14.4 %13.1 %Marathon Petroleum Corporation15.5 %11.8 %18.3 %14.4 %

We gather, transport, or store gas owned by others under fee-only contract arrangements based either on the volume of gas gathered, transported, or stored or, for firm transportation arrangements, a stated monthly fee for a specified monthly quantity with an additional fee based on actual volumes. We also buy natural gas from producers or shippers at a market index less a fee-based deduction subtracted from the purchase price of the natural gas. We then gather or transport the natural gas and sell the natural gas at a market index, thereby earning a margin through the fee-based deduction. We attempt to execute substantially all purchases and sales concurrently, or we enter into a future delivery obligation, thereby establishing the basis for the fee we will receive for each natural gas transaction. We are also party to certain long-term gas sales commitments that we satisfy through supplies purchased under long-term gas purchase agreements. When we enter into those arrangements, our sales obligations generally match our purchase obligations. However, over time, the supplies that we have under contract may decline due to reduced drilling or other causes, and we may be required to satisfy the sales obligations by buying additional gas at prices that may exceed the prices received under the sales commitments. In our purchase/sale transactions, the resale price is generally based on the same index at which the gas was purchased.
 
We typically buy mixed NGLs from our suppliers to our gas processing plants at a fixed discount to market indices for the component NGLs with a deduction for our fractionation fee. We subsequently sell the fractionated NGL products based on the same index-based prices. To a lesser extent, we transport and fractionate or store NGLs owned by others for a fee based on the volume of NGLs transported and fractionated or stored. The operating results of our NGL fractionation business are largely dependent upon the volume of mixed NGLs fractionated and the level of fractionation fees charged. With our fractionation business, we also have the opportunity for product upgrades for each of the discrete NGL products. We realize higher adjusted gross margins from product upgrades during periods with higher NGL prices.
 
We gather or transport crude oil and condensate owned by others by rail, truck, pipeline, and barge facilities under fee-only contract arrangements based on volumes gathered or transported. We also buy crude oil and condensate on our own gathering systems, third-party systems, and trucked from producers at a market index less a stated transportation deduction. We then transport and resell the crude oil and condensate through a process of basis and fixed price trades. We execute substantially all purchases and sales concurrently, thereby establishing the net margin we will receive for each crude oil and condensate transaction.

We realize adjusted gross margins from our gathering and processing services primarily through different contractual arrangements: processing margin (“margin”) contracts, POL contracts, POP contracts, fixed-fee based contracts, or a combination of these contractual arrangements. See “Item 3. Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk” for a detailed description of these contractual arrangements. Under any of these gathering and processing arrangements, we may earn a fee for the services performed, or we may buy and resell the gas and/or NGLs as part of the processing arrangement and realize a net margin as our fee. Under margin contract arrangements, our adjusted gross
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margins are higher during periods of high NGL prices relative to natural gas prices. Adjusted gross margin results under POL contracts are impacted only by the value of the liquids produced with margins higher during periods of higher liquids prices. Adjusted gross margin results under POP contracts are impacted only by the value of the natural gas and liquids produced with margins higher during periods of higher natural gas and liquids prices. Under fixed-fee based contracts, our adjusted gross margins are driven by throughput volume.
 
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Operating expenses are costs directly associated with the operations of a particular asset. Among the most significant of these costs are those associated with direct labor and supervision, property insurance, property taxes, repair and maintenance expenses, contract services, and utilities. These costs are normally fairly stable across broad volume ranges and therefore do not normally increase or decrease significantly in the short term with increases or decreases in the volume of gas, liquids, crude oil, and condensate moved through or by our assets.

CCS Business

We are currently developing an integrated offering to bringbuilding a carbon transportation business in support of CCS services to businessesactivity along the Mississippi River corridor in Louisiana, one of the highest CO2 emitting regions in the United States. We believe our existing asset footprint, including our extensive network of natural gas pipelines in Louisiana, our operating expertise and our customer relationships, provide EnLinkus with an advantage in building a CCS business.carbon transportation business and becoming the transporter of choice in the region.

Recent Developments Affecting Industry Conditions and Our Business

Current Market Environment

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

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

There has been, and we believe there will continue to be, volatility in commodity prices and in the relationships among NGL, crude oil, and natural gas prices. Commodity markets have now recovered from the reduction in global demand and low market prices experienced in 2020 due to the COVID-19 pandemic. However, oil and natural gas prices continue to remain volatile. Oil and natural gas prices rose during 2021 and rose especially rapidly in the first half of 2022 due to various factors, including a rebound in demand from economic activity after COVID-19 shutdowns, supply issues, and geopolitical events, including Russia’s invasion of Ukraine. Since that time, both oil and natural gas prices have moderated from their peaks earlier inremained volatile, with natural gas prices declining significantly since the year, although asbeginning of the date2023.

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Table of this report, the market priceContents
The table below presents selected average index prices for bothcrude oil, NGL, and natural gas are at higher levels than either has tradedfor the periods indicated.
Crude oilNGLNatural gas
$/Bbl (1)(2)$/Gal (1)(3)$/MMbtu (1)(4)
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 
2022 by quarter:
1st Quarter$95.01 $0.92 $4.56 
2nd Quarter$108.52 $0.97 $7.50 
3rd Quarter$91.43 $0.82 $7.95 
2022 Averages$98.25 $0.90 $6.68 
____________________________
(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 gas closing prices based on the OPIS Napoleonville daily average spot liquids prices.
(4)Natural gas closing prices based on Henry Hub Gas Daily closing prices.

The volatility in recent years.commodity prices may cause the adjusted gross margin and cash flows in certain areas of our business to vary from period to period. Our hedging strategies may not be sufficient to offset price volatility risk and, in any event, do not cover all of our throughput volumes.

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

Producers generally focus their drilling activity on certain producing basins depending on commodity price fundamentals and favorable drilling economics. In the last few years, many producers have increasingly focused their activities in the Permian Basin, because of the availability of higher investment returns. Currently, a large percentage of all drilling rigs operating in the
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United States are operating in the Permian Basin. We continue to experience a robust increase in volumes in our Permian segment as our operations in that basin are in a favorable position relative to producer activity. As a result of this concentration of drilling activity in the Permian Basin, other basins, including those in which we operate in Oklahoma and North Texas, have experienced reduced investment and declines in volumes produced. However, the rise in commodity prices during 2022 has led to renewed producer interest in both Oklahoma and North Texas and wewhich has continued into 2023. We expect the decline in natural gas prices since the beginning of the year will dampen producer activity to increase in boththese areas forduring the remainder of 2022 and during 2023.

Our Louisiana segment, while subject to commodity price trends, is less dependent on gathering and processing activities and more affected by industrial demand for the natural gas and NGLs that we supply. Industrial demand along the Gulf Coast region has remained strong throughout 20212022 and through the first three quarters of 2022,has continued into 2023, supported by regional industrial activity and export markets. Our activities and, in turn, our financial performance in the Louisiana segment isare highly dependent on the availability of natural gas and NGLs produced by our upstream gathering and processing business and by other market participants. To date, the supply of natural gas and NGLs has remained at levels sufficient for us to supply our customers, and maintaining such supply is a key business focus.

For additional discussion regarding these factors, see “Item 1A—Risk Factors—Business and Industry Risks” in our Annual Report on Form 10-K for the year ended December 31, 20212022 filed with the Commission on February 16, 2022.15, 2023.

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Inflation

Inflation in the United States increased significantly in 2022 and has continued to increase at a more modest pace through the third quarter of 2023. In addition, 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 2022 and 2023. This trend may continue during the remainder of 2023.

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.

Regulatory Developments

On January 20, 2021, the Biden Administration came into office and immediately issued a number of executive orders related to climate change and the production of oil and gas that could affect our operations and those of our customers, particularly those who may operate on public lands. While none of these initiatives to date have materially affected our operations or those of our customers, the Biden Administration could seek, in the future, to put into place executive orders, policy and regulatory reviews, or seek to have Congress pass legislation that could adversely affect the production of oil and natural gas, and our operations and those of our customers.

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

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

Any regulatory changes could adversely affect our business, financial condition, results of operations or cash flows, including our ability to make cash distributions to our unitholders. For more information, see our risk factors under “Environmental,Item 1A—Risk Factors—“Environmental, Legal Compliance, and Regulatory Risk” in Section 1A “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 20212022 filed with the Commission on February 16, 2022.15, 2023.

Other Recent Developments

Organic Growth and Acquisition

Acquisition of Barnett Shale Assets. On July 1, 2022, we acquired all of the equity interest in the gathering and processing assets of Crestwood Equity Partners LP located in the Barnett Shale, for a cash purchase price of $275.0 million plus working capital of $14.5 million. These assets include approximately 400 miles of lean and rich gas gathering pipeline and three processing plants with 425 MMcf/d of total processing capacity. See “Item 1. Financial Statements—Note 3” for more information regarding this acquisition.

Matterhorn Express Pipeline Joint Venture. On May 16, 2022, we entered into an agreement with WhiteWater Midstream, LLC, Devon Energy Corporation, and MPLX LP to construct a pipeline designed to transport up to 2.5 Bcf/d of natural gas through approximately 490 miles of 42-inch pipeline from Waha Hub in West Texas to Katy, Texas. Supply for the Matterhorn JV will be sourced from multiple upstream connections in the Permian Basin, including direct connections to processing facilities in the Midland Basin through an approximately 75-mile lateral, as well as a direct connection to the 3.2 Bcf/d Agua
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Blanca Pipeline. The Matterhorn Express Pipeline is expected to be in service in the third quarter of 2024, pending the receipt of customary regulatory and other approvals.

PhantomTiger II Processing Plant. In November 2021,April 2023, we began moving equipment and facilities associated with the Thunderbirdnon-operational Cowtown processing plant in Central OklahomaNorth Texas to our Delaware Basin JV operations in the Midland Basin. We completedPermian. The relocation is expected to increase the relocationprocessing capacity of the Phantom processing plant in October 2022, which increased our Permian Basin processing capacityfacilities by 235approximately 150 MMcf/d.

CCS Business

ExxonMobil Agreement. In October 2022, we entered into a transportation services agreement with a subsidiary of ExxonMobil in connection with We expect to complete the development of a CCS projectrelocation in the Mississippi River corridor in southeastern Louisiana. Under this agreement, we will deliver CO2 from the Mississippi River corridor to ExxonMobil’s storage location in Vermilion Parish. The reserved capacity available under this agreement is up to 10 million metric tonnes per year, with initial reserved capacitysecond quarter of 3.2 million metric tonnes per year, beginning in early 2025.2024.

BKV Agreement. GCF Operations. In June 2022,January 2023, we entered into an agreement with BKVbegan the process to develop a CCS projectrestart the GCF assets and expect operations to begin in the Barnett Shale. Under this agreement, wefirst half of 2024. We will separate COcontinue to make capital contributions during 2023 associated with the restart of these assets.2 from lean gas in our North Texas gathering systems and from rich gas delivered to our natural gas processing plant in Bridgeport, Texas. The CO2 waste stream will then be captured, compressed, transported, and sequestered by BKV, beginning in late 2023.

Debt and Equity

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

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

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

Common Unit Repurchase ProgramProgram. . Effective January 1, 2022,For the Board reauthorized our common unit repurchase program and reset the amount available for repurchases ofthree months ended September 30, 2023, we repurchased 2,253,012 outstanding common units in open market purchases, for an aggregate cost, including commissions, of $26.9 million, or an average of $11.93 per common unit. For the nine months ended September 30, 2023, we repurchased 7,690,821 outstanding common units in open market purchases, for an aggregate cost, including commissions, of $85.9 million, or an average of $11.16 per common unit.

GIP Repurchase Agreement. For the three months ended September 30, 2023, we repurchased 2,763,581 ENLC common units held by GIP for an aggregate cost of $27.5 million, or an average of $9.94 per common unit. For the nine months ended September 30, 2023, we repurchased 6,911,568 ENLC common units held by GIP for an aggregate cost of $75.3 million, or an average of $10.89 per common unit.

Additionally, on October 30, 2023, we repurchased 1,934,877 ENLC common units held by GIP at upan aggregate cost of $23.0 million, or an average of $11.91 per common unit. These units represent GIP’s pro rata share of the aggregate number of common units repurchased by us during the three months ended September 30, 2023. The per unit price we paid to $100.0 million. In July 2022,GIP was the Board increasedsame as the amount availableaverage 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 GIP units. As of September 30, 2023, $23.0 million is classified as “Other current liabilities” on the consolidated balance sheets related to our obligation to repurchase to $200.0 million. our common units from GIP.

See “Item 1. Financial Statements—Note 9” for more information regarding our common unit repurchase program.repurchases.

GIP Repurchase Agreement.ENLK’s Eleventh Amended and Restated Agreement of Limited Partnership. On February 15, 2022, we and GIP entered into an agreement pursuant to which we are repurchasing, on a quarterly basis, a pro rata portionSeptember 8, 2023, in connection with ENLK’s qualification of the ENLC common units held by GIP, based upon the number of common units purchased by us during the applicable quarter from public unitholders under our common unit repurchase program. The number of ENLC common units held by GIP that we repurchase in any quarter is calculated such that GIP’s then-existing economic ownership percentage of our outstanding common units is maintained after our repurchases of common units from public unitholders are taken into account, and the per unit price we pay to GIP is the average per unit price paid by us for the common units repurchased from public unitholders. See “Item 1. Financial Statements—Note 9” for more information regarding repurchases of ENLC common units held by GIP.

Redemption of Series B Preferred Units. In January 2022, we redeemed 3,333,334 Series B Preferred Units for total considerationto be eligible to be deposited through the Depository Trust Company, we amended and restated the limited partnership agreement of $50.5 million plus accrued distributions. In addition, upon such redemption, a corresponding numberENLK to, among other things, (i) reflect the cancellation of all
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outstanding ENLC Class C Common Units, which were automatically cancelled. The redemption price represents 101% of the preferred units’ par value. In connection with the Series B Preferred Unit redemption, we have agreed withnon-economic equity interests previously held by the holders of the Series B Preferred Units that we will pay cashand permitted such holders to participate in lieuany vote of making a quarterly PIK distribution through the distribution declaredholders of ENLC common units, (ii) provide for the fourthtermination of any rights of the holders of the Series B Preferred Units to PIK Distributions with respect to, and following, the earlier to occur of (x) any quarter in which the holders of 2022. the Series B Preferred Units give notice to the General Partner of its election to terminate such PIK Distribution right and (y) the quarter ending June 30, 2024, and (iii) 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 ENLK’s limited partnership agreement).

Repurchase of Series C Preferred Units. In February 2023, we repurchased 4,500 Series C Preferred Units for total consideration of $3.9 million. The repurchase price represented 87% of the preferred units’ par value.

See “Item 1. Financial Statements—Note 8” for more information regarding distributions with respect to the Series B Preferred Units and the Series C Preferred Units.

Debt

Senior Unsecured Notes Issuance. On April 3, 2023, we completed the sale of an additional $300.0 million aggregate principal amount of 6.50% senior unsecured notes due 2030 (the “Additional Notes”) at 99% of their face value. The Additional Notes were offered as an additional issuance of our existing 6.50% senior unsecured notes due 2030 that we issued on August 31, 2022 in an aggregate principal amount of $700.0 million. Net proceeds of approximately $294.5 million were used to repay a portion of the borrowings under the Revolving Credit Facility. The Additional Notes are fully and unconditionally guaranteed by ENLK.

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Non-GAAP Financial Measures

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

Adjusted Gross Margin

We define adjusted gross margin as revenues less cost of sales, exclusive of operating expenses and depreciation and amortization. We present adjusted gross margin by segment in “Results of Operations.” We disclose adjusted gross margin in addition to gross margin as defined by GAAP because it is the primary performance measure used by our management to evaluate consolidated operations. We believe adjusted gross margin is an important measure because, in general, our business is to gather, process, transport, or market natural gas, NGLs, condensate, and crude oil for a fee or to purchase and resell natural gas, NGLs, condensate, and crude oil for a margin. Operating expense is a separate measure used by our management to evaluate the operating performance of field operations. Direct labor and supervision, property insurance, property taxes, repair and maintenance, utilities, and contract services comprise the most significant portion of our operating expenses. We exclude all operating expenses and depreciation and amortization from adjusted gross margin because these expenses are largely independent of the volumes we transport or process and fluctuate depending on the activities performed during a specific period. The GAAP measure most directly comparable to adjusted gross margin is gross margin. Adjusted gross margin should not be considered an alternative to, or more meaningful than, gross margin as determined in accordance with GAAP. Adjusted gross margin has important limitations because it excludes all operating expenses and depreciation and amortization that affect gross margin. Our adjusted gross margin may not be comparable to similarly titled measures of other companies because other entities may not calculate these amounts in the same manner.
 
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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,		 Three Months Ended
September 30,		Nine Months Ended
September 30,
2022202120222021 2023202220232022
Total revenuesTotal revenues$2,663.5 $1,787.6 $7,491.8 $4,442.7 Total revenues$1,746.2 $2,663.5 $5,043.8 $7,491.8 
Cost of sales, exclusive of operating expenses and depreciation and amortizationCost of sales, exclusive of operating expenses and depreciation and amortization(2,131.1)(1,400.8)(6,030.7)(3,390.6)Cost of sales, exclusive of operating expenses and depreciation and amortization(1,244.7)(2,131.1)(3,535.6)(6,030.7)
Operating expensesOperating expenses(136.8)(106.9)(386.6)(260.0)Operating expenses(143.3)(136.8)(412.5)(386.6)
Depreciation and amortizationDepreciation and amortization(162.6)(153.0)(474.5)(455.9)Depreciation and amortization(163.8)(162.6)(489.5)(474.5)
Gross marginGross margin233.0 126.9 600.0 336.2 Gross margin194.4 233.0 606.2 600.0 
Operating expensesOperating expenses136.8 106.9 386.6 260.0 Operating expenses143.3 136.8 412.5 386.6 
Depreciation and amortizationDepreciation and amortization162.6 153.0 474.5 455.9 Depreciation and amortization163.8 162.6 489.5 474.5 
Adjusted gross marginAdjusted gross margin$532.4 $386.8 $1,461.1 $1,052.1 Adjusted gross margin$501.5 $532.4 $1,508.2 $1,461.1 

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Adjusted EBITDA

We define adjusted EBITDA as net income (loss) plus (less) interest expense, net of interest income; depreciation and amortization; impairments; (income) loss from unconsolidated affiliate investments; distributions from unconsolidated affiliate investments; (gain) loss on disposition of assets; (gain) loss on extinguishment of debt; unit-based compensation; income tax expense (benefit); unrealized (gain) loss on commodity swaps;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,		 Three Months Ended
September 30,		Nine Months Ended
September 30,
2022202120222021 2023202220232022
Net incomeNet income$116.6 $32.3 $306.5 $54.3 Net income$65.8 $116.6 $249.9 $306.5 
Interest expense, net of interest incomeInterest expense, net of interest income60.4 60.1 171.0 180.1 Interest expense, net of interest income67.9 60.4 205.2 171.0 
Depreciation and amortizationDepreciation and amortization162.6 153.0 474.5 455.9 Depreciation and amortization163.8 162.6 489.5 474.5 
Loss from unconsolidated affiliate investments1.7 2.3 4.0 9.9 
ImpairmentsImpairments20.7 — 20.7 — 
(Income) loss from unconsolidated affiliate investments(Income) loss from unconsolidated affiliate investments(1.0)1.7 3.7 4.0 
Distributions from unconsolidated affiliate investmentsDistributions from unconsolidated affiliate investments0.2 0.1 0.6 3.8 Distributions from unconsolidated affiliate investments0.1 0.2 2.4 0.6 
(Gain) loss on disposition of assets(Gain) loss on disposition of assets(0.8)(0.4)3.9 (0.7)(Gain) loss on disposition of assets(0.6)(0.8)(1.8)3.9 
Loss on extinguishment of debtLoss on extinguishment of debt5.7 — 6.2 — Loss on extinguishment of debt— 5.7 — 6.2 
Unit-based compensationUnit-based compensation11.4 6.4 23.7 19.3 Unit-based compensation5.7 11.4 14.2 23.7 
Income tax expenseIncome tax expense15.2 4.4 17.1 12.4 Income tax expense10.6 15.2 40.5 17.1 
Unrealized (gain) loss on commodity swaps(18.2)1.2 (38.4)32.9 
Unrealized (gain) loss on commodity derivativesUnrealized (gain) loss on commodity derivatives22.9 (18.2)19.0 (38.4)
Costs associated with the relocation of processing facilities (1)Costs associated with the relocation of processing facilities (1)9.7 8.8 32.1 26.6 Costs associated with the relocation of processing facilities (1)2.9 9.7 5.0 32.1 
Other (2)Other (2)(3.1)(0.2)(2.4)(0.2)Other (2)0.1 (3.1)0.6 (2.4)
Adjusted EBITDA before non-controlling interestAdjusted EBITDA before non-controlling interest361.4 268.0 998.8 794.3 Adjusted EBITDA before non-controlling interest358.9 361.4 1,048.9 998.8 
Non-controlling interest share of adjusted EBITDA from joint ventures (3)Non-controlling interest share of adjusted EBITDA from joint ventures (3)(18.0)(11.6)(51.4)(31.0)Non-controlling interest share of adjusted EBITDA from joint ventures (3)(17.0)(18.0)(49.7)(51.4)
Adjusted EBITDA, net to ENLCAdjusted EBITDA, net to ENLC$343.4 $256.4 $947.4 $763.3 Adjusted EBITDA, net to ENLC$341.9 $343.4 $999.2 $947.4 
____________________________
(1)Represents cost incurred thatto 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 related to the relocation of equipment and facilities from the Thunderbird processing plant and Battle Ridge processing plant in the Oklahoma segment to the Permian segment. The relocation of equipment and facilities from the Battle Ridge processing plant was completed in the third quarter of 2021 and we completed the relocation of equipment and facilities from the Thunderbird processing plant in October 2022.operations.
(2)Includes transaction costs, non-cash expense related to changes in the fair value of contingent consideration, accretion expense associated with asset retirement obligations, and non-cash rent, which relates to lease incentives pro-rated over the lease term.
(3)Non-controlling interest share of adjusted EBITDA from joint ventures includes NGP’s 49.9% share of adjusted EBITDA from the Delaware Basin JV and Marathon Petroleum Corporation’s 50% share of adjusted EBITDA from the Ascension JV.

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Free Cash Flow After Distributions

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

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

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

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

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

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The following table reconciles net cash provided by operating activities to adjusted EBITDA and free cash flow after distributions (in millions):
Three Months Ended
September 30,		Nine Months Ended
September 30,		Three Months Ended
September 30,		Nine Months Ended
September 30,
20222021202220212023202220232022
Net cash provided by operating activitiesNet cash provided by operating activities$343.3 $197.0 $825.9 $599.2 Net cash provided by operating activities$274.2 $343.3 $862.0 $825.9 
Interest expense (1)Interest expense (1)59.3 55.1 167.2 166.6 Interest expense (1)66.3 59.3 200.3 167.2 
Utility credits (redeemed) earned (2)(16.3)(5.6)(27.9)38.2 
Payments to terminate interest rate swaps (3)— 0.5 — 1.8 
Accruals for settled commodity swap transactions(0.3)(2.1)(1.9)(4.6)
Utility credits redeemed (2)Utility credits redeemed (2)— (16.3)(1.5)(27.9)
Accruals for settled commodity derivative transactionsAccruals for settled commodity derivative transactions— (0.3)— (1.9)
Distributions from unconsolidated affiliate investment in excess of earningsDistributions from unconsolidated affiliate investment in excess of earnings0.2 0.1 0.6 3.8 Distributions from unconsolidated affiliate investment in excess of earnings0.1 0.2 2.4 0.6 
Costs associated with the relocation of processing facilities (4)(3)Costs associated with the relocation of processing facilities (4)(3)9.7 8.8 32.1 26.6 Costs associated with the relocation of processing facilities (4)(3)2.9 9.7 5.0 32.1 
Other (5)(4)Other (5)(4)(0.1)(0.2)3.3 2.4 Other (5)(4)0.8 (0.1)0.8 3.3 
Changes in operating assets and liabilities which (provided) used cash:Changes in operating assets and liabilities which (provided) used cash:Changes in operating assets and liabilities which (provided) used cash:
Accounts receivable, accrued revenues, inventories, and otherAccounts receivable, accrued revenues, inventories, and other(54.3)167.6 255.6 276.8 Accounts receivable, accrued revenues, inventories, and other156.9 (54.3)(92.8)255.6 
Accounts payable, accrued product purchases, and other accrued liabilitiesAccounts payable, accrued product purchases, and other accrued liabilities19.9 (153.2)(256.1)(316.5)Accounts payable, accrued product purchases, and other accrued liabilities(142.3)19.9 72.7 (256.1)
Adjusted EBITDA before non-controlling interestAdjusted EBITDA before non-controlling interest361.4 268.0 998.8 794.3 Adjusted EBITDA before non-controlling interest358.9 361.4 1,048.9 998.8 
Non-controlling interest share of adjusted EBITDA from joint ventures (6)(5)Non-controlling interest share of adjusted EBITDA from joint ventures (6)(5)(18.0)(11.6)(51.4)(31.0)Non-controlling interest share of adjusted EBITDA from joint ventures (6)(5)(17.0)(18.0)(49.7)(51.4)
Adjusted EBITDA, net to ENLCAdjusted EBITDA, net to ENLC343.4 256.4 947.4 763.3 Adjusted EBITDA, net to ENLC341.9 343.4 999.2 947.4 
Growth capital expenditures, net to ENLC (7)(6)Growth capital expenditures, net to ENLC (7)(6)(82.7)(33.2)(173.1)(89.1)Growth capital expenditures, net to ENLC (7)(6)(97.4)(82.7)(264.7)(173.1)
Maintenance capital expenditures, net to ENLC (7)(6)Maintenance capital expenditures, net to ENLC (7)(6)(8.7)(6.9)(33.7)(19.1)Maintenance capital expenditures, net to ENLC (7)(6)(18.3)(8.7)(52.5)(33.7)
Interest expense, net of interest incomeInterest expense, net of interest income(60.4)(60.1)(171.0)(180.1)Interest expense, net of interest income(67.9)(60.4)(205.2)(171.0)
Distributions declared on common unitsDistributions declared on common units(54.8)(46.6)(164.9)(140.0)Distributions declared on common units(57.5)(54.8)(174.3)(164.9)
ENLK preferred unit accrued cash distributions (8)(23.3)(23.0)(70.1)(69.0)
Costs associated with the relocation of processing facilities (4)(9.7)(8.8)(32.1)(26.6)
Contribution to investment in unconsolidated affiliates(19.7)— (46.3)— 
Payments to terminate interest rate swaps— (0.5)— (1.8)
Non-cash interest expense— 2.7 — 7.3 
Other (9)0.8 0.5 1.1 1.3 
ENLK preferred unit cash distributions earned (7)ENLK preferred unit cash distributions earned (7)(24.6)(23.3)(72.2)(70.1)
Payment to redeem mandatorily redeemable non-controlling interest (8)Payment to redeem mandatorily redeemable non-controlling interest (8)— — (10.5)— 
Costs associated with the relocation of processing facilities, net to ENLC (3)(6)(9)Costs associated with the relocation of processing facilities, net to ENLC (3)(6)(9)(1.7)(9.7)5.0 (32.1)
Contributions to investment in unconsolidated affiliatesContributions to investment in unconsolidated affiliates(8.7)(19.7)(58.4)(46.3)
Other (10)Other (10)0.4 0.8 1.2 1.1 
Free cash flow after distributionsFree cash flow after distributions$84.9 $80.5 $257.3 $246.2 Free cash flow after distributions$66.2 $84.9 $167.6 $257.3 
____________________________
(1)Net of amortization of debt issuance costs, net discount of senior unsecured notes, and designated cash flow hedge, which are included in interest expense but not included in net cash provided by operating activities, and non-cash interest income, which is netted against interest expense but not included in adjusted EBITDA.
(2)Under our utility agreements, we are entitled to a base load of electricity and pay or receive credits, based on market pricing, when we exceed or do not use the base load amounts. Due to Winter Storm Uri, we received credits from our utility providers based on market rates for our unused electricity. These utility credits are recorded as “Other current assets” or “Other assets, net” on our consolidated balance sheets depending on the timing of their expected usage, and amortized as we incur utility expenses.
(3)Represents cash paid for the early termination ofcost incurred to execute discrete, project-based strategic initiatives aimed at realigning available processing capacity from our interest rate swaps dueOklahoma and North Texas segments to the partial repayment of the Term Loan in May 2021 and September 2021.
(4)Represents cost incurred thatPermian segment. These costs are not part of our ongoing operations related to the relocation of equipment and facilities from the Thunderbird processing plant and Battle Ridge processing plant in the Oklahoma segment to the Permian segment. The relocation of equipment and facilities from the Battle Ridge processing plant was completed in the third quarter of 2021 and we completed the relocation of equipment and facilities from the Thunderbird processing plant in October 2022.operations.
(5)(4)Includes transaction costs, current income tax expense, and non-cash rent, which relates to lease incentives pro-rated over the lease term.
(6)(5)Non-controlling interest share of adjusted EBITDA from joint ventures includes NGP’s 49.9% share of adjusted EBITDA from the Delaware Basin JV and Marathon Petroleum Corporation’s50% share of adjusted EBITDA from the Ascension JV.
(7)(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.
(8)(7)Represents the cash distributions earned by the Series B Preferred Units and Series C Preferred Units. See “Item“Item 1. Financial Statements—Note 8” 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. See “Item 1. Financial Statements—Note 2” for more information regarding the redemption.
(9)Includes a one-time $8.0 million contribution from an affiliate of NGP in May 2023 in connection with the Delaware Basin JV’s purchase of the Cowtown processing plant.
(10)Includes current income tax expense and proceeds from the sale of surplus or unused equipment and land, which occurred in the normal operation of our business.

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Results of Operations
 
The tables below set forth certain financial and operating data for the periods indicated. We evaluate the performance of our consolidated operations by focusing on adjusted gross margin, while we evaluate the performance of our operating segments based on segment profit and adjusted gross margin, as reflected in the tables below (in millions, except volumes):
PermianLouisianaOklahomaNorth TexasCorporateTotals
Three Months Ended September 30, 2023Three Months Ended September 30, 2023
Total revenuesTotal revenues$762.0 $972.1 $288.3 $184.7 $(460.9)$1,746.2 
Cost of sales, exclusive of operating expenses and depreciation and amortizationCost 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 marginAdjusted gross margin157.7 122.1 131.2 90.5 — 501.5 
Operating expensesOperating expenses(55.0)(35.0)(26.6)(26.7)— (143.3)
Segment profitSegment profit102.7 87.1 104.6 63.8 — 358.2 
Depreciation and amortizationDepreciation and amortization(42.1)(36.3)(54.6)(29.3)(1.5)(163.8)
Gross marginGross margin$60.6 $50.8 $50.0 $34.5 $(1.5)$194.4 
PermianLouisianaOklahomaNorth TexasCorporateTotalsPermianLouisianaOklahomaNorth TexasCorporateTotals
Three Months Ended September 30, 2022Three Months Ended September 30, 2022Three Months Ended September 30, 2022
Total revenuesTotal revenues$1,064.4 $1,652.4 $443.3 $275.6 $(772.2)$2,663.5 
Cost of sales, exclusive of operating expenses and depreciation and amortizationCost of sales, exclusive of operating expenses and depreciation and amortization(903.3)(1,517.8)(315.3)(166.9)772.2 (2,131.1)
Adjusted gross marginAdjusted gross margin161.1 134.6 128.0 108.7 — 532.4 
Operating expensesOperating expenses(49.7)(37.6)(23.5)(26.0)— (136.8)
Segment profitSegment profit111.4 97.0 104.5 82.7 — 395.6 
Depreciation and amortizationDepreciation and amortization(36.8)(39.7)(51.5)(33.4)(1.2)(162.6)
Gross marginGross margin$74.6 $57.3 $53.0 $49.3 $(1.2)$233.0 Gross margin$74.6 $57.3 $53.0 $49.3 $(1.2)$233.0 
PermianLouisianaOklahomaNorth TexasCorporateTotals
Nine Months Ended September 30, 2023Nine Months Ended September 30, 2023
Total revenuesTotal 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 amortizationCost 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 marginAdjusted gross margin446.7 388.6 388.3 284.6 — 1,508.2 
Operating expensesOperating expenses(156.2)(100.6)(78.3)(77.4)— (412.5)
Segment profitSegment profit290.5 288.0 310.0 207.2 — 1,095.7 
Depreciation and amortizationDepreciation and amortization36.8 39.7 51.5 33.4 1.2 162.6 Depreciation and amortization(123.6)(111.5)(163.1)(87.1)(4.2)(489.5)
Gross marginGross margin$166.9 $176.5 $146.9 $120.1 $(4.2)$606.2 
PermianLouisianaOklahomaNorth TexasCorporateTotals
Nine Months Ended September 30, 2022Nine Months Ended September 30, 2022
Total revenuesTotal revenues$3,069.8 $4,807.6 $1,269.9 $794.9 $(2,450.4)$7,491.8 
Cost of sales, exclusive of operating expenses and depreciation and amortizationCost of sales, exclusive of operating expenses and depreciation and amortization(2,628.0)(4,425.7)(913.4)(514.0)2,450.4 (6,030.7)
Adjusted gross marginAdjusted gross margin441.8 381.9 356.5 280.9 — 1,461.1 
Operating expensesOperating expenses(145.3)(105.4)(67.6)(68.3)— (386.6)
Segment profitSegment profit111.4 97.0 104.5 82.7 — 395.6 Segment profit296.5 276.5 288.9 212.6 — 1,074.5 
Operating expenses49.7 37.6 23.5 26.0 — 136.8 
Adjusted gross margin$161.1 $134.6 $128.0 $108.7 $— $532.4 
Three Months Ended September 30, 2021
Depreciation and amortizationDepreciation and amortization(110.6)(114.6)(154.7)(90.5)(4.1)(474.5)
Gross marginGross margin$33.7 $29.1 $34.8 $31.5 $(2.2)$126.9 Gross margin$185.9 $161.9 $134.2 $122.1 $(4.1)$600.0 
Depreciation and amortization35.4 34.6 52.3 28.5 2.2 153.0 
Segment profit69.1 63.7 87.1 60.0 — 279.9 
Operating expenses37.3 30.5 19.8 19.3 — 106.9 
Adjusted gross margin$106.4 $94.2 $106.9 $79.3 $— $386.8 

PermianLouisianaOklahomaNorth TexasCorporateTotals
Nine Months Ended September 30, 2022
Gross margin$185.9 $161.9 $134.2 $122.1 $(4.1)$600.0 
Depreciation and amortization110.6 114.6 154.7 90.5 4.1 474.5 
Segment profit296.5 276.5 288.9 212.6 — 1,074.5 
Operating expenses145.3 105.4 67.6 68.3 — 386.6 
Adjusted gross margin$441.8 $381.9 $356.5 $280.9 $— $1,461.1 
Nine Months Ended September 30, 2021
Gross margin$52.4 $106.4 $74.6 $108.8 $(6.0)$336.2 
Depreciation and amortization103.5 106.8 153.6 86.0 6.0 455.9 
Segment profit155.9 213.2 228.2 194.8 — 792.1 
Operating expenses52.9 91.4 57.3 58.4 — 260.0 
Adjusted gross margin$208.8 $304.6 $285.5 $253.2 $— $1,052.1 
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Three Months Ended
September 30,		Nine Months Ended
September 30,		Three Months Ended
September 30,		Nine Months Ended
September 30,
20222021202220212023202220232022
Midstream Volumes:Midstream Volumes:Midstream Volumes:
ConsolidatedConsolidated
Gathering and Transportation (MMbtu/d)Gathering and Transportation (MMbtu/d)7,095,800 7,316,000 7,064,400 6,724,500 
Processing (MMbtu/d)Processing (MMbtu/d)3,606,900 3,365,100 3,546,700 3,137,400 
Crude Oil Handling (Bbls/d)Crude Oil Handling (Bbls/d)216,600 197,700 201,200 200,800 
NGL Fractionation (Gals/d)NGL Fractionation (Gals/d)7,593,400 7,930,200 7,600,500 7,953,300 
Brine Disposal (Bbls/d)Brine Disposal (Bbls/d)3,400 3,000 3,000 3,100 
Permian SegmentPermian SegmentPermian Segment
Gathering and Transportation (MMbtu/d)Gathering and Transportation (MMbtu/d)1,596,400 1,111,800 1,480,200 1,021,800 Gathering and Transportation (MMbtu/d)1,840,800 1,596,400 1,752,800 1,480,200 
Processing (MMbtu/d)Processing (MMbtu/d)1,520,800 1,062,800 1,404,100 966,500 Processing (MMbtu/d)1,699,700 1,520,800 1,626,500 1,404,100 
Crude Oil Handling (Bbls/d)Crude Oil Handling (Bbls/d)157,700 157,500 161,200 129,400 Crude Oil Handling (Bbls/d)176,100 157,700 158,100 161,200 
Louisiana SegmentLouisiana SegmentLouisiana Segment
Gathering and Transportation (MMbtu/d)Gathering and Transportation (MMbtu/d)2,996,100 2,013,900 2,731,900 2,101,000 Gathering and Transportation (MMbtu/d)2,468,900 2,996,100 2,501,900 2,731,900 
Crude Oil Handling (Bbls/d)Crude Oil Handling (Bbls/d)18,500 17,600 17,400 16,000 Crude Oil Handling (Bbls/d)18,600 18,500 17,800 17,400 
NGL Fractionation (Gals/d)NGL Fractionation (Gals/d)7,930,200 7,050,500 7,953,300 7,295,100 NGL Fractionation (Gals/d)7,593,400 7,930,200 7,600,500 7,953,300 
Brine Disposal (Bbls/d)Brine Disposal (Bbls/d)3,000 3,300 3,100 2,500 Brine Disposal (Bbls/d)3,400 3,000 3,000 3,100 
Oklahoma SegmentOklahoma SegmentOklahoma Segment
Gathering and Transportation (MMbtu/d)Gathering and Transportation (MMbtu/d)1,036,400 996,900 1,017,600 983,700 Gathering and Transportation (MMbtu/d)1,223,000 1,036,400 1,218,600 1,017,600 
Processing (MMbtu/d)Processing (MMbtu/d)1,067,600 1,004,400 1,048,400 999,900 Processing (MMbtu/d)1,178,200 1,067,600 1,182,400 1,048,400 
Crude Oil Handling (Bbls/d)Crude Oil Handling (Bbls/d)21,500 20,000 22,200 20,400 Crude Oil Handling (Bbls/d)21,900 21,500 25,300 22,200 
North Texas SegmentNorth Texas SegmentNorth Texas Segment
Gathering and Transportation (MMbtu/d)Gathering and Transportation (MMbtu/d)1,687,100 1,377,600 1,494,800 1,370,700 Gathering and Transportation (MMbtu/d)1,563,100 1,687,100 1,591,100 1,494,800 
Processing (MMbtu/d)Processing (MMbtu/d)776,700 627,900 684,900 626,700 Processing (MMbtu/d)729,000 776,700 737,800 684,900 
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Three Months Ended September 30, 20222023 Compared to Three Months Ended September 30, 20212022

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

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 on 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 was $233.0is 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 $917.3 million and $886.4 million, respectively, for the three months ended September 30, 2023 compared to the three months ended September 30, 2022 due to the following:

•Product sales revenues and cost of sales, exclusive of operating expenses and depreciation and amortization, decreased $896.3 million and $886.4 million, respectively, for the three months ended September 30, 2023 compared to the three months ended September 30, 2022 primarily due to lower commodity prices in 2023.

•Revenues from midstream services increased $21.5 million for the three months ended September 30, 20222023 compared to $126.9the three months ended September 30, 2022 primarily due to higher processing volumes in 2023. Of these higher volumes in 2023, $5.2 million was related to contributions from acquisitions completed during 2022.

•Derivative losses increased $42.5 million for the three months ended September 30, 2021, an increase of $106.1 million. The primary contributors2023 compared to the increase were as follows:three months ended September 30, 2022 due to $1.4 million of decreased realized gains and $41.1 million of increased unrealized losses.

•Permian Segment.Operating Expenses. Gross margin was $74.6Operating expenses increased $6.5 million for the three months ended September 30, 20222023 compared to $33.7 million for the three months ended September 30, 2021, an increase of $40.9 million primarily due to the following:

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

•A $50.9 million increase to adjusted gross margin associated with our Permian gas assets. Adjusted gross margin, excluding derivative activity, increased $50.8 million, which was primarily due to higher volumes from increased producer activity and higher commodity prices. Derivative activity associated with our Permian gas assets increased margin by $0.1 million, which included $7.7 million from decreased realized losses and $7.6 million from decreased unrealized gains.
•A $3.8 million increase to adjusted gross margin associated with our Permian crude assets. Adjusted gross margin, excluding derivative activity, increased $1.7 million, which was primarily due to higher commodity prices. Derivative activity associated with our Permian crude assets increased margin by $2.1 million, which included $2.3 million from increased realized gains and $0.2 million from increased unrealized losses.

◦Operating expenses in the Permian segment increased $12.4 million due to higher construction fees and services, labor and benefits costs, materials and supplies expense, utility costs, and compressor rentals due to an increase in operating activity and the transfer of equipment to the Phantom processing facilities in 2022.

◦Depreciation and amortization in the Permian segment increased $1.4 million primarily due to new assets placed into service.

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

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

•An $15.1a $5.4 million increase to adjusted gross margin associated with our Louisiana NGL transmission and fractionation assets. Adjusted gross margin, excluding derivative activity, decreased $7.3 million, which was primarily due to fluctuations in market prices. Derivative activity associated with our Louisiana NGL transmission and fractionation assets increased margin by $22.4 million, which included $18.0 million from increased realized gains and $4.4 million from increased unrealized gains.
•A $25.8compressor rentals, a $1.3 million increase to adjusted gross margin associated with our Louisiana gas assets. Adjusted gross margin, excluding derivative activity, increased $18.0in labor and benefits costs, a $1.2 million which was primarily due to higher volumes from existing customers and higher commodity prices. Derivative activity associated with our Louisiana gas assets increased margin by $7.8 million, which included $0.6 million from increased realized losses and $8.4 million from decreased unrealized losses.
•A $0.5 million decrease to adjusted gross margin associated with our ORV crude assets. Adjusted gross margin, excluding derivative activity, decreased $1.3 million, which was primarily due to fluctuation in market prices. Derivative activity associated with our ORV crude assets increased margin by $0.8 million from increased realized gains.

◦Operating expenses in the Louisiana segment increased $7.1 million primarily due to increasesincrease in materials and supplies expense, utilitya $0.9 million increase in pipeline integrity compliance costs, a $0.8 million increase in construction fees and services, vehicle expenses, and a $0.7 million increase in consulting fees and services. These increases were partially offset by a $2.5 million decrease in utilities expense and a $2.4 million decrease in ad valorem taxes due to an increase in operating activity.taxes.

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

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

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

•A $21.7 million increase to adjusted gross margin associated with our Oklahoma gas assets. Adjusted gross margin, excluding derivative activity, increased $2.8 million, which was primarily due to higher volumes from existing customers. Derivative activity associated with our Oklahoma gas assets increased margin by $18.9 million, which included $7.1 million from increased realized gains and $11.8 million from increased unrealized gains.
•A $0.6 million decrease to adjusted gross margin associated with our Oklahoma crude assets. Adjusted gross margin, excluding derivative activity, decreased $0.9 million, which was primarily due to fluctuation in market prices. Derivative activity associated with our Oklahoma crude assets increased margin by $0.3 million from increased realized gains.

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

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

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

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

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

◦Depreciation and amortization in the North Texas segment increased $4.9 million primarily due to the acquisition of Barnett Shale gathering and processing assets on July 1, 2022.

•Corporate Segment. Gross margin was negative $1.2 million for the three months ended September 30, 20222023 compared to negative $2.2 million for the three months ended September 30, 2021. Corporate gross margin consists2022 primarily due to a $6.5 million increase resulting from changes in estimated useful lives, a $3.7 million increase due to additional assets placed in service, and a $1.1 million increase related to the Central Oklahoma Acquisition in December 2022. These increases were partially offset by a $9.9 million decrease in depreciation related to assets reaching the end of depreciationtheir depreciable lives.

Impairments. For the three months ended September 30, 2023, we recognized an impairment expense of $20.7 million due to changes in our future cash flow outlook and amortizationthe expected use of corporate assets.certain ORV crude assets in our Louisiana segment.

General and Administrative Expenses. General and administrative expenses were $30.4 million for the three months ended September 30, 2023 compared to $34.5 million for the three months ended September 30, 2022, compareda decrease of $4.1 million. The decrease was primarily due to $28.2a $5.5 million decrease in unit-based compensation and a $2.6 million decrease in consulting fees and services. The decrease was partially offset by a $3.2 million increase in losses related to an increase in the estimated fair value of the contingent consideration associated with the Amarillo Rattler Acquisition and the Central Oklahoma Acquisition, in addition to a $1.4 million increase in labor and benefits.

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Interest Expense, Net of Interest Income. Interest expense, net of interest income, was $67.9 million for the three months ended September 30, 2021, an increase of $6.3 million. The increase was primarily due2023 compared to an increase in unit-based compensation and consulting fees and services. The increase was partially offset by a gain related to a decrease in the estimated fair value of the Amarillo Rattler Acquisition contingent consideration.

Interest Expense. Interest expense was $60.4 million for the three months ended September 30, 2022, compared to $60.1an increase of $7.5 million. Interest expense, net of interest income, consisted of the following (in millions):
Three Months Ended
September 30,
20232022
ENLK and ENLC senior notes$58.8 $51.5 
Revolving Credit Facility4.0 4.4 
AR Facility5.2 3.6 
Amortization of debt issuance costs and net discount of senior unsecured notes1.6 1.1 
Interest rate swaps – realized(1.4)— 
Other(0.3)(0.2)
Interest expense, net of interest income$67.9 $60.4 

Income (Loss) from Unconsolidated Affiliate Investments. Income from unconsolidated affiliate investments was $1.0 million for the three months ended September 30, 2021, an increase2023 compared to a loss of $0.3 million. Interest expense consisted of the following (in millions):
Three Months Ended
September 30,
20222021
ENLK and ENLC Senior Notes$51.5 $50.3 
Term Loan— 1.0 
Revolving Credit Facility4.4 1.3 
AR Facility3.6 1.0 
Amortization of debt issuance costs and net discount of senior unsecured notes1.1 1.4 
Interest rate swaps - realized— 5.0 
Other(0.2)0.1 
Total$60.4 $60.1 

Loss from Unconsolidated Affiliate Investments. Loss from unconsolidated affiliate investments was $1.7 million for the three months ended September 30, 2022, compared to a lossan increase in income of $2.3 million for the three months ended September 30, 2021, a reduction in loss of $0.6$2.7 million. The reductionincrease in lossincome was primarily attributable to a reduction$1.6 million increase in loss of $0.9income related to the Matterhorn JV and a $1.1 million fromincrease related to our GCF investment and was partially offset by an increase in loss of $0.3 million from the Matterhorn JV.investment.

Income Tax Expense. Income tax expense was $10.6 million for the three months ended September 30, 2023 compared to an income tax expense of $15.2 million for the three months ended September 30, 2022, compared to ana decrease in income tax expense of $4.4 million for the three months ended September 30, 2021.$4.6 million. The increasedecrease in income tax expense was primarily attributable to the increasedecrease in income between periods. See “Item 1. Financial Statements—Note 7” for additional information.

Net Income Attributable to Non-Controlling Interest. Net income attributable to non-controlling interest was $36.3 million for the three months ended September 30, 2023 compared to net income of $35.8 million for the three months ended September 30, 2022, compared to net income of $30.4 million for the three months ended September 30, 2021, an increase of $5.4$0.5 million. ENLC’s non-controlling interest is comprised of Series B Preferred Units, Series C Preferred Units, NGP’s 49.9% share of the Delaware Basin JV, and Marathon Petroleum Corporation’s 50% share of the Ascension JV. The increase in income was primarily due to a $6.8$3.3 million increase in income attributable to the Series C Preferred Units and a $0.6 million increase attributable to Marathon Petroleum Corporation’s 50% share of the Ascension JV. These increases were partially offset by a $3.1 million decrease in income attributable to NGP’s 49.9% share of the Delaware Basin JV and was partially offset by a $0.6$0.3 million decrease attributable to Marathon Petroleum Corporation’s 50%
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share of the Ascension JV and a $0.8 million decrease in income attributable to the Series B Preferred Units following the partial redemptions of the Series B Units in December 2021 and January 2022.Units.

Nine Months Ended September 30, 2022 Compared to Nine Months Ended September 30, 2021Analysis of Operating Segments

Gross Margin. GrossWe manage and report our activities primarily according to the geography and nature of 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 adjusted gross margin was $600.0 millionand segment profit is gross margin. We also 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 ninethree months ended September 30, 20222023 compared to $336.2 million for the ninethree months ended September 30, 2021, an increase of $263.8 million. The primary contributors to the increase were as follows:2022.

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

◦AdjustedRevenues and cost of sales, exclusive of operating expenses and depreciation and amortization, decreased $302.4 million and $299.0 million, respectively, resulting in a decrease in adjusted gross margin in the Permian segment increased $233.0of $3.4 million, which was primarily driven by:

•A $218.3$7.9 million increase todecrease in adjusted gross margin associated with our Permian gas assets. Adjusted gross margin, excluding derivative activity, increased $146.5$0.1 million, which was primarily due to higher volumes from increased producer activity and higher commodity prices.existing customers. Derivative activity associated with our Permian gas assets increaseddecreased adjusted gross margin by $71.8$8.0 million, which included $60.5$2.9 million from decreased realized losses and $11.3$10.9 million from increased unrealized gains.losses.
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•A $14.7$4.5 million increase toin adjusted gross margin associated with our Permian crude assets. Adjusted gross margin, excluding derivative activity, increased $16.0$12.0 million, which was primarily due to higher volumes from increased producer activity.commodity prices. Derivative activity associated with our Permian crude assets decreased adjusted gross margin by $1.3$7.5 million, which included $2.0$8.6 million from increased realized losses and $1.1 million from decreased realized gains and $0.7 million from increased unrealized gains.losses.

◦Operating expenses in the Permian segment increased $92.4 million. During the nine months ended September 30, 2021, our Permian operating expenses were reduced by $48.1$5.3 million primarily due to electricity credits earned during Winter Storm Uria $3.9 million increase in February 2021 that were not available during the same period of 2022. Operating expenses also increased due to higher construction fees and services, labor and benefits costs,compressor rentals, a $2.1 million increase in utilities expense, a $1.5 million increase in materials and supplies expense, compressor rentals, and ad valorema $1.4 million increase in labor and sales and use taxesbenefits costs. These increases in operating expenses were principally due to an increase in operating activityactivity. These increases were offset by a $2.2 million decrease in construction fees and the transfer of equipment to the Warhorseservices, a $1.3 million decrease in ad valorem taxes, and Phantom processing facilitiesa $1.1 million decrease in 2022.sales and use tax.

◦Depreciation and amortization in the Permian segment increased $7.1$5.3 million primarily due to newa $3.7 million increase resulting from additional assets placed intoin service including gathering and a $1.7 million increase related to the equipment transferred to the Phantom processing assets associated with the Amarillo Rattler Acquisition in April 2021.facility.

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

◦AdjustedRevenues and cost of sales, exclusive of operating expenses and depreciation and amortization, decreased $680.3 million and $667.8 million, respectively, resulting in a decrease in adjusted gross margin in the Louisiana segment increased $77.3of $12.5 million, resulting from:

•A $43.6 million increase toNo change in adjusted gross margin associated with our Louisiana NGL transmission and fractionation assets. Adjusted gross margin, excluding derivative activity, increased $1.6$14.0 million, which was primarily due to higher volumes from existing customers.fluctuations in market prices. Derivative activity associated with our Louisiana NGL transmission and fractionation assets increaseddecreased adjusted gross margin by $42.0$14.0 million, which included $30.2$5.1 million from increaseddecreased realized gains and $11.8$8.9 million from increased unrealized gains.losses.
•An $34.3A $9.2 million increase todecrease in adjusted gross margin associated with our Louisiana gas assets. Adjusted gross margin, excluding derivative activity, increased $20.2decreased $11.2 million, which was primarily due to higher volumes from existing customers.lower commodity prices. Derivative activity associated with our Louisiana gas assets increased adjusted gross margin by $14.1$2.0 million, which included $4.0$3.1 million from increaseddecreased realized losses and $18.1$1.1 million from increased unrealized gains.losses.
•A $0.6$3.3 million decrease toin adjusted gross margin associated with our ORV crude assets. Adjusted gross margin, excluding derivative activity, increased $0.5decreased $2.0 million, which was primarily due to higher volumeslower compression fee revenue resulting from existing customers.the sale of several compressor units in December 2022. Derivative activity associated with our ORV crude assets decreased adjusted gross margin by $1.1$1.3 million from decreased unrealized gains.increased realized losses.

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◦Operating expenses in the Louisiana segment increased $14.0decreased $2.6 million primarily due to increasesa $4.5 million decrease in utility costs, construction fees and services, and compressor rentals due to an increase in operating activity. These increases wereutilities expense, partially offset by decreasesa $1.5 million increase in consultingconstruction fees and services.

◦Depreciation and amortization in the Louisiana segment increased $7.8decreased $3.4 million primarily due to a $5.8 million decrease resulting from assets reaching the end of their depreciable lives, partially offset by a $2.5 million increase in depreciation due to changes in estimated useful lives of certain non-core assets.lives.

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

◦AdjustedRevenues and cost of sales, exclusive of operating expenses and depreciation and amortization, decreased $155.0 million and $158.2 million, respectively, resulting in an increase in adjusted gross margin in the Oklahoma segment increased $71.0of $3.2 million, resulting from:

•A $73.6$2.1 million increase toin adjusted gross margin associated with our Oklahoma gas assets. Adjusted gross margin, excluding derivative activity, increased $53.6$15.1 million, which was primarily due to higheradditional volumes from existing customers, higher commodity prices, and the negative effectCentral Oklahoma Acquisition in 2021 of weather disruptions from Winter Storm Uri.December 2022. Derivative activity associated with our Oklahoma gas assets increaseddecreased adjusted gross margin by $20.0$13.0 million, which included $2.5$0.6 million from increased realized lossesgains and $22.5$13.6 million from increased unrealized gains.losses.
•A $2.6$1.1 million decrease toincrease in adjusted gross margin associated with our Oklahoma crude assets. Adjusted gross margin, excluding derivative activity, increased $0.6$1.4 million, which was primarily due to higher volumes from existing customers. Derivative activity associated with our Oklahoma crude assets decreased adjusted gross margin by $3.2 million, which included $0.7$0.3 million from increased realized losses and $2.5 million from decreased unrealized gains.losses.

◦Operating expenses in the Oklahoma segment increased $10.3$3.1 million primarily due to a $1.4 million increase in compressor rentals and a $1.1 million increase in ad valorem taxes. These increases in materials and supplies expense and construction fees and servicesoperating expenses were principally due to an increase in operating activity. Operating expenses alsoactivity from the Central Oklahoma Acquisition in December 2022.

◦Depreciation and amortization in the Oklahoma segment increased $3.1 million primarily due to a $4.1 million increase resulting from changes in estimated useful lives and a $1.1 million increase related to the Central Oklahoma Acquisition in December 2022. These increases were partially offset by a $1.7 million decrease in depreciation related to the transfer of equipment to the Phantom processing facility.

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

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

◦AdjustedRevenues and cost of sales, exclusive of operating expenses and depreciation and amortization, decreased $90.9 million and $72.7 million, respectively, resulting in a decrease in adjusted gross margin in the North Texas segment increased $27.7of $18.2 million. Adjusted gross margin, excluding derivative activity, increased $21.0decreased $17.8 million, which was primarily due to the acquisition of Barnett Shale gathering and processing assets on July 1, 2022.lower commodity prices. Derivative activity associated with our North Texas segment increaseddecreased adjusted gross margin by $6.7$0.4 million, which included $3.8$7.3 million from increased realized lossesgains and $10.5$7.7 million from increased unrealized gains.losses.

◦Operating expenses in the North Texas segment increased $9.9$0.7 million primarily due to a $1.5 million increase in construction fees and services, a $0.5 million increase in pipeline integrity compliance costs, a $0.5 million increase in consulting fees and services, and a $0.4 million increase in compressor overhauls. These increases were partially offset by a $2.1 million decrease in materials and supplies expense, ad valorem taxes, and utility costs due to an increase in operating activity and the acquisition of Barnett Shale gathering and processing assets on July 1, 2022.taxes.

◦Depreciation and amortization in the North Texas segment increased $4.5decreased $4.1 million primarily due to the acquisition of Barnett Shale gathering and processing assets on July 1, 2022, which was partially offset by assets reaching the end of their depreciable lives.

•Corporate Segment. Gross

◦Revenues and cost of sales, exclusive of operating expenses and depreciation and amortization, each increased $311.3 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 $0.3 million due to additional assets being placed in service.

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Nine Months Ended September 30, 2023 Compared to Nine Months Ended September 30, 2022

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 on 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 was negative $4.1is 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 $2,448.0 million and $2,495.1 million, respectively, for the nine months ended September 30, 2023 compared to the nine months ended September 30, 2022 due to the following:

•Product sales revenues and cost of sales, exclusive of operating expenses and depreciation and amortization, decreased $2,595.1 million and $2,495.1 million, respectively, for the nine months ended September 30, 2023 compared to the nine months ended September 30, 2022 primarily due to lower commodity prices in 2023.

•Revenues from midstream services increased $139.7 million for the nine months ended September 30, 20222023 compared to negative $6.0the nine months ended September 30, 2022 primarily due to higher processing volumes in 2023. Of these higher volumes in 2023, $33.7 million was related to contributions from acquisitions completed during 2022.

•Derivative gains increased $7.4 million for the nine months ended September 30, 2021. Corporate gross margin consists2023 compared to the nine months ended September 30, 2022 due to $64.8 million of depreciationincreased realized gains and amortization$57.4 million of corporate assets.increased unrealized losses.

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Operating Expenses. Operating expenses increased $25.9 million for the nine months ended September 30, 2023 compared to the nine months ended September 30, 2022 primarily due to a $15.4 million increase in compressor rentals, a $9.0 million increase in materials and supplies expense, a $6.6 million increase in labor and benefits costs, a $3.5 million increase in utilities expense, and a $2.4 million increase in compressor overhauls. These increases were partially offset by a $11.4 million decrease in construction fees and services and a $3.5 million decrease in sales and use tax.

Table of ContentsDepreciation and Amortization. Depreciation and amortization increased $15.0 million for the nine months ended September 30, 2023 compared to the nine months ended September 30, 2022 primarily due to an $18.0 million increase resulting from changes in estimated useful lives, an $8.1 million increase due to additional assets placed in service, a $5.5 million increase related to the Barnett Shale Acquisition in July 2022, and a $3.1 million increase related to the Central Oklahoma Acquisition in December 2022. These increases were partially offset by a $19.1 million decrease in depreciation related to assets reaching the end of their depreciable lives and a $0.5 million decrease related to the sale of several compressor units associated with our ORV assets in December 2022.

Impairments. For the nine months ended September 30, 2023, we recognized an impairment expense of $20.7 million due to changes in our future cash flow outlook and the expected use of certain ORV crude assets in our Louisiana segment.

General and Administrative Expenses. General and administrative expenses were $87.8 million for the nine months ended September 30, 2023 compared to $91.9 million for the nine months ended September 30, 2022, compareda decrease of $4.1 million. The decrease was primarily due to $80.3an $8.0 million decrease in unit-based compensation and a $2.4 million decrease in consulting fees and services. The decrease was partially offset by a $3.8 million increase in losses related to an increase in the estimated fair value of the contingent consideration associated with the Amarillo Rattler Acquisition and the Central Oklahoma Acquisition, in addition to a $2.8 million increase in labor and benefits.

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Interest Expense. Interest expense was $205.2 million for the nine months ended September 30, 2021, an increase of $11.6 million. The increase was primarily due2023 compared to an increase in unit-based compensation, labor costs, and consulting fees and services. The increase was partially offset by a gain related to a decrease in the estimated fair value of the Amarillo Rattler Acquisition contingent consideration.

Interest Expense. Interest expense was $171.0 million for the nine months ended September 30, 2022, compared to $180.1 million for the nine months ended September 30, 2021, a decreasean increase of $9.1$34.2 million. Interest expense consisted of the following (in millions):
Nine Months Ended
September 30,		Nine Months Ended
September 30,
2022202120232022
ENLK and ENLC Senior Notes$152.1 $150.9 
Term Loan— 3.7 
ENLK and ENLC senior notesENLK and ENLC senior notes$171.4 $152.1 
Revolving Credit FacilityRevolving Credit Facility8.9 4.0 Revolving Credit Facility15.8 8.9 
AR FacilityAR Facility6.4 3.0 AR Facility16.9 6.4 
Amortization of debt issuance costs and net discount of senior unsecured notesAmortization of debt issuance costs and net discount of senior unsecured notes3.7 3.9 Amortization of debt issuance costs and net discount of senior unsecured notes4.9 3.7 
Interest rate swaps - realized0.1 14.6 
Interest rate swaps – realizedInterest rate swaps – realized(3.0)0.1 
OtherOther(0.2)— Other(0.8)(0.2)
Total$171.0 $180.1 
Interest expense, net of interest incomeInterest expense, net of interest income$205.2 $171.0 

LossIncome (Loss) from Unconsolidated Affiliate Investments. Loss from unconsolidated affiliate investments was $3.7 million for the nine months ended September 30, 2023 compared to a loss of $4.0 million for the nine months ended September 30, 2022, compared to a loss of $9.9 million for the nine months ended September 30, 2021, a reductiondecrease in loss of $5.9$0.3 million. The reductiondecrease in loss was primarily attributable to a reduction$0.8 million decrease in loss of $5.7 million from our GCF investment, as a result ofrelated to the GCF assets being idled beginning in January 2021, and a reduction of loss of $0.5 million from the Cedar CoveMatterhorn JV. The reduction in lossThis decrease was partially offset by ana $0.4 million increase in loss of $0.3related to the Cedar Cove JV and a $0.1 million from the Matterhorn JV.increase in loss related to our GCF investment.

Income Tax Expense. Income tax expense was $40.5 million for the nine months ended September 30, 2023 compared to an income tax expense of $17.1 million for the nine months ended September 30, 2022, compared to an increase in income tax expense of $12.4 million for the nine months ended September 30, 2021.$23.4 million. The increase in income tax expense was primarily attributable to reduced income tax expense for the increase in income between periods and was partially offset bynine months ended September 30, 2022 due to the changes in the valuation allowance.allowance recorded on our deferred tax assets. See “Item 1. Financial Statements—Note 7” for additional information.

Net Income Attributable to Non-Controlling Interest. Net income attributable to non-controlling interest was $107.9 million for the nine months ended September 30, 2023 compared to net income of $105.2 million for the nine months ended September 30, 2022, compared to net income of $86.7 million for the nine months ended September 30, 2021, an increase of $18.5$2.7 million. ENLC’s non-controlling interest is comprised of Series B Preferred Units, Series C Preferred Units, NGP’s 49.9% share of the Delaware Basin JV, and Marathon Petroleum Corporation’s 50% share of the Ascension JV. The increase in income was primarily due to a $20.2an $8.4 million increase in income attributable to the Series C Preferred Units. The increase was partially offset by a $3.5 million decrease in income attributable to NGP’s 49.9% share of the Delaware Basin JV, a $1.7 million decrease attributable to the Series B Preferred Units, and was partially offset by a $0.1$0.5 million decrease attributable to Marathon Petroleum Corporation’s 50% share of the Ascension JVJV.

Analysis of Operating Segments

We manage and report our activities primarily according to the geography and nature of 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 adjusted gross margin and segment profit is gross margin. We also 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 nine months ended September 30, 2023 compared to the nine months ended September 30, 2022.

•Permian Segment.

◦Revenues and cost of sales, exclusive of operating expenses and depreciation and amortization, decreased $1,081.8 million and $1,086.7 million, respectively, resulting in an increase in adjusted gross margin in the Permian segment of $4.9 million, which was primarily driven by:

•A $0.5 million increase in adjusted gross margin associated with our Permian gas assets. Adjusted gross margin, excluding derivative activity, increased $1.0 million, which was primarily due to higher volumes from existing customers. Derivative activity associated with our Permian gas assets decreased adjusted gross margin by $0.5 million, which included $18.2 million from increased realized gains and $18.7 million from increased unrealized losses.
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•A $4.4 million increase in adjusted gross margin associated with our Permian crude assets. Adjusted gross margin, excluding derivative activity, increased $13.6 million, which was primarily due to higher commodity prices. Derivative activity associated with our Permian crude assets decreased adjusted gross margin by $9.2 million, which included $9.9 million from increased realized losses and $0.7 million from increased unrealized gains.

◦Operating expenses in the Permian segment increased $10.9 million primarily due to a $9.4 million increase in compressor rentals, a $7.4 million increase in utilities expense, a $3.6 million increase in labor and benefits costs, a $3.6 million increase in materials and supplies expense, and a $1.6$2.0 million increase in compressor overhauls. These increases in operating expenses were principally due to an increase in operating activity. These increases were offset by a $12.8 million decrease in income attributableconstruction fees and services, a $2.2 million decrease in sales and use tax, and a $2.2 million decrease in ad valorem taxes.

◦Depreciation and amortization in the Permian segment increased $13.0 million primarily due to a $8.1 million increase resulting from additional assets placed in service and a $5.0 million increase related to the Series B Preferred Units followingequipment transferred to the partial redemptionsPhantom processing facility.

•Louisiana Segment.

◦Revenues and cost of sales, exclusive of operating expenses and depreciation and amortization, decreased $1,880.1 million and $1,886.8 million, respectively, resulting in an increase in adjusted gross margin in the Series B UnitsLouisiana segment of $6.7 million, resulting from:

•A $10.9 million increase in adjusted gross margin associated with our Louisiana NGL transmission and fractionation assets. Adjusted gross margin, excluding derivative activity, increased $21.0 million, which was primarily due to fluctuations in market prices. Derivative activity associated with our Louisiana NGL transmission and fractionation assets decreased adjusted gross margin by $10.1 million, which included $1.4 million from decreased realized gains and $8.7 million from increased unrealized losses.
•An $8.2 million increase in adjusted gross margin associated with our Louisiana gas assets. Adjusted gross margin, excluding derivative activity, increased $1.6 million, which was primarily due to a settlement payment resulting from a customer account dispute in the amount of $6.8 million. This increase was partially offset by a $5.2 million decrease primarily due to lower commodity prices. Derivative activity associated with our Louisiana gas assets increased adjusted gross margin by $6.6 million, which included $4.9 million from decreased realized losses and $1.7 million from increased unrealized gains.
•A $12.4 million decrease in adjusted gross margin associated with our ORV crude assets. Adjusted gross margin, excluding derivative activity, decreased $14.1 million, which was primarily due to lower compression fee revenue resulting from the sale of several compressor units in December 20212022. Derivative activity associated with our ORV crude assets increased adjusted gross margin by $1.7 million from increased realized gains.

◦Operating expenses in the Louisiana segment decreased $4.8 million primarily due to a $5.6 million decrease in utilities expense, partially offset by a $0.9 million increase in construction fees and Januaryservices.

◦Depreciation and amortization in the Louisiana segment decreased $3.1 million primarily due to a $10.1 million decrease resulting from assets reaching the end of their depreciable lives and a $0.5 million decrease related to the sale of several compressor units associated with our ORV assets in December 2022. These decreases were partially offset by a $7.5 million increase in depreciation due to changes in estimated useful lives.

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•Oklahoma Segment.

◦Revenues and cost of sales, exclusive of operating expenses and depreciation and amortization, decreased $400.0 million and $431.8 million, respectively, resulting in an increase in adjusted gross margin in the Oklahoma segment of $31.8 million, resulting from:

•A $29.3 million increase in adjusted gross margin associated with our Oklahoma gas assets. Adjusted gross margin, excluding derivative activity, increased $20.0 million, which was primarily due to additional volumes from the Central Oklahoma Acquisition in December 2022. Derivative activity associated with our Oklahoma gas assets increased adjusted gross margin by $9.3 million, which included $23.4 million from increased realized gains and $14.1 million from increased unrealized losses.
•A $2.5 million increase in adjusted gross margin associated with our Oklahoma crude assets. Adjusted gross margin, excluding derivative activity, increased $2.2 million, which was primarily due to higher volumes from existing customers. Derivative activity associated with our Oklahoma crude assets increased adjusted gross margin by $0.3 million from increased realized gains.

◦Operating expenses in the Oklahoma segment increased $10.7 million primarily due to a $5.4 million increase in compressor rentals, a $3.1 million increase in ad valorem taxes, a $1.9 million increase in materials and supplies expense, a $1.8 million increase in labor and benefits costs, and a $1.3 million increase in utilities expense. These increases in operating expenses were principally due to an increase in operating activity from the Central Oklahoma Acquisition in December 2022. The increase was partially offset by a $2.5 million decrease in construction fees and services and a $0.6 million decrease in compressor overhauls.

◦Depreciation and amortization in the Oklahoma segment increased $8.4 million primarily due to a $10.5 million increase resulting from changes in estimated useful lives and a $3.1 million increase related to the Central Oklahoma Acquisition in December 2022. These increases were partially offset by a $5.0 million decrease in depreciation related to the transfer of equipment to the Phantom processing facility.

•North Texas Segment.

◦Revenues and cost of sales, exclusive of operating expenses and depreciation and amortization, decreased $251.4 million and $255.1 million, respectively, resulting in an increase in adjusted gross margin in the North Texas segment of $3.7 million. Adjusted gross margin, excluding derivative activity, decreased $5.6 million, which was primarily due to lower market prices. Derivative activity associated with our North Texas segment increased adjusted gross margin by $9.3 million, which included $27.6 million from increased realized gains and $18.3 million from increased unrealized losses.

◦Operating expenses in the North Texas segment increased $9.1 million primarily due to a $2.9 million increase in materials and supplies expense, a $2.8 million increase in construction fees and services, a $1.4 million increase in labor and benefits costs, a $0.7 million increase in compressor rentals, a $0.7 million increase in utilities expense, a $0.6 million increase in pipeline integrity compliance costs, and a $0.6 million increase in compressor overhauls. These increases in operating expenses were principally due to an increase in operating activity from the Barnett Shale Acquisition in July 2022. These increases were partially offset by a $1.0 million decrease in sales and use tax and a $0.7 million decrease in ad valorem taxes.

◦Depreciation and amortization in the North Texas segment decreased $3.4 million primarily due to a $9.1 million decrease resulting from assets reaching the end of their depreciable lives, which was partially offset by a $5.5 million increase in depreciation related to the Barnett Shale Acquisition in July 2022.

•Corporate Segment.

◦Revenues and cost of sales, exclusive of operating expenses and depreciation and amortization, each increased $1,165.3 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 $0.1 million due to additional assets placed in service.

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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, 20212022 filed with the Commission on February 16, 2022.15, 2023.

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Liquidity and Capital Resources

Cash Flows from Operating Activities. Net cash provided by operating activities was $862.0 million for the nine months ended September 30, 2023 compared to $825.9 million for the nine months ended September 30, 2022 compared to $599.2 million for the nine months ended September 30, 2021.2022. Operating cash flows before working capital and changes in working capital for the comparative periods were as follows (in millions):
Nine Months Ended
September 30,		Nine Months Ended
September 30,
2022202120232022
Operating cash flows before working capitalOperating cash flows before working capital$825.4 $559.5 Operating cash flows before working capital$841.9 $825.4 
Changes in working capitalChanges in working capital0.5 39.7 Changes in working capital20.1 0.5 

Operating cash flows before changes in working capital increased $265.9$16.5 million for the nine months ended September 30, 20222023 compared to the nine months ended September 30, 2021.2022. The primary contributor to the increase in operating cash flows wasbefore working capital is as follows:

•Gross margin, excluding depreciation and amortization, non-cash commodity swapderivative activity, utility credits redeemed or earned, and unit-based compensation, increased $273.7$48.9 million. The increase in gross margin is due to a $335.0$102.6 million increase in adjusted gross margin, excluding non-cash commodity swapderivative activity, which was partially offset by a $61.3$53.7 million increase in operating expenses, excluding utility credits redeemed or earned and unit-based compensation. For more information regarding the changes in gross margin for the nine months ended September 30, 20222023 compared to the nine months ended September 30, 2021,2022, see “Results of Operations.”

The increase in operating cash flows were partially offset by the following:

•Interest expense, net of interest income, excluding amortization of debt issue costs and net discounts, increased $33.0 million.

•General and administrative expenses, excluding unit-based compensation, increased $4.0 million.

The changes in working capital for the nine months ended September 30, 20222023 compared to the nine months ended September 30, 20212022 were primarily due to fluctuations in trade receivable and payable balances due to timing of collection and payments, changes in inventory balances attributable to normal operating fluctuations, and fluctuations in accrued revenue and accrued cost of sales.

Cash Flows from Investing Activities. Net cash used in investing activities was $373.4 million for the nine months ended September 30, 2023 compared to $547.0 million for the nine months ended September 30, 2022 compared to $155.4 million for the nine months ended September 30, 2021.2022. Our primary investing activities consisted of the following (in millions):
Nine Months Ended
September 30,		 Nine Months Ended
September 30,
20222021 20232022
Additions to property and equipment (1)Additions to property and equipment (1)$(213.2)$(104.7)Additions to property and equipment (1)$(320.9)$(213.2)
Contributions to unconsolidated affiliate investments (2)Contributions to unconsolidated affiliate investments (2)(46.3)— Contributions to unconsolidated affiliate investments (2)(58.4)(46.3)
Acquisitions, net of cash acquired (3)(289.5)(56.7)
Acquisition, net of cash acquired (3)Acquisition, net of cash acquired (3)— (289.5)
____________________________
(1)The increase in capital expenditures was due to expansion projects to accommodate increased volumes on our systems.
(2)Represents contributions to the Matterhorn JV and GCF. See “Item 1. Financial Statements—Note 10” for more information regarding the contributions to unconsolidated affiliate investments.
(3)Represents cash paid for the acquisition of Barnett Shale assetsAcquisition in July 2022 and the Amarillo Rattler Acquisition in April 2021.2022.

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Cash Flows from Financing Activities. Net cash used in financing activities was $463.1 million for the nine months ended September 30, 2023 compared to $305.1 million for the nine months ended September 30, 2022 compared to $447.3 million for the nine months ended September 30, 2021.2022. Our primary financing activities consisted of the following (in millions):
 Nine Months Ended
September 30,
 20222021
Net repayments on the Term Loan$— $(200.0)
Net borrowings (repayments) on the AR Facility (1)150.0 (5.0)
Net borrowings on the Revolving Credit Facility (1)55.0 — 
Net borrowings on ENLC’s senior unsecured notes (1)700.0 — 
Net repurchases of ENLK’s senior unsecured notes (1)(738.5)— 
Payment of installment payable for Amarillo Rattler Acquisition (2)(10.0)— 
Payment of inactive easement commitment (3)(10.0)— 
Contributions from non-controlling interests (4)14.2 2.4 
Distributions to members(167.4)(140.4)
Redemption of Series B Preferred Units (5)(50.5)— 
Distributions to Series B Preferred Unitholders (5)(53.1)(50.9)
Distributions to Series C Preferred Unitholders (5)(12.0)(12.0)
Distributions to joint venture partners (6)(50.3)(25.3)
Common unit repurchases (7)(113.2)(14.5)
 Nine Months Ended
September 30,
 20232022
Net borrowings (repayments) on the AR Facility (1)$(208.0)$150.0 
Net borrowings (repayments) on the Revolving Credit Facility (1)(95.0)55.0 
Net borrowings on ENLC’s senior unsecured notes (1)297.0 700.0 
Net repurchases of ENLK’s senior unsecured notes— (738.5)
Payment of installment payable for Amarillo Rattler Acquisition (2)— (10.0)
Payment of inactive easement commitment— (10.0)
Distributions to members(178.6)(167.4)
Distributions to Series B Preferred Unitholders (3)(47.8)(53.1)
Distributions to Series C Preferred Unitholders (3)(26.4)(12.0)
Distributions to joint venture partners (4)(58.0)(50.3)
Payment to redeem mandatorily redeemable non-controlling interest (5)(10.5)— 
Redemption of Series B Preferred Units (3)— (50.5)
Repurchase of Series C Preferred Units (3)(3.9)— 
Contributions from non-controlling interests (6)51.5 14.2 
Common unit repurchases (7)(162.4)(113.2)
Conversion of unit-based awards for common units, net of units withheld for taxes(19.3)(12.5)
____________________________
(1)See “Item 1. Financial Statements—Note 6” for more information regarding the AR Facility, the Revolving Credit Facility, and the issuanceadditional sale of newENLC’s 6.50% senior unsecured notes by us and repurchases of ENLK’s senior unsecured notes.due 2030 in April 2023.
(2)Consideration for the Amarillo Rattler Acquisition included an installment payable, which was paid on April 30, 2022.
(3)Amount related to an inactive easement commitment, which was paid in August 2022.
(4)Represents contributions from NGP to the Delaware Basin JV.
(5)See “Item 1. Financial Statements—Note 8” for information on distributions to holders of the Series B Preferred Units and Series C Preferred Units and information on the partial redemption of the Series B Preferred Units and the repurchase of the Series C Preferred Units.
(6)(4)Represents distributions to NGP for its ownership in the Delaware Basin JV and distributions to Marathon Petroleum Corporation for its ownership in the Ascension JV.
(5)In January 2023, we settled the redemption of the mandatorily redeemable non-controlling interest in one of our non-wholly owned subsidiaries. See “Item 1. Financial Statements—Note 2” for more information regarding the redemption.
(6)Represents contributions from NGP to the Delaware Basin JV.
(7)See “Item 1. Financial Statements—Note 9” for more information regarding the ENLCour common unit repurchase program.

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Capital Requirements

As of September 30, 2022,2023, the following table summarizes our expected remaining capital requirements for 20222023 (in millions):

Capital expenditures, net to ENLC (1)$108103 
Operating expenses associated with the relocation of processing facilities, net to ENLC (2)(3)1312 
Contributions to unconsolidated affiliate investments (3)(4)2417 
Total$145132 
____________________________
(1)Excludes capital expenditures that are contributed by other entities and relate to the non-controlling interest share of our consolidated entities.
(2)Represents cost incurred thatto 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 relatedoperations. These costs exclude amounts that are contributed by other entities and relate to the relocationnon-controlling interest share of equipment and facilities from the Thunderbird processing plant in the Oklahoma segment to the Permian segment. We completed the relocation of equipment and facilities from the Thunderbird processing plant in October 2022.our consolidated entities.
(3)Excludes a one-time $8.0 million contribution from an affiliate of NGP in May 2023 in connection with the Delaware Basin JV’s purchase of the Cowtown processing plant.
(4)Includes contributions made to our GCF investment and the Matterhorn JV.

Our primary remaining capital projects for 20222023 include the relocation of the PhantomCowtown processing plant, which was completed in October 2022, CCS-related initiatives, contributions to unconsolidated affiliate investments, including the restart of GCF, continued development of our existing systems through well connects, and other low-cost development projects. We expect to fund our remaining 20222023 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, 2022.2023.

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Total Contractual Cash Obligations. A summary of our total contractual cash obligations as of September 30, 20222023 is as follows (in millions):
Payments Due by Period Payments Due by Period
TotalRemainder 20222023202420252026Thereafter TotalRemainder 20232024202520262027Thereafter
ENLC’s & ENLK’s senior unsecured notesENLC’s & ENLK’s senior unsecured notes$4,009.2 $— $— $97.9 $421.6 $491.0 $2,998.7 ENLC’s & ENLK’s senior unsecured notes$4,309.2 $— $97.9 $421.6 $491.0 $— $3,298.7 
Revolving Credit Facility (1)Revolving Credit Facility (1)70.0 — — — — — 70.0 Revolving Credit Facility (1)160.0 — — — — 160.0 — 
AR Facility (2)(1)AR Facility (2)(1)500.0 — — — 500.0 — — AR Facility (2)(1)292.0 — — 292.0 — — — 
Acquisition contingent consideration (3)4.4 — — 0.2 0.1 4.1 — 
Interest payable on fixed long-term debt obligations2,498.0 59.1 215.8 213.5 202.6 193.8 1,613.2 
Interest payable on fixed long-term debt obligations (1)Interest payable on fixed long-term debt obligations (1)2,395.4 35.8 233.0 222.1 213.3 189.5 1,501.7 
Acquisition contingent consideration (2)Acquisition contingent consideration (2)6.7 — 0.2 1.2 5.0 0.3 — 
Repurchase of ENLC common units held by GIP (3)Repurchase of ENLC common units held by GIP (3)23.0 23.0 — — — — — 
Operating lease obligationsOperating lease obligations115.1 6.7 24.3 13.8 10.8 8.9 50.6 Operating lease obligations108.3 8.0 23.9 16.6 9.2 8.2 42.4 
Purchase obligationsPurchase obligations8.3 8.3 — — — — — Purchase obligations13.0 13.0 — — — — — 
Pipeline and trucking capacity and deficiency agreements (4)Pipeline and trucking capacity and deficiency agreements (4)283.9 14.6 60.6 47.8 40.5 30.9 89.5 Pipeline and trucking capacity and deficiency agreements (4)941.3 22.3 85.3 113.2 100.1 88.0 532.4 
Total contractual obligationsTotal contractual obligations$7,488.9 $88.7 $300.7 $373.2 $1,175.6 $728.7 $4,822.0 Total contractual obligations$8,248.9 $102.1 $440.3 $1,066.7 $818.6 $446.0 $5,375.2 
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(1)The interest payable related to the Revolving Credit Facility permits usand 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 borrow up to $1.40 billion on a revolving credit basistime. See “Item 1. Financial Statements—Note 6” for more information regarding the Revolving Credit Facility and will mature on June 3, 2027.the AR Facility.
(2)The AR Facility will terminate on August 1, 2025, unless extended or earlier terminated in accordance with its terms.
(3)The estimated fair value of the contingent consideration for the Amarillo Rattler Acquisition contingent considerationand 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. See “Item 1. Financial Statements—Note 13” for additional information.
(3)Relates to the repurchase of ENLC common units held by GIP on October 30, 2023. See “Item 1. Financial Statements—Note 9” for more information.
(4)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.

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

Our contractual cash obligations for the remainder of 20222023 are expected to be funded from cash flows generated from our operations.

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Indebtedness

Revolving Credit Facility. As of September 30, 2022,2023, there were $160.0 million in outstanding borrowings and $29.6 million in outstanding letters of credit under the Revolving Credit Facility.

AR Facility. As of September 30, 2023, the AR Facility had a borrowing base of $500.0$443.4 million and there were $500.0$292.0 million in outstanding borrowings under the AR Facility. 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.

In addition, asSenior Unsecured Notes. As of September 30, 2022,2023, we have $4.0had $4.3 billion in aggregate principal amount of outstanding unsecured senior notes maturing from 2024 to 2047. There were $70.02047, of which $97.9 million in outstanding borrowingsmatures on April 1, 2024 and $46.6 million in outstanding lettersis classified as “Current maturities of credit underlong-term debt” on the Revolving Credit Facility as of September 30, 2022.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, 2022,2023, 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 6” for more information on our outstanding debt.

Inflation

The annual U.S. inflation rate hasInflation in the United States increased significantly in 2022 and has continued to increase at a more modest pace through the first three quartersthird quarter of 2022. The Federal Reserve has already increased its target2023. 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 the federal funds rate (the benchmark for most interest rates) several times this year. It is widely expected that this trend will continue for the remainder of 2022. Inflation will increase the cost to acquire or replace property and equipment and the cost of labor and supplies. To the extent permitted by competition, regulation, and our existing agreements, we have and will continue to pass along increased costs to our customers in the form of higher fees. Additionally, certain of our revenue generating contracts contain clauses that increase our fees based on changes in inflation metrics.more information.

Recent Accounting Pronouncements

We have reviewed recently issued accounting pronouncements that became effective during the three months ended September 30, 20222023 and have determined that none would havehad a material impact to our consolidated financial statements.

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Disclosure Regarding Forward-Looking Statements
 
This Quarterly Report on Form 10-Q contains forward-looking statements within the meaning of the federal securities laws. Although these statements reflect the current views, assumptions and expectations of our management, the matters addressed herein involve certain assumptions, risks and uncertainties that could cause actual activities, performance, outcomes and results to differ materially from those indicated herein. Therefore, you should not rely on any of these forward-looking statements. All statements, other than statements of historical fact, included in this Quarterly Report on Form 10-Q constitute forward-looking statements, including, but not limited to, statements identified by the words “forecast,” “may,” “believe,” “will,” “should,” “plan,” “predict,” “anticipate,” “intend,” “estimate,” “expect,” “continue,” and similar expressions. Such forward-looking statements include, but are not limited to, statements about future results and growth of our CCS business, when additional capacity will beexpected 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, future cost savings or operational, environmental and climate change initiatives, our future capital structure and credit ratings, objectives, strategies, expectations, and intentions, the impact of the COVID-19 pandemic, the impact of weather related events on us and our financial results and operations, and other statements that are not historical facts. Factors that could result in such differences or otherwise materially affect our financial condition, results of operations, or cash flows, include, without limitation,(a) the impact of the ongoing coronavirus (COVID-19) pandemic (including the impact of any new variants of the virus) on our business, financial condition, and results of operations, (b) potential conflicts of interest of GIP with us and the potential for GIP to favor GIP’s own interests to the detriment of our unitholders, (c)(b) GIP’s ability to compete with us and the fact that it is not required to offer us the opportunity to acquire additional assets or businesses, (d)(c) a default under GIP’s credit facility could result in a change in control of us, could adversely affect the price of our common units, and could result in a default or prepayment event under our credit facility and certain of our other debt, (e)(d) the dependence on our significantkey customers for a substantial portion of the natural gas and crude that we gather, process, and transport, (f)(e) developments that materially and adversely affect our significantkey customers or other customers, (g)(f) adverse developments in the midstream business that may reduce our ability to make distributions, (h)(g) competition for crude oil, condensate, natural gas, and NGL supplies and any decrease in the availability of such commodities, (i)(h) decreases in the volumes that we gather, process, fractionate, or transport, (j)(i) increasing scrutiny and changing expectations from stakeholders with respect to our environment, social, and governance practices, (k)(j) our ability to receive or renew required permits and other approvals, (l)(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, (m)(l) climate change legislation and regulatory initiatives resulting in increased operating costs and reduced demand for the natural gas and NGL services we provide, (n)(m) changes in the availability and cost of capital, including as a result of a change in our credit rating, (o)(n) volatile prices and market demand for crude oil, condensate, natural gas, and NGLs that are beyond our control, (p)(o) our debt levels could limit our flexibility and adversely affect our financial health or limit our flexibility to obtain financing and to pursue other business opportunities, (q)(p) operating hazards, natural disasters, weather-related issues or delays, casualty losses, and other matters beyond our control, (r)(q) reductions in demand for NGL products by the petrochemical, refining, or other industries or by the fuel markets, (s)(r) impairments to goodwill, long-lived assets and equity method investments, (t)(s) construction risks in our major development projects, (u)(t) challenges we may face in or in connection with our strategy to enter into new lines of business related to the energy transition, (u) the impact of the coronavirus (COVID-19) pandemic (including the impact of any new variants of the virus) and similar pandemics, (v) our ability to effectively integrate and manage assets we acquire through acquisitions, and (w) the effects of existing and future laws and governmental regulations, including environmental and climate change requirements and other uncertainties. In addition to the specific uncertainties, factors, and risks discussed above and elsewhere in this Quarterly Report on Form 10-Q, the risk factors set forth in Part I, “Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 20212022, filed with the Commission on February 16, 202215, 2023, may affect our performance and results of operations. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may differ materially from those in the forward-looking statements. We disclaim any intention or obligation to update or review any forward-looking statements or information, whether as a result of new information, future events, or otherwise.

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Item 3. Quantitative and Qualitative Disclosures about Market Risk

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

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

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

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Commodity Price Risk

We are also subject to direct risks due to fluctuations in commodity prices. While approximately 90% of our adjusted gross margin for the nine months ended September 30, 20222023 was generated from arrangements with fee-based structures with minimal direct commodity price exposure, the remainder is subject to more direct commodity price exposure. Our exposure to these commodity price fluctuations is primarily in the gas processing component of our business. We currently earn adjusted gross margin under fourFor more information regarding our main types of contractual arrangements, (or a combinationsee “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” of these types of contractual arrangements) as summarized below.

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

2.Processing margin contracts. Under these contracts, we pay the producerAnnual Report on Form 10-K for the full amount of inlet gas toyear ended December 31, 2022 filed with the plant, and we make a margin basedCommission on the difference between the value of liquids recovered from the processed natural gas as compared to the value of the natural gas volumes lost and the cost of fuel used in processing. The shrink and fuel losses are referred to as plant thermal reduction, or PTR. Our margins from these contracts are high during periods of high liquids prices relative to natural gas prices and can be negative during periods of high natural gas prices relative to liquids prices. However, we mitigate our risk of processing natural gas when margins are negative primarily through our ability to bypass processing when it is not profitable for us or by contracts that revert to a minimum fee for processing if the natural gas must be processed to meet pipeline quality specifications. For the nine months ended September 30, 2022, less than 1% of our adjusted gross margin was generated from processing margin contracts.

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

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

For the nine months ended September 30, 2022, approximately 10% of our adjusted gross margin was generated from POL or POP contracts.February 15, 2023.

Our primary commodity risk management objective is to reduce volatility in our cash flows. We maintain a risk management committee, including members of senior management, which oversees all hedging activity. We enter into hedges for natural gas, crude and condensate, and NGLs using OTC derivative financial instruments with only certain well-capitalized counterparties, which have been approved in accordance with our commodity risk management policy.
 
We have hedged our exposure to fluctuations in prices for natural gas, NGLs, and crude oil volumes produced for our account. We have tailored our hedges to generally match the product composition and the delivery points to those of our physical equity volumes. The hedges cover specific products based upon our expected equity composition.

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We manage our exposure to changes in commodity prices by hedging the impact of market fluctuations. Commodity swapsderivatives are used both to manage and hedge price and location risk related to these market exposures and to manage margins on offsetting fixed-price purchase or sale commitments for physical quantities of NGLs, natural gas, and crude, and condensate. The following table presents the relevant pricing index for each commodity:
CommodityIndex
NGLsOil Price Information Service
Natural gasHenry Hub Gas Daily
Crude and condensateNew York Mercantile Exchange

The following table sets forth certain information related to derivative instruments outstanding at September 30, 2022.2023.
PeriodUnderlyingNotional Volume
(Net Position)		We PayReference PriceWe Receive (1)Price RangeNet Fair Value
Asset/(Liability)
(In millions)Millions)
October 20222023 - SeptemberOctober 2023Ethane720 (Mbbls)(1.1) MMgalsIndexOPIS Mt Belvieu$0.3930/0.29 - $0.29/Gal$3.9— 
October 20222023 - September 20232024Propane1,680 (Mbbls)(90.8) MMgalsIndexOPIS Mt Belvieu$0.8613/0.61 - $0.95/Gal16.64.4 
October 20222023 - June 2023September 2024Normal butaneButane355 (Mbbls)(20.0) MMgalsIndexOPIS Mt Belvieu$0.9710/0.71 - $0.97/Gal3.6 (1.1)
October 20222023 - October 2022December 2023Natural gasolineGasoline120 (Mbbls)(1.3) MMgalsIndexNYMEX WTI Average$1.6891/1.49 - $2.16/Gal0.3 (0.1)
October 20222023 - September 2024Natural Gasoline & Condensate69.9 MMgalsOPIS Mt Belvieu and NYMEX WTI Average differential($0.33) - ($0.24)/Gal(6.0)
October 2023 - January 2028Natural Gas(10.2) BbtuNYMEX Henry Hub$2.48 - $6.19/MMbtu13.6 
October 2023 - December 2024Natural Gas(1.1) BbtuWaha basis differential($3.02) - ($0.22)/MMbtu(3.5)
October 2023 - October 2023Natural gasGas126,379 (MMbtu/d)(1.4) BbtuIndexHenry Hub Gas Daily$6.4518/2.76 - $2.76/MMbtu(5.0)— 
October 20222023 - JanuaryOctober 2023Natural Gas(0.1) BbtuNGPL TEXOK Gas Daily$2.29 - $2.29/MMbtu— 
November 2023 - September 2024Crude and condensate& Condensate4,650 (Mbbls)(0.6) MMbblsIndexNYMEX WTI$76.61/69.77 - $94.00/Bbl4.5 (2.2)
January 2024 - December 2025Crude & Condensate(7.2) MMbblsWTI-Houston and Midland basis differential$0.70 - $0.90/Bbl1.6
Total fair value of commodity derivatives$23.96.7 
____________________________
(1)Weighted average.

Another price risk we face is the risk of mismatching volumes of gas bought or sold on a monthly price versus volumes bought or sold on a daily price. We enter each month with a balanced book of natural gas bought and sold on the same basis. However, it is normal to experience fluctuations in the volumes of natural gas bought or sold under either basis, which leaves us with short or long positions that must be covered. We use financial swaps to mitigate the exposure at the time it is created to maintain a balanced position.
 
The use of financial instruments may expose us to the risk of financial loss in certain circumstances, including instances when (1) sales volumes are less than expected requiring market purchases to meet commitments or (2) counterparties fail to 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, 2022,2023, our outstanding natural gas swap agreements, NGL swap agreements, swing swap agreements, storage swap agreements, and othercommodity derivative instruments had a net fair value asset of $23.9$6.7 million. The aggregate effect of a hypothetical 10% change, increase or decrease, in gas, crude and condensate, and NGL prices would result in a change of approximately $15.0$23.7 million in the net fair value of these contracts as of September 30, 2022.2023. 

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Interest Rate Risk

We are exposed to interest rate risk on the Revolving Credit Facility and the AR Facility. Amounts drawn on the Revolving Credit Facility and the AR Facility bear interest at rates based on SOFR. At September 30, 2022,2023, we had $70.0$160.0 million in outstanding borrowings under the Revolving Credit Facility and $500.0$292.0 million in outstanding borrowings under the AR Facility.

In January 2023, we entered into a $400.0 million interest rate swap to reduce the variability of cash outflows associated with interest payments related to our long-term debt with variable interest rates. This swap has been designated as a cash flow hedge. See “Item 1. Financial Statements—Note 12” for more information on our outstanding derivatives.

A 1.0% increase or decrease in interest rates would change our annualized interest expense by approximately $0.7$1.6 million and $5.0$2.9 million for the Revolving Credit Facility and the AR Facility, respectively.respectively, based on our outstanding borrowings at September 30, 2023. This change in interest expense would be partially 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 2024, 2025, 2026, 2044, 2045, or 2047 or our senior unsecured notes due in 2028, 2029, and 2030 as these are fixed-rate obligations. As of September 30, 2022,2023, the estimated fair value of the senior unsecured notes was approximately $3,502.5$3,879.2 million, based on the market prices of ENLK’s and our publicly traded debt at September 30, 2022.2023. 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 $209.8$215.3 million decrease in fair value of the senior unsecured notes at September 30, 2022.2023. See “Item 1. Financial Statements—Note 6” for more information on our outstanding indebtedness.

Prior to December 15, 2022, distributions on ENLK’s Series C Preferred Units were based on a fixed interest rate. Beginning with the interest period which commenced on December 15, 2022, distributions on ENLK'sENLK’s Series C Preferred Units will bewere based on a floating rate tied to LIBOR (or an alternativeplus a spread of 4.11%. As a result of the floating rate, to be established) plus 4.11% rather than a fixed rate and, therefore, the amount paid by ENLK as a distribution will befor distributions became more sensitive to changes in interest rates. Beginning with the interest period which commenced on September 15, 2023, distributions 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%. See “Item 1. Financial Statements—Note 8” for more information regarding distributions with respect to the Series C Preferred Units.

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, 2022)2023), 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, 20222023 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 16, “Commitments and Contingencies,” of the Notes to Consolidated Financial Statements contained in Part I of this Quarterly Report on Form 10-Q, which is incorporated by reference herein.

Item 1A. Risk Factors

Information about risk factors does not differ materially from that set forth in Part I, “Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 20212022 filed with the Commission on February 16, 2022.15, 2023.

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

During the three months ended September 30, 2022,2023, we re-acquired ENLC common units from certain employees in order to satisfy the employees’ tax liability in connection with the vesting of restricted incentive unitsunit-based awards and we repurchased common units in open market transactions and from GIP in connection with our common unit repurchase program.

PeriodTotal Number of Units Purchased (1)Average Price Paid Per UnitTotal Number of Units Purchased as Part of Publicly Announced Plans or Programs (2)Maximum Dollar Value of Units that May Yet Be Purchased under the Plans or Programs (in millions) (2)
July 1, 2022 to July 31, 2022904,782 $8.60 901,800 $141.5 
August 1, 2022 to August 31, 20223,742,405 9.64 3,533,555 $107.4 
September 1, 2022 to September 30, 20222,750,481 9.69 2,146,778 $86.8 
Total7,397,668 $9.53 6,582,133 
PeriodTotal Number of Units Purchased (1)Average Price Paid Per UnitTotal 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, 2023 to July 31, 20233,559,953 $10.22 3,486,076 $57.6 
August 1, 2023 to August 31, 2023902,241 11.95 766,898 $48.5 
September 1, 2023 to September 30, 2023763,619 12.59 763,619 $38.8 
Total5,225,813 $10.87 5,016,593 
____________________________
(1)The total number of units purchased shown in the table includes 815,535209,220 ENLC common units received by us from employees for the payment of personal income tax withholding on vesting transactions.
(2)Effective January 1,In December 2022, the Board reauthorized our common unit repurchase program for 2023 and resetset the amount available for repurchases of outstanding common units during 2023 at up to $100.0 million. In July 2022, the Board increased the amount available for repurchase to $200.0 million. Future repurchases under the program may be made from time to time in open market or private transactions and may be made pursuant to a trading plan meeting the requirements of Rule 10b5-1 under the Exchange Act. The repurchases will depend on market conditions and may be discontinued at any time. For more information regarding common units repurchased from public unitholders and our repurchase of common units held by GIP, see “Item 1. Financial Statements—Note 9.”

Item 5. Other Information

Disclosure Pursuant to Item 1.01 of Form 8-K – Entry into a Material Definitive Agreement.

On October 26, 2023, in connection with the amendment and restatement of the limited partnership agreement of ENLK, as described under “Item 1. Financial Statements—Note 8,” ENLC and each of Patton BIP HoldCo I LLC, Patton BIP HoldCo II LLC and OCM ENLK Holdings, LLC, the holders of all outstanding Series B Preferred Units as of the date of such agreement, entered into the Second Amended and Restated Registration Rights Agreement (the “Amended Registration Rights Agreement”). The Amended Registration Rights Agreement amended the prior Amended and Restated Registration Rights Agreement, dated as of January 25, 2019, to, among other things, (i) extend indefinitely the right of one or more holders of Registrable Securities (as defined in the Amended Registration Rights Agreement) to require ENLC to prepare and file a shelf registration statement to permit the public resale of Registrable Securities, provided such requesting holder(s) own $10.0 million or more of Registrable Securities, (ii) permit all other holders of Registrable Securities to be included in any such shelf registration statement and (iii) require each applicable holder to pay its pro rata share of all registration and related expenses incurred by ENLC in connection with such a shelf registration, a Piggy Back Registration (as defined in the Amended Registration Rights Agreement) and an Underwritten Offering (as defined in the Amended Registration Rights Agreement), in each case, subject to a maximum amount of $250,000 for any such single transaction.

The foregoing description of the Amended Registration Rights Agreement does not purport to be complete and is qualified in its entirety by reference to the full text of the Amended Registration Rights Agreement, a copy of which is filed as Exhibit 10.1 to this report and is incorporated herein by reference.
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Insider Trading Plans

During the three months ended September 30, 2023, 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. Upon her departure from the Company as of August 8, 2023, the Rule 10b5-1 trading arrangement entered into by Alaina K. Brooks was terminated.

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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):
NumberDescription
3.1—
3.2—
3.3—
3.4—
3.5—
3.6—
3.7—
3.8—
3.9—
3.10—
3.11—
3.12—
3.13—
3.14 *—
4.1—
10.14.1—
10.2—
10.310.1 *†—
22.1 *—
31.1 *—
31.2 *—
32.1 *—
101 *—The following financial information from EnLink Midstream, LLC's Quarterly Report on Form 10-Q for the quarter ended September 30, 2022,2023, formatted in iXBRL (Inline eXtensible Business Reporting Language): (i) Consolidated Balance Sheets as of September 30, 20222023 and December 31, 2021,2022, (ii) Consolidated Statements of Operations for the three and nine months ended September 30, 20222023 and 2021,2022, (iii) Consolidated Statements of Changes in Members’ Equity for the three months ended September 30, 20222023 and 2021,2022, June 30, 20222023 and 2021,2022, and March 31, 20222023 and 2021,2022, (iv) Consolidated Statements of Cash Flows for the nine months ended September 30, 20222023 and 2021,2022, and (v) the Notes to Consolidated Financial Statements.
104 *—Cover Page Interactive Data File (formatted as Inline iXBRL and included in Exhibit 101).
____________________________
*    Filed herewith.
† As required by Item 15(a)(3), this Exhibit is identified as a management contract or compensatory plan or arrangement.
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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
EnLink Midstream, LLC
By:EnLink Midstream Manager, LLC, its managing member
By:/s/ J. PHILIPP ROSSBACH
J. Philipp Rossbach
Vice President and Chief Accounting Officer
(Principal Accounting Officer)
November 2, 20221, 2023

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