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Enlink Midstream, Llc (ENLC) SEC Filing 10-Q Quarterly Report for the period ending Thursday, March 31, 2022

SEC Filings

ENLC Quarterly Reports

Enlink Midstream, Llc

CIK: 1592000 Ticker: ENLC

 

Exhibit 99.1

 

 

 

 

FOR IMMEDIATE RELEASE

May 3, 2022

 

Investor Relations: Brian Brungardt, Director of Investor Relations, 214-721-9353, brian.brungardt@enlink.com

Media Relations: Jill McMillan, Vice President of Strategic Relations & Public Affairs, 214-721-9271, jill.mcmillan@enlink.com

 

EnLink Midstream Reports First Quarter 2022 Results and Increases 2022 Guidance

 

DALLAS, May 3, 2022 — EnLink Midstream, LLC (NYSE: ENLC) (EnLink) reported financial results for the first quarter of 2022 and raised full-year 2022 guidance.

 

Highlights

 

Reported net income of $66.0 million, net cash provided by operating activities of $307.7 million, and adjusted EBITDA, net to EnLink, of $304.3 million for the first quarter of 2022, driven by robust producer activity and strong commodity prices.
Grew adjusted EBITDA 22% compared to the first quarter of 2021 and achieved the highest quarterly adjusted EBITDA result in EnLink's history.
Delivered $104.9 million of free cash flow after distributions (FCFAD) for the first quarter of 2022, driven by strong operational results and timing of capital expenditures. On a trailing 12-month basis as of March 31, 2022, EnLink has generated nearly $325 million of FCFAD.
Repurchased $23 million of common units during the first quarter of 20221.
Exited the first quarter of 2022 with leverage at 3.8x.
Subsequent to the quarter, received a Corporate Family Rating upgrade from Moody's Investor Service to Ba1. EnLink is now rated one notch below investment grade by Moody's, S&P Global Ratings, and Fitch Ratings Inc.
Taking into account the record first quarter results, the improving volume outlook, and the supportive commodity price environment, EnLink is raising its full-year 2022 guidance. EnLink now expects to report full-year 2022 net income of $315 million to $375 million and adjusted EBITDA of $1.19 billion to $1.25 billion. The midpoint of the adjusted EBITDA guidance range represents an increase of 6% over the initial 2022 guidance midpoint and implies 16% growth over full-year 2021.
Based on current producer activity and plans, EnLink expects a significant increase in volumes in 2023. As a result, EnLink expects to spend $325 million to $365 million on capital projects in 2022. These projects leverage existing infrastructure and have high expected returns and quick paybacks.
Even with increased investment levels, EnLink is raising full-year 2022 FCFAD guidance to $320 million to $370 million. This result would represent the third consecutive year of FCFAD of over $300 million.
As a result of the improved financial outlook, EnLink plans to continue to increase the return of capital to common unitholders from FCFAD in 2022.
Subsequent to the quarter, EnLink announced that it had signed its first customer with the execution of a letter of intent to enter into a Transportation Services Agreement (TSA) with Oxy Low Carbon Ventures, LLC (OLCV, a subsidiary of Occidental (NYSE: OXY)). Under the TSA, EnLink would provide carbon dioxide (CO2) transportation services for OLCV along the Mississippi River corridor from Waggaman to Baton Rouge, Louisiana.

 

 

1Includes $6 million of common units repurchased from GIP pursuant to the previously disclosed Unit Repurchase Agreement dated February 15, 2022 and which settled on May 2, 2022. These represent GIP's pro-rata share of aggregate units repurchased from February 15 through March 31, 2022.

 


The following information was filed by Enlink Midstream, Llc (ENLC) on Tuesday, May 3, 2022 as an 8K 2.02 statement, which is an earnings press release pertaining to results of operations and financial condition. It may be helpful to assess the quality of management by comparing the information in the press release to the information in the accompanying 10-Q Quarterly Report statement of earnings and operation as management may choose to highlight particular information in the press release.
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 March 31, 2022

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 Interests
ENLC
The New York Stock Exchange


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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Securities Exchange Act. (Check one):
Large accelerated filerAccelerated filer
Non-accelerated filerSmaller 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 April 28, 2022, the Registrant had 483,011,794 common units outstanding.


TABLE OF CONTENTS

2

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.
AR FacilityAn accounts receivable securitization facility of up to $350 million entered into by EnLink Midstream Funding, LLC, a bankruptcy-remote special purpose entity and our indirect subsidiary, with PNC Bank, National Association, as administrative agent and lender, and PNC Capital Markets, LLC, as structuring agent and sustainability agent. The AR Facility is scheduled to terminate on September 24, 2024, unless extended or earlier terminated in accordance with its terms.
ASCThe Financial Accounting Standards Board Accounting Standards Codification.
ASC 718
ASC 718, Compensation—Stock Compensation.
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.
BblBarrel.
BcfBillion cubic feet.
Beginning TSR Price
The beginning total shareholder return (“TSR”) price, which is the closing unit price of ENLC on the grant date of the performance award agreement or the previous trading day if the grant date was not a trading day, is one of the assumptions used to calculate the grant-date fair value of performance award agreements.
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.
CFTCU.S. Commodity Futures Trading Commission.
CNOWCentral Northern Oklahoma Woodford Shale.
CO2
Carbon dioxide.
CommissionU.S. Securities and Exchange Commission.
Consolidated Credit FacilityA $1.75 billion unsecured revolving credit facility entered into by ENLC that matures on January 25, 2024, which includes a $500.0 million letter of credit subfacility. The Consolidated Credit Facility was available upon closing of the Merger and is guaranteed by ENLK.
Delaware Basin
A large sedimentary basin in West Texas and New Mexico.
Delaware Basin 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.
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 to holders of the Series B Preferred Units with respect to ENLC.
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.
GAAPGenerally accepted accounting principles in the United States of America.
GalGallon.
GCFGulf Coast Fractionators, which owns an NGL fractionator in Mont Belvieu, Texas. ENLK owns 38.75% of GCF. The GCF assets have been temporarily idled to reduce operating expenses. We expect these assets to resume operations when there is a sustained need for additional fractionation capacity in Mont Belvieu.
General PartnerEnLink Midstream GP, LLC, the general partner of ENLK.
3

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.
MergerOn January 25, 2019, NOLA Merger Sub, LLC (previously a wholly-owned subsidiary of ENLC) merged with and into ENLK with ENLK continuing as the surviving entity and a subsidiary of ENLC.
Midland BasinA large sedimentary basin in West Texas.
MMbblsMillion barrels.
MMbtuMillion British thermal units.
MMcfMillion cubic feet.
MVCMinimum volume commitment.
NGLNatural gas liquid.
NGPNGP Natural Resources XI, LP.
OPEC+
Organization of the Petroleum Exporting Countries and its broader partners.
Operating PartnershipEnLink Midstream Operating, LP, a Delaware limited partnership and wholly owned subsidiary of ENLK.
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.
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.
STACKSooner Trend Anadarko Basin Canadian and Kingfisher Counties in Oklahoma.
Term Loan
A term loan originally in the amount of $850.0 million entered into by ENLK on December 11, 2018 with Bank of America, N.A., as Administrative Agent, Bank of Montreal and Royal Bank of Canada, as Co-Syndication Agents, Citibank, N.A. and Wells Fargo Bank, National Association, as Co-Documentation Agents, and the lenders party thereto, which ENLC assumed in connection with the Merger and the obligations of which ENLK guaranteed. The Term Loan was paid at maturity.

4

PART I—FINANCIAL INFORMATION
Item 1. Financial Statements
ENLINK MIDSTREAM, LLC AND SUBSIDIARIES
Consolidated Balance Sheets
(In millions, except unit data)
March 31, 2022December 31, 2021
(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents$68.7 $26.2 
Accounts receivable:
Trade, net of allowance for bad debt of $0.3 and $0.3, respectively
70.4 94.9 
Accrued revenue and other857.9 693.3 
Fair value of derivative assets68.1 22.4 
Other current assets112.7 83.6 
Total current assets1,177.8 920.4 
Property and equipment, net of accumulated depreciation of $4,450.6 and $4,332.0, respectively
6,321.8 6,388.3 
Intangible assets, net of accumulated amortization of $827.9 and $795.1, respectively
1,016.9 1,049.7 
Investment in unconsolidated affiliates27.3 28.0 
Fair value of derivative assets0.1 0.2 
Other assets, net96.3 96.6 
Total assets$8,640.2 $8,483.2 
LIABILITIES AND MEMBERS’ EQUITY
Current liabilities:
Accounts payable and drafts payable$131.7 $139.6 
Accrued gas, NGLs, condensate, and crude oil purchases (1)740.0 521.5 
Fair value of derivative liabilities97.2 34.9 
Other current liabilities215.4 202.9 
Total current liabilities1,184.3 898.9 
Long-term debt, net of unamortized issuance cost4,315.0 4,363.7 
Other long-term liabilities94.0 93.9 
Deferred tax liability, net140.5 137.5 
Fair value of derivative liabilities0.6 2.2 
Members’ equity:
Members’ equity (483,364,767 and 484,277,258 units issued and outstanding, respectively)
1,291.5 1,325.8 
Accumulated other comprehensive loss(1.3)(1.4)
Non-controlling interest1,615.6 1,662.6 
Total members’ equity2,905.8 2,987.0 
Commitments and contingencies (Note 14)
Total liabilities and members’ equity$8,640.2 $8,483.2 
____________________________
(1)Includes related party accounts payable balances of $5.8 million and $1.6 million at March 31, 2022 and December 31, 2021, respectively.



See accompanying notes to consolidated financial statements.
5

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES
Consolidated Statements of Operations
(In millions, except per unit data)
Three Months Ended
March 31,
20222021
(Unaudited)
Revenues:
Product sales$2,043.9 $1,122.9 
Midstream services215.0 208.9 
Loss on derivative activity(31.2)(83.4)
Total revenues2,227.7 1,248.4 
Operating costs and expenses:
Cost of sales, exclusive of operating expenses and depreciation and amortization (1)1,794.5 934.7 
Operating expenses120.9 56.3 
Depreciation and amortization152.9 151.0 
Loss on disposition of assets5.1 — 
General and administrative29.0 26.0 
Total operating costs and expenses2,102.4 1,168.0 
Operating income125.3 80.4 
Other income (expense):
Interest expense, net of interest income(55.1)(60.0)
Loss from unconsolidated affiliate investments(1.1)(6.3)
Other income (expense)0.1 (0.1)
Total other expense(56.1)(66.4)
Income before non-controlling interest and income taxes69.2 14.0 
Income tax expense(3.2)(1.4)
Net income66.0 12.6 
Net income attributable to non-controlling interest30.8 25.3 
Net income (loss) attributable to ENLC$35.2 $(12.7)
Net income (loss) attributable to ENLC per unit:
Basic common unit$0.07 $(0.03)
Diluted common unit$0.07 $(0.03)
____________________________
(1)Includes related party cost of sales of $10.6 million and $3.2 million for the three months ended March 31, 2022 and 2021, respectively.


















See accompanying notes to consolidated financial statements.
6

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES
Consolidated Statements of Comprehensive Income
(In millions)
Three Months Ended
March 31,
20222021
(Unaudited)
Net income$66.0 $12.6 
Unrealized gain on designated cash flow hedge (1)0.1 3.6 
Comprehensive income66.1 16.2 
Comprehensive income attributable to non-controlling interest30.8 25.3 
Comprehensive income (loss) attributable to ENLC$35.3 $(9.1)
____________________________
(1)Includes tax expense of $1.1 million for the three months ended March 31, 2021.




    





































See accompanying notes to consolidated financial statements.
7

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES
Consolidated Statements of Changes in Members’ Equity
(In millions)
Common UnitsAccumulated Other Comprehensive LossNon-Controlling InterestTotal
$Units$$$
(Unaudited)
Balance, December 31, 2021$1,325.8 484.3 $(1.4)$1,662.6 $2,987.0 
Conversion of restricted units for common units, net of units withheld for taxes(4.2)1.2 — — (4.2)
Unit-based 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, 2022$1,291.5 483.4 $(1.3)$1,615.6 $2,905.8 


































See accompanying notes to consolidated financial statements.
8

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 restricted units 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, 2021$1,454.2 490.1 $(11.7)$1,719.9 $3,162.4 $— 
____________________________
(1)Includes tax expense of $1.1 million.
































See accompanying notes to consolidated financial statements.
9

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES
Consolidated Statements of Cash Flows
(In millions)
Three Months Ended
March 31,
20222021
(Unaudited)
Cash flows from operating activities:
Net income$66.0 $12.6 
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization152.9 151.0 
Utility credits redeemed (earned)5.6 (40.4)
Deferred income tax expense3.0 1.3 
Loss on disposition of assets5.1 — 
Non-cash unit-based compensation6.6 6.5 
Non-cash loss on derivatives recognized in net income17.3 7.8 
Amortization of debt issuance costs and net discount of senior unsecured notes1.3 1.2 
Loss from unconsolidated affiliate investments1.1 6.3 
Other operating activities(1.1)1.4 
Changes in assets and liabilities:
Accounts receivable, accrued revenue, and other(139.9)(18.7)
Natural gas and NGLs inventory, prepaid expenses, and other(32.8)1.2 
Accounts payable, accrued product purchases, and other accrued liabilities222.6 95.6 
Net cash provided by operating activities307.7 225.8 
Cash flows from investing activities:
Additions to property and equipment(60.2)(23.5)
Other investing activities1.0 4.3 
Net cash used in investing activities(59.2)(19.2)
Cash flows from financing activities:
Proceeds from borrowings500.0 200.0 
Repayments on borrowings(550.0)(300.0)
Distributions to members(56.4)(47.1)
Distributions to non-controlling interests(34.6)(26.0)
Redemption of Series B Preferred Units(50.5)— 
Contributions by non-controlling interests7.3 0.9 
Common unit repurchases(17.0)— 
Other financing activities(4.8)(1.2)
Net cash used in financing activities(206.0)(173.4)
Net increase in cash and cash equivalents42.5 33.2 
Cash and cash equivalents, beginning of period26.2 39.6 
Cash and cash equivalents, end of period$68.7 $72.8 
Supplemental disclosures of cash flow information:
Cash paid for interest$29.4 $17.2 
Non-cash investing activities:
Non-cash accrual of property and equipment$(0.2)$(2.7)
Right-of-use assets obtained in exchange for operating lease liabilities$8.5 $10.2 








See accompanying notes to consolidated financial statements.
10

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES
Notes to Consolidated Financial Statements
March 31, 2022
(Unaudited)
(1) General

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

Please read the notes to the consolidated financial statements in conjunction with the Definitions page set forth in this report prior to Part I—Financial Information.

a.Organization of Business

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

b.Nature of Business

We primarily focus on providing midstream energy services, including:

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

Our midstream energy asset network includes approximately 12,100 miles of pipelines, 22 natural gas processing plants with approximately 5.5 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.

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.

11

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

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

(2) Significant Accounting Policies

a.Basis of Presentation

The accompanying consolidated financial statements have been prepared in accordance with the instructions to Form 10-Q, are unaudited, and do not include all the information and disclosures required by GAAP for complete financial statements. All adjustments that, in the opinion of management, are necessary for a fair presentation of the results of operations for the interim periods have been made and are of a recurring nature unless otherwise disclosed herein. The results of operations for such interim periods are not necessarily indicative of results of operations for a full year. These consolidated financial statements should be read in conjunction with the consolidated financial statements and accompanying notes included in our Annual Report on Form 10-K for the year ended December 31, 2021 filed with the Commission on February 16, 2022. Certain reclassifications were made to the financial statements for the prior period to conform to current period presentation. The effect of these reclassifications had no impact on previously reported members’ equity or net income. All significant intercompany balances and transactions have been eliminated in consolidation.

b.Revenue Recognition

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

Contractually Committed FeesCommitments
2022 (remaining)$110.3 
2023132.0 
2024112.0 
202565.1 
202657.9 
Thereafter289.7 
Total$767.0 

(3) Intangible Assets

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

12

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

The following table represents our change in carrying value of intangible assets (in millions):
Gross Carrying AmountAccumulated AmortizationNet Carrying Amount
Three Months Ended March 31, 2022
Customer relationships, beginning of period$1,844.8 $(795.1)$1,049.7 
Amortization expense— (32.8)(32.8)
Customer relationships, end of period$1,844.8 $(827.9)$1,016.9 

Amortization expense was $32.8 million and $30.9 million for the three months ended March 31, 2022 and 2021, respectively.

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

2022 (remaining)$95.6 
2023127.6 
2024127.6 
2025110.2 
2026106.3 
Thereafter449.6 
Total$1,016.9 

(4) Related Party Transactions

(a)    Transactions with Cedar Cove JV

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

(b)    Transactions with GIP

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

GIP Repurchase Agreement. On February 15, 2022, we and GIP entered into an agreement pursuant to which we are repurchasing, on a quarterly basis, a pro rata portion of the ENLC common units held by GIP, based upon the number of common units purchased by us during the applicable quarter from public unitholders under our common unit repurchase program. The number of ENLC common units held by GIP that we repurchase in any quarter is calculated such that GIP’s then-existing economic ownership percentage of our outstanding common units is maintained after our repurchases of common units from public unitholders are taken into account, and the per unit price we pay to GIP is the average per unit price paid by us for the common units repurchased from public unitholders. See “Note 8—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.
13

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

(5) Long-Term Debt

As of March 31, 2022 and December 31, 2021, long-term debt consisted of the following (in millions):
March 31, 2022December 31, 2021
Outstanding PrincipalPremium (Discount)Long-Term DebtOutstanding PrincipalPremium (Discount)Long-Term Debt
Consolidated Credit Facility due 2024 (1)$— $— $— $15.0 $— $15.0 
AR Facility due 2024 (2)315.0 — 315.0 350.0 — 350.0 
ENLK’s 4.40% Senior unsecured notes due 2024
521.8 0.6 522.4 521.8 0.7 522.5 
ENLK’s 4.15% Senior unsecured notes due 2025
720.8 (0.4)720.4 720.8 (0.4)720.4 
ENLK’s 4.85% Senior unsecured notes due 2026
491.0 (0.3)490.7 491.0 (0.3)490.7 
ENLC’s 5.625% Senior unsecured notes due 2028
500.0 — 500.0 500.0 — 500.0 
ENLC’s 5.375% Senior unsecured notes due 2029
498.7 — 498.7 498.7 — 498.7 
ENLK’s 5.60% Senior unsecured notes due 2044
350.0 (0.2)349.8 350.0 (0.2)349.8 
ENLK’s 5.05% Senior unsecured notes due 2045
450.0 (5.4)444.6 450.0 (5.5)444.5 
ENLK’s 5.45% Senior unsecured notes due 2047
500.0 (0.1)499.9 500.0 (0.1)499.9 
Debt classified as long-term$4,347.3 $(5.8)4,341.5 $4,397.3 $(5.8)4,391.5 
Debt issuance cost (3)(26.5)(27.8)
Long-term debt, net of unamortized issuance cost$4,315.0 $4,363.7 
____________________________
(1)Bears interest based on Prime and/or LIBOR plus an applicable margin. The effective interest rate was 3.9% at December 31, 2021.
(2)Bears interest based on LMIR and/or LIBOR plus an applicable margin. The effective interest rate was 1.5% and 1.2% at March 31, 2022 and December 31, 2021, respectively.
(3)Net of accumulated amortization of $19.7 million and $18.4 million at March 31, 2022 and December 31, 2021, respectively.

Consolidated Credit Facility

The Consolidated Credit Facility permits ENLC to borrow up to $1.75 billion on a revolving credit basis and includes a $500.0 million letter of credit subfacility. There were no outstanding borrowings under the Consolidated Credit Facility and $44.3 million outstanding letters of credit as of March 31, 2022.

At March 31, 2022, we were in compliance with and expect to be in compliance with the financial covenants of the Consolidated Credit Facility for at least the next twelve months.

AR Facility

On October 21, 2020, EnLink Midstream Funding, LLC, a bankruptcy-remote special purpose entity that is an indirect subsidiary of ENLC (the “SPV”) entered into the AR Facility. We are the primary beneficiary of the SPV and we consolidate its assets and liabilities, which consist primarily of billed and unbilled accounts receivable of $882.6 million. As of March 31, 2022, the AR Facility had a borrowing base of $350.0 million and there were $315.0 million in outstanding borrowings under the AR Facility.

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

14

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

(6) Income Taxes

The components of our income tax expense are as follows (in millions):
Three Months Ended
March 31,
20222021
Current income tax expense$(0.2)$(0.1)
Deferred income tax expense(3.0)(1.3)
Income tax expense$(3.2)$(1.4)

The following schedule reconciles 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
March 31,
20222021
Expected income tax benefit (expense) based on federal statutory rate$(8.1)$2.4 
State income tax benefit (expense), net of federal benefit(1.1)0.2 
Unit-based compensation (1)(2.0)(2.5)
Change in valuation allowance7.1 (1.2)
Other0.9 (0.3)
Income tax expense$(3.2)$(1.4)
____________________________
(1)Related to book-to-tax differences recorded upon the vesting of restricted incentive units.

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 March 31, 2022, we had $140.5 million of deferred tax liabilities, net of $484.8 million of deferred tax assets, which included a $144.5 million valuation allowance. As of December 31, 2021, we had $137.5 million of deferred tax liabilities, net of $481.6 million of deferred tax assets, which included a $151.6 million valuation allowance.

A valuation allowance is established to reduce deferred tax assets if all, or some portion, of such assets will more than likely not be realized. We have established a valuation allowance primarily related to federal and state tax operating loss carryforwards for which we do not believe a tax benefit is more likely than not to be realized. As of March 31, 2022, management believes it is more likely than not that the Company will realize the benefits of the deferred tax assets, net of valuation allowance.

15

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

(7) Certain Provisions of the ENLK Partnership Agreement

a.Series B Preferred Units

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

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

A summary of the distribution activity relating to the Series B Preferred Units during the three months ended March 31, 2022 and 2021 is provided below:
Declaration periodDistribution paid as additional Series B Preferred UnitsCash Distribution (in millions)Date paid/payable
2022
Fourth Quarter of 2021— $19.2 February 11, 2022 (1)
First Quarter of 2022— $17.5 May 13, 2022 (2)
2021
Fourth Quarter of 2020150,494 $16.9 February 12, 2021
First Quarter of 2021150,871 $17.0 May 14, 2021
____________________________
(1)In December 2021 and January 2022, we paid $0.9 million and $1.0 million, respectively, of accrued distributions on the Series B Preferred Units redeemed.
(2)In January 2022, we paid $0.3 million of accrued distributions on the Series B Preferred Units redeemed. The remaining distribution of $17.2 million related to the first quarter of 2022 is payable May 13, 2022.

b.Series C Preferred Units

As of March 31, 2022 and December 31, 2021, there were 400,000 Series C Preferred Units issued and outstanding, respectively. There was no distribution activity related to the Series C Preferred Units during the three months ended March 31, 2022 and 2021.

16

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

(8) Members’ Equity

a.Common Unit Repurchase Program

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

For the three months ended March 31, 2022, ENLC repurchased 2,093,842 outstanding ENLC common units for an aggregate cost, including commissions, of $17.0 million, or an average of $8.12 per common unit. For the three months ended March 31, 2021, we did not repurchase any outstanding ENLC common units.

b.GIP Repurchase Agreement

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

c.Earnings Per Unit and Dilution Computations

As required under ASC 260, Earnings Per Share, unvested share-based payments that entitle employees to receive non-forfeitable distributions are considered participating securities for earnings per unit calculations. The following table reflects the computation of basic and diluted earnings per unit for the periods presented (in millions, except per unit amounts):
Three Months Ended
March 31,
20222021
Distributed earnings allocated to:
Common units (1)$54.4 $45.9 
Unvested restricted units (1)1.1 1.1 
Total distributed earnings$55.5 $47.0 
Undistributed loss allocated to:
Common units$(19.9)$(58.3)
Unvested restricted units(0.4)(1.4)
Total undistributed loss$(20.3)$(59.7)
Net income (loss) attributable to ENLC allocated to:
Common units$34.5 $(12.4)
Unvested restricted units0.7 (0.3)
Total net income (loss) attributable to ENLC$35.2 $(12.7)
Net income (loss) attributable to ENLC per unit:
Basic$0.07 $(0.03)
Diluted$0.07 $(0.03)
____________________________
(1)Represents distribution activity consistent with the distribution activity table below.

17

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

The following are the unit amounts used to compute the basic and diluted earnings per unit for the periods presented (in millions):
Three Months Ended
March 31,
20222021
Basic weighted average units outstanding:
Weighted average common units outstanding484.0 490.0 
Diluted weighted average units outstanding:
Weighted average basic common units outstanding484.0 490.0 
Dilutive effect of non-vested restricted units (1)6.6 — 
Total weighted average diluted common units outstanding490.6 490.0 
____________________________
(1)All common unit equivalents were antidilutive for the three months ended March 31, 2021, since a net loss existed for that period.

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

d.Distributions

A summary of our distribution activity related to the ENLC common units for the three months ended March 31, 2022 and 2021, respectively, is provided below:
Declaration periodDistribution/unitDate paid/payable
2022
Fourth Quarter of 2021$0.11250 February 11, 2022
First Quarter of 2022$0.11250 May 13, 2022
2021
Fourth Quarter of 2020$0.09375 February 12, 2021
First Quarter of 2021$0.09375 May 14, 2021

18

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

(9) 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
March 31,
20222021
Cost of unit-based compensation charged to operating expense$1.6 $1.7 
Cost of unit-based compensation charged to general and administrative expense5.0 4.8 
Total unit-based compensation expense$6.6 $6.5 
Amount of related income tax benefit recognized in net income (1)$1.6 $1.5 
____________________________
(1)For the three months ended March 31, 2022 and 2021, the amount of related income tax benefit recognized in net income excluded $2.0 million and $2.5 million, respectively, of income tax expense related to book-to-tax differences recorded upon the vesting of restricted units.

b.ENLC Restricted Incentive Units

ENLC restricted incentive units were valued at their fair value at the date of grant, which is equal to the market value of ENLC common units on such date. A summary of the restricted incentive unit activity for the three months ended March 31, 2022 is provided below:
Three Months Ended
March 31, 2022
ENLC Restricted Incentive Units:Number of UnitsWeighted Average Grant-Date Fair Value
Non-vested, beginning of period7,507,471 $5.46 
Granted (1)1,761,711 8.87 
Vested (1)(2)(1,032,738)10.35 
Forfeited(2,022)3.71 
Non-vested, end of period8,234,422 $5.58 
Aggregate intrinsic value, end of period (in millions)$79.5  
____________________________
(1)Restricted incentive units typically vest at the end of three years. In March 2022, ENLC granted 193,935 restricted incentive units with a fair value of $1.7 million. These restricted incentives units vested immediately and are included in the restricted incentive units granted and vested line items.
(2)Vested units included 278,866 units withheld for payroll taxes paid on behalf of employees.

A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for the three months ended March 31, 2022 and 2021 is provided below (in millions):
Three Months Ended
March 31,
ENLC Restricted Incentive Units:20222021
Aggregate intrinsic value of units vested$7.6 $3.0 
Fair value of units vested$10.7 $10.2 

19

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

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

c.ENLC Performance Units

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

The following table presents a summary of the performance units:
Three Months Ended
March 31, 2022
ENLC Performance Units:Number of UnitsWeighted Average Grant-Date Fair Value
Non-vested, beginning of period3,574,827 $6.40 
Granted598,286 11.45 
Vested (1)(708,361)15.57 
Non-vested, end of period3,464,752 $5.40 
Aggregate intrinsic value, end of period (in millions)$33.4 
____________________________
(1)Vested units included 273,357 units withheld for payroll taxes paid on behalf of employees.

A summary of the performance units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for the three months ended March 31, 2022 and 2021 is provided below (in millions).

 Three Months Ended
March 31,
ENLC Performance Units:20222021
Aggregate intrinsic value of units vested$5.6 $0.6 
Fair value of units vested$11.0 $4.4 

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

The following table presents a summary of the grant-date fair value assumptions by performance unit grant date:
ENLC Performance Units:March 2022 (1)January 2021
Grant-date fair value$11.90 $4.70 
Beginning TSR price$8.83 $3.71 
Risk-free interest rate2.15 %0.17 %
Volatility factor75.00 %71.00 %
____________________________
(1)Excludes ENLC performance units awarded March 1, 2022 with vesting conditions based on performance metrics. The 88,863 ENLC performance units have a grant-date fair value of $8.90 and will vest in February 2023.

20

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

(10) Derivatives

Interest Rate Swaps

The components of the unrealized gain on designated cash flow hedge related to changes in the fair value of our interest rate swaps were as follows (in millions):
Three Months Ended
March 31,
20222021
Change in fair value of interest rate swaps$0.1 $4.7 
Tax expense— (1.1)
Unrealized gain on designated cash flow hedge$0.1 $3.6 

The interest expense, recognized from accumulated other comprehensive loss from the monthly settlement of our interest rate swaps and amortization of the termination payments, included in our consolidated statements of operations were as follows (in millions):
Three Months Ended
March 31,
20222021
Interest expense$0.1 $4.8 

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

Commodity Swaps

The components of loss on derivative activity in the consolidated statements of operations related to commodity swaps are (in millions):
Three Months Ended
March 31,
20222021
Change in fair value of derivatives$(15.1)$(7.9)
Realized loss on derivatives(16.1)(75.5)
Loss on derivative activity$(31.2)$(83.4)

The fair value of derivative assets and liabilities related to commodity swaps are as follows (in millions):
March 31, 2022December 31, 2021
Fair value of derivative assets—current$68.1 $22.4 
Fair value of derivative assets—long-term0.1 0.2 
Fair value of derivative liabilities—current(97.2)(34.9)
Fair value of derivative liabilities—long-term(0.6)(2.2)
Net fair value of commodity swaps$(29.6)$(14.5)

21

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

Set forth below are the summarized notional volumes and fair values of all instruments related to commodity swaps that we held for price risk management purposes and the related physical offsets at March 31, 2022 (in millions). The remaining term of the contracts extend no later than July 2023.
March 31, 2022
CommodityInstrumentsUnitVolumeNet Fair Value
NGL (short contracts)SwapsGals(181.4)$(29.7)
Natural gas (short contracts)SwapsMMbtu(3.7)(3.9)
Natural gas (long contracts)SwapsMMbtu2.8 2.9 
Crude and condensate (short contracts)SwapsMMbbls(4.7)(59.3)
Crude and condensate (long contracts)SwapsMMbbls4.0 60.4 
Total fair value of commodity swaps$(29.6)

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

22

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

(11) Fair Value Measurements

Assets and liabilities measured at fair value on a recurring basis are summarized below (in millions):
Level 2
March 31, 2022December 31, 2021
Commodity swaps (1)$(29.6)$(14.5)
____________________________
(1)    The fair values of commodity swaps represent the amount at which the instruments could be exchanged in a current arms-length transaction adjusted for our credit risk and/or the counterparty credit risk as required under ASC 820.

Fair Value of Financial Instruments

The estimated fair value of our financial instruments has been determined using available market information and valuation methodologies. Considerable judgment is required to develop the estimates of fair value; thus, the estimates provided below are not necessarily indicative of the amount we could realize upon the sale or refinancing of such financial instruments (in millions):
March 31, 2022December 31, 2021
Carrying ValueFair
Value
Carrying ValueFair
Value
Long-term debt (1)$4,315.0 $4,154.6 $4,363.7 $4,520.0 
Installment payable (2)$10.0 $10.0 $10.0 $10.0 
Contingent consideration (2)$6.9 $6.9 $6.9 $6.9 
____________________________
(1)The carrying value of long-term debt is reduced by debt issuance cost, net of accumulated amortization, of $26.5 million and $27.8 million as of March 31, 2022 and December 31, 2021, respectively. The respective fair values do not factor in debt issuance costs.
(2)Consideration paid for the acquisition of Amarillo Rattler, LLC included a $10.0 million installment payable, which was paid on April 30, 2022, and a contingent consideration capped at $15.0 million and payable between 2024 and 2026 based on Diamondback E&P LLC’s drilling activity above historical levels. Estimated fair values were calculated using a discounted cash flow analysis that utilized Level 3 inputs.

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

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

23

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

(12) Segment Information

We evaluate the financial performance of our segments by including realized and unrealized gains and losses resulting from commodity swaps activity in the Permian, Louisiana, Oklahoma, and North Texas segments. Identification of the majority of our operating segments is based principally upon geographic regions served:

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

Louisiana Segment. The Louisiana segment includes our natural gas and NGL pipelines, natural gas processing plants, natural gas and NGL storage facilities, and fractionation facilities located in Louisiana and our crude oil operations in ORV;

Oklahoma Segment. The Oklahoma segment includes our natural gas gathering, processing, and transmission activities, and our crude oil operations in the Cana-Woodford, Arkoma-Woodford, northern Oklahoma Woodford, STACK, and CNOW shale areas;

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

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

24

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

We evaluate the performance of our operating segments based on segment profit and adjusted gross margin. Adjusted gross margin is a non-GAAP financial measure. Summarized financial information for our reportable segments is shown in the following tables (in millions):
PermianLouisianaOklahomaNorth TexasCorporateTotals
Three Months Ended March 31, 2022
Natural gas sales$195.6 $211.5 $76.3 $25.4 $— $508.8 
NGL sales— 1,151.5 3.1 (0.1)— 1,154.5 
Crude oil and condensate sales272.0 73.9 34.7 — — 380.6 
Product sales467.6 1,436.9 114.1 25.3 — 2,043.9 
NGL sales—related parties399.8 36.9 208.1 146.9 (791.7)— 
Crude oil and condensate sales—related parties— — 0.3 3.0 (3.3)— 
Product sales—related parties399.8 36.9 208.4 149.9 (795.0)— 
Gathering and transportation 13.6 16.3 42.7 38.8 — 111.4 
Processing7.8 0.5 25.4 27.6 — 61.3 
NGL services— 23.9 — — — 23.9 
Crude services4.3 9.4 3.7 0.2 — 17.6 
Other services0.2 0.4 0.1 0.1 — 0.8 
Midstream services25.9 50.5 71.9 66.7 — 215.0 
Other services—related parties— 0.1 — — (0.1)— 
Midstream services—related parties— 0.1 — — (0.1)— 
Revenue from contracts with customers893.3 1,524.4 394.4 241.9 (795.1)2,258.9 
Cost of sales, exclusive of operating expenses and depreciation and amortization (1)(766.7)(1,388.7)(276.8)(157.4)795.1 (1,794.5)
Realized loss on derivatives(2.4)(6.6)(3.7)(3.4)— (16.1)
Change in fair value of derivatives(5.9)(5.6)(7.1)3.5 — (15.1)
Adjusted gross margin118.3 123.5 106.8 84.6 — 433.2 
Operating expenses(45.3)(33.0)(21.0)(21.6)— (120.9)
Segment profit73.0 90.5 85.8 63.0 — 312.3 
Depreciation and amortization(36.7)(35.5)(50.9)(28.4)(1.4)(152.9)
Gain (loss) on disposition of assets— 0.2 0.2 (5.5)— (5.1)
General and administrative— — — — (29.0)(29.0)
Interest expense, net of interest income— — — — (55.1)(55.1)
Loss from unconsolidated affiliate investments— — — — (1.1)(1.1)
Other income— — — — 0.1 0.1 
Income (loss) before non-controlling interest and income taxes$36.3 $55.2 $35.1 $29.1 $(86.5)$69.2 
Capital expenditures$34.2 $5.7 $15.4 $3.1 $1.6 $60.0 
____________________________
(1)Includes related party cost of sales of $10.6 million for the three months ended March 31, 2022.
25

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

PermianLouisianaOklahomaNorth TexasCorporateTotals
Three Months Ended March 31, 2021
Natural gas sales$125.0 $121.2 $35.9 $51.0 $— $333.1 
NGL sales— 626.0 0.6 1.2 — 627.8 
Crude oil and condensate sales107.3 41.1 13.6 — — 162.0 
Product sales232.3 788.3 50.1 52.2 — 1,122.9 
NGL sales—related parties164.9 23.6 113.1 80.9 (382.5)— 
Crude oil and condensate sales—related parties— — — 1.5 (1.5)— 
Product sales—related parties164.9 23.6 113.1 82.4 (384.0)— 
Gathering and transportation 9.7 15.8 51.3 40.4 — 117.2 
Processing8.2 0.5 15.9 27.1 — 51.7 
NGL services— 22.0 — 0.1 — 22.1 
Crude services3.5 9.9 3.3 0.2 — 16.9 
Other services0.2 0.5 0.2 0.1 — 1.0 
Midstream services21.6 48.7 70.7 67.9 — 208.9 
Crude services—related parties— — 0.1 — (0.1)— 
Other services—related parties— 2.3 — — (2.3)— 
Midstream services—related parties— 2.3 0.1 — (2.4)— 
Revenue from contracts with customers418.8 862.9 234.0 202.5 (386.4)1,331.8 
Cost of sales, exclusive of operating expenses and depreciation and amortization (1)(325.6)(740.4)(151.0)(104.1)386.4 (934.7)
Realized loss on derivatives(56.9)(10.7)(6.0)(1.9)— (75.5)
Change in fair value of derivatives(5.3)(0.4)(1.8)(0.4)— (7.9)
Adjusted gross margin31.0 111.4 75.2 96.1 — 313.7 
Operating expenses11.8 (29.2)(19.7)(19.2)— (56.3)
Segment profit42.8 82.2 55.5 76.9 — 257.4 
Depreciation and amortization(33.5)(36.1)(50.7)(28.7)(2.0)(151.0)
Gain (loss) on disposition of assets0.1 (0.1)— — — — 
General and administrative— — — — (26.0)(26.0)
Interest expense, net of interest income— — — — (60.0)(60.0)
Loss from unconsolidated affiliate investments— — — — (6.3)(6.3)
Other loss— — — — (0.1)(0.1)
Income (loss) before non-controlling interest and income taxes$9.4 $46.0 $4.8 $48.2 $(94.4)$14.0 
Capital expenditures$13.3 $2.8 $1.9 $2.4 $0.4 $20.8 
____________________________
(1)Includes related party cost of sales of $3.2 million for the three months ended March 31, 2021.



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

The table below represents information about segment assets as of March 31, 2022 and December 31, 2021 (in millions):
Segment Identifiable Assets:March 31, 2022December 31, 2021
Permian$2,500.2 $2,358.6 
Louisiana2,442.9 2,428.6 
Oklahoma2,582.9 2,619.5 
North Texas866.8 896.8 
Corporate (1)247.4 179.7 
Total identifiable assets$8,640.2 $8,483.2 
____________________________
(1)Accounts receivable and accrued revenue sold to the SPV for collateral under the AR Facility are included within the Permian, Louisiana, Oklahoma, and North Texas segments.

(13) Other Information

The following tables present additional detail for other current assets and other current liabilities, which consists of the following (in millions):
Other current assets:March 31, 2022December 31, 2021
Natural gas and NGLs inventory$73.6 $49.4 
Prepaid expenses and other39.1 34.2 
Other current assets$112.7 $83.6 

Other current liabilities:March 31, 2022December 31, 2021
Accrued interest$71.5 $47.2 
Accrued wages and benefits, including taxes9.6 33.1 
Accrued ad valorem taxes12.6 28.3 
Capital expenditure accruals22.2 23.2 
Deferred revenue24.1 3.7 
Short-term lease liability 20.3 18.1 
Installment payable (1)10.0 10.0 
Inactive easement commitment (2)9.9 9.8 
Operating expense accruals 11.7 9.6 
Other23.5 19.9 
Other current liabilities$215.4 $202.9 
____________________________
(1)Consideration paid for the acquisition of Amarillo Rattler, LLC included an installment payable, which was paid on April 30, 2022.
(2)Amount related to inactive easements paid as utilized by us with the balance due in August 2022 if not utilized.

(14) Commitments and Contingencies

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

Another of our subsidiaries, EnLink Energy GP, LLC, is also involved in litigation arising out of Winter Storm Uri. This matter is a multi-district litigation currently pending in Harris County, Texas, in which multiple individual plaintiffs assert personal injury and property damage claims arising out of Winter Storm Uri against an aggregate of over 350 power generators,
27

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

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

In addition, we are involved in various litigation and administrative proceedings arising in the normal course of business. In the opinion of management, any liabilities that may result from these claims would not, individually or in the aggregate, have a material adverse effect on our financial position, results of operations, or cash flows. We may also be involved from time to time in the future in various proceedings in the normal course of business, including litigation on disputes related to contracts, property rights, property use or damage (including nuisance claims), personal injury, or the value of pipeline easements or other rights obtained through the exercise of eminent domain or common carrier rights.
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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.

Our midstream energy asset network includes approximately 12,100 miles of pipelines, 22 natural gas processing plants with approximately 5.5 Bcf/d of processing capacity, seven fractionators with approximately 320,000 Bbls/d of fractionation capacity, barge and rail terminals, product storage facilities, purchasing and marketing capabilities, brine disposal wells, a crude oil trucking fleet, and equity investments in certain joint ventures. We manage and report our activities primarily according to the nature of activity and geography.

We evaluate the financial performance of our segments by including realized and unrealized gains and losses resulting from commodity swaps activity in the Permian, Louisiana, Oklahoma, and North Texas segments. Identification of the majority of our operating segments is based principally upon geographic regions served:

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

Louisiana Segment. The Louisiana segment includes our natural gas and NGL pipelines, natural gas processing plants, natural gas and NGL storage facilities, and fractionation facilities located in Louisiana and our crude oil operations in ORV;

Oklahoma Segment. The Oklahoma segment includes our natural gas gathering, processing, and transmission activities, and our crude oil operations in the Cana-Woodford, Arkoma-Woodford, northern Oklahoma Woodford, STACK, and CNOW shale areas;

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

Corporate Segment. The Corporate segment includes our unconsolidated affiliate investments in the Cedar Cove JV in Oklahoma, our ownership interest in GCF in South Texas, and 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 three months ended March 31, 2022.

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

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

The following customers individually represented greater than 10% of our consolidated revenues for the three months ended March 31, 2022 and 2021. The loss of these customers would have a material adverse impact on our results of operations because the revenues and adjusted gross margin received from transactions with these customers is material to us. No other customers represented greater than 10% of our consolidated revenues during the periods presented.
Three Months Ended
March 31,
20222021
Dow Hydrocarbons and Resources LLC13.9 %14.5 %
Marathon Petroleum Corporation16.1 %14.8 %

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

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

CCS Business

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

Recent Developments Affecting Industry Conditions and Our Business

Current Market Environment

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

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

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

Capital markets and the demands of public investors also affect producer behavior, production levels, and our business. Over the last several years, public investors have exerted pressure on oil and natural gas producers to increase capital discipline and focus on higher investment returns even if it means lower growth. In addition, the ability of companies in the oil and gas industry to access the capital markets on favorable terms has been 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 modestly, although global capital investments by oil and natural gas producers remain at relatively low levels compared to historical levels and producers continue to remain cautious.

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

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

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

Extreme Weather Events

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

Because of the magnitude and unprecedented nature of Winter Storm Uri, we cannot predict the full impact that the storm may have on our future results of operations. The ultimate impacts will depend on future developments, including, among other factors, the outcome of pending billing disputes or litigation with customers and regulatory actions by state legislatures and other entities responsible for the regulation and pricing of electricity and the electrical grid.

COVID-19 Update

On March 11, 2020, the World Health Organization declared the ongoing coronavirus (COVID-19) outbreak a pandemic and recommended containment and mitigation measures worldwide. Since the outbreak began, our first priority has been the health and safety of our employees and those of our customers and other business counterparties. Beginning in March 2020, we implemented preventative measures and developed a response plan to minimize unnecessary risk of exposure and prevent infection, while supporting our customers’ operations, and we continue to evaluate our response plans and business practices to meet any evolving impacts of COVID-19 and its variants. Since the inception of the pandemic, we have not experienced any significant COVID-19 related operational disruptions.

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

We cannot predict the full impact that the COVID-19 pandemic or any related volatility in oil and natural gas markets will have on our business, liquidity, financial condition, results of operations, and cash flows (including our ability to make distributions to unitholders) due to numerous uncertainties. The ultimate impacts will depend on future developments, including, among others, the ultimate duration and persistence of the pandemic, including variants of the virus, the speed at which the population is vaccinated against the virus and the efficacy of the vaccines, the emergence of any new variants of the virus against which vaccines are less effective, the effect of the pandemic on economic, social, and other aspects of everyday life, the consequences of governmental and other measures designed to prevent the spread of the virus, actions taken by members of OPEC+ and other foreign, oil-exporting countries, actions taken by governmental authorities, customers, suppliers, and other third parties, and the timing and extent to which normal economic, social, and operating conditions fully resume.

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

Regulatory Developments

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

Only a small percentage of our operations are derived from customers operating on public land, mainly in the Delaware Basin. Our operations in the Delaware Basin 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 status of recent and future rules and rulemaking initiatives under the Biden Administration remain uncertain, the regulations that might result from such initiatives, could lead to increased costs for us or our customers, difficulties in obtaining leases, permits, and other approvals for us and our customers, reduced utilization of our gathering, processing and pipeline systems or reduced rates under renegotiated transportation or storage agreements in affected regions. These impacts could, in turn, adversely affect our business, financial condition, results of operations or cash flows, including our ability to make cash distributions to our unitholders.

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

Other Recent Developments

CCS—Talos Alliance. In February 2022, we signed a memorandum of understanding with Talos Energy Inc. (“Talos”) to provide a complete CCS offering for industrial-scale emitters in Louisiana, utilizing our midstream assets combined with Talos’ subsurface assets. Talos has secured approximately 26,000 acres in Louisiana, providing sequestration capacity of over 500 million metric tonnes.

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

Common Unit Repurchase Program. Effective January 1, 2022, the Board reauthorized our common unit repurchase program and reset the amount available for repurchases of outstanding common units at up to $100.0 million. For the three
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months ended March 31, 2022, ENLC repurchased 2,093,842 outstanding ENLC common units for an aggregate cost, including commissions, of $17.0 million, or an average of $8.12 per common unit.

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

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

Redemption of Series B Preferred Units. In January 2022, we redeemed 3,333,334 Series B Preferred Units for total consideration of $50.5 million plus accrued distributions. In addition, upon such redemption, a corresponding number of ENLC Class C Common Units were automatically cancelled. The redemption price represents 101% of the preferred units’ par value. In connection with the Series B Preferred Unit redemption, we have agreed with the holders of the Series B Preferred Units that we will pay cash in lieu of making a quarterly PIK distribution through the distribution declared for the fourth quarter of 2022. See “Item 1. Financial Statements—Note 7” for more information regarding distributions with respect to the Series B Preferred Units.

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Non-GAAP Financial Measures

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

Adjusted Gross Margin

We define adjusted gross margin as revenues less cost of sales, exclusive of operating expenses and depreciation and amortization. We present adjusted gross margin by segment in “Results of Operations.” We disclose adjusted gross margin in addition to gross margin as defined by GAAP because it is the primary performance measure used by our management to evaluate consolidated operations. We believe adjusted gross margin is an important measure because, in general, our business is to gather, process, transport, or market natural gas, NGLs, condensate, and crude oil for a fee or to purchase and resell natural gas, NGLs, condensate, and crude oil for a margin. Operating expense is a separate measure used by our management to evaluate the operating performance of field operations. Direct labor and supervision, property insurance, property taxes, repair and maintenance, utilities, and contract services comprise the most significant portion of our operating expenses. We exclude all operating expenses and depreciation and amortization from adjusted gross margin because these expenses are largely independent of the volumes we transport or process and fluctuate depending on the activities performed during a specific period. The GAAP measure most directly comparable to adjusted gross margin is gross margin. Adjusted gross margin should not be considered an alternative to, or more meaningful than, gross margin as determined in accordance with GAAP. Adjusted gross margin has important limitations because it excludes all operating expenses and depreciation and amortization that affect gross margin. Our adjusted gross margin may not be comparable to similarly titled measures of other companies because other entities may not calculate these amounts in the same manner.
 
The following table reconciles total revenues and gross margin to adjusted gross margin (in millions):
 Three Months Ended
March 31,
 20222021
Total revenues$2,227.7 $1,248.4 
Cost of sales, exclusive of operating expenses and depreciation and amortization(1,794.5)(934.7)
Operating expenses(120.9)(56.3)
Depreciation and amortization(152.9)(151.0)
Gross margin159.4 106.4 
Operating expenses120.9 56.3 
Depreciation and amortization152.9 151.0 
Adjusted gross margin$433.2 $313.7 

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Adjusted EBITDA

We define adjusted EBITDA as net income (loss) plus (less) interest expense, net of interest income; depreciation and amortization; impairments; (income) loss from unconsolidated affiliate investments; distributions from unconsolidated affiliate investments; (gain) loss on disposition of assets; (gain) loss on extinguishment of debt; unit-based compensation; income tax expense (benefit); unrealized (gain) loss on commodity swaps; costs associated with the relocation of processing facilities; accretion expense associated with asset retirement obligations; transaction costs; (non-cash 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
March 31,
 20222021
Net income$66.0 $12.6 
Interest expense, net of interest income55.1 60.0 
Depreciation and amortization152.9 151.0 
Loss from unconsolidated affiliate investments1.1 6.3 
Distributions from unconsolidated affiliate investments0.2 3.6 
Loss on disposition of assets5.1 — 
Unit-based compensation6.6 6.5 
Income tax expense3.2 1.4 
Unrealized loss on commodity swaps15.1 7.9 
Costs associated with the relocation of processing facilities (1)11.3 7.6 
Other (2)0.3 (0.4)
Adjusted EBITDA before non-controlling interest316.9 256.5 
Non-controlling interest share of adjusted EBITDA from joint ventures (3)(12.6)(7.1)
Adjusted EBITDA, net to ENLC$304.3 $249.4 
____________________________
(1)Represents cost incurred that are not part of our ongoing operations related to the relocation of equipment and facilities from the Thunderbird processing plant and Battle Ridge processing plant in the Oklahoma segment to the Permian segment. The relocation of equipment and facilities from the Battle Ridge processing plant was completed in the third quarter of 2021 and we expect to complete the relocation of equipment and facilities from the Thunderbird processing plant in the fourth quarter of 2022.
(2)Includes accretion expense associated with asset retirement obligations and non-cash rent, which relates to lease incentives pro-rated over the lease term.
(3)Non-controlling interest share of adjusted EBITDA from joint ventures includes NGP’s 49.9% share of adjusted EBITDA from the Delaware Basin JV and Marathon Petroleum Corporation’s 50% share of adjusted EBITDA from the Ascension JV.

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Free Cash Flow After Distributions

We define free cash flow after distributions as adjusted EBITDA, net to ENLC, plus (less) (growth and maintenance capital expenditures, excluding capital expenditures that were contributed by other entities and relate to the non-controlling interest share of our consolidated entities); (interest expense, net of interest income); (distributions declared on common units); (accrued cash distributions on Series B Preferred Units and Series C Preferred Units paid or expected to be paid); (costs asso