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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K


ý☒     ANNUAL REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934


For the fiscal year ended December 31, 20172021


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, TexasTexas75201
(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 ACT:
Title of Each ClassTrading SymbolName of Exchange on which Registered
Common Units Representing Limited
Liability Company Interests
ENLCThe New York Stock Exchange
Liability Company Interests

Securities registered pursuant to Section 12(g) of the Act: None.


Indicate by check mark if registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x☒ No ¨☐


Indicate by check mark if registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨☐ No x☒


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 x☒ No ¨☐


Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted 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 and post such files). Yes x☒ No ¨☐

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x


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 filerx
☒
Accelerated filer¨☐
Non-accelerated filer ¨ (Do not check if a smaller reporting company)
☐
Smaller reporting company¨

☐
Emerging growth company¨
☐☐


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


Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒

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


The aggregate market value of the common units representing limited liability company interests held by non-affiliates of the registrant was approximately $1.1$1.7 billion on June 30, 2017,2021, based on $17.60$6.39 per unit, the closing price of the common units as reported on the New York Stock Exchange on such date.


At February 14, 2018,9, 2022, there were 180,883,369484,003,750 common units outstanding.



DOCUMENTS INCORPORATED BY REFERENCE:

None.




Table of Contents

TABLE OF CONTENTS


ItemDescriptionPage
PART I
1.
5
1A.
32
1B.
61
2.
62
3.
62
4.
62
PART II
5.
63
6.
63
7.
64
7A.
88
8.
92
9.
145
9A.
145
9B.
145
PART III
10.
147
11.
151
12.
166
13.
169
14.
170
PART IV
15.
172

2
Item Description Page
     
  PART I  
1. BUSINESS 
4
1A. RISK FACTORS 
29
1B. UNRESOLVED STAFF COMMENTS 
55
2. PROPERTIES 
55
3. LEGAL PROCEEDINGS 
56
4. MINE SAFETY DISCLOSURES 
56
     
  PART II  
5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES 
57
6. SELECTED FINANCIAL DATA 
58
7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 
61
7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 
87
8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 
91
9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE 
144
9A. CONTROLS AND PROCEDURES 
144
9B. OTHER INFORMATION 
144
     
  PART III  
10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE 
145
11. EXECUTIVE COMPENSATION 
149
12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS 
169
13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE 
172
14. PRINCIPAL ACCOUNTING FEES AND SERVICES 
173
     
  PART IV  
15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES 
175
Table of Contents

DEFINITIONS

Definitions

The following terms as defined generally are used in the energy industry and 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 7. 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 (“FASB”) Accounting Standards Codification.
ASC 606
ASC 606, Revenue from Contracts with Customers.
ASC 718
ASC 718, Compensation—Stock Compensation.
ASC 815
ASC 815, Derivatives and Hedging.
ASC 820
ASC 820, Fair Value Measurements.
ASC 842
ASC 842, Leases.
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.
AvengerAvenger crude oil gathering system, a crude oil gathering system in the northern Delaware Basin.
Bbls Barrels.
BcfBillion cubic feet.
Beginning TSR PriceThe beginning total shareholder return (“TSR”) price, which is the closing unit price of ENLC on the grant date of the performance award agreement or the previous trading day if the grant date was not a trading day, is one of the assumptions used to calculate the grant-date fair value of performance award agreements.
BLMBureau of Land Management.
BKVBanpu Kalnin Ventures Corporation, an affiliate of BKV Oil and Gas Capital Partners.
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 BasinA large sedimentary basin in West Texas and New Mexico.
Delaware Basin JVDelaware G&P LLC, a joint venture between a subsidiary of ENLK and an affiliate of NGP in which ENLK owns a 50.1% interest and NGP owns a 49.9% interest. The Delaware Basin JV, which was formed in August 2016, owns the Lobo processing facilities and the Tiger processing plant located in the Delaware Basin in Texas.
DevonDevon Energy Corporation.
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.
ENLC EDAEquity Distribution Agreement entered into by ENLC in February 2019 with RBC Capital Markets, LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated, Barclays Capital Inc., BMO Capital Markets Corp., Citigroup Global Markets Inc., Credit Suisse Securities (USA) LLC, J.P. Morgan Securities LLC, Jefferies LLC, Mizuho Securities USA LLC, MUFG Securities Americas Inc., SunTrust Robinson Humphrey, Inc., and Wells Fargo Securities, LLC (collectively, the “ENLC Sales Agents”) to sell up to $400.0 million in aggregate gross sales of ENLC common units from time to time through an “at the market” equity offering program.
/d = per day
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Bbls = barrels
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.
FERCFederal Energy Regulatory Commission.
GAAPGenerally accepted accounting principles in the United States of America.
GalsGallons.
GCFGulf Coast Fractionators, which owns an NGL fractionator in Mont Belvieu, Texas. ENLK owns 38.75% of GCF. Beginning in January 2021, 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, which owns a 0.4% general partner interest in ENLK. Prior to the effective time of the Merger, the General Partner also owned all of the incentive distribution rights in ENLK.
GHGGreenhouse gas.
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.
GIP TransactionOn July 18, 2018, subsidiaries of Devon closed a transaction to sell all of their equity interests in ENLK, ENLC, and the Managing Member to GIP.
GP PlanThe General Partner’s Long-Term Incentive Plan. As of the closing of the Merger, ENLC assumed all obligations in respect of the GP Plan. No additional grants of equity awards will be made under the GP Plan for periods after the Merger.
ISDAsInternational Swaps and Derivatives Association Agreements.
Managing MemberEnLink Midstream Manager, LLC, the managing member of ENLC.
MEGA systemMidland Energy Gathering Area system in Midland, Martin, and Glasscock counties, Texas.
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.
NOLA Merger SubNOLA Merger Sub, LLC, previously a wholly-owned subsidiary of ENLC prior to the Merger.
NYSENew York Stock Exchange.
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 LoanA term loan originally in the amount of $850.0 million entered into by ENLK on December 11, 2018 with Bank of America, N.A., as Administrative Agent, Bank of Montreal and Royal Bank of Canada, as Co-Syndication Agents, Citibank, N.A. and Wells Fargo Bank, National Association, as Co-Documentation Agents, and the lenders party thereto, which ENLC assumed in connection with the Merger and the obligations of which ENLK guaranteed. The Term Loan was paid at maturity on December 10, 2021.
VEXThe Victoria Express Pipeline and related truck terminal and storage assets located in the Eagle Ford Shale in South Texas, which we sold in October 2020.
White StarWhite Star Petroleum, LLC.
Bcf = billion cubic feet
4
CO2= Carbon dioxide
CPI= Consumer Price Index
HP = horsepower
MMBtu = million British thermal units
MMcf = million cubic feet
NGL = natural gas liquid

Capacity volumes for our facilities are measured based on physical volume and stated in cubic feet (“Bcf”, “Mcf” or “MMcf”). Throughput volumes are measured based on energy content and stated in British thermal units (“Btu” or “MMBtu”). A volumeTable of capacity of 100 MMcf correlates to an approximate energy content of 100,000 MMBtu, although this correlation will vary depending on the composition of natural gas and is typically higher for unprocessed gas, which contains a higher concentration of NGLs. Fractionated volumes are measured based on physical volumes and stated in gallons. Crude oil, condensate and brine services volumes are measured based on physical volume and stated in barrels (“Bbls”). Contents

We define “gross operating margin,” a non-GAAP financial measure, as revenues less cost of sales. We disclose gross operating margin in addition to total revenue because it is the primary performance measure used by our management. We believe gross operating margin is an important measure because, in general, our business is to purchase and resell natural gas, NGLs, condensate and crude oil for a margin and to gather, process, store, transport or market natural gas, NGLs, condensate and crude oil for a fee. The GAAP measure most directly comparable to gross operating margin is operating income (loss). For more information on gross operating margin, including its limitations as a financial measure, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures.”

ENLINK MIDSTREAM, LLC


PART I


Item 1. Business


General and Recent Developments


EnLink Midstream, LLC (“ENLC”)Formation

ENLC is a Delaware limited liability company formed in October 2013. Effective as of March 7, 2014, EnLink Midstream, Inc. (“EMI”) merged with and into a subsidiary wholly owned by us, and Acacia Natural Gas Corp I, Inc. (“Acacia”), formerly a wholly-owned subsidiary of Devon Energy Corporation (“Devon”), merged with and into another subsidiary wholly owned by us (collectively, the “Mergers”). Pursuant to the Mergers, each of EMI and Acacia became our wholly-owned subsidiaries and we became publicly held. EMI owns common units representing an approximate 5.0% limited partner interest in EnLink Midstream Partners, LP (“ENLK”) as of December 31, 2017 and also owns EnLink Midstream GP, LLC, the general partner of ENLK (the “General Partner”). At the conclusion of the Mergers in March 2014, Acacia directly owned a 50% limited partner interest in a limited partnership, formerly wholly owned by Devon, that was renamed EnLink Midstream Holdings, LP (“Midstream Holdings”). Concurrently with the consummation of the Mergers, a wholly-owned subsidiary of ENLK acquired the remaining 50% of the outstanding limited partner interest in Midstream Holdings and all of the outstanding equity interests in EnLink Midstream Holdings GP, LLC, the general partner of Midstream Holdings (together with the Mergers, the “Business Combination”).

In 2015, Acacia contributed the remaining 50% interest in Midstream Holdings to ENLK in exchange for 68.2 million ENLK common units in two separate drop down transactions, with 25% contributed in February 2015 and 25% contributed in May 2015 (the “EMH Drop Downs”). After giving effect to the EMH Drop Downs, ENLK owns 100% of Midstream Holdings. As a result of the EMH Drop Downs, Acacia owned approximately 16.7% of the limited partner interests in ENLK as of December 31, 2017, which brings ENLC’s total ownership, through its wholly-owned subsidiaries, of limited partner interests in ENLK to 21.7% as of December 31, 2017.

On January 7, 2016, EnLink Oklahoma Gas Processing, LP (“EnLink Oklahoma T.O.”) completed its acquisition of 100% of the issued and outstanding membership interests of TOMPC LLC and TOM-STACK, LLC. EnLink Oklahoma T.O. is sometimes used herein to refer to EnLink Oklahoma Gas Processing, LP itself or EnLink Oklahoma Gas Processing, LP, together with its consolidated subsidiaries. As a result of the acquisition, ENLK indirectly owns an 83.9% limited partnership interest in EnLink Oklahoma T.O., and ENLC owns a 16.1% limited partnership interest in EnLink Oklahoma T.O. In addition, EnLink Energy GP, LLC, the general partner of EnLink Oklahoma T.O. and an indirect subsidiary of ENLK, owns the non-economic general partnership interest.

EnLink Midstream, LLC common units are traded on the New York Stock Exchange (“NYSE”)NYSE under the symbol “ENLC.” Our executive offices are located at 1722 Routh Street, Suite 1300, Dallas, Texas 75201, and our telephone number is (214) 953-9500. Our Internet address is www.enlink.com. We post the following filings in the “Investors” section of our website as soon as reasonably practicable after they are electronically filed with or furnished to the Securities and Exchange Commission (“SEC”):Commission: our Annual Reports on Form 10-K; our quarterly reports on Form 10-Q; our current reports on Form 8-K; and any amendments to those reports or statements filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended. All such filings on our website are available free of charge.

Additionally, filings are available on the Commission’s website (www.sec.gov). In this report, the terms “Company” or “Registrant” as well as the terms “ENLC,” “our,” “we,” and “us,”“us” or like terms are sometimes used as references to EnLink Midstream, LLC itself or EnLink Midstream, LLC and its consolidated subsidiaries, including ENLK.

ENLC owns all of ENLK’s common units and also owns all of the membership interests of the General Partner. References in this report to “EnLink Midstream Partners, LP,” the “Partnership,” “ENLK”“ENLK,” or like terms refer to EnLink Midstream Partners, LP itself or EnLink Midstream Partners, LP together with its consolidated subsidiaries, including EnLink Midstream Operating, LP.


ENLINK MIDSTREAM, LLC

Our assets consistOn July 18, 2018, GIP acquired control of equity interests in ENLK and EnLink Oklahoma T.O. ENLK is a publicly traded limited partnership that primarily focuses on providing midstream energy services, including:

gathering, compressing, treating, processing, transporting, storing and selling natural gas;
fractionating, transporting, storing, exporting and selling NGLs; and

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

EnLink Oklahoma T.O. is a partnership held by us and ENLK engagedour Managing Member. See “Item 8. Financial Statements and Supplementary Data—Note 1” for more information on the GIP Transaction.

Additional Information

For more information about our organization of business before our simplification transaction in 2019, refer to “Item 1. Business—General” of our Annual Report on Form 10-K for the gathering, transmission and processing of natural gas and NGLs. As offiscal year ended December 31, 2017, our interests in ENLK consist2019, filed with the Commission on February 26, 2020, and available here.

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88,528,451 common units representing an aggregate 21.7% limited partner interest in ENLK;
100.0% ownership interest in the General Partner, which owns a 0.4% general partner interest and all of the incentive distribution rights in ENLK; and
16.1% limited partner interest in EnLink Oklahoma T.O.

Each of ENLK and EnLink Oklahoma T.O is required by its partnership agreement to distribute all its cash on hand at the end of each quarter, less reserves established by its general partner in its sole discretion to provide for the proper conduct of ENLK’s or EnLink Oklahoma T.O.’s business, as applicable, or to provide for future distributions.

The incentive distribution rights in ENLK entitle us to receive an increasing percentage of cash distributed by ENLK as certain target distribution levels are reached. Specifically, they entitle us to receive 13.0% of all cash distributed in a quarter after each unit has received $0.25 for that quarter, 23.0% of all cash distributed after each unit has received $0.3125 for that quarter and 48.0% of all cash distributed after each unit has received $0.375 for that quarter.

We intend to pay distributions to our unitholders on a quarterly basis equal to the cash we receive, if any, from distributions from ENLK less reserves for expenses, future distributions and other uses of cash, including:

federal income taxes, which we are required to pay because we are taxed as a corporation;
the expenses of being a public company;
other general and administrative expenses;
capital calls for our interest in EnLink Oklahoma T.O. to the extent not covered by our borrowings;
capital contributions to ENLK upon the issuance by it of additional partnership securities in order to maintain the General Partner’s then-current general partner interest, to the extent the board of directors of the General Partner (the “GP Board”) exercises its option to do so; and
cash reserves the board of directors of EnLink Midstream Manager, LLC, our managing member (the “Managing Member”), believes are prudent to maintain.

Our ability to pay distributions is limited by the Delaware Limited Liability Company Act, which provides that a limited liability company may not pay distributions if, after giving effect to the distribution, the company’s liabilities would exceed the fair value of its assets. While our ownership of equity interests in the General Partner and ENLK are included in our calculation of net assets, the value of these assets may decline to a level where our liabilities would exceed the fair value of our assets if we were to pay distributions, thus prohibiting us from paying distributions under Delaware law.

ENLINK MIDSTREAM PARTNERS, LP

EnLink Midstream Partners, LP is a publicly traded Delaware limited partnership formed in 2002. ENLK’s common units are traded on the NYSE under the symbol “ENLK.” ENLK’s business activities are conducted through its subsidiary, EnLink Midstream Operating, LP, a Delaware limited partnership (the “Operating Partnership”), and the subsidiaries of the Operating Partnership.

EnLink Midstream GP, LLC, a Delaware limited liability company and our wholly-owned subsidiary, is ENLK’s general partner. The General Partner manages ENLK’s operations and activities.


The following diagram depicts our organization and ownership as of December 31, 2017:2021:
___________________________
(1)
The general partner (“GP”) ownership percentage for EnLink Midstream Partners, LP accounts for general partner units, while the limited partner (“LP”) ownership percentages for EnLink Midstream Partners, LP account for ENLK common units and Series B Preferred Units (as defined below), which are convertible into ENLK common units on a one-for-one basis, subject to certain adjustments.
(2)
Series C Preferred Units (as defined below) are perpetual preferred units that are not convertible into ENLK common units, and therefore, are not factored into the EnLink Midstream Partners, LP ownership calculations for the limited partner and general partner ownership percentages presented.

enlc-20211231_g1.jpg
____________________________
(1)On August 4, 2021, all of the outstanding Series B Preferred Units and ENLC Class C Common Units were purchased by Brookfield Infrastructure Partners L.P. and funds managed by Oaktree Capital Management, L.P.
(2)Series B Preferred Units are exchangeable into ENLC common units on a 1-for-1.15 basis, subject to certain adjustments. Upon the exchange of any Series B Preferred Units into ENLC common units, an equal number of the ENLC Class C Common Units will be canceled.
(3)All ENLK common units are held by ENLC. The Series B Preferred Units are entitled to vote, on a one-for-one basis (subject to certain adjustments) as a single class with ENLC, on all matters that require approval of the ENLK unitholders.
(4)Series C Preferred Units are perpetual preferred units that are not convertible into other equity interests, and therefore, are not factored into the ENLK ownership calculations for the limited partner and general partner ownership percentages presented.
(5)EnLink Midstream Funding, LLC is a bankruptcy-remote special purpose entity that entered into the AR Facility in October 2020. See “Item 8. Financial Statements and Supplementary Data—Note 6” for more information regarding the AR Facility.

COVID-19 Update

On March 11, 2020, the World Health Organization declared the ongoing coronavirus (COVID-19) outbreak a pandemic and recommended containment and mitigation measures worldwide.

Since the outbreak began, our first priority has been the health and safety of our employees and those of our customers and other business counterparties. Beginning in March 2020, we implemented preventative measures and developed a response plan to minimize unnecessary risk of exposure and prevent infection, while supporting our customers’ operations, and we continue to follow these plans. We also continue to promote heightened awareness and vigilance, hygiene, and implementation of more stringent cleaning protocols across our facilities and operations and we continue to evaluate and adjust our preventative
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measures, response plans and business practices with the 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.

There remains considerable uncertainty regarding how long the COVID-19 pandemic (including variants of the virus) will persist and affect economic conditions and the extent and duration of changes in consumer behavior.

We cannot predict the full impact that the COVID-19 pandemic or the 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) at this time due to numerous uncertainties. The ultimate impacts will depend on future developments, including, among others, the ultimate duration and persistence of the pandemic, the impact of the Delta and Omicron 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 conditionsfully resume. Although crude oil and natural gas prices and production activities have recovered to pre-pandemic levels, producers remain cautious and a decline in commodity prices could affect producers’ exploration and production activities.A sustained significant decline in oil and natural gas exploration and production activities and related reduced demand for our services by our customers, whether due to decreases in consumer demand or reduction in the prices for crude oil, condensate, natural gas, and NGLs or otherwise, would have a material adverse effect on our business, liquidity, financial condition, results of operations, and cash flows (including our ability to make distributions to our unitholders).

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.”

Our Operations


We primarily focus on providing midstream energy services, including:


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


Our midstream energy asset network includes approximately 11,00012,100 miles of pipelines, 2022 natural gas processing plants with approximately 4.85.5 Bcf/d of processing capacity, 7seven fractionators with approximately 260,000320,000 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.


We connectOur natural gas business includes connecting the wells of producers in our market areas to our gathering systems. Our gathering systems which 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, other marketsmarketers, 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, and ourplants. Our fractionators also have the capability to receive NGLs by truck or rail terminals. We also have agreements pursuant to which third parties transport NGLs from our West Texas and Central Oklahoma operations to our NGL transmission lines that then transport the NGLs to our fractionators. In addition, we have NGL storage capacity to provide storage for customers.


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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 mayalso purchase crude oil and condensate from producers and other supply sources and sell that crude oil and condensate through our terminal facilities that provide market access.to various markets.


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

We manage and report our transactions vary in form,activities primarily according to the essential elementnature of each transaction is the use of our assets to transport a product or provide a processed product to an end-user or other marketer or pipeline at the tailgate of the plant, barge terminal or pipeline.activity and geography. We have five reportable segments:


Our assets are included in five primary segments:

Texas•Permian Segment. The TexasPermian segment includes our natural gas gathering, processing, and transmission activities and our crude oil operations in North Texas and the Midland and Delaware Basins (together, the “Permian Basin”) in West Texas;
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.Segment. The Oklahoma segment includes our natural gas gathering, processing, and transmission activities, in Cana-Woodford, Arkoma-Woodford, Northern Oklahoma Woodford, Sooner Trend Anadarko Basin Canadian and Kingfisher Counties (“STACK”) and Central Northern Oklahoma Woodford (“CNOW”) shale areas;

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

Crude and Condensate Segment. The Crude and Condensate segment includes our crude oil operations in the Permian BasinCana-Woodford, Arkoma-Woodford, northern Oklahoma Woodford, STACK, and Central Oklahoma,CNOW shale areas;

•North Texas Segment. The North Texas segment includes our Ohio River Valley (“ORV”) crude oil, condensate stabilization, natural gas compressiongathering, processing, and brine disposaltransmission activities in the UticaNorth Texas; and Marcellus Shales and our crude oil activities associated with our Victoria Express Pipeline and related truck terminal and storage assets (“VEX”) located in the Eagle Ford Shale; and


•Corporate Segment.Segment. The Corporate segment includes our unconsolidated affiliate investments in the Cedar Cove joint venture (“Cedar Cove JV”)JV in Oklahoma, our contractual right to the economic benefits and burdens associated with Devon’s 38.75% ownership interest in Gulf Coast Fractionators (“GCF”)GCF in South Texas, and our general corporate propertyassets and expenses.


For more information about our segment reporting, see “Item 8. Financial Statements and Supplementary Data—Note 16.15.”


About Devon

Devon (NYSE: DVN) is a leading independent energy company engaged primarily in the exploration, development and production of crude oil, natural gas and NGLs. Devon’s operations are concentrated in various onshore areas in the U.S. and Canada. Please see Devon’s Annual Report on Form 10-K for the year ended December 31, 2017 (the “Devon Annual Report”) for additional information concerning Devon’s business. The information contained in the Devon Annual Report is not incorporated by reference into this Annual Report on Form 10-K and should not be considered part of this or any other report that we file with or furnish to the SEC.
Our Business Strategies


We operate a differentiated midstream platform that is built for long-term, sustainable value creation. Our integrated assets are strategically located in premier production basins and core demand centers, including the Permian Basin, the Louisiana Gulf Coast, Central Oklahoma, and North Texas. Our primary business objective is to provide cash flow stability in our business while growing prudently and profitably. We intend to accomplish this objective by executing the following strategies:


Execute•Operational Excellence and Innovation. We have created a rigorous company-wide program that we refer to as the EnLink Way centered on innovation and continuous improvement in our core growth areas. business. We believe this program will allow us to optimize our operations in order to enhance the profitability of current operations, capture capital-efficient commercial opportunities, and enhance the scalability of our asset platforms for future growth.

•Financial Discipline and Flexibility. We are focused on strengthening our financial position and flexibility by generating significant cash flows, driving disciplined and balanced capital allocation, focusing on cost discipline, and maintaining liquidity and balance sheet strength. We believe that these strategies will afford us better access to the capital markets and a competitive cost of capital, and the opportunity to grow our business in a prudent manner throughout the cycles in our industry.

•Strategic Growth.We believe our assets are positioned in some of the most economically advantageous basins in the U.S., as well as key demand centers with growing end-use customers.We expect to grow certain of our systems organically over time by meeting our customers’ midstream service needs that result from their drilling activity in our areas of operation, or growth in supply needs. We continually evaluateare also focused on economically attractive organic expansion opportunities in our areas of operation that allow us to leverage our existing infrastructure, operating expertise, and customer relationships, as well as to increase our natural gas and NGL presence downstream. We are committed to becoming the future of midstream by constructing and expanding systems to meet new or increased demand for our services. participating in the energy transition. As part of this effort, we are developing an
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Maintainintegrated offering to bring CCS 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 a strong financial position. Weadvantage in building a CCS business.

•Sustainability and Safety. Sustainability and safety are integrated into all aspects of our business. Approximately 90% of our current business is focused on natural gas and natural gas liquids, which we believe that maintaining a conservative and balanced capital structure, appropriate leverage and other key financial metrics will afford us better access to the capital markets at a competitive cost of capital. We also believe a strong financial position provides us the opportunity to grow our business in a prudent manner throughout the cycles in our industry.

Maintain stable cash flows supported by long-term, fee-based contracts. We will seek to generate cash flows pursuant to long-term, firm contracts with creditworthy customers. We will continue to pursuebe important sources of clean energy for decades to come. We publish a sustainability report with key metrics that can be measured from year to year, and have announced target emission reduction milestones. To achieve those goals, we continue to evaluate opportunities to increase the fee-based components ofreduce or offset emissions in our contract portfoliooperations using process improvements and technology, or utilizing renewable energy. With respect to minimize our direct commodity price exposure.

Our Competitive Strengths

We believe thatsafety, we are well-positionedcommitted to execute our strategiesoperating safely and to achieve our primary business objective due to the following competitive strengths:

Devon’s sponsorship. We expect our relationship with Devon will continue to provide us with significant business opportunities. Devon is one of the largest independent oil and gas producers in North America. Devon has a significant interest in promoting the success of our business, due toan environmentally responsible manner. During 2021, EnLink had its 64.0% direct ownership interest in ENLC and 23.1% direct ownership interest in ENLK as of December 31, 2017. Approximately 46.8% of our gross operating margin for the best safety year ended December 31, 2017 was attributable to commercial contracts with Devon.

Strategically-located assets. The majority of our assets are strategically located in economically advantageous regionson record with the potential for increasing throughput volume and cash flow generation. Our asset portfolio includes gathering, transmission, fractionation, and processing systems that are locatedlowest number of employee reportable incidents in the areas in which producer activity is focused on crude oil, condensate and NGLs, as well as natural gas. We have established platforms in Texas, Oklahoma and Louisiana, and we are focused on growing our operations in Central Oklahoma, the Permian Basin and southern Louisiana through organic development and acquisitions.history.
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Stable cash flows. Approximately 94%Table of our gross operating margin for the year ended December 31, 2017 was generated from fee-based contract arrangements with minimal direct commodity price exposure. In addition, our cash flows are generated across a variety of products, services and geographic locations and through transactions with a strong portfolio of customers with investment-grade credit ratings. We have approximately six years remaining on fixed-fee gathering and processing agreements with a subsidiary of Devon pursuant to which we provide gathering, treating, compression, dehydration, stabilization, processing and fractionation services, as applicable, for natural gas delivered by Devon to our gathering and processing systems in the Barnett and Cana-Woodford Shales. These agreements provide us with dedication of all of the natural gas owned or controlled by Devon and produced from or attributable to existing and future wells located on certain oil, natural gas and mineral leases covering lands within theContents

acreage dedications, excluding properties previously dedicated to other natural gas gathering systems not owned and operated by Devon. These agreements also include minimum volume commitments (“MVCs”) that will remain in effect up to January 1, 2019. Additionally, our EnLink Oklahoma T.O. assets are supported by Devon with acreage dedications and MVCs for gathering and processing on Devon’s STACK acreage through 2021. For additional information, please read “Our Contractual Relationship with Devon.” We will continue to focus on contract structures that reduce volatility and support long-term stability of cash flows.

Integrated midstream services. We span the energy value chain by providing natural gas, NGL, crude oil and condensate services across a diverse customer base. These services include gathering, compressing, treating, processing, transporting, storing and selling natural gas, fractionating, transporting, storing, exporting and selling NGLs, and gathering, transporting, stabilizing, storing and trans-loading crude oil and condensate. We believe our ability to provide all of these services gives us an advantage in competing for new opportunities because we can provide substantially all services that producers, marketers and others require to move natural gas, NGLs, crude oil and condensate from the wellhead to the market on a cost-effective basis.

Experienced management team. Our management team has deep experience in the energy industry and has a proven track record of creating value through the development, acquisition, optimization and integration of midstream assets. We believe this team provides us with a strong foundation for evaluating growth opportunities and operating our assets in a safe, reliable and efficient manner.

We believe that we will leverage our competitive strengths to successfully implement our strategy; however, our business involves numerous risks and uncertainties that may prevent us from achieving our primary business objectives. For a more complete description of the risks associated with our business, please see “Item 1A. Risk Factors.”

Our Contractual Relationship with Devon

The following table includes our long-term, fixed-fee contracts with Devon:
Contract Remaining Contract Term (Years) Year Contract Entered Into Gathering MVC (MMcf/d) Processing MVC (MMcf/d) Remaining MVC Term (Years) Annual Rate Escalators
Bridgeport gathering and processing contract 6 2014 850 650
 1 CPI
Johnson County gathering contract 6 2014 125 —
 1 CPI
Cana gathering and processing contract 6 2014 330 330
 1 CPI
EnLink Oklahoma T.O. gathering and processing contract (1) 12 2016 Varies Varies
 3 —
(1)
The gathering MVCs and processing MVCs under this contract escalate on a quarterly basis over the life of the five-year commitment, beginning with an average commitment of 37 MMcf/d during 2016 and ending with an average commitment of 230 MMcf/d during 2020.

In addition, we entered into to a five-year transportation MVC, which was executed in June 2014 and expires in July 2019, with Devon related to VEX. The MVC under the VEX contract averaged 25,000 Bbls/d during the first year and will average 30,000 Bbls/d for years two through five.

Recent Growth Developments

Organic Growth

Central Oklahoma Plants. In 2017, we completed construction of two new cryogenic gas processing plants, which included the Chisholm II plant completed in April 2017 and the Chisholm III plant completed in December 2017. Each plant provides 200 MMcf/d of processing capacity and is connected to new and existing gathering pipeline and compression assets in the STACK play in Oklahoma. The new capacity is supported by new and existing long-term contracts.

In addition, we are constructing an additional 200 MMcf/d gas processing plant, referred to as the “Thunderbird plant” to expand our Central Oklahoma processing capacity. We expect to begin operations on the Thunderbird plant during the first quarter of 2019.


In June 2017, we entered into a long-term, fee-based arrangement with Oneok Partners (“Oneok”) under which Oneok transports NGLs from our Chisholm processing facility to the Gulf Coast and our Cajun-Sibon system. The agreement allows us to retain control of volumes and preferentially fill our Cajun-Sibon system.

Black Coyote Crude Oil Gathering System. In the fourth quarter of 2017, we began construction of a new crude oil gathering system that we refer to as “Black Coyote,” which will expand our operations in the core of the STACK play in Central Oklahoma. Black Coyote is being built primarily on acreage dedicated from Devon, which will be the main shipper on the system. The system is expected to be operational in the first quarter of 2018.

Lobo Natural Gas Gathering and Processing Facilities. The Lobo facilities are part of our joint venture (the “Delaware Basin JV”) with an affiliate of NGP Natural Resources XI, LP (“NGP”) and are supported by long-term contracts. In the first quarter of 2017, we completed the expansion of a 75-mile gathering system for our Lobo II processing facility. In the second quarter of 2017, we completed the construction of an expansion of the Lobo II processing facility, which provided an additional 60 MMcf/d of processing capacity to the existing 95 MMcf/d provided by the Lobo processing facilities. Furthermore, we are constructing an additional expansion of the Lobo II processing facility, which will increase capacity by 15 MMcf/d and is expected to be completed during the first half of 2018. In 2018, we will also expand our gas processing capacity at our Lobo facilities by 200 MMcf/d through the construction of the Lobo III cryogenic gas processing plant, which is expected to be operational around the second half of 2018. 

Greater Chickadee Crude Oil Gathering System.In March 2017, we completed construction and began operations of a crude oil gathering system in Upton and Midland counties, Texas in the Permian Basin, which we refer to as “Greater Chickadee.” Greater Chickadee includes over 185 miles of high- and low-pressure pipelines that transport crude oil volumes to several major market outlets and other key hub centers in the Midland, Texas area and is supported by long-term contracts. Greater Chickadee also includes multiple central tank batteries, together with pump, truck injection and storage stations to maximize shipping and delivery options for our producer customers.

Marathon Petroleum Joint Venture. In April 2017, we completed construction and began operating a new NGL pipeline, which is part of our 50/50 joint venture with a subsidiary of Marathon Petroleum Company (“Marathon Petroleum”). This joint venture, Ascension Pipeline Company, LLC (the “Ascension JV”), is a bolt-on project to our Cajun-Sibon NGL system and is supported by long-term, fee-based contracts with Marathon Petroleum.
Sale of Non-Core Assets

In March 2017, we completed the sale of our ownership interest in HEP for net proceeds of $189.7 million. For the year ended December 31, 2016, we recorded an impairment loss of $20.1 million to reduce the carrying value of our investment to the expected sales price. Upon the sale of HEP in March 2017, we recorded an additional loss of $3.4 million for the year ended December 31, 2017 based on the adjusted sales price at closing.

Acquisitions, Organic Growth and Asset Sales in 2015 and 2016

In January 2015, we acquired 100% of the voting equity interests of LPC Crude Oil Marketing LLC (“LPC”), which has crude oil gathering, transportation and marketing operations in the Permian Basin, for approximately $108.1 million.

In March 2015, we acquired 100% of the voting equity interests in Coronado Midstream Holdings LLC (“Coronado”), which owns natural gas gathering and processing facilities in the Permian Basin, for approximately $600.3 million.

In April 2015, we acquired VEX, located in the Eagle Ford Shale in South Texas, together with 100% of the voting equity interests (the “VEX interests”) in certain entities, from Devon in a drop down transaction (the “VEX Drop Down”) for $166.7 million in cash and approximately $9.0 million in ENLK common units. Additionally, we assumed $40.0 million in construction costs related to VEX.

In October 2015, we acquired 100% of the voting equity interests in a subsidiary of Matador Resources Company (“Matador”), which has gathering and processing operations in the Delaware Basin, for approximately $141.3 million.


Prior to November 2015, we co-owned the Deadwood natural gas processing plant with a subsidiary of Apache Corporation (“Apache”). In November 2015, we acquired Apache’s 50% ownership interest in the Deadwood natural gas processing facility for approximately $40.1 million. We now own 100% of the Deadwood processing plant.

In 2015, we completed the EMH Drop Downs.

In January 2016, ENLK and ENLC acquired an 83.9% and 16.1% interest, respectively, in EnLink Oklahoma T.O. for aggregate consideration of approximately $1.4 billion. The EnLink Oklahoma T.O. assets serve gathering and processing needs in the growing STACK and CNOW plays in Central Oklahoma and are supported by long-term, fixed-fee contracts with acreage dedications that, at the time of acquisition, had a weighted-average term of approximately 15 years.

In April 2016, we completed construction of the 100 MMcf/d Riptide processing plant in the Permian Basin.

In August 2016, we formed the Delaware Basin JV with NGP to operate and expand our natural gas, natural gas liquids and crude oil midstream assets in the Delaware Basin. The Delaware Basin JV is owned 50.1% by us and 49.9% by NGP.

In October 2016, we completed construction of the initial phase of the 60 MMcf/d Lobo II processing facilities.

In November 2016, we formed the Cedar Cove JV with Kinder Morgan, Inc., which consists of gathering and compression assets in Blaine County, Oklahoma, located in the heart of the STACK play. The gathering system has a capacity of 25 MMcf/d with over 50,000 gross acres of dedications and ties into our existing Oklahoma assets. All gas gathered by the Cedar Cove JV is processed at our Central Oklahoma processing system. We hold a 30% ownership interest of the Cedar Cove JV, and Kinder Morgan, Inc. holds the remaining 70% ownership interest.

In December 2016, we sold the North Texas Pipeline (the “NTPL”), a 140-mile natural gas transportation pipeline, for $84.6 million. We maintain capacity on the NTPL at competitive rates and at levels sufficient to support current and expected operations. As a result of the sale, we recorded a loss of $13.4 million for the year ended December 31, 2016.


Our Assets


Our assets consist of gathering systems, transmission pipelines, processing facilities, fractionation facilities, stabilization facilities, storage facilities, and ancillary assets. Except as stated otherwise, theThe following tables provide information about our assets as of and for the year ended December 31, 2017:2021:
Year Ended
December 31, 2021
Gathering and Transmission PipelinesApproximate Length (Miles)Compression (HP)Estimated Capacity (1)Average Throughput (2)
Gas Pipelines
Permian assets:
MEGA System gathering facilities980 205,436 545 684,500
Delaware gathering system (3)240 53,680 280 382,500
Permian gas assets (3)1,220 259,116 825 1,067,000
Louisiana assets:
Louisiana gas gathering and transmission system3,035 97,400 3,975 2,160,800
Oklahoma assets:
Central Oklahoma gathering system1,850 211,490 1,180 965,900
Northridge gathering system140 14,000 65 26,500
Oklahoma gas assets1,990 225,490 1,245 992,400
North Texas assets:
Bridgeport rich and lean gathering systems2,780 188,000 822 668,200
Johnson County gathering system385 49,000 400 92,300
Silver Creek gathering system890 45,000 205 200,600
Acacia transmission system130 16,000 920 416,300
North Texas gas assets4,185 298,000 2,347 1,377,400
Total Gas Pipelines10,430 880,006 8,392 5,597,600
NGL, Crude Oil, and Condensate Pipelines
Permian assets:
Permian Crude Oil and Condensate assets490 — 188,500 134,600
Louisiana assets:
Cajun-Sibon NGL pipeline system760 — 185,000 173,400
Ascension NGL pipeline (4)35 — 50,000 23,500
Ohio River Valley (5)210 — 17,370 15,900
Louisiana NGL, Crude Oil, and Condensate assets1,005 — 252,370 212,800
Oklahoma assets:
Central Oklahoma crude oil gathering systems200 — 160,000 20,200
Total NGL, Crude Oil, and Condensate Pipelines1,695 — 600,870 367,600
____________________________
(1)Estimated capacity for gas pipelines is MMcf/d. Estimated capacity for liquids and crude and condensate pipelines is Bbls/d.
(2)Average throughput for gas pipelines is MMbtu/d. Average throughput for NGL, crude, and condensate pipelines is Bbls/d.
(3)Includes gross mileage, compression, capacity, and throughput for the Delaware Basin JV, which is owned 50.1% by us. Estimated capacity on our Delaware gathering system includes only the Delaware Basin JV’s compression capacity and does not include gas compressed by third parties on our system.
(4)Includes gross mileage, capacity, and throughput for the Ascension JV, which is owned 50% by us.
(5)Estimated capacity is comprised of trucking capacity only.
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        Year Ended
        December 31, 2017
Gathering and Transmission Pipelines Approximate Length (Miles) Compression (HP) (1) Estimated Capacity (2) Average Throughput (3)
Gas Pipelines        
Texas assets:        
Bridgeport rich and lean gathering systems 2,840
 204,000
 861
 811,000
Johnson County gathering system 290
 44,000
 589
 134,300
Silver Creek gathering system 720
 77,000
 522
 390,600
Acacia transmission system 130
 16,600
 920
 565,700
North Texas assets 3,980
 341,600
 2,892
 1,901,600
MEGA System gathering facilities 700
 105,300
 393
 262,500
Lobo gathering system (4) 125
 15,200
 82
 98,800
Permian Basin assets (4) 825
 120,500
 475
 361,300
Texas assets 4,805
 462,100
 3,367
 2,262,900
         
Oklahoma assets:        
Central Oklahoma gathering system 1,500
 203,500
 937
 789,000
Northridge gathering system 140
 14,000
 65
 40,300
Oklahoma assets 1,640
 217,500
 1,002
 829,300
         
Louisiana assets:        
Louisiana gas gathering and transmission system 3,215
 97,400
 3,975
 1,995,800
Total Gas Pipelines 9,660
 777,000
 8,344
 5,088,000
         
NGL, Crude Oil and Condensate Pipelines        
Louisiana assets:        
Cajun-Sibon pipeline system 770
 —
 130,000
 119,200
Ascension pipeline (5) 20
 —
 50,000
 13,500
Louisiana assets 790
 —
 180,000
 132,700
         
Crude and condensate assets:        
Ohio River Valley (6) 210
 —
 25,650
 20,600
Victoria Express Pipeline 60
 —
 90,000
 15,100
Permian gathering (7) 360
 —
 118,500
 76,700
Total NGL, Crude Oil and Condensate Pipelines 1,420
 —
 414,150
 245,100
Year Ended
December 31, 2021
Processing FacilitiesProcessing Capacity (MMcf/d)Average Throughput (MMbtu/d)
Permian assets:
MEGA system processing facilities663 648,000 
Delaware processing facilities635 362,000 
Permian assets1,298 1,010,000 
Louisiana assets:
Louisiana gas processing facilities (1)1,778 214,700 
Oklahoma assets:
Central Oklahoma processing facilities (2)1,160 916,000 
Northridge processing facility200 94,300 
Oklahoma assets1,360 1,010,300 
North Texas assets:
Bridgeport processing facility800 505,200 
Silver Creek processing system (3)280 126,300 
North Texas assets1,080 631,500 
Total Processing Facilities5,516 2,866,500 
____________________________
(1)The Blue Water, Eunice, Plaquemine, and Sabine processing plants are not operational. These plants represent 193 MMcf/d, 350 MMcf/d, 225 MMcf/d, and 300 MMcf/d, respectively, for a total of 1,068 MMcf/d of the total processing capacity of the Louisiana gas processing facilities.
(2)The Thunderbird processing plant is not currently operational and represents 200 MMcf/d of the total processing capacity of the Central Oklahoma processing facilities. In November 2021, we began moving equipment and facilities associated with the Thunderbird processing plant in Central Oklahoma to the Permian Basin. When the move is completed, these assets will operate as a gas processing plant in the Permian Basin.
(3)The Azle and Goforth processing plants are not operational. These plants represent 50 MMcf/d and 30 MMcf/d, respectively, of the total processing capacity of the Silver Creek processing system.


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Year Ended
December 31, 2021
Fractionation FacilitiesEstimated NGL Fractionation Capacity (Bbls/d)Average Throughput (Bbls/d)
Permian assets:
Mesquite terminal (1)15,000 — 
Louisiana assets:
Plaquemine fractionation facility (2)136,800 80,900 
Riverside fractionation facility (2)— 32,900 
Plaquemine processing plant8,500 1,100 
Eunice fractionation facility75,000 62,600 
Louisiana assets220,300 177,500 
North Texas assets:
Bridgeport processing facility25,000 11,000 
Corporate assets:
GCF (3)56,000 11,800 
Total Fractionation Facilities316,300 200,300 
____________________________
(1)The Mesquite terminal fractionator is not currently operational.
(2)The Plaquemine fractionation facility produces purity ethane and propane for sale to markets via pipeline, while butane and heavier products are sent to the Riverside fractionation facility for further processing. The Plaquemine fractionation facility and the Riverside fractionation facility have an aggregate fractionation capacity of 136,800 Bbls/d.
(3)Volumes shown reflect our 38.75% ownership in GCF. The GCF fractionation facility is not currently operational.

(1)
Includes power generation units.
(2)
Estimated capacity for gas pipelines is MMcf/d. A volume capacity of 100 MMcf/d correlates to an approximate energy content of 100,000 MMBtu/d. Estimated capacity for liquids and crude and condensate pipelines is Bbls/d.
(3)
Average throughput for gas pipelines is MMBtu/d. Average throughput for NGL, crude and condensate pipelines is Bbls/d.
(4)
Includes gross mileage, compression, capacity and throughput for the Delaware Basin JV, which is owned 50.1% by us. Estimated capacity on our Lobo gathering system includes only the Delaware Basin JV’s compression capacity and does not include gas compressed by third parties on our system.
(5)
Includes gross mileage, capacity and throughput for the Ascension JV, which is owned 50% by us.
(6)
Estimated capacity is comprised of trucking capacity only.
(7)
Estimated capacity is comprised of 68,500 Bbls/d of pipeline capacity and 50,000 Bbls/d of trucking capacity.

    Year Ended
    December 31, 2017
Processing Facilities Processing Capacity (MMcf/d) Average Throughput (MMBtu/d)
Texas assets:    
Bridgeport processing facility 800
 605,500
Silver Creek processing system 280
 193,600
North Texas assets    1,080
 799,100
MEGA system processing facilities 408
 291,100
Lobo processing facilities 155
 94,200
Permian Basin assets 563
 385,300
Texas assets 1,643
 1,184,400
     
Oklahoma Assets:    
Central Oklahoma processing facilities 1,005
 759,500
Northridge processing facility 200
 50,800
Oklahoma assets 1,205
 810,300
     
Louisiana assets:    
Louisiana gas processing facilities 1,903
 453,300
Total Processing Facilities 4,751
 2,448,000
    Year Ended
    December 31, 2017
Fractionation Facilities Estimated NGL Fractionation Capacity (MBbls/d) Average Throughput (Bbls/d)
Louisiana assets:    
Plaquemine fractionation facility (1) 110
 59.9
Plaquemine processing plant 11
 4.0
Eunice fractionation facility 55
 43.1
Riverside fractionation facility (1) —
 30.4
Louisiana assets 176
    137.4
     
Texas assets:    
Bridgeport processing facility (2) 15
 —
Mesquite terminal (2) 15
 —
Texas assets 30
 —
     
Gulf Coast Fractionators (3) 56
 38.9
Total Fractionation Facilities 262
 176.3
(1)
The Plaquemine fractionation facility produces purity ethane and propane for sale to markets via pipeline, while butane and heavier products are sent to the Riverside fractionation facility for further processing. The Plaquemine fractionation facility and the Riverside fractionation facility have an aggregate fractionation capacity of 110 MBbls/d.
(2)
We have two fractionation facilities with capacity of 15 MBbls/d each. Our Mesquite terminal in the Permian Basin and our Bridgeport processing plant in North Texas provide operational flexibility for the related processing plants but are not the primary fractionation facilities for the NGLs produced by the processing plants. Under our current contracts, we do not earn fractionation fees for operating these facilities, so throughput volumes through these facilities are not captured on a routine basis and are not significant to our gross operating margins.
(3)
Volumes shown reflect only our contractual right to the benefits and burdens of a 38.75% economic interest in Gulf Coast Fractionators held by Devon.


Year Ended
December 31, 2021
Storage AssetsStorage TypeEstimated Storage Capacity (1)
Gas storage:Permian assets:
Avenger storageCrude0.1 
Louisiana assets:
Belle Rose gas storage facility                  11.9Gas
9.0 
Sorrento gas storage facility                    7.3Gas
5.6 
Total gasJefferson Island storage facility                  19.2Gas
3.0 
NGL storage:
Napoleonville NGL storage facility4.7NGL
6.8 
ORV storageCrude0.7 
Crude oil storage:
ORV storage                    0.5
VEX storage                    0.2
Total crude oil storage                    0.7
(1)Oklahoma assets:
Estimated capacity for gas
Central Oklahoma storage is Bcf, and includes linefill capacity necessary to operate storage facilities. Estimated capacity for NGL and crude oil storage is MMBbls.Crude0.2 

Texas____________________________
(1)Estimated capacity for gas storage is Bcf and includes linefill capacity necessary to operate storage facilities. Estimated capacity for NGL and crude oil storage is MMbbls.

Permian Segment Assets. Our TexasPermian segment assets include transmission pipelines,gas gathering systems, crude oil gathering systems and storage, gas processing facilities, and a fractionation facility, which assets are primarily in West Texas and New Mexico.

•Gas Gathering Systems.Our gas gathering systems in the Barnett ShalePermian segment consist of the following:

•MEGA system gathering facilities. This gathering system in North Texasthe Midland Basin serves as an interconnected system of pipelines and compressors to deliver gas from wellheads in the Permian Basin in West Texas.

to the MEGA system processing facilities.
Acacia Transmission System. The Acacia transmission
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•Delaware gas gathering system. This rich natural gas gathering system consists of gathering pipeline and compression assets in the Delaware Basin in Texas and New Mexico. These gathering systems are connected to our Lobo processing facilities and Tiger processing plant, which are owned by the Delaware Basin JV.

•Crude Oil Gathering Systems.Our crude oil gathering systems in the Permian segment consist of crude oil and condensate pipelines and above ground storage, including:

•Avenger. Avenger is a pipelinecrude oil gathering system in the northern Delaware Basin that connects production from the Barnett Shaleis supported by a long-term contract with Devon on dedicated acreage in their Todd and Potato Basin development areas in Eddy and Lea counties in New Mexico.

•Greater Chickadee Gathering System. Greater Chickadee delivers crude oil for customers to markets in North Texas accessed by Atmos Energy, Brazos Electric, Enbridge Energy Partners, Energy Transfer Partners, Enterprise Product Partners L.P.’s crude oil terminal in West Texas. Greater Chickadee also includes multiple central tank batteries with pump, truck injection, and GDF Suez. Devon is the Acacia transmission system’s only customer with approximately six years remaining on a fixed-fee transportation agreement that covers transmission servicesstorage stations to maximize shipping and includes annual rate escalators.
delivery options for producers.



•Gas Processing and Fractionation Facilities.Our gas processing facilities in Texas include 10 gas processing plants andthe Permian segment consist of the following:


North Texas Assets. Our North Texas processing systems include the following:

Bridgeport processing facility. Our Bridgeport natural gas processing facility, located in Wise County, Texas, approximately 40 miles northwest of Fort Worth, Texas, is one of the largest processing plants in the U.S. with seven cryogenic turboexpander plants. Devon is the Bridgeport facility’s largest customer, providing substantially all of the natural gas processed for the year ended December 31, 2017. We currently have approximately six years remaining on a fixed-fee processing agreement with Devon pursuant to which we provide processing services for natural gas delivered by Devon to the Bridgeport processing facility. This contractual arrangement includes an MVC from Devon of 650 MMcf/d of natural gas delivered to the Bridgeport processing facility that will remain in effect up to January 1, 2019.

Silver Creek processing system. Our Silver Creek processing system, located in Weatherford, Azle and Fort Worth, Texas, includes three processing plants: the Azle plant, the Silver Creek plant and the Goforth plant, which account for 50 MMcf/d, 200 MMcf/d and 30 MMcf/d of processing capacity, respectively.

Permian Basin Assets. Our Permian Basin processing facilities consist of the following:

•MEGA system processing facilities. Our Permian BasinMEGA system natural gas processing plantsfacilities are located in Midland, Martin, and Glasscock counties, Texas and operate as a connected system. These assets consist of the Bearkat processing facility with a capacity of 75 MMcf/d, the Deadwood processing facility with a capacity of 58 MMcf/d, the Midmar processing facilities with a capacity of 175195 MMcf/d, and the Riptide processing facility with a capacity of 100240 MMcf/d, (collectively,and the “Midland Energy Gathering Area” or “MEGA system”).
War Horse processing plant with a capacity of 95 MMcf/d.



Lobo•Delaware processing facilities. The Delaware processing facilities include our Lobo natural gas processing facilities and the Tiger processing plant. Our Lobo natural gas processing facilities are located in Loving County, Texas and include twoLobo I, Lobo II, and Lobo III processing plants the Lobo I plant and the Lobo II plant, which account for 35 MMcf/d, 140 MMcf/d, and 120220 MMcf/d of processing capacity, respectively. Our Tiger processing plant is located in Culberson County, Texas, and accounts for 240 MMcf/d of processing capacity. The Lobo processing facilities and the connected gathering system and the Tiger processing plant are owned by the Delaware Basin JV.


Gathering Systems. Our gathering systems in Texas are connected to our North Texas or Permian Basin processing assets.

North Texas Assets. Our North Texas gathering systems include the following:

Bridgeport rich gathering system. A substantial majority•Fractionation Facility.The Mesquite fractionator has an approximate capacity of the natural gas gathered on the Bridgeport rich gas gathering system is delivered to the Bridgeport processing facility. Devon is the largest customer on the Bridgeport rich gathering system contributing substantially all of the natural gas gathered for the year ended December 31, 2017. As described above, we currently have approximately six years remaining on a fixed-fee gathering agreement with Devon pursuant to which we provide gathering services on the Bridgeport system. The agreement includes an MVC from Devon that will remain in effect up to January 1, 2019, with a combined 850 MMcf/15,000 Bbls/d of natural gas to be delivered for gathering into the Bridgeport rich and Bridgeport lean gathering systems.

Bridgeport lean gathering system. Natural gas gathered on the Bridgeport lean gathering system is all attributable to Devon and is delivered to the Acacia transmission system and to intrastate pipelines without processing. As described above, we are party to a fixed-fee gathering and processing agreement with Devon that covers gathering services on the Bridgeport system.

Johnson County gathering system. Naturallocated at our Midland gas gathered on this system is primarily attributable to Devon and is delivered to intrastate pipelines without processing. We currently have approximately six years remaining on a fixed-fee gathering agreement pursuant to which we provide gathering services on the Johnson County gathering system. This contractual arrangement includes an MVC from Devon that will remain in effect up to January 1, 2019, with 125 MMcf/d of natural gas to be delivered for gathering into the Johnson County gathering system.

Silver Creek gathering system. Our Silver Creek gathering system is located primarily in Hood, Parker and Johnson counties, Texas, and connects to the Silver Creek processing system.

Permian Basin assets. Our Permian Basin gathering systems include the following:

MEGA system gathering facilities. This gathering system in the Permian Basin serves as an interconnected system of pipelines and compressors to deliver gas from wellheads in the Permian Basin to the MEGA system processing facilities.

Lobo gathering system. The rich natural gas gathering system consists of gathering pipeline and compression assets in the Delaware Basin primarily in Texas, with a minor portion in New Mexico. The Lobo gathering system is owned by the Delaware Basin JV.

Oklahoma Assets. Our Oklahoma assets consist of processing facilities and gathering systems in southern and Central Oklahoma.

Oklahoma processing system. Our processing facilities include the following:

Central Oklahoma processing facilities. The Central Oklahoma plants include the Chisholm plants, the Battle Ridge plant and the Cana processing facilities (collectively, the “Central Oklahoma processing system”), which account for 520 MMcf/d, 85 MMcf/d and 400 MMcf/d of processing capacity, respectively. The residue natural gas from the Cana processing facility is delivered to Enable Midstream Partners and ONEOK. The unprocessed NGLs from the Chisholm facilities are transported by ONEOK to NGL transmission lines, which then transport the NGLs to our fractionators in Louisiana. Devon is the primary customer of the Cana processing facilities and has approximately six years remaining on a fixed-fee gathering and processing agreement with us pursuant to which we provide processing services for natural gas delivered by Devon to

the Cana processing facility. In addition, contractual arrangements related to the Central Oklahoma processing system that contain an MVC include the following:

Our contractual arrangement with Devon includes an MVC that will remain in effect until October 2020. For 2018, the MVC dictates that approximately 145 MMcf/d of natural gas will be delivered to the Chisholm plant processing facility. The MVC escalates quarterly, resulting in approximately 230 MMcf/d to be delivered in 2020.

We have another contractual arrangement with Devon that includes an MVC that will remain in effect up to January 1, 2019 with 330 MMcf/d of natural gas to be delivered to the Cana processing facility.

Northridge processing facility. Our Northridge processing plant complex. The Mesquite fractionator is located in Hughes County in the Arkoma-Woodford Shale in southeastern Oklahoma. The residue natural gas from the Northridge processing facility is delivered to Centerpoint, Enable Midstream Partners and MPLX.
not currently operational.


Oklahoma gathering system. Our Oklahoma gathering systems include the following:

Central Oklahoma gathering system. The Central Oklahoma gathering system serves the STACK and CNOW plays. Contractual arrangements related to the Central Oklahoma gathering system that contain an MVC include the following:

Our contractual arrangement with Devon includes an MVC that will remain in effect until October 2020. For 2018, the MVC dictates that approximately 153 MMcf/d of natural gas will be handled through the Chisholm gathering system. The MVC escalates quarterly, resulting in approximately 230 MMcf/d to be delivered in 2020.

We have another contractual arrangement with Devon that includes an MVC that will remain in effect up to January 1, 2019, with 330 MMcf/d of natural gas to be handled through the Cana gathering system.

Northridge gathering system. Our Northridge gathering system is located in the Arkoma-Woodford Shale in Southeastern Oklahoma.

Louisiana Segment Assets. Our Louisiana segment assets consist of gas and NGL gathering and transmission pipelines, gas processing facilities, gathering systems and gas and NGL storage.storage, and our ORV crude logistics assets.


Louisiana Gas Pipeline•Transmission and ProcessingGathering Systems. The Louisiana gas pipeline system in the Louisiana segment includes gathering and transmission systems, processing facilities, and underground gas storage.


•Gas Transmission and Gathering Systems. Our transmission system consists of a portfolio of large capacity interconnections with the Gulf Coast pipeline grid that provides customers with supply access to multiple domestic production basins for redelivery to major industrial market consumption located primarily in the Mississippi River Corridor between Baton Rouge, Louisiana and New Orleans.Orleans, Louisiana. Our natural gas transmission services are supplemented by fully integrated, high deliverability salt dome storage capacity strategically located in the natural gas consumption corridor. In combination with our transmission system, our gathering systems provide a fully integrated wellhead to burner tip value chain that includes local gathering, processing, and treating services to Louisiana producers.


•Gas Processing and Storage Facilities. Facilities.Our gas processing facilities and storage facilities in the Louisiana include five gas processing plants,segment consist of which three are currently operational.
the following:


Plaquemine Processing Plant. The Plaquemine processing plant has 225 MMcf/d of processing capacity and is connected to the Plaquemine fractionation facility.

•Gibson Processing Plant. The Gibson processing plant has 110 MMcf/d of processing capacity and is located in Gibson, Louisiana. The Gibson processing plant is connected to our Louisiana gathering system.

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•Pelican Processing Plant. The Pelican processing plant complex is located in Patterson, Louisiana and has a designed capacity of 600 MMcf/d of natural gas. The Pelican processing plant is connected with continental shelf and deepwater production and has downstream connections to the ANR Pipeline. This plant has an interconnection with the Louisiana gas pipeline system allowing us to process natural gas from this system at our Pelican processing plant when markets are favorable.


•Belle Rose Gas Storage Facility. The Belle Rose gas storage facility is located in Assumption Parish, Louisiana. This facility is designed for injecting pipeline quality gas into storage or withdrawing stored gas for delivery by pipeline.

•Sorrento Gas Storage Facility. The Sorrento gas storage facility is located in Ascension Parish, Louisiana. This facility is designed for injecting pipeline quality gas into storage or withdrawing stored gas for delivery by pipeline.

•Jefferson Island Storage Facility. The Jefferson Island storage facility and pipeline header system is located in Iberville and Vermilion Parishes in Louisiana. In December 2020, we acquired the Jefferson Island storage facility, which includes natural gas storage capacity that is connected to our extensive Louisiana natural gas system.

•Idled Processing Plants:

•Blue Water Gas Processing Plant. We operate and own a 64.29% interest in the Blue Water gas processing plant. The Blue Water gas processing plant is located in Crowley, Louisiana and is connected to the Blue Water pipeline system. Our share of the plant’s capacity is approximately 193 MMcf/d. TheWe have shut down the Blue Water gas processing plant, isand we do not expectedexpect to operate it in the near future unless fractionation spreads are favorable and volumes are sufficient to run the plant.


•Plaquemine Processing Plant. The Plaquemine processing plant has 225 MMcf/d of processing capacity and is connected to the Plaquemine fractionation facility. While the Plaquemine processing plant is currently idle, it has operated periodically throughout 2021 when volumes were sufficient to run the plant. We expect to continue to operate the plant when volumes are sufficient.

•Eunice Processing Plant. The Eunice processing plant is located in south centralSouth Central Louisiana and has a capacity of 475350 MMcf/d of natural gas. In August 2013, weWe have shut down the Eunice processing plant, due to adverse economics driven by low NGL prices and low processing volumes, which we do not see improvingexpect the plant to operate in the near term based on forecasted prices.
future unless volumes are sufficient to run the plant.


•Sabine Pass Processing Plant. The Sabine Pass processing plant is located east of the Sabine River atin Johnson's Bayou, Louisiana and has a processing capacity of 300 MMcf/d of natural gas. In 2013, weWe have shut down the Sabine Pass processing plant, and we do not anticipate reopeningexpect the plant based on current market conditions.
to operate in the near future unless volumes are sufficient to run the plant.


Belle Rose Gas Storage Facility. The Belle Rose storage facility is located•NGL and Crude Oil Pipeline Systems.Our NGL and crude oil pipeline systems in Assumption Parish, Louisiana. This facility was placed in service in May 2016the Louisiana segment consist of NGL pipelines, crude oil and is designed for injecting pipeline quality gas into storage or withdrawing stored gas for delivery by pipeline.

Sorrento Gas Storage Facility. The storage facility is located in Assumption Parish, Louisiana. This facility is designed for injecting pipeline quality gas into storage or withdrawing stored gas for delivery by pipeline.

Louisiana Liquids Pipeline System. Our Louisiana liquids pipeline system includes NGL transport lines, fractionation assets andcondensate pipelines, underground NGL storage.
storage, and our ORV crude logistics assets.


•Cajun-Sibon Pipeline System. The Cajun-Sibon pipeline system transports unfractionated NGLs from areas such as the Liberty, Texas interconnects near Mont Belvieu, Texas, and, from time to time, our Gibson and Pelican processing plants in South Louisiana to either the RiversidePlaquemine or Eunice fractionators or to third-party fractionators when necessary.
necessary.


•Ascension Pipeline. The Ascension JV is an NGL pipeline that connects our Riverside fractionator to Marathon Petroleum’sPetroleum Corporation’s Garyville refinery and is owned 50% by Marathon Petroleum.Petroleum Corporation.

•Napoleonville Storage Facility. The Napoleonville NGL storage facility is connected to the Riverside facility and is comprised of two existing caverns. The caverns currently provide butane storage.

•Ohio River Valley. Our ORV operations are an integrated network of assets comprised of a 5,000-barrel-per-hour crude oil and condensate barge loading terminal on the Ohio River, a 20-spot crude oil and condensate
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rail loading terminal on the Ohio Central Railroad network, crude oil and condensate pipelines in Ohio and West Virginia, above ground crude oil storage, a trucking fleet comprised of both semi and straight trucks, trailers for hauling NGL volumes, and seven existing brine disposal wells. Additionally, our ORV operations include condensate stabilization and natural gas compression stations that are supported by long-term, fee-based contracts with multiple producers.

•Fractionation Facilities.There are four fractionation facilities located in the Louisiana segment that are connected to our processing facilities and to Mont Belvieu, Texas and other hubs through our Cajun-Sibon pipeline system.


•Plaquemine Fractionation Facility. The Plaquemine fractionator is located at our Plaquemine gas processing plant complex and is connected to our Cajun-Sibon pipeline. The Plaquemine fractionation facility produces purity ethane and propane for sale to markets via pipeline, while butane and heavier products are sent to our Riverside facility for further processing. The Plaquemine fractionator, collectively with the Riverside Fractionation Facility, has an approximate capacity of 110,000136,800 Bbls/d of raw-make NGL products.


•Plaquemine Gas Processing Plant. In addition to the Plaquemine fractionation facility, the adjacent Plaquemine Gas Processing Plantgas processing plant also has an on-site fractionator.


•Eunice Fractionation Facility. The Eunice fractionation facility is located in south centralSouth Central Louisiana. Liquids are delivered to the Eunice fractionation facility by the Cajun-Sibon pipeline.pipeline system. The Eunice fractionation facility fractionates butane and heavier products from our Riverside facility and is directly connected to the southeast propane marketNGL markets and to a third-party storage facility.


•Riverside Fractionation Facility. The Riverside fractionator and loading facility isare located on the Mississippi River upriver from Geismar, Louisiana. Liquids are delivered to the Riverside fractionator by the Cajun-Sibon pipeline system from the Eunice and Pelican processing plants or by third-party truck and rail assets. The loading/unloading facility has the capacity to transload 15,000 Bbls/d of crude oil and condensate from rail cars to barges.

Oklahoma Segment Assets. Our Oklahoma segment assets consist of gas processing facilities, gas gathering systems, and crude oil gathering systems and storage in Southern and Central Oklahoma.

•Gas Gathering Systems.Our gas gathering systems in the Oklahoma segment consist of the following:

•Central Oklahoma gathering system. The Central Oklahoma gathering system serves the STACK and CNOW plays.

•Northridge gathering system. Our Northridge gathering system is located in the Arkoma-Woodford Shale in Southeastern Oklahoma.

•Gas Processing Facilities.Our gas processing facilities in the Oklahoma segment consist of the following:

•Central Oklahoma processing facilities. The Central Oklahoma processing facilities include the Thunderbird processing plant, the Chisholm processing plants, and the Cana processing plant (collectively, the “Central Oklahoma processing system”), which account for 200 MMcf/d, 560 MMcf/d, and 400 MMcf/d of processing capacity, respectively.

•The processing facility at the Thunderbird processing plant was idled due to decreased volumes. In November 2021, we began moving equipment and facilities associated with the Thunderbird processing plant in Central Oklahoma to the Midland Basin. We expect to complete the relocation in the second half of 2022.

•The unprocessed NGLs from the Chisholm processing plants are transported by ONEOK, Inc. (“ONEOK”) to NGL transmission lines, which then transport the NGLs to our fractionators in Louisiana.

•The residue natural gas from the Cana processing plant is delivered to Enable Midstream Partners, LP and an affiliate of ONEOK. Devon is the primary customer of the Cana processing plant. We have extended our fixed-fee processing agreement with Devon, which was effective after the GIP Transaction, and currently have approximatelyseven years remaining on the fixed-fee gathering and processing
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agreement pursuant to which we provide processing services for natural gas delivered by Devon to the Cana processing plant.

Napoleonville Storage Facility. •Northridge processing facility. Our Northridge processing plant is located in Hughes County in the Arkoma-Woodford Shale in Southeastern Oklahoma. The Napoleonville NGL storageresidue natural gas from the Northridge processing facility is connecteddelivered to CenterPoint Energy, Inc., Enable Midstream Partners, LP, and MPLX LP.

•Crude Oil Gathering Systems.Our crude and condensate assetsin the Riverside facility and is comprised of two existing caverns. The caverns are currently operated in butane service, and space is leased to customers for a fee.

Crude and Condensate. Our Crude and Condensate assets consist ofOklahoma segment have crude oil and condensate pipelines and above ground storage and a trucking fleet.in Central Oklahoma. These assets consist of the following:


Ohio River Valley.•Central Oklahoma Crude Oil Gathering Systems. Our ORV operations are an integrated network of assets comprised of a 5,000-barrel-per-hour crude oil and condensate barge loading terminal on the Ohio River, a 20-spot crude oil and condensate rail loading terminal on the Ohio Central Railroad network, crude oil and condensate pipelines in Ohio and West Virginia, above ground crude oil storage, a trucking fleet comprised of both semi and straight trucks, trailers for hauling NGL volumes and seven existing brine disposal wells. Additionally, our ORV operations include eight condensate stabilization and natural gas compression stations that are supported by long-term, fee-based contracts with multiple producers.

Permian Crude and Condensate. Our Permian Crude and Condensate assets haveOklahoma crude oil gathering transportation and marketing operations in the Permian Basin. These assetssystems include trucking and crude gathering pipelines acquired in the LPC acquisition and the Greater Chickadee gathering system, which was placed into service in March 2017 and delivers crude oil for customers to Enterprise Product Partners L.P.’s crude oil terminal in West Texas. Greater Chickadee also includes multiple central tank batteries, with pump, truck injection and storage stations to maximize shipping and delivery options for producers.

Black Coyote Crude Oil Gathering System. We are expanding our operationsand Redbud. Black Coyote operates in the core of the STACK play in Central Oklahoma with the construction of the Black Coyote crude oil gathering system. Black Coyote isand was built primarily being built onto service acreage dedicated acreage from Devon, which will beis the main shipperanchor customer on the system. TheRedbud also operates in the core of the STACK play and is supported by a contract with Marathon Oil Company.

North Texas Segment Assets. Our North Texas segment assets include gas gathering systems, a gas transmission system, gas processing facilities, and a fractionation facility in the Barnett Shale.

•Gas Gathering Systems.Our gas gathering systems in the North Texas segment are connected to our processing assets and consist of the following:

•Bridgeport rich gas gathering system. A substantial majority of the natural gas gathered on the Bridgeport rich gas gathering system is expecteddelivered to be operationalthe Bridgeport processing facility. BKV was the largest customer on the Bridgeport rich gas gathering system contributing substantially all of the natural gas gathered for the year ended December 31, 2021. BKV acquired Devon’s Barnett Shale assets in October 2020. As a result of this acquisition, we have extended a fixed-fee gathering agreement with BKV and currently have approximately eleven years remaining on the fixed-fee gathering agreement pursuant to which we provide gathering services on the Bridgeport system.

•Bridgeport lean gas gathering system. Natural gas gathered on the Bridgeport lean gas gathering system was primarily attributable to BKV for the year ended December 31, 2021 and was delivered to the Acacia transmission system and to intrastate pipelines without processing. As described above, we are party to a fixed-fee gathering and processing agreement with BKV that covers gathering services on the Bridgeport system.

•Johnson County gathering system. Natural gas gathered on this system is primarily attributable to one customer with whom we have a fixed-fee processing agreement that currently has approximately two years remaining.

•Silver Creek gathering system. Our Silver Creek gathering system is located primarily in Hood, Parker, and Johnson counties, Texas, and connects to the Silver Creek processing system.

•Gas Transmission System.The Acacia transmission system is a pipeline that connects production from the Barnett Shale to markets in North Texas accessed by Atmos Energy, Brazos Electric, Enbridge Inc, Energy Transfer Partners, Enterprise Product Partners, and GDF Suez. BKV was the largest customer on the Acacia pipeline for the year ended December 31, 2021. We currently have approximately two years remaining on a fixed-fee transportation agreement with BKV that covers transmission services and includes annual rate escalators.


•Gas Processing Facilities.Our gas processing facilities in the first quarterNorth Texas segment consist of 2018.
the following:


•Bridgeport processing facility. Our Bridgeport natural gas processing facility, located in Wise County, Texas, is one of the largest processing plants in the U.S. with seven cryogenic turboexpander plants. BKV was the Bridgeport facility’s largest customer, providing substantially all of the natural gas processed for the year ended December 31, 2021. As described above, we have extended a fixed-fee processing agreement with BKV and currently have approximately eleven years remaining on our agreement with BKV pursuant to which we provide processing services for natural gas delivered to the Bridgeport processing facility.
Victoria Express Pipeline. VEX
•Silver Creek processing system. Our Silver Creek processing system, located in Weatherford, Azle, and Fort Worth, Texas, includes a multi-grade crude oil pipeline with terminals in Cuerothree processing plants: the Azle plant, the Silver Creek plant, and the PortGoforth plant,
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which account for 50 MMcf/d, 200 MMcf/d, and barge docks.30 MMcf/d of processing capacity, respectively. The Cuero truck unloading terminalAzle and Goforth plants are idled due to decreased volumes, and these plants remain non-operational. Currently, the processing capacity at the origin ofSilver Creek plant is sufficient to process all gas on the VEX system contains eight unloading baysSilver Creek processing system.

•Fractionation Facility.Our Bridgeport processing plant in North Texas also has fractionation capabilities that provide operational flexibility for the related processing plants but is not the primary fractionation facility for the NGLs produced by the processing plants. Under our current contracts, we do not earn fractionation fees for operating this facility, so throughput volumes through this facility are not captured on a routine basis and above-ground storage capacity for receipt from and deliveryare not significant to the VEX pipeline. The VEX pipeline terminates at the Port of Victoria Terminal, which has an eight-bay truck unloading dock and above-ground storage capacity. The Port of Victoria Terminal delivers to two barge loading docks at the Port of Victoria. We have an agreement with Devon, which includes an MVC of 30,000 Bbls/d, that will remain in effect until July 2019.
our adjusted gross margin.


Corporate. Corporate Segment Assets. Our Corporate segment assets primarily consist of a contractual right to the benefits and burdens associated with Devon’sour 38.75% ownership interest in GCF and a 30% ownership interest in the Cedar Cove JV.


Gulf Coast Fractionators•GCF. We are entitled to receive the economic benefits and burdens of theown a 38.75% interest in GCF, held by Devon, with the remaining interests owned 22.5% by Phillips 66, and 38.75% by Targa Resources Partners.Partners, LP. GCF owns an NGL fractionator located on the Gulf Coast at Mont Belvieu, Texas. Phillips 66Targa Resources Partners, LP is the operator of the fractionator. GCF receives raw mix NGLs from customers, fractionates the raw mix, and redelivers the finished products to the customers for a fee.
Beginning in January 2021, the GCF assets were 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.


•Cedar Cove JV. On November 9, 2016, we formedWe own a joint venture with Kinder Morgan, Inc. consisting of30% interest in the Cedar Cove JV, which operates gathering and compression assets in Blaine County, Oklahoma whichthat tie into our existing Oklahoma assets. Kinder Morgan, Inc. owns a 70% interest in, and is the operator of, the Cedar Cove JV. All gas gathered by the Cedar Cove JV is processed by our Central Oklahoma processing facilities.

Recent Developments

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 own 30%expect to complete the relocation in the second half of 2022.

Amarillo Rattler Acquisition. On April 30, 2021, we completed the Cedar Cove JV.acquisition of Amarillo Rattler, LLC, the owner of a gathering and processing system located in the Midland Basin. In connection with the purchase, we entered into an amended and restated gas gathering and processing agreement with Diamondback Energy, strengthening our dedicated acreage position with that entity. We acquired the system with an upfront payment of $50.0 million, which was paid with cash-on-hand, with an additional $10.0 million to be paid on April 30, 2022, and contingent consideration capped at $15.0 million and payable between 2024 and 2026 based on Diamondback Energy’s drilling activity above historical levels.

War Horse Processing Plant. In December 2020, we began moving equipment and facilities previously associated with the Battle Ridge processing plant in Central Oklahoma to the Permian Basin. The move has been completed and the War Horse processing plant began operations in August 2021. In November 2021, we completed an expansion to the War Horse processing plant, which increased the processing capacity to 95 MMcf/d.

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Industry Overview


The following diagram illustrates the gathering, processing, fractionation, stabilization, and transmission process.

enlc-20211231_g2.jpg


The midstream industry is the link between the exploration and production of natural gas and crude oil and condensate and the delivery of its components to end-user markets. The midstream industry is generally characterized by regional competition based on the proximity of gathering systems and processing plants to natural gas and crude oil and condensate producing wells.


Natural gas gathering. The natural gas gathering process follows the drilling of wells into gas-bearing rock formations. After a well has been completed, it is connected to a gathering system. Gathering systems typically consist of a network of small diameter pipelines and, if necessary, compression and treating systems that collect natural gas from points near producing wells and transport it to larger pipelines for further transmission.


Compression. Gathering systems are operated at pressures that will maximize the total natural gas throughput from all connected wells. Because wells produce gas at progressively lower field pressures as they age, it becomes increasingly difficult to deliver the remaining production in the ground against the higher pressure that exists in the connected gathering system. Natural gas compression is a mechanical process in which a volume of gas at an existing pressure is compressed to a desired higher pressure, allowing gas that no longer naturally flows into a higher-pressure downstream pipeline to be brought to market. Field compression is typically used to allow a gathering system to operate at a lower pressure or provide sufficient discharge pressure to deliver gas into a higher-pressure downstream pipeline. The remaining natural gas in the ground will not be produced if field compression is not installed because the gas will be unable to overcome the higher gathering system pressure. A declining well can continue delivering natural gas if field compression is installed.


Natural gas processing. The principal components of natural gas are methane and ethane, but most natural gas also contains varying amounts of heavier NGLs and contaminants, such as water and CO2, sulfur compounds, nitrogen, or helium. Natural gas produced by a well may not be suitable for long-haul pipeline transportation or commercial use and may need to be processed to remove the heavier hydrocarbon components and contaminants. Natural gas in commercial distribution systems mostly consists of methane and ethane, and moisture and other contaminants have been removed, so there are negligible
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amounts of them in the gas stream. Natural gas is processed to remove unwanted contaminants that would interfere with pipeline transportation or use of the natural gas and to separate those hydrocarbon liquids from the gas that have higher value as NGLs. The removal and separation of individual hydrocarbons through processing is possible due to differences in weight, boiling point, vapor pressure, and other physical characteristics. Natural gas processing involves the separation of natural gas into pipeline-quality natural gas and a mixed NGL stream and the removal of contaminants.



NGL fractionation. NGLs are separated into individual, more valuable components during the fractionation process. NGL fractionation facilities separate mixed NGL streams into discrete NGL products: ethane, propane, isobutane, normal butane, natural gasoline, and stabilized crude oil and condensate. Ethane is primarily used in the petrochemical industry as feedstock for ethylene, one of the basic building blocks for a wide range of plastics and other chemical products. Propane is used as a petrochemical feedstock in the production of ethylene and propylene and as a heating fuel, an engine fuel, and industrial fuel. Isobutane is used principally to enhance the octane content of motor gasoline. Normal butane is used as a petrochemical feedstock in the production of ethylene and butylene (a key ingredient in synthetic rubber), as a blend stock for motor gasoline, and to derive isobutene through isomerization. Natural gasoline, a mixture of pentanes and heavier hydrocarbons, is used primarily as motor gasoline blend stock or petrochemical feedstock.


Natural gas transmission. Natural gas transmission pipelines receive natural gas from mainline transmission pipelines, processing plants, and gathering systems and deliver it to industrial end-users, utilities, and to other pipelines.


Crude oil and condensate transmission. Crude oil and condensate are transported by pipelines, barges, rail cars, and tank trucks. The method of transportation used depends on, among other things, the resources of the transporter, the locations of the production points and the delivery points, cost-efficiency, and the quantity of product being transported.


Condensate Stabilization. Condensate stabilization is the distillation of the condensate product to remove the lighter end components, which ultimately creates a higher quality condensate product that is then delivered via truck, rail, or pipeline to local markets.


Brine gathering and disposal services. Typically, shale wells produce significant amounts of water that, in most cases, require disposal. Produced water and frac-flowback is hauled via truck transport or is pumped through pipelines from its origin at the oilfield tank battery or drilling pad to the disposal location. Once the water reaches the delivery disposal location, water is processed and filtered to remove impurities, and injection wells place fluids underground for storage and disposal.


Storage. Demand for natural gas, NGLs, and crude oil fluctuate daily and seasonally, while production and pipeline deliveries are relatively constant in the short term. Storage of products during periods of low demand helps to ensure that sufficient supplies are available during periods of high demand. Natural gas and NGLs are stored in large volumes in underground facilities and in smaller volumes in tanks above and below ground, while crude oil is typically stored in tanks above ground.


Crude oil and condensate terminals. Crude oil and condensate rail terminals are an integral part of ensuring the movement of new crude oil and condensate production from the developing shale plays in the United States and Canada. In general, the crude oil and condensate rail loading terminals are used to load rail cars and transport the commodity out of developing basins into market rich areas of the country where crude oil and condensate rail unloading terminals are used to unload rail cars and store crude oil and condensate volumes for third parties until the crude oil and condensate is redelivered to premium market delivery points via pipelines, trucks, or rail.


Balancing Supply and Demand


When we purchase natural gas, NGLs, crude oil, and condensate, we establish a margin normally by selling it for physical delivery to third-party users. We can also use over-the-counter derivative instruments or enter into future delivery obligations under futures contracts on the New York Mercantile Exchange (“NYMEX”) related to our natural gas purchases.purchases to balance our margin position. Through these transactions, we seek to maintain a position that is balanced between (1) purchases and (2) sales or future delivery obligations. Our policy is not to acquire and hold natural gas, NGL, or crude oil futures contracts or derivative products for the purpose of speculating on price changes.


Competition


The business of providing gathering, transmission, processing, and marketing services for natural gas, NGLs, crude oil, and condensate is highly competitive. We face strong competition in obtaining natural gas, NGLs, crude oil, and condensate
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supplies and in the marketing, transportation, and transportationprocessing of natural gas, NGLs, crude oil, and condensate. Our competitors include major integrated and independent exploration and production companies, natural gas producers, interstate and intrastate pipelines, other natural gas, NGLs, and crude oil and condensate gatherers, and natural gas processors. Competition for natural gas and crude oil and condensate supplies is primarily based on geographic location of facilities in relation to production or markets, the reputation, efficiency, and reliability of the gatherer, and the pricing arrangements offered by the gatherer. For areas where acreage is not dedicated to us, we will compete with similar enterprises in providing additional gathering and processing

services in its respective areas of operation, whichoperation. Many of our competitors may offer more services or have stronggreater financial resources and access to larger natural gas, NGLs, crude oil, and condensate supplies than we do. Our competition varies in different geographic areas.


In marketing natural gas, NGLs, crude oil, and condensate, we have numerous competitors, including marketing affiliates of interstate pipelines, major integrated oil and gas companies, and local and national natural gas producers, gatherers, brokers, and marketers of widely varying sizes, financial resources, and experience. Local utilities and distributors of natural gas are, in some cases, engaged directly and through affiliates in marketing activities that compete with our marketing operations.


We face strong competition for acquisitions and development of new projects from both established and start-up companies. Competition increases the cost to acquire existing facilities or businesses and results in fewer commitments and lower returns for new pipelines or other development projects. Our competitors may have greater financial resources than we possess or may be willing to accept lower returns or greater risks. Our competition differs by region and by the nature of the business or the project involved.


Natural Gas, NGL, Crude Oil, and Condensate Supply


Our gathering and transmission pipelines have connections with major intrastate and interstate pipelines, which we believe have ample natural gas and NGL supplies in excess of the volumes required for the operation of these systems. We evaluate well and reservoir data that is either publicly available or furnished by producers or other service providers in connection with the construction and acquisition of our gathering systems and assets to determine the availability of natural gas, NGLs, crude oil, and condensate supply for our systems and assets and/or obtain an MVC from the producer that results in a rate of return on investment. We do not routinely obtain independent evaluations of reserves dedicated to our systems and assets due to the cost and relatively limited benefit of such evaluations. Accordingly, we do not have estimates of total reserves dedicated to our systems and assets or the anticipated life of such producing reserves.


Credit Risk and Significant Customers


We are subject to risk of loss resulting from nonpayment or nonperformance by our customers and other counterparties, such as our lenders and hedging counterparties. We diligently attempt to ensure that we issue credit to only credit-worthy customers. However, our purchase and resale of crude oil, condensate, NGLs, and natural gas exposes us to significant credit risk, as the margin on any sale is generally a very small percentage of the total sales price. Therefore, a credit loss can be very large relative to our overall profitability. A substantial portion of our throughput volumes come from customers that have investment-grade ratings. However, lower commodity prices in future periods and other macro-economic factors, including the ongoing or future effects of the COVID-19 pandemic on our industry and our customers may result in a reduction in our customers’ liquidity and ability to make payments or perform on their obligations to us. Some

The following customers individually represented greater than 10% of our consolidated revenues during 2021, 2020, or 2019. These customers have filed for bankruptcy protection, and their debts and payments to us are subject to laws governing bankruptcy.

For the years ended December 31, 2017, 2016 and 2015, Devon represented 14.4%, 18.5% and 16.6%, respectively,a significant percentage of our consolidated revenues, and Dow Hydrocarbons & Resources LLC (“Dow Hydrocarbons”) represented 11.2%, 10.8% and 11.7%, respectively, of our consolidated revenues. No other customer represented greater than 10.0% of our revenue. Our operations are dependent on the volume of natural gas that Devon provides to us under commercial agreements, which constitutes a substantial portion of our natural gas supply. The loss of Devon or Dow Hydrocarbons as a customer couldthese customers would have a material adverse impact on our results of operations if we were not able to sell our products to another customer with similar margins because the revenues and adjusted gross operating marginsmargin received from transactions with Devon and Dow Hydrocarbons arethese customers is material to us. No other customers represented greater than 10% of our total gross operating margin.consolidated revenues during the periods presented.

Year Ended December 31,
202120202019
Devon6.7 %14.4 %10.5 %
Dow Hydrocarbons and Resources LLC14.5 %13.2 %10.0 %
Marathon Petroleum Corporation13.4 %12.2 %13.8 %

Regulation
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Regulation

Recent Regulatory Developments. On January 20, 2021, the Acting Secretary for the Department of the Interior signed an order suspending new fossil fuel leasing and permitting on federal lands, including offshore pipeline leases, for 60 days.Then 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 a comprehensive review and reconsideration of federal oil and gas permitting and leasing practices.Several states filed lawsuits challenging the suspension and on June 15, 2021, 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.

If our customers are unable to secure permits, sustained reductions in exploration or production activity in our areas of operation could lead to reduced utilization of our pipeline and terminal systems or reduced rates under renegotiated transportation or storage agreements. We are still evaluating the effects of the potential change to the federal leasing program on our operations and our customers’ operations, but our inability and our customers’ inability to secure required permits could adversely affect our business, financial condition, results of operations, or cash flows, including our ability to make cash distributions to our unitholders.

Natural Gas Pipeline Regulation. We own an interstate natural gas pipelinespipeline that areis subject to regulation as a natural gas companiescompany by the Federal Energy Regulatory Commission (“FERC”)FERC under the Natural Gas Actof 1938 (“NGA”). FERC regulates the rates and terms and conditions of service on interstate natural gas pipelines, as well as the certification, construction, modification, expansion, and abandonment of facilities.

The rates and terms and conditions of service for our interstate pipeline services regulated by FERC must be just and reasonable and not unduly preferential or unduly discriminatory, although negotiated or settlement rates may be accepted in certain circumstances. Such rates and terms and conditions of service are set forth in FERC-approved tariffs. Proposed rate increases and changes to our tariffstariff are subject to FERC approval. Pursuant to FERC’s jurisdiction over rates, existing rates may be challenged by complaint or by FERC on its own initiative and proposed new or changed rates may be challenged by protest. If protested, a rate increase may be suspended for up to five months and collected, subject to refund. If, upon completion of an investigation, FERC finds that

the new or changed rate is unlawful, it is authorized to require the pipeline to refund revenues collected in excess of the just and reasonable rate during the term of the investigation.


The rates charged by our FERC regulated natural gas pipelines may also be affected by the ongoing uncertainty regarding FERC’s current income tax allowance policy. In July 2016, the United States Court of Appeals for the District of Columbia Circuit issued its opinion in United Airlines, Inc., et al.v. FERC, finding that FERC had acted arbitrarily and capriciously when it failed to demonstrate that permitting an interstate petroleum products pipeline organized as a limited partnership to include an income tax allowance in the cost of service underlying its rates in addition to the discounted cash flow return on equity would not result in the pipeline double-recovering its investors’ income taxes. The court vacated FERC’s order and remanded to FERC to consider mechanisms for demonstrating that there is no double recovery as a result of the income tax allowance. On December 15, 2016, FERC issued a Notice of Inquiry seeking comment on how to address any double recovery resulting from its income tax allowance policy. FERC is currently considering whether, and if so, to what extent, pipelines owned by pass-through entities such as MLPs may include income tax allowance in rates to compensate for the income tax liability of investors.

Interstatepolicies regarding rate setting, interstate natural gas pipelines regulated by FERC are required to comply with numerous regulations related to standards of conduct, market transparency, and market manipulation. FERC’s standards of conduct regulate the manner in which interstate natural gas pipelines may interact with their marketing affiliates.affiliates if such marketing affiliates are shippers on their interstate natural gas pipelines. FERC’s market oversight and transparency regulations require regulated entities to submit annual reports of threshold purchases or sales of natural gas and publicly post certain information on scheduled volumes. FERC’s market manipulation regulations, promulgated pursuant to the Energy Policy Act of 2005 (the “EPAct 2005”), make it unlawful for any entity, directly or indirectly in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, to (1) use or employ any device, scheme, or artifice to defraud; (2) make any untrue statement of material fact or omit to state a material fact necessary to make the statements made not misleading (in light of the circumstances under which the statements were made); or (3) engage in any act, practice, or course of business that operates (or would operate) as a fraud or deceit upon any person. The EPAct 2005 also amends the NGA and the Natural Gas Policy Act of 1978 (“NGPA”) to givegives FERC authority to impose civil penalties for violations of these statutes up to $1.0 million per day per violation for violations occurring after August 8, 2005. The maximum penalty authority established by the statute has been adjusted to $1.2approximately $1.39 million per day per violation and will continue to be adjusted periodically for inflation. Should we fail to comply with all applicable FERC-administered statutes, rules, regulations, and orders, we could be subject to substantial penalties and fines.


Certain of our intrastate natural gas pipelines also transport gas in interstate commerce and, thus, the rates, terms and conditions of such services are subject to FERC jurisdiction under Section 311 of the NGPANatural Gas Policy Act of 1978 (“Section 311”NGPA”). Pipelines providing transportation service under Section 311 of the NGPA are required to provide services on an open and nondiscriminatory basis, and the maximum rates for interstate transportation services provided by such pipelines must be “fair and equitable.” Such rates are generally subject to review every five years by FERC or by an appropriate state agency.


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In addition to regulation under Section 311 regulation,of the NGPA, our intrastate natural gas pipeline operations are subject to regulation by various state agencies. Most state agencies possess the authority to review and authorize natural gas transportation transactions and the construction, acquisition, abandonment, and interconnection of physical facilities for intrastate pipelines. State agencies also may regulate transportation rates, service terms and conditions, and contract pricing.

Liquids Pipeline Regulation. We own certain liquids and crude oil pipelines that are regulated by FERC as common carrier interstate pipelines under the Interstate Commerce Act (“ICA”), the Energy Policy Act of 1992, and related rules and orders.


FERC regulation requires that interstate liquids pipeline rates and terms and conditions of service, including rates for transportation of crude oil, condensate, and NGLs, be filed with FERC and that these rates and terms and conditions of service be “just and reasonable” and not unduly discriminatory or unduly preferential.


Rates of interstate liquids pipelines are currently regulated by FERC primarily through an annual indexing methodology, under which pipelines increase or decrease their rates in accordance with an index adjustment specified by FERC. This adjustment is subject to review every five years. ForOn December 17, 2020, for the five-year period beginning on July 1, 2016,2021, FERC established an annual index adjustment equal to the change in the producer price index for finished goods plus 1.23%0.78%. On OctoberJanuary 20, 2016,2022, however, FERC issued an Advance Notice of Proposed Rulemaking indicating that FERC is consideringOrder on Rehearing revising the annual index adjustment to the change in the producer price index for finished goods minus 0.21% (“Order on Rehearing”). As a new policy that would deny proposed index increases for pipelines under certain circumstances where revenues exceed cost-of-service by a certain percentage or where the proposed index increases exceed certain annual cost changes reported to FERC. Under current FERC regulations, liquids pipelines can request a rate increase that exceeds the rate obtained through applicationresult of the indexing methodology by using a cost-of-service approach, but only afterchange in the pipeline establishes that a substantial divergence exists between the actual costs experienced by the pipeline and the rates resulting from application of the indexing

methodology. The rates charged byindex adjustment, certain ceiling levels for our interstate liquids pipelines may also be affected bywere reduced and any rates that exceeded the ongoing uncertainty regarding FERC’s current income tax allowance policy discussed above.newly computed ceiling levels were subsequently lowered to bring those rates into compliance with the revised ceiling level. The revised rates will become effective March 1, 2022.


The ICA permits interested persons to challenge proposed new or changed rates and authorizes FERC to suspend the effectiveness of such rates for up to seven months and investigate such rates. If, upon completion of an investigation, FERC finds that the new or changed rate is unlawful, it is authorized to require the pipeline to refund revenues collected in excess of the just and reasonable rate during the term of the investigation. FERC may also investigate, upon complaint or on its own motion, rates that are already in effect and may order a carrier to change its rates prospectively. Under certain circumstances, FERC could limit our ability to set rates based on our costs or could order us to reduce our rates and pay reparations to complaining shippers for up to two years prior to the date of the complaint. FERC also has the authority to change our terms and conditions of service if it determines that they are unjust and unreasonable or unduly discriminatory or preferential.


As we acquire, construct, and operate new liquids assets and expand our liquids transportation business, the classification and regulation of our liquids transportation services, including services that our marketing companies provide on our FERC-regulated liquids pipelines, are subject to ongoing assessment and change based on the services we provide and determinations by FERC and the courts. Such changes may subject additional services we provide to regulation by FERC.


Intrastate NGL and other petroleum pipelines are not generally subject to rate regulation by FERC, but they are subject to regulation by various agencies in the respective states where they are located. While such regulatory regimes vary, state agencies typically require intrastate NGL and petroleum pipelines to file their rates with the agencies and permit shippers to challenge existing rates or proposed rate increases.


Gathering Pipeline Regulation. Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of FERC under the NGA.NGA (no such exemption exists under the ICA for pipelines transporting liquids in interstate commerce). We own a number of natural gas pipelines that we believe meet the traditional tests FERC has used to establish that a pipeline is a gathering pipeline and therefore not subject to FERC jurisdiction. The distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of substantial, ongoing litigation,a fact-intensive analysis, however, so the classification and regulation of our gathering facilities are subject to change. Application of FERC jurisdiction to our gathering facilities could increase our operating costs, decrease our rates, and adversely affect our business. State regulation of gathering facilities generally includes various safety, environmental, and, in some circumstances, nondiscriminatory requirements and complaint-based rate regulation.


In addition, we are subject to some state ratable take and common purchaser statutes. The ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply.


Natural Gas Storage Regulation. In December 2016, the DOT’s The U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (“PHMSA”) issued an interim final rule (“IFR”) that addressesregulates safety issues related to downhole facilities located at both intrastate and interstate underground natural gas storage facilities. The IFR incorporates by reference two of the American Petroleum Institute’s Recommended Practice standards andPHMSA mandates certain reporting requirements for operators of underground
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natural gas storage facilities. Under the IFR,facilities and sets minimum federal safety standards. In addition, all intrastate transportation related underground natural gas storage facilities will becomeare subject to minimum federal safety standards and beare inspected by PHMSA or by a state entity that has chosen to expand its authority to regulate these facilities under a certification filed with PHMSA. The IFR became effective on January 18, 2017, with a compliance deadline of January 18, 2018. PHMSA subsequently determined, however, that it will not issue enforcement citations to any operators for violations of provisions of the IFR that had previously been non-mandatory provisions of American Petroleum Institute Recommended Practices 1170 and 1171 until one year after PHMSA issues a final rule. On October 19, 2017, PHMSA formally reopened the comment period on the IFR in response to a petition for reconsideration. This matter remains ongoing and subject to future PHMSA determinations. We are in compliance with this IFR.these PHMSA rules.


Certain of our field injection and withdrawal wells and water disposal wells are subject to the jurisdiction of the Railroad Commission of Texas (“TRRC”). TRRC regulations require that we report the volumes of natural gas and water disposal associated with the operations of such wells on a monthly and annual basis, respectively. Results of periodic mechanical integrity tests must also be reported to the TRRC. In addition, our underground gas storage caverns in Louisiana are subject to the jurisdiction of the Louisiana Department of Natural Resources (“LDNR”). In recent years, LDNR has put in place more comprehensive regulations governing underground hydrocarbon storage in salt caverns.caverns, and we are in compliance with these newer regulations.


We also operate brine disposal wells that are regulated as Class II wells under the federal Safe Drinking Water Act (“SDWA”). The SDWA imposes requirements on owners and operators of Class II wells through the EPA’s Underground

Injection Control program, including construction, operating, monitoring and testing, reporting, and closure requirements. Our brine disposal wells are also subject to comparable state laws and regulations. For more information, see “Environmental Matters” below.


Sales of Natural Gas and NGLs. The prices at which we sell natural gas and NGLs currently are not subject to federal regulation and, for the most part, are not subject to state regulation. Our natural gas and NGL sales are, however, affected by the availability, terms, cost, and regulation of pipeline transportation.


Employee Safety. We are subject to the requirements of the Occupational Safety and Health Act (“OSHA”), and comparable state laws that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities, and citizens. We believe that our operations are in substantial compliance with the OSHA requirements including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances.


Pipeline Safety Regulations. Our pipelines are subject to regulation by PHMSA pursuant to the Natural Gas Pipeline Safety Act of 1968 (“NGPSA”) and the Pipeline Safety Improvement Act of 2002 (“PSIA”). The NGPSA regulates safety requirements in the design, construction, operation, and maintenance of gas pipeline facilities. The PSIA established mandatory inspections for all U.S. crude oil and natural gas transportation pipelines and some gathering lines in high-consequence areas (“HCAs”), which include, among other things, areas of high population density or that serve as sources of drinking water. PHMSA has developed regulations implementing the PSIA that require transportation pipeline operators to implement integrity management programs, including more frequent inspections and other measures to ensure pipeline safety in HCAs. More recently,Additionally, the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 increased penalties for safety violations, established additional safety requirements for newly constructed pipelines, and required studies of certain safety issues that could result in the adoption of new regulatory requirements for existing pipelines, and in June 2016,pipelines. In December 2020, the President of the United States signed the Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 20162020 (the “PIPES Act”), which reauthorizes PHMSA’s oil and gas pipeline programs through 2019.

In April 2016, PHMSA published a notice of proposed rulemaking (“NPRM”), addressing natural gas transmission2023 and gathering lines. The proposed rule would,imposes additional mandates on the agency. For example, the law requires, among other things, change existingrulemaking to amend the integrity management program, emergency response plan, operation and maintenance manual, and pressure control recordkeeping requirements expand assessmentfor gas distribution operators; to create new leak detection and repair requirementsprogram obligations; and to pipelines in “moderate-consequence areas,” including areas of medium population density, and increase requirementsset new minimum federal safety standards for monitoring and inspection of pipeline segments located outside of HCAs. Furthermore, this NPRM would require that records or other data relied on to determine operating pressures must be traceable, verifiable and complete. Locating such records and, in the absence of any such records, verifyingonshore gas gathering lines. Additionally, PHMSA’s maximum pressures through physical testing or modifying or replacing facilities, could significantly increase our costs. Additionally, failure to locate such records or verify maximum pressures could result in the reduction of allowable operating pressures, which would reduce available capacity on our pipelines. PHMSA, however, has yet to finalize this rulemaking, and the contents and timing of any final rule are currently uncertain.

In addition,civil penalties were increased in January 2017, PHMSA finalized new hazardous liquid pipeline safety regulations that would have extended certain regulatory reporting requirements to all hazardous liquid gathering (including oil) pipelines. The final rule also would have required additional event-driven and periodic inspections, required the use of leak detection systems on all hazardous liquid pipelines, modified repair criteria, and required certain pipelines to eventually accommodate in-line inspection tools. The effective date of this final rule is currently uncertain due to a regulatory freeze implemented by the Trump administration on January 20, 2017.2021.


On January 23, 2017, PHMSA published in the Federal Register amendments to theissued a final rule amending its pipeline safety regulations to address requirements of the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 and to update and clarify certain regulatory requirements regarding notifications of accidents and incidents. The final rule also addsadded provisions for cost recovery for design reviews of certain new projects, provides for renewal of existing special permits, and incorporates certain standards for in-line inspections and stress corrosion cracking assessments. On January 11, 2021, PHMSA issued another final rule amending its pipeline safety regulations to ease regulatory burdens on the construction, operation, and maintenance of gas transmission, distribution, and gathering pipeline systems. The amendments also modified the monetary threshold for reporting to PHMSA incidents that result in property damage from $50,000 to $122,000.


In July 2018, PHMSA issued an advance notice of proposed rulemaking seeking comment on the class location requirements for natural gas transmission pipelines, and particularly the actions operators must take when class locations change due to population growth or building construction near the pipeline. The associated notice of proposed rulemaking,
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issued October 14, 2020, proposes an integrity management alternative for managing class location changes in areas that increase in population above a defined threshold.

In October 2019, PHMSA issued three new final rules. One rule, effective in December 2019, establishes procedures to implement the expanded emergency order enforcement authority set forth in an October 2016 interim final rule. Among other things, this rule allows PHMSA to issue an emergency order without advance notice or opportunity for a hearing. The other two rules, effective in July 2020, impose several new requirements on operators of onshore gas transmission systems and hazardous liquids pipelines. The rule concerning gas transmission extends the requirement to conduct integrity assessments beyond HCAs to pipelines in Moderate Consequence Areas (“MCAs”). It also includes requirements to reconfirm Maximum Allowable Operating Pressure (“MAOP”), report MAOP exceedances, consider seismicity as a risk factor in integrity management, and use certain safety features on in-line inspection equipment. The rule concerning hazardous liquids extends the required use of leak detection systems beyond HCAs to all regulated non-gathering hazardous liquid pipelines, requires reporting for gravity fed lines and unregulated gathering lines, requires periodic inspection of all lines not in HCAs, calls for inspections of lines after extreme weather events, and adds a requirement to make all lines in or affecting HCAs capable of accommodating in-line inspection tools over the next 20 years.

In addition, PHMSA has taken recent action to regulate gathering systems, which includes integrity management requirements. In November 2021, PHMSA issued a final rule that extended pipeline safety requirements to onshore gas gathering pipelines. The rule requires all onshore gas gathering pipeline operators to comply with PHMSA’s incident and annual reporting requirements.It also extends existing pipeline safety requirements to a new category of gas gathering pipelines, “Type C” lines, which generally include high-pressure pipelines that are larger than 8.625 inches in diameter. Safety requirements applicable to Type C lines vary based on pipeline diameter and potential failure consequences. The final rule becomes effective in May 2022 and operators must comply with the applicable safety requirements by November 2022.

At the state level, several states have passed legislation or promulgated rules dealing with pipeline safety. We believe that our pipeline operations are in substantial compliance with applicable PHMSA and state requirements; however, due to the possibility of new or amended laws and regulations or reinterpretation of existing laws and regulations, there can be no assurance that future compliance with PHMSA or state requirements will not have a material adverse effect on our financial condition, results of operations, or cash flows.



Environmental Matters

Recent Developments. On November 2, 2015, PHMSAJanuary 20, 2021, the Biden Administration came into office and immediately issued a Noticenumber of Probable Violationexecutive orders related to environmental matters that could affect our operations and Proposed Compliancethose of our customers, including an Executive Order (the “NOPV”) assertingon “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 we have probable violationsare identified as conflicting with the Biden Administration’s climate policies. Among the areas that could be affected by the review are regulations addressing methane emissions and the part of 49 CFR Part 195 due to the misclassificationextraction process known as hydraulic fracturing. The Biden Administration has also issued other orders that could ultimately affect our business, such as the executive order rejoining the Paris Agreement. As part of a transmission line as a gathering line. Transmission lines are subject to more fulsome pipeline safety regulations than gathering lines. The NOPV proposed a compliance order requiring us to satisfyrejoining the Part 195 requirements applicable to transmission lines but did not propose a penalty. On January 18, 2018, we received a letter from PHMSA withdrawingParis Agreement, the NOPV and indicatingBiden Administration announced that the case was closed effective asUnited States would commit to a 50 to 52 percent reduction from 2005 levels of January 18, 2018. GHG emissions by 2030, and set the goal of reaching net-zero GHG emissions by 2050. The Biden Administration could seek, in the future, to put into place additional executive orders, policy and regulatory reviews, and seek to have Congress pass legislation that could adversely affect the production of oil and gas assets and our operations and those of our customers.


Environmental Matters

General. Our operations involve processing and pipeline services for delivery of hydrocarbons (natural gas, NGLs, crude oil, and condensates) from point-of-origin at crude oil and gas wellheads operated by our suppliers to our end-use market customers. Our facilities include natural gas processing and fractionation plants, natural gas and NGL storage caverns, brine disposal wells, pipelines and associated facilities, fractionation and storage units for NGLs, and transportation and delivery of hydrocarbons. As with all companies in our industrial sector, our operations are subject to stringent and complex federal, state, and local laws and regulations relating to the discharge of hazardous substances or solid wastes into the environment or otherwise relating to protection of the environment. Compliance with existing and anticipated environmental laws and regulations increases our overall costs of doing business, including costs of planning, constructing, and operating plants, pipelines, and other facilities, as well as capital expenditures necessary to maintain or upgrade equipment and facilities. Similar costs are likely upon changes in laws or regulations and upon any future acquisition of operating assets.


Any failure to comply with applicable environmental laws and regulations, including those relating to equipment failures, and obtaining required governmental approvals and permits, may result in the assessment of administrative, civil, or criminal penalties, imposition of investigatory or remedial activities, and, in certain, less common circumstances, issuance of temporary
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or permanent injunctions, or construction or operation bans or delays. As part of the regular evaluation of our operations, we routinely review and update governmental approvals as necessary.


The continuing trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. Moreover, risks of process upsets, accidental releases, or spills are associated with possible future operations, and we cannot assure you that we will not incur significant costs and liabilities, including those relating to claims for damage to the environment, property, and persons as a result of any such upsets, releases, or spills. We may be unable to pass on current or future environmental costs to our customers. A discharge or release of hydrocarbons, hazardous substances, or solid wastes into the environment could, to the extent losses related to the event are not insured, subject us to substantial expense, including both the cost to comply with applicable laws and regulations and to pay fines or penalties that may be assessed and the cost related to claims made by neighboring landowners and other third parties for personal injury or damage to natural resources or property. We attempt to anticipate future regulatory requirements that might be imposed and plan accordingly to comply with changing environmental laws and regulations and to minimize costs with respect to more stringent future laws and regulations or more rigorous enforcement of existing laws and regulations.


Hazardous Substances and Solid Waste. Environmental laws and regulations that relate to the release of hazardous substances or solid wastes into soils, sediments, groundwater, and surface water and/or include measures to prevent and control pollution may pose significant costs to our industrial sector. These laws and regulations generally regulate the generation, storage, treatment, transportation, and disposal of solid wastes and hazardous substances and may require investigatory and corrective actions at facilities where such waste or substance may have been released or disposed. For instance, the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the federal “Superfund” law, and comparable state laws impose liability without regard to fault or the legality of the original conduct on certain classes of persons that contributed to a release of a “hazardous substance” into the environment. Potentially responsible parties include the owner or operator of the site where a release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at an off-site location, such as a landfill. Under CERCLA, these persons may be subject to joint and several liability for the costs of cleaning up and restoring sites where hazardous substances have been released into the environment and for damages to natural resources. CERCLA also authorizes the U.S. Environmental Protection Agency (“EPA”) and, in some cases, third parties, to take actions in response to threats to public health or the environment and to seek recovery of costs they incur from the potentially responsible classes of persons. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or solid wastes released into the environment. Although petroleum, natural gas, and NGLs are excluded from CERCLA’s definition of a “hazardous substance,” in the course of ordinary operations, we may generate wastes that may fall within the definition of a “hazardous substance.” In addition, there are other laws and regulations that can create liability for releases of petroleum, natural gas, or NGLs. Moreover, we may be responsible under CERCLA or other laws for all or part of

the costs required to clean up sites at which such substances have been disposed. We have not received any notification that we may be potentially responsible for cleanup costs under CERCLA or any analogous federal, state, or local law.


We also generate, and may in the future generate, both hazardous and nonhazardous solid wastes that are subject to requirements of the federal Resource Conservation and Recovery Act (“RCRA”) and/or comparable state statutes. From time to time, the EPA and state regulatory agencies have considered the adoption of stricter disposal standards for nonhazardous wastes, including crude oil, condensate, and natural gas wastes. Moreover, it is possible that some wastes generated by us that are currently exempted from the definition of hazardous waste may in the future lose this exemption and be designated as “hazardous wastes,” resulting in the wastes being subject to more rigorous and costly management and disposal requirements. Additionally, the Toxic Substances Control Act (“TSCA”) and analogous state laws impose requirements on the use, storage, and disposal of various chemicals and chemical substances. In June 2017, the EPA finalized three rulemakings to update its implementation of TSCA. Two of the new rules establish the EPA’s process and criteria for identifying high priority chemicals for risk evaluation and determining whether these high priority chemicals present an unreasonable risk to health or the environment. The third rule requires industry reporting of chemicals manufactured or processed in the U.S. over the past 10 years. Changes in applicable laws or regulations may result in an increase in our capital expenditures or plant operating expenses or otherwise impose limits or restrictions on our production and operations.


We currently own or lease, have in the past owned or leased, and in the future may own or lease, properties that have been used over the years for brine disposal operations, crude oil and condensate transportation, natural gas gathering, treating, or processing and for NGL fractionation, transportation, or storage. Solid waste disposal practices within the NGL industry and other oil and natural gas related industries have improved over the years with the passage and implementation of various environmental laws and regulations. Nevertheless, some hydrocarbons and other solid wastes may have been released on or under various properties owned, leased, or operated by us during the operating history of those properties. In addition, a number of these properties may have been operated by third parties over whose operations and hydrocarbon and waste management practices we had no control. These properties and wastes disposed thereon may be subject to the SWDA, CERCLA, RCRA,
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TSCA, and analogous state laws. Under these laws, we could be required, alone or in participation with others, to remove or remediate previously disposed wastes or property contamination, if present, including groundwater contamination, or to take action to prevent future contamination.


Air Emissions. Our current and future operations are subject to the federal Clean Air Act and regulations promulgated thereunder and under comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including our facilities, and impose various control, monitoring, and reporting requirements. Pursuant to these laws and regulations, we may be required to obtain environmental agency pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in an increase in existing air emissions, obtain and comply with the terms of air permits, which include various emission and operational limitations, or use specific emission control technologies to limit emissions. We likely will be required to incur certain capital expenditures in the future for air pollution control equipment in connection with maintaining or obtaining governmental approvals addressing air emission-related issues. Failure to comply with applicable air statutes or regulations may lead to the assessment of administrative, civil, or criminal penalties and may result in the limitation or cessation of construction or operation of certain air emission sources or require us to incur additional capital expenditures. Although we can give no assurances, we believe such requirements will not have a material adverse effect on our financial condition, results of operations, or cash flows, and the requirements are not expected to be more burdensome to us than to any similarly situated company.


In addition, the EPA included Wise County, the location of our Bridgeport facility, in its January 2012 revision to the Dallas-Fort Worth ozone nonattainment area (“DFW area”) for the 2008 revised ozone national ambient air quality standard (“NAAQS”). AsEffective September 23, 2019, the DFW area was reclassified to a result ofserious nonattainment area under this moderatestandard, potentially requiring the state to adopt more stringent permitting requirements. Under the area’s serious nonattainment designation, new major sources in Wise County, meaning sources that emit greater than 10050 tons/year of nitrogen oxides (“NOx”) and volatile organic compounds (“VOCs”), as well as major modifications of existing facilities in the county resulting in net emissions increases of greater than 4025 tons/year of NOx or VOCs, are subject to more stringent new source review (“NSR”) pre-construction permitting requirements than they would be in an area that is in attainment with the 2008 ozone NAAQS. NSR pre-construction permits can take twelve to eighteen months to obtain and require the permit applicant to offset the proposed emission increases with reductions elsewhere at a 1.151.2 to 1 ratio. The attainment date for serious nonattainment areas was July 20, 2021, with a 2020 attainment year. The DFW area did not comply with the 2008 ozone NAAQs by the end of 2020 and thus risks reclassification to severe nonattainment. Reclassification for the DFW area is anticipated in early 2022.

In October 2015, the EPA lowered thepromulgated a new NAAQS for ozone from 75 toof 70 parts per billion (“ppb”) for both the 8-hour primary and secondary standards. This newstandards, down from the 75 ppb standards of the 2008 ozone NAAQS. On June 4, 2018, EPA designated the DFW area, including Wise County, as a marginal nonattainment area under this standard. EPA published a final rule to implement the 2015 ozone NAAQS on December 6, 2018. The area’s marginal classification does not require the additional control measures to be implemented. The DFW Area, however, failed to attain this standard is being challenged in a pending appeal before the U.S. Courtby its marginal attainment date of Appeals for the D.C. Circuit, but if the standard is implemented, itAugust 2021, and now risks reclassification to moderate nonattainment, which could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits, and result in potentially significant expenditures for pollution control equipment. Furthermore, the area remains subject to the requirements associated with its serious classification under the 2008 standard notwithstanding its marginal classification under the 2015 standard. The 2015 standards were challenged before the U.S. Court of Appeals for the D.C. Circuit. On August 23, 2019, the D.C. Circuit upheld the EPA’s primary ozone standard and remanded the secondary standard to EPA for reconsideration. The implementation of these standards could result in stricter permitting requirements, delays or prohibitions on our ability to obtain such permits, and result in potentially significant expenditures for pollution control equipment. Reclassification for the DFW area is anticipated in early 2022.


The EPA reviewed the 2015 NAAQS standard in 2020 but decided to retain the standard without revision. EPA, however, recently announced that it intends to reconsider the 2020 decision to retain the 2015 NAAQS standards.To the extent that EPA’s reconsideration results in a new standard, the new standard could cause stricter permitting requirements, delays or prohibitions on our ability to obtain such permits, and result in potentially significant expenditures for pollution control equipment.Furthermore, the area remains subject to the requirements associated with its serious classification under the 2008 standard notwithstanding its marginal classification under the 2015 standard.

Effective May 15, 2012, the EPA promulgated rules under the Clean Air Act that established new air emission controls for oil and natural gas production, pipelines, and processing operations under the New Source Performance Standards (“NSPS”) and

National Emission Standards for Hazardous Air Pollutants (“NESHAPs”) programs. These rules require the control of emissions through reduced emission (or “green”) completions and establish specific new requirements regarding emissions from wet seal and reciprocating compressors, pneumatic controllers, and storage vessels at production facilities, gathering systems, boosting facilities, and onshore natural gas processing plants. In addition, the rules revised existing requirements for VOC emissions from equipment leaks at onshore natural gas processing plants by lowering the leak definition for valves from
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10,000 parts per million to 500 parts per million and requiring the monitoring of connectors, pumps, pressure relief devices, and open-ended lines. These rules required a number of modifications to our assets and operations. In October 2012, several challenges to the EPA’s NSPS and NESHAPs rules for the industry were filed by various parties, including environmental groups, and industry associations. In a January 16, 2013 unopposed motion to hold this litigation in abeyance, the EPA indicated that it may reconsider some aspects of the rules. The case remains in abeyance. The EPA has since revised certain aspects of the rules and has indicated that it may reconsider other aspects of the rules. Depending on the outcome of such proceedings, the rules may be further modified or rescinded or the EPA may issue new rules. We cannot predict the costs of compliance with any modified or newly issued rules.


In partial response to the issues raised regarding the 2012 rulemaking, the EPA recently finalized new rules that took effect August 2, 2016 to regulate emissions of methane and VOCs from new and modified sources in the oil and gas sector. sector under the NSPS. In September 2020, the EPA published two additional final rules, the 2020 Policy Rule and the 2020 Technical Amendments.The 2020 Policy Rule removed sources in the transmission and storage segment from the regulated source category of the 2016 NSPS, rescinded the NSPS (including both VOC and methane requirements) applicable to those sources, and rescinded the methane-specific requirements of the NSPS applicable to sources in the production and processing segments. On January 21, 2021, President Biden issued an Executive Order on “Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis” directing EPA announcedto consider publishing for notice and comment, by September 2021, a proposed rule suspending, revising, or rescinding the 2020 NSPS for the oil and natural gas sector, and on June 30, 2021, President Biden signed a joint congressional resolution rescinding the 2020 Policy rule. In November 2021, the EPA proposed a new rule targeting methane and VOC emissions from new and existing oil and gas sources, including sources in the production, processing, transmission, and storage segments. The proposed rule would: (1) update NSPS subpart OOOOa; (2) adopt a new NSPS subpart OOOOb for sources that commence construction, modification, or reconstruction after the date the proposed rule is published in the Federal Register; and (3) adopt a new NSPS subpart OOOOc to establish emissions guidelines, which will inform state plans to establish standards for existing sources. If finalized, these increasingly stringent requirements, or the application of new requirements to existing facilities, could result in additional restrictions on operations and increased compliance costs for us or our customers. 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 intention to reconsider those regulations in April 2017 and has sought to stay its requirements. However, the rule remains in effect. operations.

In June 2016, the EPA also finalized a rule regarding alternative criteria for aggregating multiple small surface sites into a single source for air quality permitting purposes. This rule could cause small facilities within one-quarter mile of one another to be deemed a major source on an aggregate basis, thereby triggering more stringent air permitting processes and requirements across the oil and gas industry. On November 10, 2016,EPA draft guidance issued in September 2018 clarified that this rule pertains to the EPA issued a final Information Collection Request (“ICR”) that requires numerous oil and gas companies to provide information regarding methane emissions from existing oil and gas facilities, a step used to provide a basis for future rulemaking. The EPA withdrew this ICR in March 2017. The Obama Administration indicated that otherindustry.

Other federal agencies including the Bureau of Land Management (“BLM”), PHMSA, and the Department of Energy would be imposinghave also taken steps to impose new or more stringent regulations on the oil and gas sector in order to further reduce methane emissions. For example, the BLM adopted new rules, on November 15, 2016, to be effective on January 17, 2017, to reduce venting, flaring, and leaks during oil and natural gas production activities on onshore federal and Indian leases. Certain provisions of the BLM rule went into effect in January 2017, while the effective date of others were scheduled to go into effect in January 2018.was delayed until 2019 pending reconsideration. In December 2017,September 2018, BLM published a final rule delayingthat rescinded several requirements of the 2016 methane rules. The September 2018 provisions until 2019.rule was challenged in the U.S. District Court for the Northern District of California almost immediately after issuance. In July 2020, the U.S. District Court for the Northern District of California vacated BLM’s 2018 revision rule. Additionally, in October 2020, a Wyoming federal district judge vacated the 2016 venting and flaring rule. In December 2020, environmental groups appealed the October 2020 decision, and litigation is ongoing. As a result of this continued regulatory focus and other factors, additional GHG regulation of the oil and gas industry remains possible. Compliance with such rules could result in additional costs, including increased capital expenditures and operating costs for us and for other companies in our industry. While we are not able at this time to estimate such additional costs, as is the case with similarly situated entities in the industry, they could be significant for us. Compliance with such rules, as well as any new state rules, may also make it more difficult for our suppliers and customers to operate, thereby reducing the volume of natural gas transported through our pipelines, which may adversely affect our business. However, the status of recent and future rules and rulemaking initiatives under the TrumpBiden Administration remains uncertain.


Climate Change. In December 2009, the EPA determined that emissions of certain gases, commonly referred to as “greenhouse gases,” present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA adopted regulations under existing provisions of the federal Clean Air Act that require Prevention of Significant Deterioration (“PSD”) pre-construction permits and Title V operating permits for greenhouse gas emissions from certain large stationary sources. Under these regulations, facilities required to obtain PSD permits must meet “best available control technology” standards for their greenhouse gas emissions established by the states or, in some cases, by the EPA on a case by case basis. The EPA has also adopted rules requiring the monitoring and reporting of greenhouse gas emissions from specified sources in the United States, including, among others, certain onshore oil and natural gas processing and fractionating facilities. The EPA announced its intentionIn addition, on January 21, 2021, President Biden issued an Executive Order on “Protecting Public Health and the Environment and Restoring Science to reconsider thoseTackle the Climate Crisis” seeking to adopt new regulations in April 2017 and has soughtpolicies to stay its requirements. However,address
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climate change and suspend, revise, or rescind, prior agency actions that are identified as conflicting with the rule remains in effect. Biden Administration’s climate policies.

In addition, efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues. Because regulation of greenhouse gas emissions is relatively new, further regulatory, legislative, and judicial developments are likely to occur. Such developments in greenhouse gas initiatives may affect us and other companies operating in the oil and gas industry. In addition to these developments, recent judicial decisions have allowed certain tort claims alleging property damage to proceed against greenhouse gas emissions sources, which may increase our litigation risk for such claims. In addition, in 2015, the United States participated in the United Nations Conference on Climate Change, which led to the creation of the Paris Agreement. The Paris Agreement entered into force November 4, 2016, and requires countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals every five years beginning in 2020. In June 2017,November 2019, the Trump Administration announced its intent to withdrawState Department formally informed the United Nations of the United States’ withdrawal from the Paris Agreement. Pursuant toAgreement and withdrew from the terms ofagreement in November 2020. However, on January 20, 2021, President Biden signed an instrument that reverses this withdrawal, and the United States will formally re-join the Paris Agreement on February 19, 2021. As part of rejoining the earliest dateParis Agreement, President Biden announced that the United States can withdraw is November 2020.would commit to a 50 to 52 percent reduction from 2005 levels of GHG emissions by 2030 and set the goal of reaching net-zero GHG emissions by 2050. Due to the

uncertainties surrounding the regulation of and other risks associated with greenhouse gas emissions, we cannot predict the financial impact of related developments on us.


Federal or state legislative or regulatory initiatives that regulate or restrict emissions of greenhouse gases in areas in which we conduct business could adversely affect the availability of, or demand for, the products we store, transport, and process, and, depending on the particular program adopted, could increase the costs of our operations, including costs to operate and maintain our facilities, install new emission controls on our facilities, acquire allowances to authorize our greenhouse gas emissions, pay any taxes related to our greenhouse gas emissions, and/or administer and manage a greenhouse gas emissions program. We may be unable to recover any such lost revenues or increased costs in the rates we charge our customers, and any such recovery may depend on events beyond our control, including the outcome of future rate proceedings before FERC or state regulatory agencies and the provisions of any final legislation or regulations. Reductions in our revenues or increases in our expenses as a result of climate control initiatives could have adverse effects on our business, financial condition, results of operations, or cash flows.


Due to their location, our operations along the Gulf Coast are vulnerable to operational and structural damages resulting from hurricanes and other severe weather systems, while inland operations include areas subject to tornadoes. Our insurance may not cover all associated losses. We are taking steps to mitigate physical risks from storms, but no assurance can be given that future storms will not have a material adverse effect on our business.


Hydraulic Fracturing and Wastewater. The Federal Water Pollution Control Act, also known as the Clean Water Act, and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including NGL-related wastes, into state waters or waters of the United States. In June 2015, the EPA and the U.S. Army Corps of Engineers (“USACE”) finalized a rule intended to clarify the meaning of the term “waters of the United States,” (“WOTUS”) which establishes the scope of regulated waters under the Clean Water Act. The rule has been challenged and was stayed by federal courts. Absent Congressional action, the rule will become applicable if the courts do not continue the stay of the rule during the litigation; ifIf upheld, the rule is expected to expand federal jurisdiction under the Clean Water Act. In November 2017, theOn February 6, 2018, EPA and USACE published a final rule to postpone the effectiveness of the WOTUS rule until February 6, 2020. The February 2018 delay rule is subject to pending judicial challenges in multiple federal district courts. In October 2019, EPA and USACE issued a final rule that repealed the 2015 WOTUS definition and reinstated the agencies’ narrower pre-2015 scope of federal CWA jurisdiction. In April 2020, EPA and USACE issued a new final WOTUS definition that continues to provide a narrower scope of federal CWA jurisdiction than contemplated under the 2015 WOTUS definition, while also providing for greater predictability and consistency of federal CWA jurisdiction. Judicial challenges to EPA’s 2015 WOTUS definition, the October 2019 repeal rule and the April 2020 final rule are currently before multiple federal district courts. Additionally, the rules are among agency actions listed for review in accordance with President Biden’s January 20, 2021 Executive Order: “Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis.”

On August 30, 2021, the U.S. Army CorpsDistrict Court for the District of EngineersArizona vacated and remanded the April 2020 final rule. Following the August 30, 2021 decision, EPA and USACE ceased implementing the April 2020 final rule, and on December 7, 2021, published a proposed rule titled the addition“Revised Definition of an applicability date‘Waters of the United States.’” The proposed rule provides that EPA and USACE will began interpreting the WOTUS definition consistent with the Pre-2015 regulatory regime, generally referred to as the “1986 definition,” subject to some amendments that reflect the agencies’ interpretation of the statutory limits on the WOTUS definition and Supreme Court precedent. The proposed rule, if finalized, would be expected to significantly expand federal jurisdiction as compared to the 2015 Clean Water Rule that would be two years after the date of aApril 2020 final rule. This change, if adopted, would effectively prevent the rule, from coming back into effect immediately if the stay is lifted.and as such, we could face increased costs and delays with respect to obtaining permits for activities in jurisdictional waters, including wetlands. Regulations promulgated pursuant to the Clean Water Act require that entities that discharge into federal and state waters obtain National Pollutant Discharge
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Elimination System (“NPDES”) permits and/or state permits authorizing these discharges. The Clean Water Act and analogous state laws assess administrative, civil, and criminal penalties for discharges of unauthorized pollutants into the water and impose substantial liability for the costs of removing spills from such waters. In addition, the Clean Water Act and analogous state laws require that individual permits or coverage under general permits be obtained by covered facilities for discharges of storm water runoff. We believe that we are in substantial compliance with Clean Water Act permitting requirements as well as the conditions imposed by our permits and that continued compliance with such existing permit conditions will not have a material effect on our financial condition, results of operations, or cash flows.


In December 2016, the EPA released the final results of its comprehensive research study on the potential adverse impacts that hydraulic fracturing may have on drinking water resources. The EPA concluded that hydraulic fracturing activities can impact drinking water resources under some circumstances, including large volume spills and inadequate mechanical integrity of wells. The results of the EPA’s study could spur action toward federal legislation and regulation of hydraulic fracturing or similar production operations. We operate brine disposal wells that are regulated as Class II wells under the SDWA. The SDWA imposes requirements on owners and operators of Class II wells through the EPA’s Underground Injection Control program, including construction, operating, monitoring and testing, reporting, and closure requirements. Our brine disposal wells are also subject to comparable state laws and regulations, which in some cases are more stringent than requirements under the SDWA, such as the Ohio Department of Natural Resources (“ODNR”) rules that took effect October 1, 2012. These rules set new, more stringent standards for the permitting and operating of brine disposal wells, including extensive review of geologic data and use of state-of-the-art technology. The Ohio Department of Natural ResourcesODNR also imposes requirements on the transportation and disposal of brine. Compliance with current and future laws and regulations regarding our brine disposal wells may impose substantial costs and restrictions on our brine disposal operations, as well as adversely affect demand for our brine disposal services. State and federal regulatory agencies recently have focused on a possible connection between the operation of injection wells used for oil and gas waste waters and an observed increase in minor seismic activity and tremors. When caused by human activity, such events are called induced seismicity. In a few instances, operators of injection wells in the vicinity of minor seismic events have reduced injection volumes or suspended operations, often voluntarily. A 2012 report published by the National Academy of Sciences concluded that only a very small fraction of the tens of thousands of injection wells have been suspected to be, or have been, the likely cause of induced seismicity. However, some state regulatory agencies have modified their regulations to account for induced seismicity. For example, TRRC rules allow the TRRC to modify, suspend, or terminate a permit based on a determination that the permitted activity is likely to be contributing to seismic activity. In the state of Ohio, the Ohio

Department of Natural Resources (“ODNR”)ODNR requires a seismic study prior to the authorization of any new disposal well. In addition, the ODNR has instituted a continuous monitoring network of seismographs and is able to curtail injected volumes regionally based upon seismic activity detected. The Oklahoma Corporation Commission (“OCC”) has also taken steps to focus on induced seismicity, including increasing the frequency of required recordkeeping for wells that dispose into certain formations and considering seismic information in permitting decisions. For instance, on August 3, 2015, the OCC adopted a plan calling for mandatory reductions in oil and gas wastewater disposal well volumes, the implementation of which has involved reductions of injection or shut-ins of disposal wells. The OCC also recently released well completion seismicity guidelines in December 2016 for operators in the STACK play that call for hydraulic fracturing operations to be suspended following earthquakes of certain magnitudes in the vicinity. Regulatory agencies are continuing to study possible linkage between injection activity and induced seismicity. To the extent these studies result in additional regulation of injection wells, such regulations could impose additional regulations, costs, and restrictions on our brine disposal operations. Such regulations could also affect our customers’ injection well operations and, therefore, impact our gathering business.


It is common for our customers or suppliers to recover natural gas from deep shale formations through the use of hydraulic fracturing, combined with sophisticated horizontal drilling. Hydraulic fracturing is an important and commonly used process in the completion of wells by oil and gas producers. Hydraulic fracturing involves the injection of water, sand, and chemical additives under pressure into rock formations to stimulate gas production. Due to public concerns raised regarding potential impacts of hydraulic fracturing on groundwater quality, legislative, and regulatory efforts at the federal level and in some states and localities have been initiated to require or make more stringent the permitting and other regulatory requirements for hydraulic fracturing operations of our customers and suppliers. There are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. On December 13, 2016, the EPA released a study of the potential adverse effects that hydraulic fracturing may have on water quality and public health, concluding that there is scientific evidence that hydraulic fracturing activities potentially can impact drinking water resources in the United States under some circumstances. This study or similar studies could spur initiatives to further regulate hydraulic fracturing. In June 2016, the EPA finalized rules prohibiting discharges of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. The EPA has also issued an advance notice of proposed rulemaking under the Toxic Substances Control Act to gather information regarding the potential regulation of chemical substances and mixtures used in oil and gas exploration and production. Also, effective June 24, 2015, BLM adopted rules regarding well stimulation, chemical disclosures, water management, and other requirements for hydraulic fracturing on federal and American Indian lands; however, alands. A federal district court invalidated these BLM rules in June 2016, but the rulesthey were reinstated on appeal by the U.S. Court of Appeals for the Tenth Circuit in September 2017. While thisIn December 2017, BLM published a final rule rescinding the 2015 BLM rules. The final rule was challenged in the U.S. District Court for the Northern District of California almost immediately after issuance. On March 27, 2020, the District Court upheld the BLM’s rescission of the 2015 rules. This decision is pending appeal was pending,in the U.S. Court of Appeals for the Ninth Circuit. Reinstatement of the 2015 BLM proposed a rulemaking in July 2017 to rescind these rules, in their entirety. BLM has yet to finalize this rulemaking. Additionalor the adoption of additional regulatory burdens in the future, whether federal, state, or local, could increase the cost of or restrict the ability of our customers or suppliers to perform hydraulic fracturing. As a result, any increased federal, state, or local regulation could reduce the volumes of natural
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gas that our customers move through our gathering systems which would materially adversely affect our financial condition, results of operations, or cash flows.


Endangered Species and Migratory Birds. The Endangered Species Act (“ESA”), Migratory Bird Treaty Act (“MBTA”), and similar state and local laws restrict activities that may affect endangered or threatened species or their habitats or migratory birds. Some of our pipelines may be located in areas that are designated as habitats for endangered or threatened species, potentially exposing us to liability for impacts on an individual member of a species or to habitat. The ESA can also make it more difficult to secure a federal permit for a new pipeline.


Office Facilities


We occupylease approximately 157,600 square feet of space at our executive offices in Dallas, Texas under a lease expiring in February 2030. We also occupylease office space of approximately 56,000 square feet in Midland, Texas, and 32,00047,500 square feet in Houston, Texas under long-term leases.leases, and various other locations to support our operations.


EmployeesHuman Capital


As of December 31, 2017,2021, we (through our subsidiaries) employed 1,4941,073 full-time employees. Of these employees, 330249 were general and administrative, engineering, accounting, and commercial personnel, and the remainder were operational employees. We are not party to any collective bargaining agreements, and we have not had any significant labor disputes in the past. We believe that we have good relations with our employees.


One of our core values is a “focus on people.”We strive to provide our employees with a rewarding work environment, including the opportunity for success and a platform for personal and professional development. We are committed to providing a working environment that empowers our employees, allows them to execute at their highest potential, keeps them safe, and promotes their professional growth. We offer a competitive total rewards program to our employees. Our total rewards program is comprised of base salary, short-term incentives tied to our performance, comprehensive employee benefits that include medical and dental coverage, company-paid life insurance, disability coverage, and paid parental leave for both birth and non-birth parents. We also offer a 401(k) program, which includes fully-vested employer matched contributions. We believe that our values, rewarding work environment, and competitive pay help us retain our employees and minimize employee turnover in a very challenging personnel market. Our employees have an average tenure of eight years and voluntary turnover rates over the last three years have remained relatively flat, averaging approximately 9% per year.

The safety of our employees is a key management priority. We strive to promote a safety-centric culture, including linking a portion of short-term incentive compensation for our employees to our safety standards and performance. We also maintain strict safety protocols and require quarterly safety training for all field employees and annual safety training for corporate employees. During 2021, EnLink had its best safety year on record. We assess the effectiveness of our safety record by closely monitoring various measures, including our Total Recordable Incident Rate (“TRIR”), which is an industry standard measurement of safety. In 2021, we had a TRIR of 0.44, representing the lowest number of employee reportable incidents in our history. We also require annual safety training by every employee. Additional hours of safety training are required for field personnel. During 2021, our employees completed approximately 8,000 online courses comprising more than 8,500 hours of compliance-based training. In addition, our employees completed over 4,500 hours of required safety training.

We also see value in having a diverse and inclusive environment. We have a Diversity, Equity, and Inclusion Action Team, which is responsible for helping us to promote and foster a welcoming, open, and diverse workplace, and whose members are drawn from throughout the company. As of December 31, 2021, women represented approximately 39% of the positions at our corporate offices in Dallas and Houston and held approximately 36% of all manager and above positions in those offices. At the same date, minorities represented approximately 26% of the manager and above positions at our corporate offices in Dallas and Houston and held approximately 20% of all manager and above positions company-wide. Additionally, women and minorities constituted 29% of all officers company-wide. We also require annual anti-harassment and discrimination training for all employees, and, in 2021, all people managers completed inclusive leadership training.

For more information on our employee initiatives, see the “Our People” section of our Sustainability Report (located on our website at www.enlink.com) regarding our Human Capital programs and initiatives. In addition, see “General and Recent Developments—Current Market Environment” for more information regarding our actions to prioritize the health and safety of our employees with respect to the COVID-19 pandemic. Information included in our Sustainability Report or otherwise included on our website is not incorporated into this Annual Report on Form 10-K.

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Sustainability

We strive for sustainable business practices, including safe, responsible and ethical operations, respect for the environment, a focus on customers, and support for our team of employees. We maximize safe operations of our assets by focusing on mitigating risk, routinely increasing knowledge and skills of our employees, improving our processes, and measuring our performance. We link a portion of short-term incentive compensation for our employees to our safety standards and performance in order to promote a safety-centric culture. We also operate our assets and construct new facilities to minimize our footprint and environmental impact, control pollution, and conserve resources. We focus on serving our customers safely and reliability and providing the highest level of service through innovation and continuous improvement processes in our business. We support our employees by providing competitive pay and benefits, training, and a respectful and inclusive culture.

We have a standing Sustainability Committee (“Sustainability Committee”) of the Board of Directors of the Managing Member (the “Board”), which assists the Board in its general oversight of our environmental, social, and governance initiatives, including our environmental, health and safety, and operational excellence initiatives, and also provides oversight with respect to identifying, evaluating, and monitoring of risks associated with such matters. We have also formed an executive sponsored, cross-functional committee, comprised of leaders from various departments of our company, to put into action our sustainable business practices. In addition, we publish an annual sustainability report, which provides both accountability to us regarding sustainable business practices as well as transparency to our stakeholders regarding our progress toward becoming a more sustainable company. Our most recent sustainability report can be found on our website (www.enlink.com). Information included in our Sustainability Report or otherwise included on our website is not incorporated into this Annual Report on Form 10-K.

Environmental Responsibility

We strive for safe operations that minimize our environmental impact. We demonstrate that objective by complying with applicable environmental laws, focusing on prevention of spills and emissions of unpermitted substances into the atmosphere, reducing our impact on land, waterways, and wildlife habitats, and managing our resource consumption to minimize waste. We have also adopted technologies that support the continuous improvement of our operations to minimize their environmental impact.

We work to operate our assets in a way that maximizes their usefulness, reliability, and safe operations, including through the use of smart tool runs, pressure testing, cathodic protection and robust corrosion management, and routine tests of our assets. We utilize the latest technology to monitor and operate our pipeline systems, such as leak detection monitoring software and vibration monitoring of our compressor stations, which accelerates response time to potential incidents and increases our reliability. We also hold safety trainings for our employees each month and require employees to attend based on their job position.

We attempt to minimize our environmental impact through our operations. Many of our facilities are self-powered, generating energy from the hydrocarbons being processed and reducing the need for public grid connection. We also employ processes that allow us to repurpose exhaust heat, a byproduct of operations, for warming purposes required elsewhere in our process. We utilize solar capabilities to power our methanol pumps, meter stations, and line operating data gathering stations, reducing our need for additional power. We maintain a robust leak detection and repair program and have implemented infrared optical gas image surveys at most of our facilities. To improve emissions performance and operational efficiency, we replaced flares with thermal oxidizers at many of our plants, and we installed vapor recovery units and exhaust catalysts and rerouted compressor blowdown gas back into our system at many of our compressor stations and we continue to make similar changes to our operations, from time to time, to minimize our environmental impact.

We also reuse our resources to limit our waste production. We focus on repurposing and refurnishing idle materials and equipment to be used in new ways at other facilities, including meters, filter separators, compressors, treaters, scrubbers, dehydration systems, amine systems, process vessels, cylinders, valves, pipe, tanks, and pig traps.

We seek to minimize impacts from the construction of our facilities and other operations as well. We first identify site options during the project planning phase to avoid wetlands, habitats, and other environmentally sensitive areas, when possible. Once operational, we partner closely with regulatory agencies to ensure we are compliant with environmental regulations. We also generally restore land to preconstruction conditions, often beyond the footprint that we utilize.

We also seek to minimize the CO2 emissions in our operations. In May 2021, we announced our intention to reach net zero
greenhouse gas emissions by 2050, positioning us among industry leaders in sustainability. We plan to execute substantial
emissions reduction strategies that will systematically move EnLink toward a net zero goal, including achieving a 30%
reduction in methane emissions intensity by 2024 and a path to reach a 30% reduction in total CO2-equivalent emissions
intensity levels by 2030, both as compared to 2020 levels. In November 2021, we entered into an agreement with Continental Carbonic Products, Inc., a wholly owned subsidiary of Matheson Tri-Gas, Inc., and member of the Nippon Sanso Holdings Corporation group of companies, to capture and sell CO2 emitted from our Bridgeport processing plant in North Texas. The
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CO2 will be sold on a firm basis for 15 years and will be converted into food-grade products. This project is expected to be in service in early 2024. The project makes meaningful progress toward our goal of a 30% reduction in total CO2-equivalent emissions intensity by 2030, while being modestly profitable.

Social Responsibility

We provide our employees with a rewarding work environment, providing a platform for personal and professional development. We focus on providing a working environment that empowers, and invests in, our employees. We often participate in community events throughout our area of operations each year, and we encourage our employees to participate in at least one community service project each year.

We provide competitive pay packages that support the financial security of our employees and help attract and retain top talent. For more information on our employee initiatives, see “Item 1. Business—Human Capital” in this report.

Governance

The Board includes directors with extensive energy, finance, sustainability, and public company governance experience. The compensation of our executives is determined and approved by the Board and by the Governance and Compensation Committee (the “Compensation Committee”) of the Board, which Compensation Committee includes independent directors. The determination of executive compensation includes an analysis of the evolving demands of the industry, assessment of individual contributions to the business strategy, and an in-depth comparison of the compensation practices of a defined peer company group. We foster a strong culture of ownership among our executives and align the interests of our leaders with those of our stakeholders by tying a large portion of the short-term and long-term compensation of our executives to the performance of the company.

We require our employees to complete annual training courses related to our corporate policies, including our Code of Business Conduct and Ethics, which outlines our requirements to maintain a work culture based on integrity, ethics, and safe and fair business dealings. We also identify and prioritize the risks associated with our business each quarter through our enterprise risk management program, conducted by leaders throughout our business. We identify top risks to our business and regularly review them with the Board and its committees, including the Sustainability Committee, and through biannual meetings held with the Audit Committee.

Item 1A. Risk Factors


The following risk factors and all other information contained in this report should be considered carefully when evaluating us. These risk factors could affect our actual results. Other risks and uncertainties, in addition to those that are

described below, may also impair our business operations. If any of the following risks occur, our business, financial condition, results of operations, or cash flows (including our ability to make distributions to our unitholders and noteholders) could be affected materially and adversely. In that case, we may be unable to make distributions to our unitholders and the trading price of our common units could decline. In this report, the terms “Company” or “Registrant,” as well as the terms “ENLC,” “our,” “we,” “us” or like terms, are sometimes used to refer to EnLink Midstream, LLC itself or EnLink Midstream, LLC and its consolidated subsidiaries, including ENLK and its consolidated subsidiaries. Readers are advised to refer to the context in which terms are used, and to read these risk factors in conjunction with other detailed information concerning our business as set forth in our accompanying financial statements and notes and contained in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” included herein.


Risk Factor Summary

The following is a summary of risk factors that could adversely impact our financial condition, results of operations, or cash flows:

Risks Inherent in an Investment in ENLC


DevonRisks Inherent to an Investment in ENLC include the following risks:

•GIP owns approximately 63.8%46.4% of our outstanding common units as of February 9, 2022and controls the Managing Member, and therefore, GIP could favor GIP’s own interests to the detriment of our unitholders in any conflict of interest;
•GIP may compete with us and is not required to offer us the opportunity to acquire additional assets or businesses;
•we are a “controlled company” under NYSE rules and rely on exemptions from certain listing requirements.
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•our operating agreement replaces fiduciary duties otherwise owed to our unitholders with limited contractual standards;
•our operating agreement restricts remedies available to our unitholders for actions of the Managing Member, and unitholders cannot remove the Managing Member without its consent without a vote of the holders of at least 66 2/3% of all outstanding ENLC common units;
•unitholders have limited voting rights and are not entitled to elect the Managing Member or its directors;
•a default under GIP’s credit facility could result in a change in control and a default under some of our debt agreements;
•our operating agreement restricts the voting rights of unitholders owning more than 20% of our units;
•control of the Managing Member may be transferred to a third party without unitholder consent;
•we may issue additional units, including senior units, without the approval of holders of common units;
•the holders of Series B Preferred Units have certain voting rights and the preferred units may be exchanged for our common units, diluting common unitholders;
•GIP may sell common units, which could adversely impact the trading price of common units;
•our Managing Member has a call right that may require unitholders to sell their common units at an undesirable time or price;
•costs reimbursements due to the Managing Member and its affiliates will be determined by the Managing Member and could be substantial;
•unitholders may have liability to repay distributions that were wrongfully distributed to them; and
•the price of our common units may fluctuate significantly.

Financial and Indebtedness Risks

Financial and Indebtedness Risks include the following risks:

•our cash flow consists almost exclusively of cash flows from ENLK, and we may not have sufficient cash available to pay distributions to unitholders each quarter;
•our debt agreements have terms, which may restrict our current and future operations;
•our debt levels could limit our flexibility and adversely affect our financial health or limit our flexibility to obtain financing and to pursue other business opportunities;
•changes in the availability and cost of capital, as a result of a change in our credit rating, could increase our financing costs and reduce our cash available for distribution;
•impairments to long-lived assets, lease right-of-use assets, and equity method investments could reduce our earnings;
•exposure to credit risk of our customers and counterparties could have an adverse effect on our financial condition;
•interest rate increases could adversely impact the price of ENLC’s common units, our ability to issue equity or incur indebtedness, and our ability to make cash distributions;
•we may not realize our deferred tax assets;
•entity level corporate income taxes will reduce cash available for distributions to common unitholders; and
•changes in determining LIBOR or its replacement with a new benchmark rate under our debt agreements may adversely impact interest expense.

Business and Industry Risks

Business and Industry Risks include the following risks:

•the ongoing coronavirus (COVID-19) pandemic has persisted and the outlook remains uncertain and could adversely affect our business, financial condition, and results of operation;
•our inability to retain existing customers or acquire new customers would reduce our revenues and limit our future profitability;
•decreases in the volumes that we gather, process, fractionate, or transport would adversely affect our financial condition, results of operations, or cash flows;
•volumes we service in the future could be less than we anticipate as a result of uncertainty regarding hydrocarbon reserves, which could have a material adverse effect on our financial condition, results of operations, or cash flows;
•any inability to balance our purchases and sales under our sale and purchase arrangements would increase our exposure to commodity price risks and could cause volatility in our operating income;
•adverse developments in the midstream business would adversely affect our financial condition and results of operations and reduce our ability to make distributions;
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•competition for crude oil, condensate, natural gas, and NGL supplies and any decrease in the availability of such commodities, volatile prices and market demand for crude oil, condensate, natural gas, and NGLs that are beyond our control could each adversely affect our financial condition, results of operation, or cash flows;
•reductions in demand for NGL products by the petrochemical, refining, or other industries or by the fuel markets could materially adversely affect our financial condition, results of operations, or cash flows;
•increasing scrutiny and changing expectations from stakeholders with respect to our environment, social, and governance practices may impose additional costs on us or expose us to new or additional risks;
•vulnerability to weather-related risks, particularly for our South Louisiana and Texas Gulf Coast assets, could adversely impact our financial condition, results of operations, or cash flows;
•our dependency on certain of our large customers for a substantial portion of the natural gas that we gather, process, and transport could result in a decline in our operating results and cash available for distribution, and developments that materially and adversely affect these customers could adversely affect us;
•future growth may be limited if we are unable to make acquisitions on economically acceptable terms and integrate assets into our asset base effectively;
���entering into new businesses in connection with our strategy to participate in the energy transition could limit our future growth if we are unable to execute on this strategy or operate these new lines of business effectively or the new lines of business may never develop or present risks that we cannot effectively manage;
•disruption of our assets due to costs to acquire rights-of-way or leases could cause us to cease operations on the affected land, increase costs related to continuing operations elsewhere, and reduce our revenue;
•occurrence of a significant accident or other event not fully insured could adversely affect our operations and financial condition;
•risks to conduct of certain operations through joint ventures could have a material adverse effect on the success of these operations, our financial position, results of operations, or cash flows;
•unavailability of third-party pipelines or midstream facilities interconnected to our assets could adversely affect our adjusted gross margin and cash flow;
•loss of key members of management or the failure to retain an appropriately qualified workforce could disrupt our business operations or have a material adverse effect on our business and results of operations;
•fluctuations in commodity prices and interest rates could result in financial losses or reduce our income;
•our use of derivative financial instruments does not eliminate our exposure to commodity price fluctuations and could result in financial losses or reduce our income; and
•terrorist or cyberattack or a failure of our computer systems may adversely affect our ability to operate our business and may harm our reputation.

Environmental, Legal Compliance, and Regulatory Risks

Environmental, Legal Compliance, and Regulatory Risks include the following risks:

•increases in federal, state, and local legislation, and regulatory initiatives, as well as government reviews relating to hydraulic fracturing could result in increased costs and reductions or delays in natural gas production by our customers and could adversely impact our revenues and results of operation;
•climate change legislation and regulatory initiatives could result in increased operating costs and reduced demand for the natural gas and NGL services we provide;
•our ability to receive or renew required permits and other approvals from governmental authorities or other third parties could impact our operations;
•federal and state rate and service regulation and pipeline safety regulation on our natural gas or liquids pipelines could limit our revenues and increase our operating costs;
•compliance with existing or new environmental laws and regulations could increase our operating costs;
•compliance with privacy and data protection laws could increase our operating costs;
•recent rules under the Clean Air Act could increase our capital expenditures and operating costs and reduce demand for our services; and
•restrictions on our operations imposed by the ESA and MBTA could have an adverse impact on our operations.

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Risks Inherent in an Investment in ENLC

GIP owns approximately 46.4% of ENLC’s outstanding common units as of February 14, 20189, 2022 and controls the Managing Member, which has sole responsibility for conducting our business and managing our operations. Our Managing Member and its affiliates, including Devon,GIP, have conflicts of interest with us and limited duties to us and may favor their own interests to your detriment.


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


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


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


Devon, as a major customer of ours, has an economic incentive to cause us to not seek higher transportation rates and processing fees, even if such higher rates or fees would reflect rates and fees that could be obtained in arm’s-length, third-party transactions;

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


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


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


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


•any future contracts between us, on the one hand, and the Managing Member and its affiliates of GIP, on the other, willmay not be the result of arm’s-length negotiations;


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



disputes may arise under commercial agreements between Devon and us or our subsidiaries, including ENLK;

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


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


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


Devon may compete with us.

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

GIP is a private equity firm with significant resources and experience making investments in midstream energy businesses. GIP is not prohibited from owning assets or interests in entities, or engaging in businesses, that compete directly or indirectly with us. Affiliates of GIP currently own interests in other oil and gas companies, including by developingmidstream companies, which may compete directly or acquiringindirectly with us. In addition, GIP and its affiliates may acquire, construct, or dispose of additional gathering
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midstream or other assets and processing assets. may be presented with new business opportunities, without any obligation to offer us the opportunity to purchase or construct such assets or to engage in such business opportunities.

Pursuant to the terms of our operating agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to the Managing Member, or any of its affiliates, including DevonGIP and its executive officers and directors.officers. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any of our membersunitholder for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity, or does not communicate such opportunity or information to us. As a result, competition from GIP, its affiliates, and other companies in which it owns interests could materially and adversely impact our results of operations and the level of our distributions. This may create actual and potential conflicts of interest between us and affiliates of the Managing Member and result in less than favorable treatment of us and our unitholders.


Cost reimbursements dueWe are a “controlled company” within the meaning of NYSE rules and, as a result, we qualify for, and rely on, exemptions from some of the listing requirements with respect to independent directors.

Because GIP controls more than 50% of the voting power for the election of directors of the Managing Member, and its affiliateswe are a controlled company within the meaning of NYSE rules, which exempt controlled companies from the following corporate governance requirements:

•the requirement that a majority of the board consist of independent directors;

•the requirement that the board of directors have a nominating or corporate governance committee, composed entirely of independent directors, that is responsible for services provided, which will be determinedidentifying individuals qualified to become board members, consistent with criteria approved by the Managing Member, couldboard, selection of board nominees for the next annual meeting of equity holders, development of corporate governance guidelines, and oversight of the evaluation of the board and management;

•the requirement that we have a compensation committee of the board, composed entirely of independent directors, that is responsible for reviewing and approving corporate goals and objectives relevant to chief executive officer compensation, evaluation of the chief executive officer’s performance in light of the goals and objectives, determination and approval of the chief executive officer’s compensation, making recommendations to the board with respect to compensation of other executive officers and incentive compensation and equity-based plans that are subject to board approval and producing a report on executive compensation to be substantialincluded in an annual proxy statement or Form 10-K filed with the Commission;

•the requirement that we conduct an annual performance evaluation of the nominating, corporate governance and would reduce cash availablecompensation committees; and

•the requirement that we have written charters for distribution to our unitholders.the nominating, corporate governance and compensation committees addressing the committees’ responsibilities and annual performance evaluations.


Prior to making distributions on ENLC common units,For so long as we remain a controlled company, we will reimbursenot be required to have a majority of independent directors or nominating, corporate governance or compensation committees composed entirely of independent directors. Accordingly, you may not have the Managing Member and its affiliates for all expenses they incur on our behalf. These expenses will include all costs incurred by the Managing Member and its affiliates in managing and operating us, including costs for rendering corporate staff and support servicessame protections afforded to us, if any. There is no limit on the amountstockholders of expenses for which the Managing Member and its affiliates may be reimbursed. Our operating agreement provides that the Managing Member will determine the expensescompanies that are allocablesubject to us. In addition, toall of the extent the Managing Member incurs obligations on behalf of us, we are obligated to reimburse or indemnify the Managing Member. If we are unable or unwilling to reimburse or indemnify the Managing Member, the Managing Member may take actions to cause us to make payments of these obligations and liabilities. Any such payments could reduce the amount of cash otherwise available for distribution to our unitholders.NYSE corporate governance requirements.


Our operating agreement replaces the fiduciary duties otherwise owed to our unitholders by the Managing Member with contractual standards governing its duties.


Our operating agreement contains provisions that eliminate and replace the fiduciary standards that the Managing Member would otherwise be held to by state fiduciary duty law. For example, our operating agreement permits the Managing Member to make a number of decisions, in its individual capacity, as opposed to in its capacity as the Managing Member, or otherwise, free of fiduciary duties to us and our unitholders. This entitles the Managing Member to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates, or our members. Examples of decisions that the Managing Member may make in its individual capacity include:


•how to allocate business opportunities among us and its other affiliates;


•whether to exercise its call right;

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•how to exercise its voting rights with respect to any membership interests it owns;


•whether or not to consent to any merger or consolidation of us or any amendment to our operating agreement; and


•whether or not to seek the approval of the conflicts committee of the board of directors of the Managing Member, or the unitholders, or neither, of any conflicted transaction.


By purchasing any ENLC common units, a unitholder is treated as having consented to the provisions in our operating agreement, including the provisions discussed above.


Our operating agreement restricts the remedies available to holders of our membership interests for actions taken by the Managing Member that might otherwise constitute breaches of fiduciary duty.


Our operating agreement contains provisions that restrict the remedies available to holders of ENLC common units for actions taken by the Managing Member that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our operating agreement provides that:


•whenever the Managing Member makes a determination or takes, or declines to take, any other action in its capacity as the Managing Member, the Managing Member is required to make such determination, or take or decline to take such other action, in good faith, and will not be subject to any other or different standard imposed by Delaware law, or any other law, rule, or regulation, or at equity;


•the Managing Member will not have any liability to us or our unitholders for decisions made in its capacity as a managing member so long as it acted in good faith, meaning that it subjectively believed that the decision was in, or not opposed to, our best interests;


•our operating agreement is governed by Delaware law and any claims, suits, actions, or proceedings:


•arising out of or relating in any way to our operating agreement (including any claims, suits, or actions to interpret, apply, or enforce the provisions of our operating agreement or the duties, obligations, or liabilities among members or of members to us, or the rights or powers of, or restrictions on, the members or the company);


•brought in a derivative manner on our behalf;


•asserting a claim of breach of a fiduciary duty owed by any of our directors, officers, or other employees or the Managing Member, or owed by the Managing Member, to us or our members;


•asserting a claim arising pursuant to any provision of the DLLCA;Delaware Limited Liability Company Act (“DLLCA”); or


•asserting a claim governed by the internal affairs doctrine;


must be exclusively brought in the Court of Chancery of the State of Delaware (or, if such court does not have subject matter jurisdiction thereof, any other court located in the State of Delaware with subject matter jurisdiction), regardless of whether such claims, suits, actions, or proceedings sound in contract, tort, fraud, or otherwise, are based on common law, statutory, equitable, legal, or other grounds, or are derivative or direct claims. By purchasing ENLC common units, a member is irrevocably consenting to these limitations and provisions regarding claims, suits, actions, or proceedings and submitting to the exclusive jurisdiction of the Court of Chancery of the State of Delaware (or such other Delaware courts) in connection with any such claims, suits, actions, or proceedings;


•the Managing Member and its officers and directors will not be liable for monetary damages to us or our members resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the Managing Member or its officers or directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct, or, in the case of a criminal matter, acted with knowledge that the conduct was unlawful; and


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•the Managing Member will not be in breach of its obligations under our operating agreement or its duties to us or our members if a transaction with an affiliate or the resolution of a conflict of interest is:


•approved by the conflicts committee of the board of directors of the Managing Member, although the Managing Member is not obligated to seek such approval; or


•approved by the vote of a majority of the outstanding ENLC common units, excluding any ENLC common units owned by the Managing Member and its affiliates, although the Managing Member is not obligated to seek such approval.



Our Managing Member will not have any liability to us or our unitholders for decisions whether or not to seek the approval of the conflicts committee of the board of directors of the Managing Member or holders of a majority of ENLC common units, excluding any ENLC common units owned by the Managing Member and its affiliates. If an affiliate transaction or the resolution of a conflict of interest is not approved by the conflicts committee or holders of ENLC common units, then it will be presumed that, in making its decision, taking any action or failing to act, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any member or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.


Holders of ENLC common units will have limited voting rights and willare not be entitled to elect the Managing Member or the board of directors of the Managing Member, which could reduce the price at which ENLC common units will trade.


Unlike the holders of common stock in a corporation, ENLC unitholders will have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders do not have the right to elect the Managing Member or the board of directors of the Managing Member on an annual or other continuing basis. The board of directors of the Managing Member, including its independent directors, is chosen by the sole member of the Managing Member, subject, in certain circumstances, to the approval of a majority of our independent directors and our Chief Executive Officer.Member. Furthermore, if unitholders are dissatisfied with the performance of the Managing Member, they will have very limited ability to remove the Managing Member. Our operating agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management. As a result of these limitations, the price at which ENLC common units trade could be diminished because of the absence or reduction of a takeover premium in the trading price.


Even if our unitholders are dissatisfied, they cannot initially remove the Managing Member without its consent.


ENLC’s unitholders are unable to remove the Managing Member without its consent because the Managing Member and its affiliates own sufficient units to be able to prevent its removal. The vote of the holders of at least 66 2/3% of all outstanding ENLC common units voting together as a single class is required to remove the Managing Member. As of February 14, 2018,9, 2022, the Managing Member and its affiliates owned approximately 63.8%46.4% of the outstanding ENLC common units.


GIP has pledged all of the equity interests that it owns in ENLC and the Managing Member to GIP’s lenders under its credit facility. A default under GIP’s credit facility could result in a change of control of the Managing Member.

GIP has pledged all of the equity interests that it owns in ENLC and the Managing Member to its lenders as security under a secured credit facility entered into by a GIP entity in connection with the GIP Transaction (the “GIP Credit Facility”). Although we are not a party to this credit facility, if GIP were to default under the GIP Credit Facility, GIP’s lenders could foreclose on the pledged equity interests. Any such foreclosure on GIP’s interest would result in a change of control of the Managing Member and would allow the new owner to replace the board of directors and officers of the Managing Member with its own designees and to control the decisions taken by the board of directors and officers. Moreover, any change of control of the Managing Member would permit the lenders under ENLC’s Consolidated Credit Facility and AR Facility to declare all amounts thereunder immediately due and payable, and if any such event occurs, we may be required to refinance our debt on unfavorable terms, which could negatively impact our results of operations and our ability to make distributions to our unitholders.

Our operating agreement restricts the voting rights of unitholders owning 20% or more of ENLC’s common units.


Unitholders’ voting rights are further restricted by our operating agreement, which provides that any units held by a person that owns 20% or more of any class of units, other than the Managing Member, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of the Managing Member, including the holders of the ENLC Class C Common Units, cannot vote on any matter.


Control
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The control of the Managing Member may be transferred to a third party without unitholder consent.


Our Managing Member may transfer its managing member interest in us to a third party in a merger or in a sale of all or substantially all of its assets without the consent of our unitholders. Furthermore, our operating agreement does not restrict the ability of DevonGIP to transfer all or a portion of the ownership interest in the Managing Member to a third party. If the managing member interest were transferred, the new owner of the Managing Member would then be in a position to replace the board of directors and officers of the Managing Member with its own choices and thereby exert significant control over the decisions made by such board of directors and officers. This effectively permits a “change of control” of the Managing Member without the vote or consent of the unitholders. On July 18, 2018, Devon sold its equity interests in us and our Managing Member to affiliates of GIP, without a vote or consent of the unitholders. For more information about the GIP transaction, see “Item 8. Financial Statements and Supplementary Data—Note 1.”


We may issue additional units, including units that are senior to ENLC common units, without yourthe approval of the holders of common units, which would dilute your existing ownership interests.


Our operating agreement does not limit the number of additional membership interests that we may issue at any time without the approval of our unitholders.unitholders, except that our operating agreement restricts our ability to issue any membership interests senior to or on parity with the Series B Preferred Units with respect to distributions on such membership interests or upon liquidation without the affirmative vote of the holders of a majority of our outstanding ENLC Class C Common Units, voting separately as a class. The issuance by us of additional ENLC common units or other equity securities of equal or senior rank will have the following effects:


•each unitholder’s proportionate ownership interest in us will decrease;
•the amount of cash available for distribution on each unit may decrease;
•the relative voting strength of each previously outstanding unit may be diminished; and
•the market price of ENLC common units may decline.



The ENLC Class C Common Units give the holders thereof certain voting rights, and the ability to exchange such holder’s Series B Preferred Units into our common units, which could cause dilution to our common unitholders.
Devon
The holders of our Series B Preferred Units have an equal number of ENLC Class C Common Units, which provide these holders with certain voting rights at ENLC in accordance with our operating agreement. For each additional Series B Preferred Unit issued by ENLK pursuant to its partnership agreement, ENLC will issue an additional Class C Common Unit to the applicable holders of Series B Preferred Units, so that the number of ENLC Class C Common Units issued and outstanding will always equal the number of Series B Preferred Units issued and outstanding. The holders of ENLC Class C Common Units will vote with the holders of common units as a single class on all matters on which holders of common units are entitled to vote. Each Class C Common Unit will be entitled to the number of votes equal to the number of common units into which a Series B Preferred Unit is then exchangeable, which is the product of the number of Series B Preferred Units being exchanged multiplied by 1.15 (subject to certain adjustments).

In addition, the holders of ENLC Class C Common Units are entitled to vote as a separate class on any matter that (i) adversely affects the rights, preferences, and privileges of the ENLC Class C Common Units or the Series B Preferred Units, including certain leverage ratio restrictions and other minority protections with respect to substantially the same matters for which the holders of Series B Preferred Units have approval rights under the ENLK partnership agreement, or (ii) amends or modifies any of the terms of the ENLC Class C Common Units or Series B Preferred Units. The approval of a majority of the ENLC Class C Common Units is required to approve any matter for which the holders of ENLC Class C Common Units are entitled to vote as a separate class. These restrictions may adversely affect our ability to finance future operations or capital needs or to engage in other business activities.

Furthermore, the exchange of the Series B Preferred Units into common units, which the holders of the Series B Preferred Units may elect to cause at any time, may cause substantial dilution to the holders of the common units. As of February 9, 2022, on an as-exchanged basis, the Series B Preferred Units (and the corresponding voting power of the ENLC Class C Common Units) represented approximately 10.1% of the membership interests of ENLC.

GIP may sell ENLC common units in the public markets or otherwise, which sales could have an adverse impact on the trading price of our common units.


As of February 14, 2018, Devon9, 2022, GIP held 115,495,669224,355,359 ENLC common units. Additionally, we have agreed to provide DevonGIP with certain registration rights with respect to the ENLC common units held by it. The sale of these units could have an adverse
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impact on the price of ENLC common units or on any trading market that may develop. On February 15, 2022, we and GIP entered into an agreement pursuant to which we will repurchase, on a quarterly basis, a pro rata portion of the ENLC common units held by GIP, based upon the number of common units purchased by us during the applicable quarter from public unitholders under our common unit repurchase program. The number of ENLC common units held by GIP that we repurchase in any quarter will be calculated such that GIP’s then-existing economic ownership percentage of our outstanding common units is maintained after our repurchases of common units from public unitholders are taken into account, and the per unit price we pay to GIP will be the average per unit price paid by us for the common units repurchased from public unitholders. For more information about our repurchase agreement with GIP, see Item 9B of this Report.


Our Managing Member has a call right that may require unitholders to sell their ENLC common units at an undesirable time or price.


If at any time the Managing Member and its affiliates own more than 90% of ENLC’s common units, the Managing Member will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of ENLC common units held by unaffiliated persons at a price equal to the greater of (1) the average of the daily closing price of ENLC common units over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed and (2) the highest per-unit price paid by the Managing Member or any of its affiliates for ENLC common units during the 90-day period preceding the date such notice is first mailed. As a result, unitholders may be required to sell their ENLC common units at an undesirable time or price and may not receive any return or a negative return on their investment. Unitholders may also incur a tax liability upon a sale of their units. Our Managing Member is not obligated to obtain a fairness opinion regarding the value of ENLC common units to be repurchased by it upon exercise of the call right. There is no restriction in our operating agreement that prevents the Managing Member from issuing additional ENLC common units and exercising its call right. If the Managing Member exercised its call right, the effect would be to take us private. As of February 14, 2018, Devon9, 2022, GIP owned an aggregate of approximately 63.8%46.4% of outstanding ENLC common units.


Cost reimbursements due to the Managing Member and its affiliates for services provided, which will be determined by the Managing Member, could be substantial and would reduce cash available for distribution to our unitholders.

Prior to making distributions on ENLC common units, we will reimburse the Managing Member and its affiliates for all expenses they incur on our behalf. These expenses will include all costs incurred by the Managing Member and its affiliates in managing and operating us, including costs for rendering corporate staff and support services to us, if any. There is no limit on the amount of expenses for which the Managing Member and its affiliates may be reimbursed. Our operating agreement provides that the Managing Member will determine the expenses that are allocable to us. In addition, to the extent the Managing Member incurs obligations on behalf of us, we are obligated to reimburse or indemnify the Managing Member. During 2021, we reimbursed the Managing Member and its affiliates for $0.5 million in connection with personnel secondment services provided by GIP. If we are unable or unwilling to reimburse or indemnify the Managing Member, the Managing Member may take actions to cause us to make payments of these obligations and liabilities. Any such payments could reduce the amount of cash otherwise available for distribution to our unitholders.

Unitholders may have liability to repay distributions that were wrongfully distributed to them.


Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under the DLLCA, a limited liability company may not make a distribution to a member if, after the distribution, all liabilities of the limited liability company, other than liabilities to members on account of their membership interests and liabilities for which the recourse of creditors is limited to specific property of the company, would exceed the fair value of the assets of the limited liability company. For the purpose of determining the fair value of the assets of a limited liability company, the DLLCA provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited liability company only to the extent that the fair value of that property exceeds the non-recourse liability. The DLLCA provides that a member who receives a distribution and knew at the time of the distribution that the distribution was in violation of the DLLCA will be liable to the limited liability company for the amount of the distribution for three years.years following the date of the distribution.


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The price of ENLC common units may fluctuate significantly, which could cause youour unitholders to lose all or part of yourtheir investment.


As of February 14, 2018, only9, 2022, approximately 36.2%53.6% of ENLC common units were held by public unitholders. The lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of ENLC common units, and limit the number of investors who are able to buy ENLC common units. The market price of ENLC common units may be influenced by many factors, some of which are beyond our control, including:


•the quarterly distributions paid by us with respect to ENLC common units;
•our quarterly or annual earnings, or those of other companies in our industry;
•the loss of Devon as a significant customer;
•events affecting Devon;GIP;
•announcements by us or our competitors of significant contracts or acquisitions;
•changes in accounting standards, policies, guidance, interpretations, or principles;
•general economic conditions;conditions, including the impacts of COVID-19 (or any of its variants) or any other pandemic;
•the failure of securities analysts to cover ENLC common units or changes in financial estimates by analysts;
•future sales of ENLC common units; and
•other factors described in these “Risk Factors.”



In March 2020, soon after the World Health Organization declared the ongoing COVID-19 outbreak a pandemic, the ENLC common units reached a historically low trading price of $0.93.
We are a “controlled company” within the meaning of NYSE rules
Financial and as a result, we qualify for, and rely on, exemptions from some of the listing requirements with respect to independent directors.Indebtedness Risks

Because Devon controls more than 50% of the voting power for the election of directors of the Managing Member, we are a controlled company within the meaning of NYSE rules, which exempt controlled companies from the following corporate governance requirements:

the requirement that a majority of the board consist of independent directors;

the requirement that the board of directors have a nominating or corporate governance committee, composed entirely of independent directors, that is responsible for identifying individuals qualified to become board members, consistent with criteria approved by the board, selection of board nominees for the next annual meeting of equity holders, development of corporate governance guidelines and oversight of the evaluation of the board and management;

the requirement that we have a compensation committee of the board, composed entirely of independent directors, that is responsible for reviewing and approving corporate goals and objectives relevant to chief executive officer compensation, evaluation of the chief executive officer’s performance in light of the goals and objectives, determination and approval of the chief executive officer’s compensation, making recommendations to the board with respect to compensation of other executive officers and incentive compensation and equity-based plans that are subject to board approval and producing a report on executive compensation to be included in an annual proxy statement or Form 10-K filed with the SEC;

the requirement that we conduct an annual performance evaluation of the nominating, corporate governance and compensation committees; and

the requirement that we have written charters for the nominating, corporate governance and compensation committees addressing the committees’ responsibilities and annual performance evaluations.

For so long as we remain a controlled company, we will not be required to have a majority of independent directors or nominating, corporate governance or compensation committees. Accordingly, you may not have the same protections afforded to stockholders of companies that are subject to all of the NYSE corporate governance requirements.


Our cash flow consists almost exclusively of distributionscash flows from ENLK.


Currently, our only cash-generating assets areasset is our partnership interests in ENLK and our 16.1% limited partner interest in EnLink Oklahoma T.O. Although EnLink Oklahoma T.O. generates positive cash flows from operating activities, our capital contributions exceeded distributions received during 2017, and estimated capital contributions during 2018 will exceed its cash flows from operating activities. We have a $250.0 million revolving credit facility (the “ENLC Credit Facility”) in place to fund our share of capital expenditures to the extent not funded by EnLink Oklahoma T.O.’s operating cash flows. See “Item 8. Financial Statements and Supplementary Data—Note 6” for further discussion. If our borrowing capacity under the ENLC Credit Facility is not sufficient to fund our share of EnLink Oklahoma T.O.’s capital expenditures, we may have to use our cash flow from ENLK distributions to fund such costs.ENLK. Our cash flow is therefore completely dependent upon the ability of ENLK to make distributionsgenerate cash or our ability to its partners.borrow under the Consolidated Credit Facility and the AR Facility.


The amount of cash that ENLK can distributeprovide to its partners, including us each quarter principally depends upon the amount of cash it generates from its operations, which will fluctuate from quarter to quarter based on, among other things:


the amount of natural gas transported in its gathering and transmission pipelines;
the level of ENLK’s processing operations;
•the fees ENLK charges and the margins it realizes for its services;
•the prices of, levels of production of, and demand for crude oil, condensate, NGLs, and natural gas;
•the volume of natural gas ENLK gathers, compresses, processes, transports, and sells, the volume of NGLs ENLK processes or fractionates and sells, the volume of crude oil ENLK handles at its crude terminals, the volume of crude oil and condensate that ENLK gathers, transports, purchases, and sells, the volumes of condensate stabilized, and the volumes of brine ENLK disposes;
•the relationship between natural gas and NGL prices; and
•ENLK’s level of operating costs.



In addition, the actual amount of cash generated by ENLK that will havebe available for distributionto us will depend on other factors, some of which are beyond its control, including:


•the level of capital expenditures ENLK makes;
•the cost of acquisitions, if any;
•ENLK’s debt service requirements;requirements and distribution requirements with respect to Series B Preferred Units and Series C Preferred Units;
•fluctuations in its working capital needs;
ENLK’s ability to make working capital borrowings under its $1.5 billion revolving credit facility (the “ENLK Credit Facility”) to pay distributions;
•prevailing economic conditions; and
•the amount of cash reserves established by the General Partner in its sole discretion for the proper conduct of business.


Because of these and potentially other factors, we and ENLK may not be able, or may not have sufficient available cash to pay distributions to unitholders each quarter. Furthermore, you should also be aware that the amount of cash ENLK has available for distribution depends primarily upon its cash flows, including cash flow from financial reserves and working capital borrowings, and is not solely a function of profitability, which will be affected by non-cash items. As a result, ENLK may make cash distributions during periods when it records losses and may not make cash distributions during periods when it records net income.


Although
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The terms of the Consolidated Credit Facility, the AR Facility, and indentures governing our senior notes and ENLK’s senior notes may restrict our current and future operations, particularly our ability to respond to changes in business or to take certain actions.

The Consolidated Credit Facility, the AR Facility, and the indentures governing our senior notes and ENLK’s senior notes contain, and any future indebtedness we incur will likely contain, a number of restrictive covenants that impose significant operating and financial restrictions, including restrictions on our ability to engage in acts that may be in our best long-term interest. One or more of these agreements include covenants that, among other things, restrict our ability to:

•incur subsidiary indebtedness;
•engage in transactions with our affiliates;
•consolidate, merge, or sell substantially all of our assets;
•incur liens;
•enter into sale and lease back transactions; and
•change business activities we conduct.

In addition, the Consolidated Credit Facility requires us to satisfy and maintain specified financial ratios, and the AR Facility requires ENLC’s consolidated leverage ratio not to exceed limits identical to those in the Consolidated Credit Facility. The AR Facility also contains events of default relating to a borrowing base deficiency and events negatively affecting the overall credit quality of the receivables securing the AR Facility. Our ability to meet those financial ratios and receivables-related tests can be affected by events beyond our control, ENLK,including prevailing economic, financial, and industry conditions, and we cannot assure you that we will meet those ratios and receivables-related tests, particularly if market or other economic conditions deteriorate.

A breach of any of these covenants could result in an event of default under the General Partner owes fiduciary dutiesapplicable debt agreement. Upon the occurrence of such an event of default, all amounts outstanding under the applicable debt agreements could be declared to be immediately due and payable and all applicable commitments to extend further credit could be terminated. If indebtedness under the applicable debt agreements is accelerated, there can be no assurance that we will have sufficient assets to repay the indebtedness. The operating and financial restrictions and covenants in these debt agreements and any future debt agreements may adversely affect our ability to finance future operations or capital needs or to engage in other business activities.

Our debt levels could limit our flexibility and adversely affect our financial health or limit our flexibility to obtain financing and to pursue other business opportunities.

We continue to have the ability to incur debt, subject to limitations in our debt agreements. Our level of indebtedness could have important consequences to us, including the following:

•our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions, or other purposes may be impaired or such financing may not be available on favorable terms;
•our funds available for operations, future business opportunities, and distributions to unitholders will be reduced by that portion of our cash flows required to make interest payments on our debt;
•our debt level will make us more vulnerable to general adverse economic and industry conditions;
•our ability to plan for, or react to, changes in our business and the industry in which we operate; and
•our risk that we may default on our debt obligations.

In addition, our ability to make scheduled payments or to refinance our obligations depends on our successful financial and operating performance, which will be affected by prevailing economic, financial, and industry conditions, many of which are beyond our control. If our cash flow and capital resources are insufficient to fund our debt service obligations, we may be forced to take actions such as further reducing distributions, reducing or delaying our business activities, acquisitions, investments, or capital expenditures, selling assets, restructuring or refinancing our debt, or seeking additional equity capital. We may not be able to undertake any of these actions on satisfactory terms or at all.

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Any reductions in our credit ratings could increase our financing costs, increase the cost of maintaining certain contractual relationships, and reduce our cash available for distribution.

We cannot guarantee that our credit ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. As of February 9, 2022, Fitch Ratings, S&P, and Moody’s have assigned a BB+, BB+, and Ba2 credit rating, respectively, to ENLK and itsENLC. Any downgrade could also lead to higher borrowing costs for future borrowings and could require:

•additional or more restrictive covenants that impose operating and financial restrictions on us and our subsidiaries;
•our subsidiaries to guarantee such debt and certain other debt;
•us and our subsidiaries to provide collateral to secure such debt; and
•us or our subsidiaries to post cash collateral or letters of credit under our hedging arrangements or in order to purchase commodities or obtain trade credit.

Any increase in our financing costs or additional or more restrictive covenants resulting from a credit rating downgrade could adversely affect our ability to finance future operations. If a credit rating downgrade and the resultant collateral requirement were to occur at a time when we were experiencing significant working capital requirements or otherwise lacked liquidity, our results of operations could be adversely affected.

An impairment of long-lived assets, including intangible assets, equity method investments, and right-of-use assets related to leases could reduce our earnings.

GAAP requires us to test long-lived assets, including intangible assets with finite useful lives, for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. For the investments we account for under the equity method, the impairment test considers whether the fair value of the unconsolidated affiliate investment as a whole, not the underlying net assets, has declined and whether that decline is other than temporary. If we determine that an impairment is indicated, we would be required to take an immediate non-cash charge to earnings with a correlative effect on equity and balance sheet leverage as measured by debt to total capitalization. For the year ended December 31, 2021, we recognized $0.8 million impairment expense related to property and equipment and lease right-of-use assets. We have recognized impairments on property and equipment in the past. See “Item 8. Financial Statements and Supplementary Data—Note 2” for more information about impairment of long-lived assets. Additional impairment of the value of our existing long-lived assets could have a significant negative impact on our future operating results.

We are exposed to the credit risk of our customers and counterparties, and a general increase in the nonpayment and nonperformance by our customers could have an adverse effect on our financial condition, results of operations, or cash flows.

Risks of nonpayment and nonperformance by our customers are a major concern in our business. We are subject to risks of loss resulting from nonpayment or nonperformance by our customers and other counterparties, such as our lenders and hedging counterparties. Any increase in the nonpayment and nonperformance by our customers could adversely affect our results of operations and reduce our ability to make distributions to our unitholders. Additionally, equity values for many of our customers continue to be low. The combination of a reduction in cash flow from lower commodity prices, a reduction in borrowing bases under reserve-based credit facilities, and the lack of availability of debt or equity financing may result in a significant reduction in our customers’ liquidity and ability to make payment or perform on their obligations to us. Furthermore, some of our customers may be highly leveraged and subject to their own operating and regulatory risks, which increases the risk that they may default on their obligations to us. In May 2019, White Star, the counterparty to our $58.0 million second lien secured term loan receivable, filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code and was not able to repay the outstanding amounts owed to us under the second lien secured term loan. For additional information regarding this transaction, refer to “Item 8. Financial Statements and Supplementary Information—Note 2.”


Conflicts
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Increases in interest existrates could adversely impact the price of ENLC’s common units, ENLC’s or ENLK’s ability to issue equity or incur debt for acquisitions or other purposes, and ENLC’s or ENLK’s ability to make cash distributions.

Interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, ENLC’s unit price is impacted by ENLC’s level of cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may ariseaffect the yield requirements of investors who invest in ENLC’s units, and a rising interest rate environment could have an adverse impact on the price of ENLC’s common units, ENLC’s or ENLK’s ability to issue equity or incur debt for acquisitions or other purposes and ENLC’s or ENLK’s ability to make cash distributions at our intended levels or at all. Beginning on December 15, 2022, distributions on ENLK’s Series C Preferred Units will be based on a floating rate tied to LIBOR rather than a fixed rate and, therefore, the amount paid by ENLK as a distribution will be more sensitive to changes in interest rates.

We may not realize our deferred tax assets.

As of December 31, 2021, we had deferred tax assets (primarily consisting of federal and state net operating loss carryovers) of $633.2 million, against which we provided a valuation allowance of $151.6 million. The ultimate realization of our deferred tax assets is dependent upon generating future taxable income to utilize our net operating loss carryovers before they expire. While we have recorded valuation allowances against certain of our deferred tax assets, the valuation allowances are subject to change as facts and circumstances change.

Additionally, Section 382 of the Internal Revenue Code of 1986, as amended (“Section 382”), generally imposes an annual limitation on the amount of net operating losses and other pre-change tax attributes (such as tax credits) that may be used to offset taxable income by a corporation that has undergone an “ownership change” (as determined under Section 382). An ownership change generally occurs if one or more shareholders (or groups of shareholders) that are each deemed to own at least 5% of our stock increase their ownership by more than 50 percentage points over their lowest ownership percentage during a rolling three-year period. As of December 31, 2021, we have not experienced an ownership change. Therefore, our utilization of net operating loss carryforwards was not subject to an annual limitation. However, if we were to experience ownership changes in the future as a result of subsequent shifts in our common unit ownership, our ability to use our pre-change net operating loss carryforwards to offset future taxable income may be subject to limitations, which could potentially result in increased future tax liability to us. Additionally, at the relationship between usstate level, there may be periods during which the use of NOL carryforwards is suspended or otherwise limited, which could accelerate or permanently increase state taxes owed. In any case, our net operating loss and tax credit carryforwards are subject to review and potential disallowance upon audit by the tax authorities of the jurisdictions where these tax attributes are incurred.

The value of our affiliates, includingdeferred tax assets and liabilities are also dependent upon the General Partner, on the one hand, and ENLK and its limited partners, on the other hand. The directors and officers of EnLink Midstream GP, LLC have fiduciary dutiestax rates expected to manage the General Partner in a manner beneficial to us, its owner. At the same time, the General Partner has a fiduciary duty to manage ENLK in a manner beneficial to ENLK and its limited partners. The board of directors of EnLink Midstream GP, LLC will resolve any such conflict and has broad latitude to consider the interests of all parties to the conflict. The resolution of these conflicts may not always be in effect at the time they are realized. A change in enacted corporate tax rates in our best interest or that of our unitholders.

For example, conflicts of interest may arise inmajor jurisdictions, especially the following situations:

the allocation of shared overhead expenses to ENLK and us;
the interpretation and enforcement of contractual obligations between us and our affiliates, on the one hand, and ENLK, on the other hand;
the determination of the amount of cash to be distributed to ENLK’s partners and the amount of cash to be reserved for the future conduct of ENLK’s business;
the determination whether to make borrowings under the ENLK Credit Facility to pay distributions to partners; and
any decision we make in the future to engage in activities in competition with ENLK.

If the General Partner is not fully reimbursed or indemnified for obligations and liabilities it incurs in managing the business and affairs of ENLK, its value, and thereforeU.S. federal corporate tax rate, would change the value of ENLC common units,our deferred taxes, which could decline.be material.

The General Partner may make expenditures on behalf of ENLK for which it will seek reimbursement from ENLK. In addition, under Delaware law, the General Partner, in its capacity as the General Partner of ENLK, has unlimited liability for the obligations of ENLK, such as its debts and environmental liabilities, except for those contractual obligations of ENLK that are expressly made without recourse to the General Partner. To the extent the General Partner incurs obligations on behalf of ENLK, it is entitled to be reimbursed or indemnified by ENLK. In the event that ENLK is unable or unwilling to reimburse or indemnify the General Partner, the General Partner may be unable to satisfy these liabilities or obligations, which would reduce its value and therefore the value of ENLC common units.

If in the future we cease to manage and control ENLK, we may be deemed to be an investment company under the Investment Company Act of 1940.

If we cease to manage and control ENLK and are deemed to be an investment company under the Investment Company Act of 1940, we would either have to register as an investment company under the Investment Company Act of 1940, obtain exemptive relief from the SEC or modify our organizational structure or our contractual rights so as to fall outside the definition of an investment company. Registering as an investment company could, among other things, materially limit our ability to engage in transactions with affiliates, including the purchase and sale of certain securities or other property to or from our

affiliates, restrict our ability to borrow funds or engage in other transactions involving leverage and require us to add additional directors who are independent of us and our affiliates, and adversely affect the price of ENLC common units.


We are treated as a corporation subject to entity level federal and state income taxation. Any such entity level income taxes will reduce the amount of cash available for distribution to you.distribution.


We are treated as a corporation for tax purposes that is required to pay federal and state income tax on our taxable income at corporate rates. Historically, we have had net operating losses (“NOLs”) that eliminated substantially all of our taxable income and, thus, we historically have not had to pay material amounts of income taxes. We anticipate generating net operating lossesNOLs for tax purposes during 2018,2021, and as a result, do not expect to incur material amounts of federal and state income tax liabilities. In the event we do generate taxable income, federal and state income tax liabilities will reduce the cash available for distribution to our unitholders.

Changes in the method of determining the London Interbank Offered Rate, or the replacement of the London Interbank Offered Rate with an alternative reference rate, may adversely affect interest expense related to outstanding debt.

Amounts drawn under the Consolidated Credit Facility and the AR Facility currently bear interest at rates based on the U.S. Dollar London Interbank Offered Rate (“LIBOR”). On December 22,July 27, 2017, tax legislation commonly knownthe Financial Conduct Authority in the United Kingdom (“FCA”) announced that it would phase out LIBOR as a benchmark by the end of 2021. On March 5, 2021, ICE Benchmark Administration, the current administrator of LIBOR, announced that it intends to cease publication of 1-week and 2-month LIBOR at the end of 2021 and, subject to compliance with applicable regulations, including as to representativeness, it does not intend to cease publication of the remaining tenors until June 30, 2023. It is uncertain whether USD LIBOR will be available as a benchmark for pricing our floating rate indebtedness until, or after, June 30, 2023. The Consolidated Credit Facility and the AR Facility include mechanisms to amend the facilities to reflect the establishment of an alternative rate of interest upon the
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occurrence of certain events related to the phase-out of LIBOR and on September 24, 2021, EnLink Midstream Funding, LLC entered into the Second Amendment to the Receivables Financing Agreement to, among other things, provide for the technical amendment and contractual alternative to address the anticipated replacement of LIBOR. The expected replacement reference rate for the AR Facility, plus the applicable spread adjustment, could result in a higher interest rate under the AR Facility than if our borrowings were still based upon LIBOR. If no such amendment or other contractual alternative is established for the Consolidated Credit Facility on or prior to the phase-out of LIBOR, interest under the Consolidated Credit Facility will bear interest at higher rates based on the prime rate until such amendment or other contractual amendment is established. Even where we have entered into interest rate swaps or other derivative instruments for purposes of managing our interest rate exposure, our hedging strategies may not be effective as a result of the replacement or phasing out of LIBOR, and our earnings may be subject to volatility. In addition, the overall financial markets may be disrupted as a result of the phase-out or replacement of LIBOR. The potential increase in our interest expense as a result of the phase-out of LIBOR and uncertainty as to the nature of such potential phase-out and alternative reference rates or disruption in the financial market could have an adverse effect on our financial condition, results of operations and cash flows.

Business and Industry Risks

The ongoing coronavirus (COVID-19) pandemic has adversely affected and could continue to adversely affect our business, financial condition, and results of operations.

On March 11, 2020, the World Health Organization declared the ongoing coronavirus (COVID-19) outbreak a pandemic and recommended containment and mitigation measures worldwide. The ongoing pandemic and related travel and operational restrictions, as well as business closures and curtailed consumer activity, resulted in a reduction in global demand for energy, volatility in the market prices for crude oil, condensate, natural gas, and NGLs, and a significant reduction in the market price of crude oil and a related curtailment of drilling and production activity, including by some of our customers, during the first and second quarter of 2020. As a result of these decreases in producer activity, we experienced reduced volumes gathered, processed, fractionated, and transported on our assets in some of the regions that supply our systems during this same period, although commodity prices and our volumes have now returned to pre-pandemic levels.

Since the outbreak began, our first priority has been the health and safety of our employees and those of our customers and other business counterparties. Beginning in March 2020, we implemented preventative measures and developed a response plan to minimize unnecessary risk of exposure and prevent infection, while supporting our customers’ operations, and we continue to follow these plans. We maintain a crisis management team for health, safety and environmental matters and personnel issues and a cross-functional COVID-19 response team to address various impacts of the situation, as they develop. We also continue to promote heightened awareness, vigilance, and hygiene, and we continue to evaluate and adjust our preventative measures, response plans and business practices with the evolving impacts of COVID-19 and its variants. We have continued to maintain these COVID protocols since the inception of the pandemic and to date we have not experienced any significant COVID-19 related operational disruptions. However, the quarantine of personnel or the inability to access our facilities or customer sites could adversely affect our operations. If a large proportion of our employees in critical positions were to contract COVID-19 at the same time, we would rely upon our business continuity plans in an effort to continue operations at our systems, pipelines, and facilities, but there is no certainty that such measures will be sufficient to mitigate the adverse impact to our operations that could result from shortages of highly skilled employees.

There remains considerable uncertainty regarding how long the COVID-19 pandemic (including the Delta and Omicron variants of the virus, as well as any other variants) will persist and affect economic conditions and the extent and duration of changes in consumer behavior, such as the Tax Cutsreluctance to travel, as well as whether governmental and Jobs Act (“Tax Cutsother measures implemented to try to slow the spread of the virus and Jobs Act”) was enacted. Amongits variants, such as large-scale travel bans and restrictions, border closures, quarantines, shelter-in-place orders, and business and government shutdowns that exist as of the date of this report will be extended or whether new measures will be imposed. As a result, there is significant uncertainty as to whether COVID-19 will cause additional market dislocations or how significantly and how long any such market disruptions may affect us. We expect to see continued volatility in crude oil, condensate, natural gas, and NGL prices for the foreseeable future, which may, over the long term, adversely impact our business. A sustained significant decline in oil and natural gas exploration and production activities and related reduced demand for our services by our customers, whether due to decreases in consumer demand or reduction in the prices for oil, condensate natural gas and NGLs or otherwise, would have a material adverse effect on our business, liquidity, financial condition, results of operations, and cash flows.

These uncertain economic conditions may also result in the inability of our customers and other things,counterparties to make payments to us, on a timely basis or at all, which could adversely affect our business, liquidity, financial condition, results of operations, and cash flows. A substantial deterioration in our business and/or a prolonged period of market dislocation could also affect our compliance with the Tax Cutsfinancial covenants in our revolving credit facility, particularly the consolidated leverage
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ratio covenant. If we were unable to continue to meet any of the financial covenants, we would not be able to borrow funds under our revolving credit facility and Jobs Act (i) reduces the U.S. corporate income tax rate from 35%AR Facility.

We cannot predict the full impact that the COVID-19 pandemic or the related volatility in oil and natural gas markets will have on our business, liquidity, financial condition, results of operations, and cash flows at this time due to 21% (beginningnumerous uncertainties. Furthermore, the COVID-19 pandemic (including federal, state and local governmental responses, broad economic impacts and market disruptions) has heightened a number of the risks discussed in 2018), (ii) generallythe risk factors described in this report. The ultimate impacts will depend on future developments, including, among others, the ultimate duration and persistence of the pandemic, the impact of the Delta and Omicron variants of the virus, the speed at which the population is vaccinated against the virus and the efficacy of the vaccines, the emergence of 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 resume.

We may not be able to retain existing customers or acquire new customers, which would reduce our revenues and limit our annual deductionsfuture profitability.

The renewal or replacement of existing contracts with our customers at rates sufficient to maintain current revenues and cash flows depends on a number of factors beyond our control, including the price of, and demand for, interest expensecrude oil, condensate, NGLs, and natural gas in the markets we serve and competition from other midstream service providers. Our competitors include companies larger than we are, which could have both a lower cost of capital and a greater geographic coverage, as well as companies smaller than we are, which could have lower total cost structures. In addition, competition is increasing in some markets that have been overbuilt, resulting in an excess of midstream energy infrastructure capacity, or where new market entrants are willing to noprovide services at a discount in order to establish relationships and gain a foothold. The inability of our management to renew or replace our current contracts as they expire and to respond appropriately to changing market conditions could have a negative effect on our profitability.

In particular, our ability to renew or replace our existing contracts with industrial end-users and utilities impacts our profitability. As a consequence of the increase in competition in the industry and volatility of natural gas prices, industrial end-users and utilities may be reluctant to enter into long-term purchase contracts. Many industrial end-users purchase natural gas from more than 30%one natural gas company and have the ability to change providers at any time. Some of our “adjusted taxable income” (plus 100%these industrial end-users also have the ability to switch between gas and alternate fuels in response to relative price fluctuations in the market. Because there are numerous companies of our business interest income) forgreatly varying size and financial capacity that compete with us in marketing natural gas, we often compete in the yearindustrial end-user and (iii) will permit us to offset only 80% (rather than 100%)utilities markets primarily on the basis of our taxable income with any net operating losses (NOLs)price.

Any decrease in the volumes that we generate after 2017. Currently we do not expect the provisions of the Tax Cuts and Jobs Act, taken as a whole, to have any material adverse impact ongather, process, fractionate, or transport would adversely affect our cash tax liabilities, financial condition, results of operations, or cash flows. However, it is possible in the future thatthe NOL and/or interest deductibility limitations could have the effect of causing us to incur income tax liability sooner than we otherwise would have incurred such liability or, in certain cases, could cause us to incur income tax liability that we might otherwise not have incurred, in the absence of these tax law changes.flows.

The terms of the ENLC Credit Facility may restrict our current and future operations, particularly our ability to respond to changes in business or to take certain actions.


Our credit agreement contains, and any future indebtedness we incur will likely contain,financial performance depends to a number of restrictive covenants that impose significant operating and financial restrictions, including restrictionslarge extent on our ability to engage in acts that may be in our best long-term interest. In addition, the ENLC Credit Facility requires us to satisfy and maintain specified financial ratios and other financial condition tests. Our ability to meet those financial ratios and tests can be affected by events beyond our control, and we cannot assure you that we will meet those ratios and tests.

A breach of any of these covenants could result in an event of default under the ENLC Credit Facility. Upon the occurrence of such an event of default, all amounts outstanding under the ENLC Credit Facility could be declared to be immediately due and payable and all applicable commitments to extend further credit could be terminated. If we are unable to repay the accelerated debt under the ENLC Credit Facility, the lenders could proceed against the collateral granted to them to secure that indebtedness. We have pledged our ENLK common units and the 100% membership interest in the General Partner that are indirectly held by us and our 100% equity interest in each of our wholly-owned subsidiaries as collateral under the ENLC Credit Facility. If indebtedness under the ENLC Credit Facility is accelerated, there can be no assurance that we will have sufficient assets to repay the indebtedness. The operating and financial restrictions and covenants in the ENLC Credit Facility and any future financing agreements may adversely affect our ability to finance future operations or capital needs or to engage in other business activities.

Certain events of default under the ENLK Credit Facility, the occurrence of certain bankruptcy events affecting ENLK or our failure to continue to control ENLK could constitute an event of default under our credit facility.

Under the terms of the ENLC Credit Facility, certain events of default under the ENLK Credit Facility could constitute an event of default under the ENLC Credit Facility. Additionally, certain events of default under the ENLC Credit Facility relate specifically to events relating to ENLK, including certain bankruptcy events affecting ENLK or any event that causes us to no longer indirectly control ENLK. Additionally, any default by ENLK under the terms of the ENLK Credit Facility could limit its ability to make distributions to us.


Risks Inherent in our Business

We are dependent on Devon for a substantial portion of the natural gas that we gather, process and transport. The expiration of five-year MVCsfrom Devon in 2019 and 2020 could result in a material decline in our operating results and cash available for distribution because the volumes of natural gas, that wecrude oil, condensate, and NGLs gathered, processed, fractionated, and transported for Devon during 2017 have been below the MVC levels under certain ofon our contracts.

We are dependent on Devon for a substantial portion of our natural gas supply. For the year ended December 31, 2017, Devon represented approximately 46.8% of our gross operating margin. In order to minimize volumetric exposure,assets. Decreases in March 2014, we obtained five-year MVCs from Devon at the Bridgeport processing facility, Bridgeport and East Johnson County gathering systems and the Central Oklahoma gathering system, and these MVCs expire on January 1, 2019. We also have a five-year MVC from Devon attributable to VEX, and this MVC expires on July 31, 2019. If the volumes of natural gas, and crude oil, thatcondensate, and NGLs we gather, process, fractionate, or transport would directly and transportadversely affect our financial condition. These volumes can be influenced by factors beyond our control, including:

•continued fluctuations in commodity prices, including the prices of natural gas, NGLs, crude oil, and condensate;
•environmental or other governmental regulations;
•weather conditions, including the impact of hurricanes and winter storms;
•increases in storage levels of natural gas, NGLs, crude oil, and condensate;
•increased use of alternative energy sources;
•decreased demand for natural gas, NGLs, crude oil, and condensate;
•economic conditions, including the impacts of COVID-19 (or any of its variants) or any other pandemic;
•supply disruptions;
•availability of supply connected to our systems; and
•availability and adequacy of infrastructure to gather and process supply into and out of our systems.

The volumes of natural gas, crude oil, condensate, and NGLs gathered, processed, fractionated, and transported on our assets also depend on the production from the regions that supply our systems. Supply of natural gas, crude oil, condensate, and NGLs can be affected by many of the factors listed above, including commodity prices and weather. In order to maintain or increase throughput levels on our systems, we must obtain new sources of natural gas, crude oil, condensate, and NGLs. The
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primary factors affecting our ability to obtain non-dedicated sources of natural gas, crude oil, condensate, and NGLs include (i) the level of successful leasing, permitting, and drilling activity in our areas of operation, (ii) our ability to compete for volumes from new wells and (iii) our ability to compete successfully for volumes from sources connected to other pipelines. We have no control over the level of drilling activity in our areas of operation, the amount of reserves associated with wells connected to our systems, or the rate at which production from a well declines. In addition, we have no control over producers or their drilling or production decisions, which are belowaffected by, among other things, the MVCavailability and cost of capital, levels afterof reserves, availability of drilling rigs, and other costs of production and equipment.

We typically do not obtain independent evaluations of hydrocarbon reserves; therefore, volumes we service in the contracts expire,future could be less than we anticipate.

We typically do not obtain independent evaluations of hydrocarbon reserves connected to our gathering systems or that we otherwise service due to the unwillingness of producers to provide reserve information as well as the cost of such evaluations. Accordingly, we do not have independent estimates of total reserves serviced by our assets or the anticipated life of such reserves. If the total reserves or estimated life of the reserves is less than we anticipate, and we are unable to secure additional sources, then the volumes transported on our gathering systems or that we otherwise service in the future could experience a materialbe less than anticipated. A decline in our operating revenues and cash flow. For the year ended December 31, 2017, we recognized $59.2 million, $13.8 million and $8.9 million in MVC shortfall revenue from Devon attributable to our Texas, Oklahoma and Crude and Condensate segments, respectively, because volumes were below the minimum level. For the year ended December 31, 2016, we recognized $26.4 million, $10.8 million and $9.0 million in MVC shortfall revenue from Devon attributable to our Texas, Oklahoma and Crude and Condensate segments, respectively. For the year ended December 31, 2015, we recognized $3.8 million, $20.1 million, and $0.5 million in MVC shortfall revenue from Devon attributable to our Texas, Oklahoma and Crude and Condensate segments, respectively.

Because we are substantially dependent on Devon as one of our primary customers and through its indirect control of our general partner, any development that materially and adversely affects Devon’s operations, financial condition or market reputation could have a material and adverse impacteffect on us. Material adverse changes at Devon could restrict our access to capital, make it more expensive to access the capital markets or increase the costs of our borrowings.

We are substantially dependent on Devon as one of our primary customers and through its indirect control of our general partner, and we expect to derive a significant portion of our gross operating margin from Devon for the foreseeable future. As a result, any event, whether in our area of operations or otherwise, that adversely affects Devon’s production, financial condition, leverage, market reputation, liquidity, results of operations, or cash flowsflows.

We may adverselynot be successful in balancing our purchases and sales.

We are a party to certain long-term gas, NGL, crude oil, and condensate sales commitments that we satisfy through supplies purchased under long-term gas, NGL, crude oil, and condensate 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 purchasing additional gas at prices that may exceed the prices received under the sales commitments. In addition, a producer could fail to deliver contracted volumes or deliver in excess of contracted volumes, or a consumer could purchase more or less than contracted volumes. Any of these actions could cause our purchases and sales not to be balanced. If our purchases and sales are not balanced, we will face increased exposure to commodity price risks and could have increased volatility in our operating income.

We have made commitments to purchase natural gas in production areas based on production-area indices and to sell the natural gas into market areas based on market-area indices, pay the costs to transport the natural gas between the two points, and capture the difference between the indices as margin. Changes in the index prices relative to each other (also referred to as basis spread) can significantly affect our revenues and cash available for distribution. Accordingly, we are indirectly subject to the business risks of Devon, some of which are the following:

potential changes in the supply of and demand for oil, natural gas and NGLs and related products and services;
risks relating to Devon’s exploration and drilling programs, including potential environmental liabilities;
adverse effects of governmental and environmental regulation; and
general economic and financial market conditions.

Further, we are subject to the risk of non-paymentmargins or non-performance by Devon, including with respect to our gathering and processing agreements. We cannot predict the extent to which Devon’s business will be impacted by pricing conditions in the energy industry, nor can we estimate the impact such conditions would have on Devon’s ability to perform under our gathering and processing agreements. Additionally, due to our relationship with Devon, our ability to access the capital markets, or the pricing or other terms of any capital markets transactions, may be adversely affected by any impairments to Devon’s financial condition or adverse changes in its credit ratings. S&P Global Ratings (“S&P”) and Moody’s Investors Services (“Moody’s”) have currently assigned to Devon a BBB and Ba1 credit rating, respectively. Any material limitations on our ability to access capital as a result of such adverse changes at Devon could limit our ability to obtain future financing under favorable terms, or at all, or couldeven result in increased financing costs in the future. Similarly, material adverse changes at Devon could negatively impact our unit price, limiting our ability to raise capital through equity issuances or debt financing or our ability to engage in, expand or pursue our business activities and could also prevent us from engaging in certain transactions that might otherwise be considered beneficial to us.losses.


Please see “Item 1A. Risk Factors” in Devon’s Annual Report on Form 10-K for the year ended December 31, 2017 for a full discussion of the risks associated with Devon’s business.

Adverse developments in our gathering, transmission, processing, crude oil, condensate, natural gas, and NGL services businesses would adversely affect our financial condition and results of operations, and reduce our ability to make distributions to our unitholders.


We rely exclusively on the revenues generated from our gathering, transmission, processing, fractionation, crude oil, natural gas, condensate, and NGL services businesses, and as a result, our financial condition depends upon prices of, and

continued demand for, natural gas, NGLs, crude oil, and condensate. An adverse development in one of these businesses may have a significant impact on our financial condition and our ability to make distributions to our unitholders.


A significant portion of our operations are located in the Barnett Shale, making us vulnerable to risks associated with having revenue-producing operations concentrated in a limited number of geographic areas.

Our revenue-producing operations are geographically concentrated in the Barnett Shale, causing us to be exposed to risks associated with regional factors. Specifically, our operations in the Barnett Shale accounted for approximately 11.9% of our consolidated revenues and approximately 34.1% of our consolidated gross operating margin for the year ended December 31, 2017. The concentration of our operations in this region also increases exposure to unexpected events that may occur in this region such as natural disasters or labor difficulties. Any one of these events has the potential to have a relatively significant impact on our operations and growth plans, decrease cash flows, increase operating and capital costs and prevent development within originally anticipated time frames. Any of these risks could have a material adverse effect on our financial condition, results of operations or cash flows.

We must continually compete for crude oil, condensate, natural gas, and NGL supplies, and any decrease in supplies of such commodities could adversely affect our financial condition, results of operations, or cash flows.


In order to maintain or increase throughput levels in our gathering systems and asset utilization rates at our processing plants and fractionators, we must continually contract for new product supplies. We may not be able to obtain additional contracts for crude oil, condensate, natural gas, and NGL supplies. The primary factors affecting our ability to connect new wells to our gathering facilities include our success in contracting for existing supplies that are not committed to other systems and the level of drilling activity near our gathering systems. If we are unable to maintain or increase the volumes on our systems by accessing new supplies to offset the natural decline in reserves, our business and financial results could be materially, adversely affected. In addition, our future growth will depend in part upon whether we can contract for additional supplies at a greater rate than the rate of natural decline in our current supplies.


Fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new crude oil, condensate, and natural gas reserves. During 2015 and 2016, we saw suppressedAs recently as 2020, during the COVID-19 pandemic, commodity prices fell,
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which led to lower drilling activity, due to low commodity prices. Although drilling activity has improved during 2017 in some of the most economic basins, we could see downward pressure on future drilling activity in these basins if commodity prices decline below current levels, which may resultand resulted in lower volumes.volumes in the basins in which we operate. Although crude oil and natural gas prices and production activities have generally recovered to pre-pandemic levels, global capital investments by oil and natural gas producers remain at relatively low levels compared to historical levels, and producers remain cautious. Tax policy changes or additional regulatory restrictions on development could also have a negative impact on drilling activity, reducing supplies of product available to our systems and assets. Additional governmental regulation of, or delays in issuance of permits for, the offshore exploration and production industry may negatively impact current and future volumesdrilling activity. In addition, real or perceived differences in economic returns from offshore pipelines supplying our processing plants.various producing basins could influence producers to direct their future drilling activity away from basins in which we currently operate. We have no control over producers and depend on them to maintain sufficient levels of drilling activity. A continued decrease in the level of drilling activity or a material decrease in production in our principal geographic areas for a prolonged period, as a result of unfavorable commodity prices or otherwise, likely would have a material adverse effect on our financial condition, results of operations, and cash flows.


Any decreaseOur profitability is dependent upon prices and market demand for crude oil, condensate, natural gas, and NGLs that are beyond our control and have been volatile. A depressed commodity price environment could result in financial losses and reduce our cash available for distribution.

We are subject to significant risks due to fluctuations in commodity prices. We are directly exposed to these risks primarily in the gas processing and NGL fractionation components of our business. For the year ended December 31, 2021, approximately 6% of our total adjusted gross margin was generated under percent of liquids contracts and percent of proceeds contracts, with most of these contracts relating to our processing plants in the Permian Basin. Under percent of liquids contracts, we receive a fee in the form of a percentage of the liquids recovered, and the producer bears all the cost of the natural gas shrink. Accordingly, our revenues under percent of liquids contracts are directly impacted by the market price of NGLs. Adjusted gross margin under percent of proceeds contracts is impacted only by the value of the natural gas or liquids produced with margins higher during periods of higher natural gas and liquids prices.

We also realize adjusted gross margins under processing margin contracts. For the year ended December 31, 2021, less than 1% of our total adjusted gross margin was generated under processing margin contracts. We have a number of processing margin contracts for activities at our Plaquemine and Pelican processing plants. Under this type of contract, we pay the producer for the full amount of inlet gas to the plant, and we make a margin based on the difference between the value of liquids recovered from the processed natural gas as compared to the value of the natural gas volumes lost (“shrink”) and the cost of fuel used in processing. The shrink and fuel losses are referred to as plant thermal reduction (“PTR”). Our margins from these contracts can be greatly reduced or eliminated during periods of high natural gas prices relative to liquids prices.

We are also indirectly exposed to commodity prices due to the negative impacts of low commodity prices on production and the development of production of crude oil, condensate, natural gas, and NGLs connected to or near our assets and on the levels of volumes we transport between certain market centers.

Although the majority of our NGL fractionation business is under fee-based arrangements, a portion of our business is exposed to commodity price risk because we realize a margin due to product upgrades associated with our Louisiana fractionation business. For the year ended December 31, 2021, adjusted gross margin realized associated with product upgrades represented less than 2% of our adjusted gross margin.

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Commodity prices were volatile during 2021. Crude oil prices increased 58%, weighted average NGL prices increased 77%, and natural gas prices increased 45% from January 1, 2021 to December 31, 2021. We expect continued volatility in these commodity prices. For example, see the table below for the range of closing prices for crude oil, NGL, and natural gas during 2021.
CommodityClosing PriceDate
Crude oil (high) (1)$84.65 October 26, 2021
Crude oil (low) (1)$47.62 January 4, 2021
Crude oil (average) (1)(4)$68.11 Not applicable
NGL (high) (2)$1.02 November 1, 2021
NGL (low) (2)$0.46 January 4, 2021
NGL (average) (2)(4)$0.71 Not applicable
Natural gas (high) (3)$6.31 October 5, 2021
Natural gas (low) (3)$2.45 January 22, 2021
Natural gas (average) (3)(4)$3.72 Not applicable
____________________________
(1)Crude oil closing prices based on the NYMEX futures daily close prices.
(2)Weighted average NGL gas closing prices based on the Oil Price Information Service Napoleonville daily average spot liquids prices.
(3)Natural gas closing prices based on Gas Daily Henry Hub closing prices.
(4)The average closing price was computed by taking the sum of the closing prices of each trading day divided by the number of trading days during the period presented.

The markets and prices for crude oil, condensate, natural gas, and NGLs depend upon factors beyond our control that make it difficult to predict future commodity price movements with any certainty. These factors include the supply and demand for crude oil, condensate, natural gas, and NGLs, which fluctuate with changes in market and economic conditions and other factors, including:

•the impact of weather on the supply and demand for crude oil and natural gas;
•the level of domestic crude oil, condensate, and natural gas production;
•technology, including improved production techniques (particularly with respect to shale development);
•the level of domestic industrial and manufacturing activity;
•the availability of imported crude oil, natural gas, and NGLs;
•international demand for crude oil and NGLs;
•actions taken by foreign crude oil and gas producing nations;
•the continued threat of terrorism and the impact of military action and civil unrest;
•public health crises that reduce economic activity and affect the demand for travel, including the impacts of COVID-19 (or any of its variants) or any other pandemic;
•the availability of local, intrastate, and interstate transportation systems;
•the availability of downstream NGL fractionation facilities;
•the availability and marketing of competitive fuels;
•the development and adoption of alternative energy technologies, such as electric vehicles;
•the impact of energy conservation efforts; and
•the extent of governmental regulation and taxation, including the regulation of hydraulic fracturing and “greenhouse gases.”

Changes in commodity prices also indirectly impact our profitability by influencing drilling activity and well operations, and thus the volume of gas, crude oil, and condensate we gather and process fractionateand NGLs we fractionate. Volatility in commodity prices may cause our adjusted gross margin and cash flows to vary widely from period to period. Our hedging strategies may not be sufficient to offset price volatility risk and, in any event, do not cover all of our throughput volumes. Moreover, hedges are subject to inherent risks, which we describe in “Item 7A. Quantitative and Qualitative Disclosure about Market Risk.” Our use of derivative financial instruments does not eliminate our exposure to fluctuations in commodity prices and interest rates and has (in the past) resulted and could (in the future) result in financial losses or transport wouldreductions in our income.

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A reduction in demand for NGL products by the petrochemical, refining, or other industries or by the fuel markets could materially adversely affect our financial condition, results of operations, or cash flows.


The NGL products we produce have a variety of applications, including as heating fuels, petrochemical feedstocks, and refining blend stocks. A reduction in demand for NGL products, whether because of general or industry specific economic conditions, new government regulations, global competition, reduced demand by consumers for products made with NGL products (for example, reduced petrochemical demand observed due to lower activity in the automobile and construction industries), increased competition from petroleum-based feedstocks due to pricing differences, mild winter weather for some NGL applications, or other reasons could result in a decline in the volume of NGL products we handle or reduce the fees we charge for our services. Our NGL products and the demand for these products are affected as follows:

•Ethane. Ethane is typically supplied as purity ethane or as part of ethane-propane mix. Ethane is primarily used in the petrochemical industry as feedstock for ethylene, one of the basic building blocks for a wide range of plastics and other chemical products. Although ethane is typically extracted as part of the mixed NGL stream at gas processing plants, if natural gas prices increase significantly in relation to NGL product prices or if the demand for ethylene falls, it may be more profitable for natural gas processors to leave the ethane in the natural gas stream. Such “ethane rejection” reduces the volume of NGLs delivered for fractionation and marketing.

•Propane. Propane is used as a petrochemical feedstock in the production of ethylene and propylene, as a heating, engine, and industrial fuel, and in agricultural applications such as crop drying. Changes in demand for ethylene and propylene could adversely affect demand for propane. The demand for propane as a heating fuel is significantly affected by weather conditions. The volume of propane sold is at its highest during the six-month peak heating season of October through March. Demand for our propane may be reduced during periods of warmer-than-normal weather.

•Normal Butane. Normal butane is used in the production of isobutane, as a refined product blending component, as a fuel gas, and in the production of ethylene and propylene. Changes in the composition of refined products resulting from governmental regulation, changes in feedstocks, products, and economics, demand for heating fuel and for ethylene and propylene could adversely affect demand for normal butane.

•Isobutane. Isobutane is predominantly used in refineries to produce alkylates to enhance octane levels. Accordingly, any action that reduces demand for motor gasoline or demand for isobutane to produce alkylates for octane enhancement might reduce demand for isobutane.

•Natural Gasoline. Natural gasoline is used as a blending component for certain refined products and as a feedstock used in the production of ethylene and propylene. Changes in the mandated composition resulting from governmental regulation of motor gasoline and in demand for ethylene and propylene could adversely affect demand for natural gasoline.

NGLs and products produced from NGLs are sold in competitive global markets. Any reduced demand for ethane, propane, normal butane, isobutane, or natural gasoline in the markets we access for any of the reasons stated above could adversely affect demand for the services we provide as well as NGL prices, which would negatively impact our financial performance dependscondition, results of operations, or cash flows.

Increasing scrutiny and changing expectations from stakeholders with respect to our environmental, social and governance practices may impose additional costs on us or expose us to new or additional risks.

Companies across all industries are facing increasing scrutiny from stakeholders related to their environmental, social, and governance (“ESG”) practices. Investor advocacy groups, certain institutional investors, investment funds, and other influential investors are also increasingly focused on ESG practices and in recent years have placed increasing importance on the implications and social cost of their investments. Regardless of the industry, investors’ increased focus and activism related to ESG and similar matters may hinder access to capital, as investors may decide to reallocate capital or to not commit capital as a result of their assessment of a company’s ESG practices. Companies that do not adapt to or comply with investor or stakeholder expectations and standards, which are evolving, or which are perceived to have not responded appropriately to the growing concern for ESG issues, regardless of whether there is a legal requirement to do so, may suffer from reputational damage and the business, financial condition, and/or stock price of such a company could be materially and adversely affected.

We could also face pressures from stakeholders, who are increasingly focused on climate change, to prioritize sustainable energy practices, reduce our carbon footprint and promote sustainability. These stakeholders could require us to implement ESG procedures or standards in order to remain invested in us or before they could make further investments in us.
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Additionally, we could face reputational challenges in the event our ESG procedures or standards do not meet the standards set by certain constituencies. We have adopted certain practices as highlighted in our annual sustainability report, including a focus on environmental stewardship by operating our assets and constructing new facilities in order to minimize our footprint and environmental impact, control pollution, and conserve resources. It is possible, however, that our stakeholders might not be satisfied with our sustainability efforts or the speed of their adoption. If we do not meet stakeholder expectations, our business, ability to access capital, and/or our common unit price could be harmed.

Additionally, adverse effects upon the oil and gas industry related to the worldwide social and political environment, including uncertainty or instability resulting from climate change, changes in political leadership and environmental policies, changes in geopolitical-social views toward fossil fuels and renewable energy, concern about the environmental impact of climate change and investors’ expectations regarding ESG matters, may also adversely affect demand for our services. Any long-term material adverse effect on the oil and gas industry could have a significant financial and operational adverse impact on our business.

Our business is subject to a large extentnumber of weather-related risks. These weather conditions can cause significant damage and disruption to our operations and adversely impact our financial condition, results of operations, or cash flows.

Virtually all of our operations are exposed to potential natural disasters, including hurricanes, tornadoes, storms, floods, ice storms, blizzards, extreme cold weather, fires, severe temperatures, and earthquakes, and also disruptions caused by these natural events, such as electrical blackouts. In particular, South Louisiana and the Texas Gulf Coast experience hurricanes and other extreme weather conditions on a frequent basis. The location of significant assets and concentration of activity in these regions make us particularly vulnerable to weather risks in these areas.

During the third quarter of 2021, we experienced a temporary loss of some processing volumes in our Louisiana operations due to the effects of Hurricane Ida, which forced a temporary shut-down of some of our operations and those of our downstream customers. All of our operations and those of our customers are now operating normally. In 2020, our Louisiana assets were also affected by hurricanes. The location of significant assets and concentration of activity in these active hurricane regions make us particularly vulnerable to weather events in these areas.

In addition, our assets are vulnerable to winter storms and extreme cold weather. For example, 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”). 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.

High winds, storm surge, flooding, ice storms, extreme cold weather, and other natural disasters can cause significant damage and curtail our operations for extended periods during and after such weather conditions and could cause significant disruptions in electrical power, all of which may result in decreased revenues and otherwise adversely impact our financial condition, results of operations, or cash flow. These interruptions could involve significant damage to people, property, or the environment, and repair time and costs could be extensive. Any such event that interrupts the revenues generated by our operations, or which causes us to make significant expenditures not covered by insurance, could reduce our cash available for paying distributions to our unitholders and, accordingly, adversely affect our financial condition and the market price of our securities. Moreover, as a larger portion of our operations become dependent on a steady supply of electric power to operate, in part as a result of a shift to electrical power in order to minimize CO2 emissions, we would be more vulnerable to events such as extreme weather that cause blackouts, which could disrupt our operations and persist for a significant period of time.

In addition, we rely on the volumes of natural gas, crude oil, condensate, and NGLs gathered, processed, fractionated, and transported on our assets. Decreases in the volumes of natural gas, crude oil, condensate and NGLs we gather, process, fractionate or transport would directly and adversely affect our financial condition. These volumes can beare influenced by factors beyond our control, including:

environmental or other governmental regulations;
weather conditions;
increases in storage levels of natural gas, NGLs, crude oil and condensate;
increased use of alternative energy sources;
decreased demand for natural gas, NGLs, crude oil and condensate;
continued fluctuations in commodity prices, including the prices of natural gas, NGLs, crude oil and condensate;
economic conditions;
supply disruptions;
availability of supply connected to our systems; and
availability and adequacy of infrastructure to gather and process supply into and out of our systems.

The volumes of natural gas, crude oil, condensate and NGLs gathered, processed, fractionated and transported on our assets also depend on the production from the regions that supply our systems. SupplyAdverse weather conditions and persistent electrical blackouts can cause direct or indirect disruptions to the operations of, natural gas, crude oil, condensate and NGLs canotherwise negatively affect, producers, suppliers, customers, and other third parties to which our assets are connected, even if our assets are not damaged. As a result, our financial condition, results of operations, and cash flows could be affectedadversely affected. Also, disruptions in our operations, which affect our customers and other third parties, have generated, and could in the future generate, commercial and legal disputes with these parties that could cause us to pay damages or make business concessions to these parties, and these damages or business concessions might be costly to the Company and adversely affect our financial condition, results of operation, and cash flows.

Our pipeline operations along the Gulf Coast and offshore could be impacted by many of the factors listed above, including commodity pricessubsidence and weather. In ordercoastal erosion. Such processes could cause serious damage to maintain or increase throughput levels on our systems, we must obtain new sources of natural gas, crude oil, condensate and NGLs. The primary factors affectingpipelines, which could affect our ability to obtain non-dedicated sourcesprovide transportation services.
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Additionally, such processes could impact our customers who operate along the Gulf Coast, and NGLs include (i) the level of successful leasing, permittingthey may be unable to utilize our services. Subsidence and drilling activity incoastal erosion could also expose our areas of operation, (ii) our abilityoperations to compete for volumes from new wells and (iii) our ability to compete successfully for volumes from sources connected to other pipelines. We have no control over the level of drilling activity in our areas of operation, the amount of reservesincreased risks associated with wells connectedsevere weather conditions, such as hurricanes, flooding, and rising sea levels. As a result, we may incur significant costs to repair and preserve our systems or the rate at which production from a well declines. In addition, we have no control over producers or their drilling or production decisions, which are affected by, among other things, the availability and cost of capital, levels of reserves, availability of drilling rigs and otherpipeline infrastructure. Such costs of production and equipment.

An impairment of goodwill, long-lived assets, including intangible assets and equity method investments, could reduce our earnings.

GAAP requires us to test goodwill and intangible assets with indefinite useful lives for impairment on an annual basis or when events or circumstances occur indicating that goodwill might be impaired. Long-lived assets, including intangible assets with finite useful lives, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. For the investments we account for under the equity method, the impairment test considers whether the fair value of the unconsolidated affiliate investment as a whole, not the underlying net assets, has declined and whether that decline is other than temporary. If we determine that an impairment is indicated, we would be required to take an immediate non-cash charge to earnings with a correlative effect on equity and balance sheet leverage as measured by debt to total capitalization. For the year ended December 31, 2015, we recognized impairments on property and equipment of $12.1 million, an intangible asset impairment of $223.1 million and a goodwill impairment of $1,328.2 million. In the first quarter of 2016, we recognized an additional goodwill impairment of $873.3 million, which consisted of $566.3 million at ENLK and $307.0 million at ENLC. For the year ended December 31, 2017, we recognized impairments on property and equipment of $17.1 million. Additional impairment of the value of our existing goodwill and intangible assets could have a significant negative impact on our future operating results.
Our construction of new assets may be more expensive than anticipated, may not result in revenue increases and may be subject to regulatory, environmental, political, legal and economic risks that could adversely affect our financial condition, results of operations, or cash flows.


We are dependent on certain large customers fora substantial portion of the natural gas that we gather, process, and transport. The constructionloss of additions or modifications to our existing systems and the constructionany of new midstream assets involves numerous regulatory, environmental, political and legal uncertainties beyond our control including potential protests or legal actions by interested third parties, and may require the expenditure of significant amounts of capital. Financing may not be available on economically acceptable terms or at all. If we undertake these projects, we may not be able to complete them on schedule, at the budgeted cost or at all. Moreover, our revenues may not increase due to the successful construction of a particular project. For instance, if we expand a pipeline or construct a new pipeline, the construction may occur over an extended period of time, and we may not receive any material increases in revenues promptly following completion of a project or at all. Moreover, we may construct facilities to capture anticipated future production growth in a region in which such growth does not materialize. As a result, new facilities may not be able to attract enough throughput to achieve our expected investment return, which couldcustomers would adversely affect our financial condition, results of operations, or cash flows. In addition,

We are dependent on certain large customers for a substantial portion of our natural gas supply. For the constructionyear ended December 31, 2021, Dow Hydrocarbons and Resources LLC, Marathon Petroleum Corporation, and Devon represented 14.5%, 13.4%, and 6.7%, respectively, of additionsour consolidated revenues and each also represented a similar percentage of our adjusted gross margin. We expect to derive a significant portion of our revenues from these customers for the foreseeable future. As a result, any development, whether in our area of operations or otherwise, that adversely affects their production, financial condition, leverage, market reputation, liquidity, results of operations, or cash flows may adversely affect our revenues and cash available for distribution.

Further, we are subject to the risk of non-payment or non-performance by these customers. We cannot predict the extent to which these customers’ business will be impacted by pricing conditions in the energy industry, nor can we estimate the impact such conditions would have on these customers’ ability to perform under our gathering and processing agreements. If we were to lose any of these customers, and we are unable to replace the shortfall revenue from other sources, our operating results and cash flows would be adversely affected.

If we do not make acquisitions on economically acceptable terms or efficiently and effectively integrate the acquired assets with our asset base, our future growth will be limited.

Our ability to grow depends, in part, on our ability to make acquisitions that result in an increase in cash generated from operations on a per unit basis. If we are unable to make accretive acquisitions either because we are (1) unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them, (2) unable to obtain financing for these acquisitions on economically acceptable terms or at all or (3) outbid by competitors, then our future growth and our ability to increase distributions will be limited.

From time to time, we may evaluate and seek to acquire assets or businesses that we believe complement our existing business and related assets. We may acquire assets or businesses that we plan to use in a manner materially different from their prior owner’s use. Any acquisition involves potential risks, including:

•the inability to integrate the operations of recently acquired businesses or assets, especially if the assets acquired are in a new business segment or geographic area;
•the diversion of management’s attention from other business concerns;
•the failure to realize expected volumes, revenues, profitability, or growth;
•the failure to realize any expected synergies and cost savings;
•the coordination of geographically disparate organizations, systems, and facilities;
•the assumption of unknown liabilities;
•the loss of customers or key employees from the acquired businesses;
•a significant increase in our indebtedness; and
•potential environmental or regulatory liabilities and title problems.

Management’s assessment of these risks is inexact and may not reveal or resolve all existing or potential problems associated with an acquisition. Realization of any of these risks could adversely affect our operations and cash flows. If we consummate any future acquisition, our capitalization and results of operations may change significantly, and you will not have the opportunity to evaluate the economic, financial, and other relevant information that we will consider in determining the application of these funds and other resources.

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We intend to enter into new businesses in connection with our strategy to participate in the energy transition. If we are unable to execute on this strategy or operate these new lines of business effectively, our future growth could be limited. These new lines of business may never develop or may present risks that we cannot effectively manage.

As part of our strategy, we intend to build a CCS business, and we may enter into other new lines of business as part of adapting to the energy transition. These are new businesses that have no track record and which, while similar to our existing gatheringbusinesses, may present different challenges and processing assets will generally require us to obtain new rights-of-way and permits prior to constructing new pipelines or facilities.risks. We may be unable to timely obtainexecute on our business plans, demand for these new services may not develop on a large or economic scale, or we may fail to operate these businesses effectively. In addition, we may not be able to compete with companies who also plan to enter into these new lines of business, and who may be larger than us and may have greater financial resources to devote to these businesses. These new businesses may also present novel issues in law, taxation, safety or environmental policy, and other areas that we may not be able to manage effectively. Management’s assessment of the risks in these new lines of business may be inexact and not identify or resolve all the problems that we would face. If we were not able to enter into these new lines of business effectively or at all, it could limit our future growth as lines of business connected to the energy transition grow and become a more important part of the energy business.

We do not own all of the land on which our pipelines, compression, and plant facilities are located, which could disrupt our operations.

We do not own all of the land on which our pipelines, compression, and plant facilities are located, and we are therefore subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid rights-of-way or leases or if such rights-of-way or permitsleases lapse or terminate. We sometimes obtain the rights to connect new product suppliesland owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew right-of-way contracts, leases, or otherwise, could cause us to cease operations on the affected land, increase costs related to continuing operations elsewhere, and reduce our revenue.

Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. The occurrence of a significant accident or other event that is not fully insured could adversely affect our operations and financial condition.

Our operations are subject to the many hazards inherent in the gathering, compressing, processing, transporting, fractionating, disposing, and storage of natural gas, NGLs, condensate, crude oil, and brine, including:

•damage to pipelines, facilities, storage caverns, equipment, and surrounding properties caused by hurricanes, floods, sink holes, fires, and other natural disasters and acts of terrorism;
•inadvertent damage to our existing gathering linesassets from construction or capitalize onfarm equipment;
•leaks of natural gas, NGLs, crude oil, condensate, and other attractive expansion opportunities. Additionally, ithydrocarbons;
•induced seismicity;
•rail accidents, barge accidents, and truck accidents;
•equipment failure; and
•fires and explosions.

These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment, and pollution or other environmental damage and may become more expensive for us to obtain new rights-of-wayresult in curtailment or to expand or renew existing rights-of-way. If the cost of renewing or obtaining new rights-of-way increases, our cash flows could be adversely affected.

Constructionsuspension of our major development projectsrelated operations. We are not fully insured against all risks incident to our business. In accordance with typical industry practice, we have appropriate levels of business interruption and property insurance on our underground pipeline systems. We are not insured against all environmental accidents that might occur. If a significant accident or event occurs that is not fully insured, it could adversely affect our operations and financial condition.

We conduct a portion of our operations through joint ventures, which subjects us to additional risks that could have a material adverse effect on the success of construction delays, cost over-runs, limitations on our growth and negative effects onthese operations, our financial condition,position, results of operations, or cash flows.


We are engagedparticipate in several joint ventures, and we may enter into other joint venture arrangements in the planning and constructionfuture. The nature of several major development projects, some of which will take a number of months before commercial operation. These projects are complex and subjectjoint venture requires us to a number of factors beyondshare control with unaffiliated third parties. If our control, including delays from vendors, suppliers and third-party landowners, the permitting process, changes in laws, unavailability of materials, labor disruptions, environmental hazards, financing, accidents, weatherjoint venture partners do not fulfill their contractual and other factors. Any delayobligations, the affected joint venture may be unable to operate according to its business plan, and we may be required to increase our level of commitment. If we do not timely meet our financial commitments or otherwise comply with our joint venture agreements, our ownership of and rights with respect to the applicable joint venture may be reduced or otherwise adversely affected. In addition, certain of our joint venture arrangements provide our joint venture partners with the right, under certain circumstances, to cause us to purchase their interest in the completionjoint venture or to seek to sell the entire joint venture. Differences in views among joint venture participants could also result in delays in business decisions or otherwise,
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failures to agree on major issues, operational inefficiencies and impasses, litigation, or other issues. Third parties may also seek to hold us liable for the joint ventures’ liabilities. These issues or any other difficulties that cause a joint venture to deviate from its original business plan could have a material adverse effect on our financial condition, results of operations, or cash flows.


The constructionIf third-party pipelines or other midstream facilities interconnected to our gathering or transportation systems become partially or fully unavailable, or if the volumes we gather, process, or transport do not meet the quality requirements of the pipelines or facilities to which we connect, our adjusted gross margin and gathering and processing and fractionation facilities requires the expenditure of significant amounts of capital, which may exceed our estimated costs. Estimating the timing and expenditures related to these development projects is very complex and subject to variables that can significantly increase expected costs. Should the actual costs of these projects exceed our estimates, our liquidity and capital positioncash flow could be adversely affected. This level

Our gathering, processing, and transportation assets connect to other pipelines or facilities owned and operated by unaffiliated third parties. The continuing operation of, developmentand our continuing access to, such third-party pipelines, processing facilities, and other midstream facilities is not within our control. These pipelines, plants, and other midstream facilities may become unavailable because of testing, turnarounds, line repair, maintenance, reduced operating pressure, lack of operating capacity, regulatory requirements, and curtailments of receipt or deliveries due to insufficient capacity or because of damage from severe weather conditions or other operational issues. Further, these pipelines and facilities connected to our assets impose product quality specifications. We may be unable to access such facilities or transport product along interconnected pipelines if the volumes we gather or transport do not meet their product quality requirements. In addition, if our costs to access and transport on these third-party pipelines significantly increase, our profitability could be reduced. If any such increase in costs occurs, if any of these pipelines or other midstream facilities become unable to receive, transport, or process product, or if the volumes we gather or transport do not meet the product quality requirements of such pipelines or facilities, it will adversely affect our financial condition, results of operations, or cash flows.

Our success depends on key members of our management, the loss or replacement of whom could disrupt our business operations.

We depend on the continued employment and performance of the officers of the Operating Partnership and key operational personnel. If any of these officers or other key personnel resign or become unable to continue in their present roles and are not adequately replaced, our business operations could be materially adversely affected. We do not maintain any “key man” life insurance for any officers.

Failure to attract and retain an appropriately qualified workforce could reduce labor productivity and increase labor costs, which could have a material adverse effect on our business and results of operations.

Gathering and compression services require laborers skilled in multiple disciplines, such as equipment operators, mechanics, and engineers, among others. Our business is dependent on our ability to recruit, retain, and motivate employees. Certain circumstances, such as an aging workforce without appropriate replacements, a mismatch of existing skill sets to future needs, competition for skilled labor, or the unavailability of contract resources, may lead to operating challenges such as a lack of resources, loss of knowledge, or a lengthy time period associated with skill development. Our costs, including costs for contractors to replace employees, productivity costs, and safety costs, may rise. In addition, it has been widely reported in the press and elsewhere that businesses have faced a more challenging hiring environment since the onset of the pandemic and have had to pay higher wages to attract skilled labor. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to the new employees, or the future availability and cost of contract labor may adversely affect our ability to manage and operate our business. If we are unable to successfully attract and retain an appropriately qualified workforce, our results of operations could be negatively affected.

Our use of derivative financial instruments does not eliminate our exposure to fluctuations in commodity prices and interest rates and has in the past and could in the future result in financial losses or reduce our income.

Our operations expose us to fluctuations in commodity prices, and the Consolidated Credit Facility and the AR Facility expose us to fluctuations in interest rates. We use over-the-counter price and basis swaps with other natural gas merchants and financial institutions. Use of these instruments is intended to reduce our exposure to volatility in commodity prices. As of December 31, 2021, we have hedged only portions of our expected exposures to commodity price risk. In addition, to the extent we hedge our commodity price risk using swap instruments, we will forego the benefits of favorable changes in commodity prices.

Even though monitored by management, our hedging activities may fail to protect us and could reduce our earnings and cash flow. Our hedging activity requires significant effortmay be ineffective or adversely affect cash flow and earnings because, among other factors, variations in the index we use to price a commodity hedge may not adequately correlate with variations in the index we use to sell the physical commodity (known as basis risk), and we may not produce or process sufficient volumes to cover swap arrangements we enter into for a given period. In addition, our counterparty in any hedging transaction could default on its obligation to pay or otherwise fail to perform. If our actual volumes are lower than the volumes we estimated when entering
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into a swap for the period, we might be forced to satisfy all or a portion of our derivative obligation without the benefit of cash flow from our managementsale or purchase of the underlying physical commodity, which could adversely affect our liquidity.

A failure in our computer systems or a terrorist or cyberattack on us, or third parties with whom we have a relationship, may adversely affect our ability to operate our business.

We are reliant on technology to conduct our business. Our business is dependent upon our operational and technical personnelfinancial computer systems and places additional requirementsthose of our third-party providers with whom we are connected to process the data necessary to conduct almost all aspects of our business, including operating our pipelines, plants, truck fleet, and other facilities, recording and reporting commercial and financial transactions, and receiving and making payments. Dependence on automated systems may increase the risks related to operational systems failures and breaches of critical operational or financial controls, and tampering or deliberate manipulation of such systems may result in losses that are difficult to detect. In addition, any failure of our or our third-party providers’ computer systems, or those of our customers, suppliers, or others with whom we do business, could materially disrupt our ability to operate our business. Some individuals and groups, including criminal organizations and state-sponsored groups, have attempted to gain unauthorized access to computer networks of U.S. businesses and mounted cyberattacks to disable or disrupt computer systems, disrupt operations, and steal funds or data including through phishing schemes, which are attempts to obtain unauthorized access by targeted acts of deception against individuals with legitimate access to physical locations or information. For example, in 2021, a company in the midstream industry suffered a ransomware cyberattack that impacted computerized equipment managing a pipeline and resulted in the halt of the pipeline’s operations in order to contain the attack.

Cyberattacks could also result in the loss of confidential or proprietary data or security breaches of other information technology and pipeline systems that could damage our reputation and disrupt our operations and critical business functions. Due to COVID-19 protocols, many of our employees and those of our service providers, vendors and customers have been accessing computer systems remotely where their cybersecurity protections may be less robust and our cybersecurity procedures and safeguards may be less effective. Our assets may also be targets of vandalism, theft, destructive forms of protests and opposition by extremists, including acts of sabotage and terrorism, that could disrupt our ability to conduct our business and may have a material adverse effect on our business and results of operations. Furthermore the U.S. government has continued to issue public warnings that the nation’s strategic infrastructure, such as energy-related assets, may be at greater risk of future terrorist or cyberattacks than other targets in the United States. Any such terrorist or cyberattack that affects us or our customers, suppliers, or others with whom we do business, or that severely disrupts the markets we serve, could have a material adverse effect on our business, cause us to incur a material financial resources. Weloss, subject us to possible legal claims and liability, and/or damage our reputation. Our insurance may not protect us against losses relating to such occurrences.

Moreover, as cyberattacks continue to evolve, we may be required to expend significant additional resources to further enhance our digital security or to remediate vulnerabilities. In addition, cyberattacks against us or others in our industry could result in additional regulations, which could lead to increased regulatory compliance costs, insurance coverage cost, or capital expenditures and any failure by us to comply with these additional regulations could result in significant penalties and liability to us. We cannot predict the potential impact to our business or the energy industry resulting from additional regulations.

Environmental, Legal Compliance, and Regulatory Risks

Increased federal, state, and local legislation, and regulatory initiatives, as well as government reviews, relating to hydraulic fracturing could result in increased costs and reductions or delays in natural gas production by our customers, which could adversely impact our revenues and results of operations.

A portion of our suppliers’ and customers’ natural gas production is developed from unconventional sources, such as deep gas shales, that require hydraulic fracturing as part of the completion process. State legislatures and agencies have enacted legislation and promulgated rules to regulate hydraulic fracturing, require disclosure of hydraulic fracturing chemicals, temporarily or permanently ban hydraulic fracturing and impose additional permit requirements and operational restrictions in certain jurisdictions or in environmentally sensitive areas. EPA and the BLM have also issued rules, conducted studies, and made proposals that, if implemented, could either restrict the practice of hydraulic fracturing or subject the process to further regulation. For instance, the EPA has issued final regulations under the federal Clean Air Act establishing performance standards, including standards for the capture of air emissions released during hydraulic fracturing, and adopted rules prohibiting the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. The EPA announced its intention to reconsider the regulations relating to the capture of air emissions in April 2017 and sought to stay its requirements, however, EPA’s stay of these requirements was vacated by the D.C. Circuit in July 2017. In September 2020, the EPA published two additional final rules, the 2020 Policy Rule and the 2020 Technical Amendments. The 2020 Policy Rule removed sources in the transmission and storage segments from the regulated source category and rescinding the
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application of the NSPS and methane-specific requirements to these sources. On January 21, 2021, President Biden issued an Executive Order on “Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis” directing the EPA to consider publishing for notice and comment, by September 2021, a proposed rule suspending, revising, or rescinding the September 2020 NSPS for the oil and natural gas sector, and on June 30, 2021, President Biden signed a joint congressional resolution rescinding the 2020 Policy rule. In November 2021, the EPA proposed a new rule targeting methane and VOC emissions from new and existing oil and gas sources, including sources in the production, processing, transmission, and storage segments. The proposed rule would: (1) update NSPS subpart OOOOa; (2) adopt a new NSPS subpart OOOOb for sources that commence construction, modification, or reconstruction after the date the proposed rule is published in the Federal Register; and (3) adopt a new NSPS subpart OOOOc to establish emissions guidelines, which will inform state plans to establish standards for existing sources. The BLM also adopted new rules, effective on January 17, 2017, to reduce venting, flaring and leaks during oil and natural gas production activities on onshore federal and Indian leases. In September 2018, BLM published a final rule that repealed several of the requirements of the 2016 methane rule. The September 2018 rule was challenged in the U.S. District Court for the Northern District of California almost immediately after issuance. In July 2020, the U.S. District Court for the Northern District of California vacated BLM’s 2018 revision rule. Additionally, in October 2020, a Wyoming federal district judge vacated the 2016 venting and flaring rule. Environmental groups have appealed the October 2020 decision, and litigation is ongoing.

In addition, President Biden has declared that he would support federal government efforts to limit or prohibit hydraulic fracturing. These declarations include threats to take actions banning hydraulic fracturing of crude oil and natural gas wells and banning new leases for production of minerals on federal properties, including onshore lands and offshore waters. On January 20, 2021, the Acting Secretary for the Department of the Interior signed an order suspending new fossil fuel leasing and permitting on federal lands for 60 days, which may cover our offshore pipeline permits. Several states filed lawsuits challenging the suspension and on June 15, 2021, 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. If our customers are unable to secure permits, sustained reductions in exploration or production activity in our areas of operation could lead to reduced utilization of our pipeline and terminal systems or reduced rates under renegotiated transportation or storage agreements. We are still evaluating the effects of the recent order on our operations and our customers’ operations, but our inability and our customers’ inability to secure required permits could adversely affect our business, financial condition, results of operations, or cash flows, including our ability to attractmake cash distributions to our unitholders. The Biden administration could also pursue the imposition of more restrictive requirements for the establishment of pipeline infrastructure or the permitting of LNG export facilities.

State and federal regulatory agencies also have recently focused on a possible connection between the operation of injection wells used for oil and gas waste waters and an observed increase in induced seismicity, which has resulted in some regulation at the state level. For instance, in December 2016 the Oklahoma Corporation Commission released well completion seismicity guidelines for operators in the STACK play that call for hydraulic fracturing operations to be suspended following earthquakes of certain magnitudes in the vicinity. As regulatory agencies continue to study induced seismicity, additional legislative and regulatory initiatives could affect our brine disposal operations and our customers’ injection well operations, which could impact our gathering business.

We cannot predict whether any additional legislation or regulations will be enacted regarding hydraulic fracturing and, if so, what the provisions would be. If additional levels of regulation and permits or a ban on new leases on federal lands were to be implemented through the adoption of new laws and regulations at the federal or state level, that could lead to delays, increased operating costs, process prohibitions and fewer drilling opportunities for our suppliers and customers that could reduce the volumes of natural gas or crude oil that move through our gathering systems, which could materially adversely affect our revenue and results of operations.

Climate change legislation and regulatory initiatives could result in increased operating costs and reduced demand for the natural gas and NGL services we provide.

The United States Congress has from time to time considered adopting legislation to reduce emissions of GHGs, and there has been a wide-ranging policy debate, both nationally and internationally, regarding the impact of these gases and possible means for their regulation. In addition, efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues. In 2015, the United States participated in the United Nations Conference on Climate Change, which led to the adoption of the Paris Agreement. The Paris Agreement became effective November 4, 2016 and requires countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals, every five years beginning in 2020. In November 2019, the State Department formally informed the United Nations of the United States’ withdrawal from the Paris
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Agreement and withdrew from the agreement in November 2020. However, on January 20, 2021, President Biden signed an instrument that reverses this withdrawal, and the United States formally re-joined the Paris Agreement on February 19, 2021. At the federal regulatory level, both the EPA and the BLM have adopted regulations for the control of methane emissions, which also include leak detection and repair requirements, from the oil and gas industry. Additionally, President Biden has issued an executive order 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.

Governmental, scientific and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political risks in the U.S.. President Biden declared that he would support federal government efforts to limit or prohibit hydraulic fracturing and ban new leases for production of minerals on federal properties, including onshore lands and offshore waters. In addition, as discussed under “Item 1. Business—Regulation,” on January 20, 2021, the Acting Secretary for the Department of the Interior signed an order suspending new fossil fuel leasing and permitting on federal lands, including offshore pipeline leases, for 60 days. Then 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 a comprehensive review and reconsideration of federal oil and gas permitting and leasing practices. Several states filed lawsuits challenging the suspension and on June 15, 2021, a federal judge issued a nationwide temporary injunction blocking the suspension. The Department of the Interior appealed the judge’s ruling but resumed oil and gas leasing pending resolution of the appeal. The Biden administration could also pursue the imposition of more restrictive requirements for the establishment of pipeline infrastructure or the permitting of LNG export facilities.

In addition, many states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or retainregional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and NGL fractionation plants, to acquire and surrender emission allowances with the necessary number of personnelallowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved.

In addition to the regulatory efforts described above, there have also been efforts in recent years aimed at the investment community, including investment advisors, sovereign wealth funds, public pension funds, universities, and other groups, promoting the divestment of fossil fuel equities as well as pressuring lenders and other financial services companies and their regulators, such as the Federal Reserve, to limit or curtail activities with fossil fuel companies. These efforts could have a material adverse effect on the skillsprice of our securities and our ability to access equity capital markets. Members of the investment community have begun to screen companies such as ours for sustainability performance, including practices related to GHGs and climate change, before investing in our securities. In addition, discussions of GHG emissions and their possible impacts have become more widespread generally in society and public sentiment regarding these topics may become more challenging for fossil fuel companies. As a result, we could experience additional costs or financial penalties, delayed or cancelled projects, and/or reduced production and reduced demand for hydrocarbons, which could have a material adverse effect on our earnings, cash flows, and financial condition. Furthermore, recent judicial decisions have allowed certain tort claims brought by government and private plaintiffs alleging property damages due to climate change to proceed against GHG emissions sources, which may increase our litigation risk for such claims.Increasing scrutiny and changing expectations from stakeholders with respect to our environmental, social and governance practices may impose additional costs on us or expose us to new or additional risks.

Although it is not possible at this time to predict whether future legislation or new regulations may be adopted to address GHG emissions or how such measures would impact our business, the adoption of legislation or regulations imposing reporting or permitting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur additional costs to reduce emissions of GHGs associated with our operations, could adversely affect our performance of operations in the absence of any permits that may be required to bring complicated projectsregulate emission of GHGs, or could adversely affect demand for the natural gas or crude oil we gather, process, or otherwise handle in connection with our services. Moreover, many scientists have concluded that increasing concentrations of GHGs may produce climate changes associated with an increase in severity and frequency of extreme weather conditions which may affect our operations. See “—Our business is subject to successful conclusions.a number of weather-related risks. These weather conditions can cause significant damage and disruption to our operations and adversely impact our financial condition, results of operations, or cash flows” for more information regarding risks from extreme weather conditions.


Our operations are dependent on our rights and ability to receive or renew the required permits and other approvals from governmental authorities and other third parties.

Performance of our operations requires that we obtain and maintain numerous environmental and land use permits and other approvals authorizing our business activities. A decision by a governmental authority or other third party to deny, delay,
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or restrictively condition the issuance of a new or renewed permit or other approval, or to revoke or substantially modify an existing permit or other approval, could have a material adverse effect on our ability to initiate or continue operations at the affected location or facility. Expansion of our existing operations is also predicated on securing the necessary environmental or land use permits and other approvals, which we may not receive in a timely manner or at all.

In order to obtain permits and renewals of permits and other approvals in the future, we may be required to prepare and present data to governmental authorities pertaining to the potential adverse impact that any proposed activities may have on the environment, individually or in the aggregate, including on public and Indian lands. Certain approval procedures may require preparation of archaeological surveys, endangered species studies, and other studies to assess the environmental impact of new sites or the expansion of existing sites. Compliance with these regulatory requirements is expensive and significantly lengthens the time needed to develop a site or pipeline alignment. Also, obtaining or renewing required permits or other approvals is sometimes delayed or prevented due to community opposition and other factors beyond our control. The denial of a permit or other approvals essential to our operations or the imposition of restrictive conditions with which it is not practicable or feasible to comply could impact our operations or prevent our ability to expand our operations or obtain rights-of-way. Significant opposition to a permit or other approvals by neighboring property owners, members of the public, or non-governmental organizations, or other third parties or delays in the environmental review and permitting process also could impact our operations or prevent our ability to expand our operations or obtain rights-of-way.


We conduct a portion of our operations through joint ventures, which subjects us to additional risks that could have a material adverse effect on the success of these operations, our financial position, results of operations or cash flows.

We participate in several joint ventures, and we may enter into other joint venture arrangements in the future. The nature of a joint venture requires us to share control with unaffiliated third parties. If our joint venture partners do not fulfill their contractual and other obligations, the affected joint venture may be unable to operate according to its business plan, and we may be required to increase our level of commitment. If we do not timely meet our financial commitments or otherwise comply with our joint venture agreements, our ownership of and rights with respect to the applicable joint venture may be reduced or otherwise adversely affected. Differences in views among joint venture participants could also result in delays in business decisions or otherwise, failures to agree on major issues, operational inefficiencies and impasses, litigation or other issues. Third parties may also seek to hold us liable for the joint ventures’ liabilities. These issues or any other difficulties that cause a joint venture to deviate from its original business plan could have a material adverse effect on our financial condition, results of operations or cash flows.

Any reductions in ENLK’s credit ratings could increase our financing costs, the cost of maintaining certain contractual relationships and reduce ENLK’s and, consequently, ENLC’s cash available for distribution.

We cannot guarantee that our credit ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. S&P and Moody’s have currently assigned to ENLK a BBB- and Ba1 credit rating, respectively. Any future downgrade could increase the cost of borrowings under the ENLK Credit Facility. Any downgrade could also lead to higher borrowing costs for future borrowings and, if below investment grade, could require:

additional or more restrictive covenants that impose operating and financial restrictions on ENLK and its subsidiaries;
ENLK’s subsidiaries to guarantee such debt and certain other debt;
ENLK and its subsidiaries to provide collateral to secure such debt; and

ENLK and its subsidiaries to post cash collateral or letters of credit under our hedging arrangements or in order to purchase commodities or obtain trade credit.

Any increase in our financing costs or additional or more restrictive covenants resulting from a credit rating downgrade could adversely affect our ability to finance future operations and make cash distributions to unitholders. If a credit rating downgrade and the resultant collateral requirement were to occur at a time when we were experiencing significant working capital requirements or otherwise lacked liquidity, our results of operations and our ability to make cash distributions to unitholders could be adversely affected.

We typically do not obtain independent evaluations of hydrocarbon reserves; therefore, volumes we service in the future could be less than we anticipate.

We typically do not obtain, on a regular basis, independent evaluations of hydrocarbon reserves connected to our gathering systems or that we otherwise service due to the unwillingness of producers to provide reserve information as well as the cost of such evaluations. Accordingly, we do not have independent estimates of total reserves serviced by our assets or the anticipated life of such reserves. If the total reserves or estimated life of the reserves is less than we anticipate and we are unable to secure additional sources, then the volumes transported on our gathering systems or that we otherwise service in the future could be less than anticipated. A decline in the volumes could have a material adverse effect on our financial condition, results of operations or cash flows.

We may not be successful in balancing our purchases and sales.

We are a party to certain long-term gas, NGL and condensate sales commitments that we satisfy through supplies purchased under long-term gas, NGL and condensate 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 purchasing additional gas at prices that may exceed the prices received under the sales commitments. In addition, a producer could fail to deliver contracted volumes or deliver in excess of contracted volumes, or a consumer could purchase more or less than contracted volumes. Any of these actions could cause our purchases and sales not to be balanced. If our purchases and sales are not balanced, we will face increased exposure to commodity price risks and could have increased volatility in our operating income.

We have made commitments to purchase natural gas in production areas based on production-area indices and to sell the natural gas into market areas based on market-area indices, pay the costs to transport the natural gas between the two points and capture the difference between the indices as margin. Changes in the index prices relative to each other (also referred to as basis spread) can significantly affect our margins or even result in losses. For example, we are a party to one contract associated with our North Texas operations with a term to July 2019 to supply approximately 150,000 MMBtu/d of gas. We buy gas for this contract on several different production-area indices and sell the gas into a different market area index. We realize a loss on the delivery of gas under this contract each month based on current prices. As of December 31, 2017, the balance sheet reflected a liability of $26.9 million related to this performance obligation based on forecasted discounted cash obligations in excess of market under this gas delivery contract. Reduced supplies and narrower basis spreads in recent periods have increased the losses on this contract, and greater losses on this contract could occur in future periods if these conditions persist or become worse.

Our profitability is dependent upon prices and market demand for crude oil, condensate, natural gas and NGLs that are beyond our control and have been volatile. A depressed commodity price environment could result in financial losses and reduce our cash available for distribution.

We are subject to significant risks due to fluctuations in commodity prices. We are directly exposed to these risks primarily in the gas processing and NGL fractionation components of our business. For the year ended December 31, 2017, approximately 3.4% of our total gross operating margin was generated under percent of liquids contracts and percent of proceeds contracts, with most of these contracts relating to our processing plants in the Permian Basin. Under percent of liquids contracts, we receive a fee in the form of a percentage of the liquids recovered, and the producer bears all the cost of the natural gas shrink. Accordingly, our revenues under percent of liquids contracts are directly impacted by the market price of NGLs. Gross operating margin under percent of proceeds contracts is impacted only by the value of the natural gas or liquids produced with margins higher during periods of higher natural gas and liquids prices.

We also realize gross operating margins under processing margin contracts. For the year ended December 31, 2017, approximately 1.3% of our total gross operating margin was generated under processing margin contracts. We have a number of

processing margin contracts for activities at our Plaquemine and Pelican processing plants. Under this type of contract, we pay the producer for the full amount of inlet gas to the plant, and we make a margin based on the difference between the value of liquids recovered from the processed natural gas as compared to the value of the natural gas volumes lost (“shrink”) and the cost of fuel used in processing. The shrink and fuel losses are referred to as plant thermal reduction (“PTR”). Our margins from these contracts can be greatly reduced or eliminated during periods of high natural gas prices relative to liquids prices.

We are also indirectly exposed to commodity prices due to the negative impacts of low commodity prices on production and the development of production of crude oil, condensate, natural gas and NGLs connected to or near our assets and on our margins for transportation between certain market centers. Low prices for these products have reduced the demand for our services and volumes on our systems, and continued low prices may reduce such demand even further.

Although the majority of our NGL fractionation business is under fee-based arrangements, a portion of our business is exposed to commodity price risk because we realize a margin due to product upgrades associated with our Louisiana fractionation business. For the year ended December 31, 2017, gross operating margin realized associated with product upgrades represented approximately 1.3% of our gross operating margin.

The prices of crude oil, condensate, natural gas and NGLs were volatile during 2017. Crude oil and weighted average NGL prices increased 15% and 21%, while natural gas prices decreased 11%, from January 1, 2017 to December 31, 2017, respectively. We expect this volatility to continue. For example, crude oil prices (based on the NYMEX futures daily close prices for the prompt month) in 2017 ranged from a high of $60.42 per Bbl in December 2017 to a low of $42.53 per Bbl in June 2017. Weighted average NGL prices in 2017 (based on the Oil Price Information Service (“OPIS”) Napoleonville daily average spot liquids prices) ranged from a high of $0.78 per gallon in February 2017 to a low of $0.41 per gallon in January 2017. Natural gas prices (based on Gas Daily Henry Hub closing prices) during 2017 ranged from a high of $3.42 per MMBtu in May 2017 to a low of $2.56 per MMBtu in February 2017.

The markets and prices for crude oil, condensate, natural gas and NGLs depend upon factors beyond our control that make it difficult to predict future commodity price movements with any certainty. These factors include the supply and demand for crude oil, condensate, natural gas and NGLs, which fluctuate with changes in market and economic conditions and other factors, including:

the impact of weather on the supply and demand for crude oil and natural gas;
the level of domestic crude oil, condensate and natural gas production;
technology, including improved production techniques (particularly with respect to shale development);
the level of domestic industrial and manufacturing activity;
the availability of imported crude oil, natural gas and NGLs;
international demand for crude oil and NGLs;
actions taken by foreign crude oil and gas producing nations;
the continued threat of terrorism and the impact of military action and civil unrest;
the availability of local, intrastate and interstate transportation systems;
the availability of downstream NGL fractionation facilities;
the availability and marketing of competitive fuels;
the impact of energy conservation efforts; and
the extent of governmental regulation and taxation, including the regulation of hydraulic fracturing and “greenhouse gases.”

Changes in commodity prices also indirectly impact our profitability by influencing drilling activity and well operations, and thus the volume of gas, crude oil and condensate we gather and process and NGLs we fractionate. Volatility in commodity prices may cause our gross operating margin and cash flows to vary widely from period to period. Our hedging strategies may not be sufficient to offset price volatility risk and, in any event, do not cover all of our throughput volumes. Moreover, hedges are subject to inherent risks, which we describe in “Item 7A. Quantitative and Qualitative Disclosure about Market Risk.” Our use of derivative financial instruments does not eliminate our exposure to fluctuations in commodity prices and interest rates and has (in the past) resulted and could (in the future) result in financial losses or reductions in our income.


If third-party pipelines or other midstream facilities interconnected to our gathering or transportation systems become partially or fully unavailable, or if the volumes we gather, process or transport do not meet the quality requirements of the pipelines or facilities to which we connect, our gross operating margin and cash flow could be adversely affected.

Our gathering, processing and transportation assets connect to other pipelines or facilities owned and operated by unaffiliated third parties. The continuing operation of, and our continuing access to, such third-party pipelines, processing facilities and other midstream facilities is not within our control. These pipelines, plants and other midstream facilities may become unavailable because of testing, turnarounds, line repair, maintenance, reduced operating pressure, lack of operating capacity, regulatory requirements and curtailments of receipt or deliveries due to insufficient capacity or because of damage from severe weather conditions or other operational issues. Further, these pipelines and facilities connected to our assets impose product quality specifications. We may be unable to access such facilities or transport product along interconnected pipelines if the volumes we gather or transport do not meet their product quality requirements. In addition, if our costs to access and transport on these third-party pipelines significantly increase, our profitability could be reduced. If any such increase in costs occurs, if any of these pipelines or other midstream facilities become unable to receive, transport or process product, or if the volumes we gather or transport do not meet the product quality requirements of such pipelines or facilities, our operating margin and cash flow could be adversely affected.

Our debt levels could limit our flexibility and adversely affect our financial health or limit our flexibility to obtain financing and to pursue other business opportunities.

We continue to have the ability to incur debt, subject to limitations in the ENLC Credit Facility and the ENLK Credit Facility. Our level of indebtedness could have important consequences to us, including the following:

our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;
our funds available for operations, future business opportunities and distributions to unitholders will be reduced by that portion of our cash flows required to make interest payments on our debt;
our debt level will make us more vulnerable to general adverse economic and industry conditions;
our ability to plan for, or react to, changes in our business and the industry in which we operate; and
our risk that we, or ENLK, may default on our debt obligations.

In addition, our ability to make scheduled payments or to refinance our obligations depends on our successful financial and operating performance, which will be affected by prevailing economic, financial and industry conditions, many of which are beyond our control. If our cash flow and capital resources are insufficient to fund our debt service obligations, we may be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets, restructuring or refinancing our debt or seeking additional equity capital. We may not be able to effect any of these actions on satisfactory terms or at all.

The terms of the ENLC Credit Facility and the ENLK Credit Facility and ENLK’s indentures may restrict our current and future operations, particularly our ability to respond to changes in business or to take certain actions.

The agreements governing the ENLC Credit Facility and the ENLK Credit Facility and the indentures governing ENLK’s senior notes contain, and any future indebtedness we incur will likely contain, a number of restrictive covenants that impose significant operating and financial restrictions, including restrictions on our ability to engage in acts that may be in our best long-term interest. One or more of these agreements include covenants that, among other things, restrict our ability to:

incur indebtedness through ENLC;
engage in transactions with our affiliates;
consolidate, merge or sell substantially all of our assets;
incur liens;
enter into sale and lease back transactions; and
change business activities we conduct.

In addition, the ENLK Credit Facility requires us to satisfy and maintain a specified financial ratio. Our ability to meet that financial ratio can be affected by events beyond our control, and we cannot assure you that we will continue to meet that ratio.


Our ability to comply with the covenants and restrictions contained in the ENLC Credit Facility, the ENLK Credit Facility and indentures may be affected by events beyond our control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. A breach of any of these covenants could result in an event of default under the ENLC Credit Facility, the ENLK Credit Facility and indentures. Upon the occurrence of such an event of default, all amounts outstanding under the applicable debt agreements could be declared to be immediately due and payable, and all applicable commitments to extend further credit could be terminated. If indebtedness under the ENLC Credit Facility, the ENLK Credit Facility or indentures is accelerated, there can be no assurance that we will have sufficient assets to repay the indebtedness. The operating and financial restrictions and covenants in these debt agreements and any future financing agreements may adversely affect our ability to finance future operations or capital needs or to engage in other business activities.

Increases in interest rates could adversely impact the price of ENLC’s or ENLK’s common units, ENLC’s or ENLK’s ability to issue equity or incur debt for acquisitions or other purposes and ENLC’s or ENLK’s ability to make cash distributions.

Interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, ENLC’s and ENLK’s unit price is impacted by ENLC’s and ENLK’s respective level of cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in ENLC’s or ENLK’s units, and a rising interest rate environment could have an adverse impact on the price of ENLC’s or ENLK’s common units, ENLC’s or ENLK’s ability to issue equity or incur debt for acquisitions or other purposes and ENLC’s or ENLK’s ability to make cash distributions at our intended levels or at all.

We are vulnerable to operational, regulatory and other risks due to our significant assets in South Louisiana and the Texas Gulf Coast, including the effects of adverse weather conditions such as hurricanes.

Our operations and revenues could be significantly impacted by conditions in South Louisiana and the Texas Gulf Coast because we have significant assets located in these two areas. Our concentration of activity in Louisiana and the Texas Gulf Coast makes us more vulnerable than many of our competitors to the risks associated with these areas, including:

adverse weather conditions, including hurricanes and tropical storms;
delays or decreases in production, the availability of equipment, facilities or services; and
changes in the regulatory environment.

Because a significant portion of our operations could experience the same condition at the same time, these conditions could have a relatively greater impact on our results of operations than they might have on other midstream companies that have operations in more diversified geographic areas.

Our business is subject to a number of weather-related risks. These weather conditions can cause significant damage and disruption to our operations and adversely impact our financial condition, results of operations or cash flows. 

Virtually all of our operations are exposed to potential natural disasters, including hurricanes, tornadoes, storms, floods, fires, severe temperatures and earthquakes. In particular, South Louisiana and the Texas Gulf Coast experience hurricanes and other extreme weather conditions on a frequent basis. The location of our significant assets and concentration of activity in these regions make us particularly vulnerable to weather risks in these areas.

 High winds, storm surge, flooding and other natural disasters can cause significant damage and curtail our operations for extended periods during and after such weather conditions, which may result in decreased revenues and otherwise adversely impact our financial condition, results of operations or cash flow. These interruptions could involve significant damage to people, property or the environment, and repair time and costs could be extensive. Any such event that interrupts the revenues generated by our operations, or which causes us to make significant expenditures not covered by insurance, could reduce our cash available for paying distributions to our partners and, accordingly, adversely affect our financial condition and the market price of our securities.

In addition, we rely on the volumes of natural gas, crude oil, condensate and NGLs gathered, processed, fractionated and transported on our assets. These volumes are influenced by the production from the regions that supply our systems. Adverse weather conditions can cause direct or indirect disruptions to the operations of, and otherwise negatively affect, producers,

suppliers, customers and other third parties to which our assets are connected, even if our assets are not damaged. As a result, our financial condition, results of operations and cash flows could be adversely affected.

We may also suffer reputational damage as a result of a natural disaster or other similar event. The occurrence of such an event, or a series of such events, especially if one or more of them occurs in a highly populated or sensitive area, could negatively impact public perception of our operations and/or make it more difficult for us to obtain the approvals, permits, licenses, rights-of-way or real property interests we need in order to operate our assets or complete planned growth projects.

A reduction in demand for NGL products by the petrochemical, refining or other industries or by the fuel markets could materially adversely affect our financial condition, results of operations or cash flows.

The NGL products we produce have a variety of applications, including as heating fuels, petrochemical feedstocks and refining blend stocks. A reduction in demand for NGL products, whether because of general or industry specific economic conditions, new government regulations, global competition, reduced demand by consumers for products made with NGL products (for example, reduced petrochemical demand observed due to lower activity in the automobile and construction industries), increased competition from petroleum-based feedstocks due to pricing differences, mild winter weather for some NGL applications or other reasons could result in a decline in the volume of NGL products we handle or reduce the fees we charge for our services. Our NGL products and the demand for these products are affected as follows:

Ethane. Ethane is typically supplied as purity ethane or as part of ethane-propane mix. Ethane is primarily used in the petrochemical industry as feedstock for ethylene, one of the basic building blocks for a wide range of plastics and other chemical products. Although ethane is typically extracted as part of the mixed NGL stream at gas processing plants, if natural gas prices increase significantly in relation to NGL product prices or if the demand for ethylene falls, it may be more profitable for natural gas processors to leave the ethane in the natural gas stream. Such “ethane rejection” reduces the volume of NGLs delivered for fractionation and marketing.

Propane. Propane is used as a petrochemical feedstock in the production of ethylene and propylene, as a heating, engine and industrial fuel, and in agricultural applications such as crop drying. Changes in demand for ethylene and propylene could adversely affect demand for propane. The demand for propane as a heating fuel is significantly affected by weather conditions. The volume of propane sold is at its highest during the six-month peak heating season of October through March. Demand for our propane may be reduced during periods of warmer-than-normal weather.

Normal Butane. Normal butane is used in the production of isobutane, as a refined product blending component, as a fuel gas, and in the production of ethylene and propylene. Changes in the composition of refined products resulting from governmental regulation, changes in feedstocks, products and economics, demand for heating fuel and for ethylene and propylene could adversely affect demand for normal butane.

Isobutane. Isobutane is predominantly used in refineries to produce alkylates to enhance octane levels. Accordingly, any action that reduces demand for motor gasoline or demand for isobutane to produce alkylates for octane enhancement might reduce demand for isobutane.

Natural Gasoline. Natural gasoline is used as a blending component for certain refined products and as a feedstock used in the production of ethylene and propylene. Changes in the mandated composition resulting from governmental regulation of motor gasoline and in demand for ethylene and propylene could adversely affect demand for natural gasoline.

NGLs and products produced from NGLs are sold in competitive global markets. Any reduced demand for ethane, propane, normal butane, isobutane or natural gasoline in the markets we access for any of the reasons stated above could adversely affect demand for the services we provide as well as NGL prices, which would negatively impact our financial condition, results of operations or cash flows.

We expect to encounter significant competition in any new geographic areas into which we seek to expand, and our ability to enter such markets may be limited.

If we expand our operations into new geographic areas, we expect to encounter significant competition for natural gas, condensate, NGLs and crude oil supplies and markets. Competitors in these new markets will include companies larger than us, which have both lower cost of capital and greater geographic coverage, as well as smaller companies, which have lower total

cost structures. As a result, we may not be able to successfully develop greenfield or acquire assets located in new geographic areas and our results of operations could be adversely affected.

We do not own most of the land on which our pipelines, compression and plant facilities are located, which could disrupt our operations.

We do not own most of the land on which our pipelines, compression and plant facilities are located, and we are therefore subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid rights-of-way or leases or if such rights-of-way or leases lapse or terminate. We sometimes obtain the rights to land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew right-of-way contracts, leases or otherwise, could cause us to cease operations on the affected land, increase costs related to continuing operations elsewhere and reduce our revenue.

We offer pipeline, truck, rail and barge services. Significant delays, inclement weather or increased costs affecting these transportation methods could materially affect our results of operations.

We offer pipeline, truck, rail and barge services. The costs of conducting these services could be negatively affected by factors outside of our control, including rail service interruptions, new laws and regulations, rate increases, tariffs, rising fuel costs or capacity constraints. Inclement weather, including hurricanes, tornadoes, snow, ice and other weather events, can negatively impact our distribution network. In addition, rail, truck or barge accidents involving the transportation of hazardous materials could result in significant environmental penalties and remediation, claims arising from personal injury and property damage.

We could experience increased severity or frequency of trucking accidents and other claims, which could materially affect our results of operations.

Potential liability associated with accidents in the trucking industry is severe and occurrences are unpredictable. A material increase in the frequency or severity of accidents or workers’ compensation claims or the unfavorable development of existing claims could materially adversely affect our results of operations. In the event that accidents occur, we may be unable to obtain desired contractual indemnities, and our insurance may be inadequate in certain cases. The occurrence of an event not fully insured or indemnified against, or the failure or inability of a customer or insurer to meet its indemnification or insurance obligations, could result in substantial losses.

Changes in trucking regulations may increase our costs and negatively impact our results of operations.

Our trucking services are subject to regulation as motor carriers by the DOT and by various state agencies, whose regulations include certain permit requirements of state highway and safety authorities. These regulatory authorities exercise broad powers over our trucking operations, generally governing such matters as the authorization to engage in motor carrier operations, safety, equipment testing and specifications and insurance requirements. There are additional regulations specifically relating to the trucking industry, including testing and specification of equipment and product handling requirements. The trucking industry is subject to possible regulatory and legislative changes that may impact our operations and affect the economics of the industry by requiring changes in operating practices or by changing the demand for or the cost of providing trucking services. Some of these possible changes include increasingly stringent fuel emission limits, changes in the regulations that govern the amount of time a driver may drive or work in any specific period, limits on vehicle weight and size and other matters, including safety requirements.

If we do not make acquisitions on economically acceptable terms or efficiently and effectively integrate the acquired assets with our asset base, our future growth will be limited.

Our ability to grow depends, in part, on our ability to make acquisitions that result in an increase in cash generated from operations on a per unit basis. If we are unable to make accretive acquisitions either because we are (1) unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them, (2) unable to obtain financing for these acquisitions on economically acceptable terms or at all or (3) outbid by competitors, then our future growth and our ability to increase distributions will be limited.


From time to time, we may evaluate and seek to acquire assets or businesses that we believe complement our existing business and related assets. We may acquire assets or businesses that we plan to use in a manner materially different from their prior owner’s use. Any acquisition involves potential risks, including:

the inability to integrate the operations of recently acquired businesses or assets, especially if the assets acquired are in a new business segment or geographic area;
the diversion of management’s attention from other business concerns;
the failure to realize expected volumes, revenues, profitability or growth;
the failure to realize any expected synergies and cost savings;
the coordination of geographically disparate organizations, systems and facilities;
the assumption of unknown liabilities;
the loss of customers or key employees from the acquired businesses;
a significant increase in our indebtedness; and
potential environmental or regulatory liabilities and title problems.

Management’s assessment of these risks is inexact and may not reveal or resolve all existing or potential problems associated with an acquisition. Realization of any of these risks could adversely affect our operations and cash flows. If we consummate any future acquisition, our capitalization and results of operations may change significantly, and you will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources.

We may not be able to retain existing customers or acquire new customers, which would reduce our revenues and limit our future profitability.

The renewal or replacement of existing contracts with our customers at rates sufficient to maintain current revenues and cash flows depends on a number of factors beyond our control, including the price of, and demand for, crude oil, condensate, NGLs and natural gas in the markets we serve and competition from other midstream service providers. Our competitors include companies larger than we are, which could have both a lower cost of capital and a greater geographic coverage, as well as companies smaller than we are, which could have lower total cost structures. In addition, competition is increasing in some markets that have been overbuilt, resulting in an excess of midstream energy infrastructure capacity, or where new market entrants are willing to provide services at a discount in order to establish relationships and gain a foothold. The inability of our management to renew or replace our current contracts as they expire and to respond appropriately to changing market conditions could have a negative effect on our profitability.

In particular, our ability to renew or replace our existing contracts with industrial end-users and utilities impacts our profitability. For the year ended December 31, 2017, approximately 53.9% of our sales of gas transported using our physical facilities were to industrial end-users and utilities. As a consequence of the increase in competition in the industry and volatility of natural gas prices, industrial end-users and utilities may be reluctant to enter into long-term purchase contracts. Many industrial end-users purchase natural gas from more than one natural gas company and have the ability to change providers at any time. Some of these industrial end-users also have the ability to switch between gas and alternate fuels in response to relative price fluctuations in the market. Because there are numerous companies of greatly varying size and financial capacity that compete with us in marketing natural gas, we often compete in the industrial end-user and utilities markets primarily on the basis of price.

We are exposed to the credit risk of our customers and counterparties, and a general increase in the nonpayment and nonperformance by our customers could have an adverse effect on our financial condition, results of operations or cash flows.

Risks of nonpayment and nonperformance by our customers are a major concern in our business. We are subject to risks of loss resulting from nonpayment or nonperformance by our customers and other counterparties, such as our lenders and hedging counterparties. Any increase in the nonpayment and nonperformance by our customers could adversely affect our results of operations and reduce our ability to make distributions to our unitholders. Additionally, equity values for many of our customers continue to be low. The combination of a reduction in cash flow from lower commodity prices, a reduction in borrowing bases under reserve-based credit facilities and the lack of availability of debt or equity financing may result in a significant reduction in our customers’ liquidity and ability to make payment or perform on their obligations to us. Furthermore, some of our customers may be highly leveraged and subject to their own operating and regulatory risks, which increases the risk that they may default on their obligations to us.

Increased federal, state and local legislation and regulatory initiatives, as well as government reviews relating to hydraulic fracturing could result in increased costs and reductions or delays in natural gas production by our customers, which could adversely impact our revenues.

A portion of our suppliers’ and customers’ natural gas production is developed from unconventional sources, such as deep gas shales, that require hydraulic fracturing as part of the completion process. State legislatures and agencies have enacted legislation and promulgated rules to regulate hydraulic fracturing, require disclosure of hydraulic fracturing chemicals, temporarily or permanently ban hydraulic fracturing and impose additional permit requirements and operational restrictions in certain jurisdictions or in environmentally sensitive areas. EPA and the BLM have also issued rules, conducted studies and made proposals that, if implemented, could either restrict the practice of hydraulic fracturing or subject the process to further regulation. For instance, the EPA has issued final regulations under the federal Clean Air Act establishing performance standards, including standards for the capture of air emissions released during hydraulic fracturing, and adopted rules prohibiting the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. Although the EPA has announced its intention to reconsider the regulations relating to the capture of air emissions in April 2017 and has sought to stay its requirements, the rule remains in effect along with the restriction on discharges to publicly owned wastewater treatment plants. The BLM also adopted new rules, effective on January 17, 2017, to reduce venting, flaring and leaks during oil and natural gas production activities on onshore federal and Indian leases. Certain provisions of the BLM rule went into effect in January 2017, while others were scheduled to go into effect in January 2018. In December 2017, BLM published a final rule delaying the 2018 provisions until 2019. State and federal regulatory agencies also have recently focused on a possible connection between the operation of injection wells used for oil and gas waste waters and an observed increase in induced seismicity, which has resulted in some regulation at the state level. For instance, in December 2016 the Oklahoma Corporation Commission released well completion seismicity guidelines for operators in the STACK play that call for hydraulic fracturing operations to be suspended following earthquakes of certain magnitudes in the vicinity. As regulatory agencies continue to study induced seismicity, additional legislative and regulatory initiatives could affect our customers’ injection well operations as well as our brine disposal operations.

We cannot predict whether any additional legislation or regulations will be enacted and, if so, what the provisions would be. If additional levels of regulation and permits were required through the adoption of new laws and regulations at the federal or state level, that could lead to delays, increased operating costs and process prohibitions for our suppliers and customers that could reduce the volumes of natural gas that move through our gathering systems which could materially adversely affect our revenue and results of operations.

Transportation on certain of our natural gas pipelines is subject to federal and state rate and service regulation, which could limit the revenues we collect from our customers and adversely affect the cash available for distribution to our unitholders. The imposition of regulation on our currently unregulated natural gas pipelines also could increase our operating costs and adversely affect the cash available for distribution to our unitholders.


The rates, terms, and conditions of service under which we transport natural gas in our pipeline systems in interstate commerce are subject to regulation by FERC under the NGA and Section 311 of the NGPA and the rules and regulations promulgated under those statutes. Under the NGA, FERC regulation requires that interstate natural gas pipeline rates be filed with FERC and that these rates be “just and reasonable,” not unduly preferential and not unduly discriminatory, although negotiated or settlement rates may be accepted in certain circumstances. Interested persons may challenge proposed new or changed rates, and FERC is authorized to suspend the effectiveness of such rates pending an investigation or hearing. FERC may also investigate, upon complaint or on its own motion, rates that are already in effect and may order a pipeline to change its rates prospectively. Accordingly, action by FERC could adversely affect our ability to establish rates that cover operating costs and allow for a reasonable return. An adverse determination in any future rate proceeding brought by or against us could have a material adverse effect on our business, financial condition, results of operations, and cash available for distribution. Under the NGPA, we are required to justify our rates for interstate transportation service on a cost-of-service basis every five years. In addition, our intrastate natural gas pipeline operations are subject to regulation by various agencies of the states in which they are located. Should FERC or any of these state agencies determine that our rates for transportation service should be lowered, our business could be adversely affected.


The rates charged by our natural gas pipelines may also be affected by the ongoing uncertainty regarding FERC’s income tax allowance policy as a result of ongoing proceedings at FERC related to third parties or general FERC policies. The ultimate outcome of these proceedings, which may not be definitively resolved for some time, is not certain and could result in changes to FERC’s general treatment of income tax allowances in the cost of service or to the discounted cash flow return on equity. Additionally, recently enacted legislation commonly referred to as the Tax Cuts and Jobs Act (the “Tax Cuts and Jobs Act”)

includes a reduction in the highest marginal U.S. federal corporate income tax rate from 35% to 21%, effective for taxable years beginning on or after January 1, 2018. At this time, it is uncertain how and when FERC will require this reduction in corporate tax rates to be reflected in the income tax allowance of regulated entities for rate-making purposes.  Depending upon the resolution of these issues, the cost of service rates of our interstate natural gas pipelines could be affected to the extent FERC proposes new rates or changes to our existing rates or if our rates are subject to compliance or challenged by FERC.

Our natural gas gathering and processing activities generally are exempt from FERC regulation under the Natural Gas Act. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of substantial, ongoing litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC and the courts. Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels since FERC has less extensively regulated the gathering activities of interstate pipeline transmission companies, and a number of such companies have transferred gathering facilities to unregulated affiliates. Application of FERC jurisdiction to our gathering facilities could increase our operating costs, decrease our rates, and adversely affect our business. Our gathering operations also may be or become subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement, and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.


If we fail to comply with all the applicable FERC-administered statutes, rules, regulations, and orders, we could be subject to substantial penalties and fines. Under the EPAct 2005, FERC has civil penalty authority to impose penalties for current violations of the NGA or NGPA of up to $1.0 million per day for each violation. The maximum penalty authority established by statute has been adjusted to $1.2approximately $1.39 million per day and will continue to be adjusted periodically for inflation. FERC also has the power to order disgorgement of profits from transactions deemed to violate the NGA and EPAct 2005.


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Other state and local regulations also affect our business. We are subject to some ratable take and common purchaser statutes in the states where we operate. Ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes have the effect of restricting our right as an owner of gathering facilities to decide with whom we contract to purchase or transport natural gas. Federal law leaves any economic regulation of natural gas gathering to the states, and some of the states in which we operate have adopted complaint-based or other limited economic regulation of natural gas gathering activities. States in which we operate that have adopted some form of complaint-based regulation, like Texas, generally allow natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering access and rate discrimination.


Transportation on our liquids pipelines is subject to federal and state rate and service regulation, which could limit the revenues we collect from our customers and adversely affect the cash available for distribution to our unitholders. The imposition of regulation on our currently unregulated liquids pipeline operations also could increase our operating costs and adversely affect the cash available for distribution to our unitholders.


Our interstate liquids transportation pipelines are subject to regulation by FERC under the ICA, the Energy Policy Act of 1992, and the rules and regulations promulgated under those laws. If, upon completion of an investigation, FERC finds that new or changed rates are unlawful, it is authorized to require the pipeline to refund revenues collected in excess of the just and reasonable rates during the term of the investigation. FERC may also investigate, upon complaint or on its own motion, rates that are already in effect and may order a carrier to change its rates prospectively if it determines that the rates are unjust and unreasonable or unduly discriminatory or preferential. Under certain circumstances, FERC could limit our recovery of costs or could require us to reduce our rates and the payment of reparations to complaining shippers for up to two years prior to the date of the complaint. In particular, ongoing uncertainty surrounding FERC’s current income tax allowance policy could affect our rates going forward, although we do not currently expect to experience any impact to financial results as a result of this policy. In addition, our rates going forward could be affected by proposed changes to FERC’s annual indexing methodology, including both changes to the methodology to account for the impact of the tax reduction from the Tax Cuts and Jobs Act of 2017 as well as the potential adoption of a policy that would deny proposed index increases for pipelines under certain circumstances where revenues exceed cost-of-service numbers by a certain percentage or where the proposed index increases exceed certain annual cost changes, allchanges. All of whichthese FERC policies and potential changes could have a material impact on our business. Such changes,business and, if accepted, could decrease our rates and adversely affect our business.


As we acquire, construct, and operate new liquids assets and expand our liquids transportation business, the classification and regulation of our liquids transportation services, including services that our marketing companies provide on our FERC-regulated liquids pipelines, are subject to ongoing assessment and change based on the services we provide and determinations

by FERC and the courts. Such changes may subject additional services we provide to regulation by FERC, which could increase our operating costs, decrease our rates, and adversely affect our business.


We may incur significant costs and liabilities resulting from compliance with pipeline safety regulations.


The pipelines we own and operate are subject to stringent and complex regulation related to pipeline safety and integrity management. For instance, the Department of Transportation, through PHMSA, has established a series of rules that require pipeline operators to develop and implement integrity management programs for hazardous liquid (including oil) pipeline segments that, in the event of a leak or rupture, could affect HCAs. In October 2019, PHMSA issued three new final rules. One rule, effective in December 2019, establishes procedures to implement the expanded emergency order enforcement authority set forth in an October 2016 interim final rule. Among other things, this rule allows PHMSA to issue an emergency order without advance notice or opportunity for a hearing. The other two rules, effective in July 2020, impose several new requirements on operators of onshore gas transmission systems and hazardous liquids pipelines. The rule concerning gas transmission extends the requirement to conduct integrity assessments beyond HCAs to pipelines in MCAs. It also recently proposed rules that would expand existingincludes requirements to reconfirm MAOP, report MAOP exceedances, consider seismicity as a risk factor in integrity management, requirementsand use certain safety features on in-line inspection equipment. The rule concerning hazardous liquids extends the required use of leak detection systems beyond HCAs to natural gas transmissionall regulated non-gathering hazardous liquid pipelines, requires reporting for gravity fed lines and unregulated gathering lines, requires periodic inspection of all lines not in areas with medium population densities.HCAs, calls for inspections of lines after extreme weather events, and adds a requirement to make all lines in or affecting HCAs capable of accommodating in-line inspection tools over the next 20 years. Additional action by PHMSA with respect to pipeline integrity management requirements may occur in the future. At this time, we cannot predict the cost of such requirements, but they could be significant. Moreover, violations of pipeline safety regulations can result in the imposition of significant penalties.


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Several states have also passed legislation or promulgated rules to address pipeline safety. Compliance with pipeline integrity laws and other pipeline safety regulations issued by state agencies, such as the TRRC, could result in substantial expenditures for testing, repairs, and replacement. For example, TRRC regulations require periodic testing of all intrastate pipelines meeting certain size and location requirements. Our costs relating to compliance with the required testing under the TRRC regulations were approximately $2.3$3.2 million, $3.3$2.6 million, and $3.3$3.1 million for the years ended December 31, 2017, 20162021, 2020, and 2015,2019, respectively. If our pipelines fail to meet the safety standards mandated by the TRRC or PHMSA regulations, then we may be required to repair or replace sections of such pipelines or operate the pipelines at a reduced operating pressure, the cost of which actions cannot be estimated at this time.


Due to the possibility of new or amended laws and regulations or reinterpretation of existing laws and regulations, there can be no assurance that future compliance with PHMSA or state requirements will not have a material adverse effect on our results of operations or financial positions. Moreover, because certain of our operations are located around urban or more populated areas, such as the Barnett Shale, we may incur additional expenses from compliance with municipal and other local or state regulations that impose various obligations including, among other things, regulating the locations of our facilities; limiting the noise, odor, or light levels of our facilities; and requiring certain other improvements, including to the appearance of our facilities, that result in increased costs for our facilities. We are also subject to claims by neighboring landowners for nuisance related to the construction and operation of our facilities, which could subject us to damages for declines in neighboring property values due to our construction and operation activities.


Failure to comply with existing or new environmental laws or regulations or an accidental release of hazardous substances, hydrocarbons, or wastes into the environment may cause us to incur significant costs and liabilities.


Many of the operations and activities of our pipelines, gathering systems, processing plants, fractionators, brine disposal operations, and other facilities are subject to significant federal, state, and local environmental laws and regulations, the violation of which can result in administrative, civil, and criminal penalties, including civil fines, injunctions, or both. The obligations imposed by these laws and regulations include obligations related to air emissions and discharge of pollutants from our pipelines and other facilities and the cleanup of hazardous substances and other wastes that are or may have been released at properties currently or previously owned or operated by us or locations to which we have sent wastes for treatment or disposal. These laws impose strict, joint and several liability for the remediation of contaminated areas. Private parties, including the owners of properties near our facilities or upon or through which our gathering systems traverse, may also have the right to pursue legal actions to enforce compliance and to seek damages for non-compliance with environmental laws for releases of contaminants or for personal injury or property damage.


Our business may be adversely affected by increased costs due to stricter pollution control requirements or liabilities resulting from non-compliance with required operating or other regulatory permits. New environmental laws or regulations, including, for example, legislation relating to the control of greenhouse gas emissions, or changes in existing environmental laws or regulations might adversely affect our products and activities, including processing, storage, and transportation, as well as waste management and air emissions. Federal and state agencies could also impose additional safety requirements, any of which could affect our profitability. Changes in laws or regulations could also limit our production or the operation of our assets or adversely affect our ability to comply with applicable legal requirements or the demand for crude oil, brine disposal services, or natural gas, which could adversely affect our business and our profitability.



Recent rules under the Clean Air Act imposing more stringent requirements on the oil and gas industry could cause our customers and us to incur increased capital expenditures and operating costs as well as reduce the demand for our services.


We are subject to stringent and complex regulation under the federal Clean Air Act, implementing regulations, and state and local equivalents, including regulations related to controls for oil and natural gas production, pipelines, and processing operations. For instance, the EPA finalized new rules, effective August 2, 2016, to regulate emissions of methane and volatile organic compoundsVOCs from new and modified sources in the oil and gas sector. In September 2020, the EPA published two additional final rules, the 2020 Policy Rule and the 2020 Technical Amendments. The 2020 Policy Rule removed sources in the transmission and storage segment from the regulated source category of the 2016 NSPS, rescinded the NSPS (including both VOC and methane requirements) applicable to those sources, and rescinded the methane-specific requirements of the NSPS applicable to sources in the production and processing segments. In June 2020, President Biden signed a joint congressional resolution rescinding the 2020 Policy Rule, and in November 2021, the EPA announced its intentionproposed a new rule targeting methane and VOC emissions from new and existing oil and gas sources, including sources in the production, processing, transmission, and storage segments. The proposed rule would: (1) update NSPS subpart OOOOa; (2) adopt a new NSPS subpart OOOOb for sources that commence construction, modification, or reconstruction after the date the proposed rule is published in the Federal Register; and (3) adopt a new NSPS subpart OOOOc to reconsider those regulations in April 2017 and has soughtestablish emissions guidelines, which will inform state plans to stay its requirements. However, the rule remains in effect.establish standards for existing sources. The
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EPA also finalized a rule regarding the alternative criteria for aggregating multiple small surface sites into a single source for air quality permitting purposes. This rule could cause small facilities, on an aggregate basis, to be deemed a major source if within one quarter-mile of one another, thereby triggering more stringent air permitting processes and requirements across the oil and gas industry. In addition, on November 10, 2016, the EPA issued a final Information Collection Request (“ICR”) that requires numerous oil and gas companies to provide information regarding methane emissions from existing oil and gas facilities, a step used to provide a basis for future rulemaking. The EPA withdrew this ICR in March of 2017.

The BLM also adopted new rules, on November 15, 2016, effective January 17, 2017, to reduce venting, flaring, and leaks during oil and natural gas production activities on onshore federal and Indian leases. Certain provisions of the BLM rule went into effect in January 2017, while others were scheduled to go into effect in January 2018. In December 2017, BLM published a final rule delaying the 2018 provisions until 2019. In September 2018, BLM published a final rule to repeal certain requirements of the 2016 methane rule. The September 2018 rule was challenged in the U.S. District Court for the Northern District of California almost immediately after issuance. In July 2020, the U.S. District Court for the Northern District of California vacated BLM’s 2018 revision rule. Additionally, in October 2020, a Wyoming federal district judge vacated the 2016 venting and flaring rule.


Additional regulation of GHG emissions from the oil and gas industry remains a possibility. These regulations could require a number of modifications to our operations, and our natural gas exploration and production suppliers’ and customers’ operations, including the installation of new equipment, which could result in significant costs, including increased capital expenditures and operating costs. The incurrence of such expenditures and costs by our suppliers and customers could result in reduced production by those suppliers and customers and thus translate into reduced demand for our services. Responding to rule challenges, the EPA has since revised certain aspects of its April 2012 rules and has indicated that it may reconsider other aspects of the rules.


Climate change legislation and regulatory initiatives could result in increased operating costs and reduced demand for the natural gas and NGL services we provide.

The United States Congress has from time to time considered adopting legislation to reduce emissions of GHGs, and there has been a wide-ranging policy debate, both nationally and internationally, regarding the impact of these gases and possible means for their regulation. In addition, efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues. In 2015, the United States participated in the United Nations Conference on Climate Change, which led to the adoption of the Paris Agreement. The Paris Agreement became effective November 4, 2016 and requires countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals, every five years beginning in 2020. Although the Trump Administration has announced its intent to withdraw from the Paris Agreement, the earliest effective date of this withdrawal pursuant to the terms of the Paris Agreement is November 2020. At the federal regulatory level, both the EPA and the BLM have adopted regulations for the control of methane emissions, which also include leak detection and repair requirements, from the oil and gas industry.

In addition, many states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and NGL fractionation plants, to acquire and surrender emission allowances with the number of allowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved.

Although it is not possible at this time to predict whether future legislation or new regulations may be adopted to address greenhouse gas emissions or how such measures would impact our business, the adoption of legislation or regulations imposing reporting or permitting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur additional costs to reduce emissions of GHGs associated with our operations, could adversely affect our performance of operations in the absence of any permits that may be required to regulate emission of GHGs or could adversely affect demand for the natural gas we gather, process or otherwise handle in connection with our services.


The ESA and MBTA govern our operations and additional restrictions may be imposed in the future, which could have an adverse impact on our operations.


The ESA and analogous state laws restrict activities that may affect endangered or threatened species or their habitats. Similar protections are offered to migratory birds under the MBTA. The U.S. Fish and Wildlife Service and state agencies may designate critical or suitable habitat areas that they believe are necessary for the survival of threatened or endangered species, which could materially restrict use of or access to federal, state, and private lands. Some of our operations may be located in areas that are designated as habitats for endangered or threatened species or that may attract migratory birds. In these areas, we may be obligated to develop and implement plans to avoid potential adverse impacts to protected species, and we may be prohibited from conducting operations in certain locations or during certain seasons, such as breeding and nesting seasons, when our operations could have an adverse effect on the species. It is also possible that a federal or state agency could order a complete halt to our activities in certain locations if it is determined that such activities may have a serious adverse effect on a protected species. In addition, the U.S. Fish and Wildlife Service and state agencies regularly review species that are listing candidates, and designations of additional endangered or threatened species, or critical or suitable habitat, under the ESA could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas.


Our business involves many hazardsis subject to complex and operational risks, someevolving U.S. laws and regulations regarding privacy and data protection (“data protection laws”). Many of which may notthese laws and regulations are subject to change and uncertain interpretation, and could result in claims, increased cost of operations, or otherwise harm our business.

The regulatory environment surrounding data privacy and protection is constantly evolving and can be fully coveredsubject to significant change. New data protection laws pose increasingly complex compliance challenges and potentially elevate our costs. Complying with varying jurisdictional requirements could increase the costs and complexity of compliance, and violations of applicable data protection laws can result in significant penalties. Any failure, or perceived failure, by insurance. The occurrenceus to comply with applicable data protection laws could result in proceedings or actions against us by governmental entities or others, subject us to significant fines, penalties, judgments, and negative publicity, require us to change our business practices, increase the costs and complexity of a significant accident or other event that is not fully insured couldcompliance, and adversely affect our operations and financial condition.

Our operationsbusiness. As noted above, we are also subject to the many hazards inherent in the gathering, compressing, processing, transporting, fractionating, disposing and storagepossibility of natural gas, NGLs, condensate, crude oil and brine, including:

damage to pipelines, facilities, storage caverns, equipment and surrounding properties caused by hurricanes, floods, sink holes, fires and other natural disasters and acts of terrorism;
inadvertent damage to our assets from construction or farm equipment;
leaks of natural gas, NGLs, crude oil, condensate and other hydrocarbons;
induced seismicity;
rail accidents, barge accidents and truck accidents;
equipment failure; and
fires and explosions.

These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage andcyberattacks, which themselves may result in curtailmenta violation of these laws. Additionally, if we acquire a company that has violated or suspension of our related operations. We are not fully insured against all risks incident to our business. In accordance with typical industry practice, we have appropriate levels of business interruption and property insurance on our underground pipeline systems. We are not insured against all environmental accidents that might occur. If a significant accident or event occurs that is not fully insured, it could adversely affect our operations and financial condition.

The adoption of derivatives legislation by the United States Congress and promulgation of related regulations could have an adverse effect on our ability to hedge risks associatedin compliance with our business.

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

In particular, on October 18, 2011, the CFTC adopted final rules under the Dodd-Frank Act establishing position limits for certain energy commodity futures and options contracts and economically equivalent swaps, futures and options. The position limit levels set the maximum amount of covered contracts that a trader may own or control separately or in combination, net long or short. The final rules also contained limited exemptions from position limits which would be phased in over time for certain bona fide hedging transactions and positions. The CFTC’s original position limits rule was challenged in court by two industry associations and was vacated and remanded by a federal district court. However, the CFTC proposed and revised new rules in November 2013 and December 2016, respectively, that would place limits on positions in certain core futures and

equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. The CFTC has sought comment on the position limits rule as reproposed, but these new position limit rules are not yet final and the impact of those provisions on us is uncertain at this time. The CFTC has withdrawn its appeal of the court order vacating the original position limits rule.

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

Our use of derivative financial instruments does not eliminate our exposure to fluctuations in commodity prices and interest rates and has in the past and could in the future result in financial losses or reduce our income.

Our operations expose us to fluctuations in commodity prices, and the ENLK Credit Facility and ENLC Credit Facility expose us to fluctuations in interest rates. We use over-the-counter price and basis swaps with other natural gas merchants and financial institutions. Use of these instruments is intended to reduce our exposure to short-term volatility in commodity prices. As of December 31, 2017, we have hedged only portions of our expected exposures to commodity price risk. In addition, to the extent we hedge our commodity price risk using swap instruments, we will forego the benefits of favorable changes in commodity prices. Although we do not currently have any financial instruments to eliminate our exposure to interest rate fluctuations, we may use financial instruments in the future to offset our exposure to interest rate fluctuations.

Even though monitored by management, our hedging activities may fail to protect us and could reduce our earnings and cash flow. Our hedging activity may be ineffective or adversely affect cash flow and earnings because, among other factors:

hedging can be expensive, particularly during periods of volatile prices;
our counterparty in the hedging transaction may default on its obligation to pay or otherwise fail to perform; and
available hedges may not correspond directly with the risks against which we seek protection. For example:
the duration of a hedge may not match the duration of the risk against which we seek protection;
variations in the index we use to price a commodity hedge may not adequately correlate with variations in the index we use to sell the physical commodity (known as basis risk); and
we may not produce or process sufficient volumes to cover swap arrangements we enter into for a given period. If our actual volumes are lower than the volumes we estimated when entering into a swap for the period, we might be forced to satisfy all or a portion of our derivative obligation without the benefit of cash flow from our sale or purchase of the underlying physical commodity, which could adversely affect our liquidity.

A failure in our computer systems or a terrorist or cyber-attack on us, or third parties with whom we have a relationship, may adversely affect our ability to operate our business.

We are reliant on technology to conduct our business. Our business is dependent upon our operational and financial computer systems to process theapplicable data necessary to conduct almost all aspects of our business, including operating our pipelines, truck fleet and storage facilities, recording and reporting commercial and financial transactions and receiving and making payments. Any failure of our computer systems, or those of our customers, suppliers or others with whom we do business, could materially disrupt our ability to operate our business. Unknown entities or groups have mounted so-called “cyber-attacks” on businesses to disable or disrupt computer systems, disrupt operations and steal funds or data. Cyber-attacks could also result in the loss of confidential or proprietary data or security breaches of other information technology systems that could disrupt our operations and critical business functions. In addition, our pipeline systems may be targets of terrorist activities that could disrupt our ability to conduct our business and have a material adverse effect on our business and results of operations. Strategic targets, such as energy-related assets, may be at greater risk of future terrorist or cyber-attacks than other targets in the United States. Our insurance may not protect us against such occurrences. Any such terrorist or cyber-attack that affects us or our customers, suppliers or others with whom we do business, could have a material adverse effect on our business, cause us to incur a material financial loss, subject us to possible legal claims and liability and/or damage our reputation.


Moreover, as the sophistication of cyber attacks continues to evolve, we may be required to expend significant additional resources to further enhance our digital security or to remediate vulnerabilities. In addition, cyber-attacks against us or others in our industry could result in additional regulations, which could lead to increased regulatory compliance costs, insurance coverage cost or capital expenditures. We cannot predict the potential impact to our business or the energy industry resulting from additional regulations.

Our success depends on key members of our management, the loss or replacement of whom could disrupt our business operations.

We depend on the continued employment and performance of the officers of our general partner and key operational personnel. If any of these officers or other key personnel resign or become unable to continue in their present roles and are not adequately replaced, our business operations could be materially adversely affected. We do not maintain any “key man” life insurance for any officers.

Failure to attract and retain an appropriately qualified workforce could reduce labor productivity and increase labor costs, which could have a material adverse effect on our business and results of operations.

Gathering and compression services require laborers skilled in multiple disciplines, such as equipment operators, mechanics and engineers, among others. Our business is dependent on our ability to recruit, retain and motivate employees. Certain circumstances, such as an aging workforce without appropriate replacements, a mismatch of existing skill sets to future needs, competition for skilled labor or the unavailability of contract resources, may lead to operating challenges such as a lack of resources, loss of knowledge or a lengthy time period associated with skill development. Our costs, including costs for contractors to replace employees, productivity costs and safety costs, may rise. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to the new employees, or the future availability and cost of contract labor may adversely affect our ability to manage and operate our business. If we are unable to successfully attract and retain an appropriately qualified workforce, our results of operations could be negatively affected.

Subsidence and coastal erosion could damage our pipelines along the Gulf Coast and offshore and the facilities of our customers, which could adversely affect our operations and financial condition.

Our pipeline operations along the Gulf Coast and offshore could be impacted by subsidence and coastal erosion. Such processes could cause serious damage to our pipelines, which could affect our ability to provide transportation services. Additionally, such processes could impact our customers who operate along the Gulf Coast, and they may be unable to utilize our services. Subsidence and coastal erosion could also expose our operations to increased risks associated with severe weather conditions, such as hurricanes, flooding and rising sea levels. As a result,protection laws, we may incur significant costs to repairliabilities and preserve our pipeline infrastructure. Such costs could adversely affect our financial condition, results of operation or cash flows.penalties as a result.


Our assets were constructed over many decades using varying construction and coating techniques, which may cause our inspection, maintenance or repair costs to increase in the future. In addition, there could be service interruptions due to unknown events or conditions or increased downtime associated with our pipelines that could have a material adverse effect on our financial condition, results of operations or cash flows.

Our pipelines were constructed over many decades. Pipelines are generally long-lived assets, and pipeline construction and coating techniques have varied over time and can vary for individual pipelines. Depending on the construction era and quality, some assets will require more frequent inspections or repairs, which could result in increased maintenance or repair expenditures in the future. Any significant increase in these expenditures could adversely affect our financial condition, results of operations or cash flows.

Item 1B. Unresolved Staff Comments


We do not have any unresolved staff comments.


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Item 2. Properties


A description of our properties is contained in “Item 1. Business.”


Title to Properties


Substantially all of our pipelines are constructed on rights-of-way granted by the apparent record owners of the property. Lands over which pipeline rights-of-way have been obtained may be subject to prior liens that have not been subordinated to the right-of-way grants. We have obtained, where necessary, easement agreements from public authorities and railroad companies to cross over or under, or to lay facilities in or along, watercourses, county roads, municipal streets, railroad properties, and state highways, as applicable. In some cases, property on which our pipeline was built was purchased in fee. Our processing plants are located on land that we lease or own in fee.


We believe that we have satisfactory title to all of our rights-of-way and land assets. Title to these assets may be subject to encumbrances or defects. We believe that none of such encumbrances or defects should materially detract from the value of our assets or from our interest in these assets or should materially interfere with their use in the operation of the business.


Item 3. Legal Proceedings


Our operations are subject to a variety of risks and disputes normally incident to our business. As a result, at any given time we may be a defendant in various legal proceedings and litigation arising in the ordinary course of business, including litigation on disputes related to contracts, property rights, property use or damage, and personal injury. We may continue to see claims brought by landowners, such as nuisance claims and other claims based on property rights. We may also be involved in lawsuits with landowners in which a court determines the value to be paid for a pipeline easement or other property right as a result of our exercise of eminent domain or common carrier rights. Except as otherwise set forth herein, we do not believe that any pending or threatened claim or dispute is material to our financial condition, results of operations, or cash flows. We maintain insurance policies with insurers in amounts and with coverage and deductibles that our general partnerManaging Member believes are reasonable and prudent. However, we cannot assure you that this insurance will be adequate to protect us from all material expenses related to potential future claims for personal and property damage or that these levels of insurance will be available in the future at economical prices.


At times, our subsidiaries acquire pipeline easementsSee “Item 8. Financial Statements and other property rights by exercising rights of eminent domainSupplementary Data—Note 14” for more information on litigation proceedings and common carrier. As a result, from time to time we or our subsidiaries are party to lawsuits under which a court will determine the value of pipeline easements or other property interests obtained by our subsidiaries by condemnation. Damage awards in these suits should reflect the value of the property interest acquired and the diminution in the value of the remaining property owned by the landowner. However, some landowners have alleged unique damage theories to inflate their damage claims or assert valuation methodologies that could result in damage awards in excess of the amounts anticipated. Although it is not possible to predict the ultimate outcomes of these matters, we do not expect that awards in these matters will have a material adverse impact on our consolidated financial condition, results of operations or cash flows.contingencies.


We (or our subsidiaries) are defending lawsuits filed by owners of property located near processing facilities or compression facilities that we own or operate as part of our systems. The suits generally allege that the facilities create a private nuisance and have damaged the value of surrounding property. Claims of this nature have arisen as a result of the industrial development of natural gas gathering, processing, and treating facilities in urban and occupied rural areas.


We own and operate a high-pressure pipeline and underground natural gas and NGL storage reservoirs and associated facilities near Bayou Corne, Louisiana. In August 2012, a large sinkhole formed in the vicinity of this pipeline and underground storage reservoirs, resulting in damage to certain of our facilities. In order to recover our losses from responsible parties, we sued the operator of a failed cavern in the area, and its insurers, as well as other parties we alleged to have contributed to the formation of the sinkhole seeking recovery for these losses. We also filed a claim with our insurers, which our insurers denied. We disputed the denial and sued our insurers, and we subsequently reached settlements regarding the entirety of our claims in both lawsuits. In August 2014, we received a partial settlement with respect to our claims in the amount of $6.1 million. We secured additional settlement payments during 2017, which resulted in the recognition of “Gain on litigation settlement” of $26.0 million on the consolidated statement of operations for the year ended December 31, 2017.

Item 4. Mine Safety Disclosures


Not applicable.



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PART II


Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters, and Issuer Purchases of Equity Securities


Our common units are listed on the NYSE under the symbol “ENLC.” On February 14, 2018,January 31, 2022, there were approximately 20,72830,873 record holders and beneficial owners (held in street name) of ENLC common units. For equity compensation plan information, see the discussion under “Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters—Equity Compensation Plan Information.”


The following table shows the high and low closing sales prices per ENLC common unit, as reportedUnless restricted by the NYSE and cash distributions declared per common unit forterms of the periods indicated:

 Range Cash Distribution
 High Low Declared Per Unit
2017     
Quarter Ended December 31$17.60
 $15.25
 $0.259
Quarter Ended September 3018.05
 16.05
 0.255
Quarter Ended June 3019.75
 15.65
 0.255
Quarter Ended March 3120.15
 17.35
 0.255
      
2016     
Quarter Ended December 31$19.25
 $14.85
 $0.255
Quarter Ended September 3017.70
 14.81
 0.255
Quarter Ended June 3016.73
 10.00
 0.255
Quarter Ended March 3115.38
 7.13
 0.255

WeConsolidated Credit Facility, we intend to pay distributions to ENLCour unitholders on a quarterly basis equal to thefrom our available cash we receive, if any, from distributions from ENLK and EnLink Oklahoma T.O. less reserves for expenses, future distributions, and other uses of cash, including:


•provisions for the proper conduct of our business;
•paying federal income taxes, which we are required to pay because we are taxed as a corporation; and
the expenses of being a public company;
other general and administrative expenses;
capital contributions to ENLK upon the issuance by it of additional ENLK securities in order to maintain the General Partner’s then-current general partner interest, to the extent the GP Board exercises its option to do so;
capital calls for our interest in EnLink Oklahoma T.O. to the extent not covered by our borrowings; and
•maintaining cash reserves the board of directors of the Managing Member believes are prudent to maintain.


Our ability to pay distributions is limited byPurchases of Equity Securities

During the Delaware Limited Liability Company Act, which provides that a limited liability company may not pay distributions if, after giving effect to the distribution, the company’s liabilities would exceed the fair value of its assets. While our ownership of equity interests in the General Partner and ENLK are included in our calculation of net assets, the value of these assets may decline to a level where our liabilities would exceed the fair value of our assets if we were to pay distributions, thus prohibiting us from paying distributions under Delaware law.

In 2017, ENLK paid quarterly distributions to ENLK common unitholders in May, August and November of $0.390 related to the first, second and third quarters of 2017, respectively. ENLK paid a quarterly distribution of $0.390 in February 2018 related to the fourth quarter of 2017. Our share of the distributions with respect to our limited and general partner interests in ENLK totaled $199.3 million for the yearthree months ended December 31, 2017.


Performance Graph

The following graph sets forth the cumulative total stockholder return for our2021, we re-acquired ENLC common units from certain employees in order to satisfy the Standard & Poor’s 500 Stock Index and a peer group of publicly traded limited partnerships in the midstream natural gas, natural gas liquids, propane, and pipeline industries for the year ended December 31, 2017. The chart assumes that $100 was invested on March 10, 2014, with distributions reinvested. The peer group includes MPLX, Energy Transfer Equity, L.P., Targa Resources, Inc. and Western Gas Equity Partners, L.P.
Item 6. Selected Financial Data

The historical financial statements included in this report reflect (1) for periods prior to March 7, 2014, the assets, liabilities and operations of EnLink Midstream Holdings, LP Predecessor (the “Predecessor”), the predecessor to Midstream Holdings, which is the historical predecessor of the Partnership and (2) for periods on or after March 7, 2014, the results of our operations after giving effect to the Business Combination discussed under “Item 1. Business—General.” The Predecessor was comprised of all of the U.S. midstream assets and operations of Devon prior to the Business Combination, including its 38.75% interest in GCF. However,employees’ tax liability in connection with the Business Combination, onlyvesting of restricted incentive units, and we repurchased common units in open market transactions in connection with a common unit repurchase program.
Period Total Number of Units Purchased (1)Average Price Paid Per Unit Total Number of Units Purchased as Part of Publicly Announced Plans or Programs (2) Maximum Dollar Value of Units that May Yet Be Purchased under the Plans or Programs (in millions) (2)
October 1, 2021 to October 31, 20211,919 $6.82 — $84.3 
November 1, 2021 to November 30, 20211,679,243 $7.24  1,679,243 $72.2 
December 1, 2021 to December 31, 20212,028,069 $6.69  2,017,462 $58.7 
Total3,709,231 $6.94  3,696,705 
____________________________
(1)The total number of units purchased shown in the Predecessor’s systems servingtable includes 12,526 units received by us from employees for the Barnett, Cana-Woodfordpayment of personal income tax withholding on vesting transactions.
(2)On November 4, 2020, we announced a $100.0 million common unit repurchase program. As of December 31, 2021, we had repurchased a total of 6.5 million common units for an aggregate cost of $41.3 million, or an average of $6.38 per common unit under such program. In December 2021, we announced that our Board had reauthorized our common unit repurchase program and Arkoma-Woodford Shalesreset the amount available for repurchase of outstanding common units at up to $100.0 million effective January 1, 2022. Future repurchases under the program may be made from time to time in Texasopen market or private transactions and Oklahoma,may be made pursuant to a trading plan meeting the requirements of Rule 10b5-1 under the Securities Exchange Act of 1934, as well as the economic benefitsamended. The repurchases will depend on market conditions and burdensmay be discontinued at any time. On February 15, 2022, we and GIP entered into an agreement pursuant to which we will repurchase, on a quarterly basis, a pro rata portion of the 38.75% interestENLC 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 GCF, were contributed to Midstream Holdings, effective asany quarter will be calculated such that GIP’s then-existing economic ownership percentage of March 7, 2014.

The following table presents our selected historical financial and operating dataoutstanding common units is maintained after our repurchases of EnLink Midstream, LLCcommon units from public unitholders are taken into account, and the Predecessorper unit price we pay to GIP will be the average per unit price paid by us for the periods indicated. Financial and operating data for the years ended December 31, 2017, 2016, 2015 and 2014 reflect acquisitions and dispositions for periods subsequent to the applicable transaction date. The selected historical financial data should be read togethercommon units repurchased from public unitholders. For more information about our repurchase agreement with “Item 7. Management’s Discussion and AnalysisGIP, see Item 9B of Financial Condition and Resultsthis Report.

Item 6. [Reserved]

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Table of Operations” and the consolidated financial statements and accompanying notes in “Item 8. Financial Statements and Supplementary Data.”

Contents
 EnLink Midstream, LLC
 Year Ended December 31,
 2017 2016 2015 2014 (4) 2013 (4)
 (In millions, except per unit data)
Revenues:         
Product sales$4,358.4
 $3,008.9
 $3,253.7
 $2,159.3
 $179.4
Product sales—related parties144.9
 134.3
 119.4
 505.6
 2,116.5
Midstream services552.3
 467.2
 451.0
 253.4
 —
Midstream services—related parties688.2
 653.1
 618.6
 567.4
 —
Gain (loss) on derivative activity(4.2) (11.1) 9.4
 22.1
 —
Total revenues5,739.6
 4,252.4
 4,452.1
 3,507.8
 2,295.9
Operating costs and expenses:         
Cost of sales (1)4,361.5
 3,015.5
 3,245.3
 2,494.5
 1,736.3
Operating expenses (2)418.7
 398.5
 419.9
 283.6
 156.2
General and administrative (3)128.6
 122.5
 136.9
 97.3
 45.1
(Gain) loss on disposition of assets—
 13.2
 1.2
 (0.1) —
Depreciation and amortization545.3
 503.9
 387.3
 284.3
 187.0
Impairments17.1
 873.3
 1,563.4
 —
 —
Gain on litigation settlement(26.0) —
 —
 (6.1) —
Total operating costs and expenses5,445.2
 4,926.9
 5,754.0
 3,153.5
 2,124.6
Operating income (loss)294.4
 (674.5) (1,301.9) 354.3
 171.3
Other income (expense):         
Interest expense, net of interest income(190.4) (189.5) (103.3) (49.8) —
Gain on extinguishment of debt9.0
 —
 —
 3.2
 —
Income (loss) from unconsolidated affiliates9.6
 (19.9) 20.4
 18.9
 14.8
Other income (expense)0.6
 0.3
 0.8
 (0.5) —
Total other income (expense)(171.2) (209.1) (82.1) (28.2) 14.8
Income (loss) from continuing operations before non-controlling interest and income taxes123.2
 (883.6) (1,384.0) 326.1
 186.1
Income tax (provision) benefit196.8
 (4.6) (25.7) (76.4) (67.0)
Net income (loss) from continuing operations320.0
 (888.2) (1,409.7) 249.7
 119.1
Discontinued operations:         
Income (loss) from discontinued operations, net of tax—
 —
 —
 1.0
 (2.3)
Income from discontinued operations attributable to non-controlling interest, net of tax—
 —
 —
 —
 (1.3)
Discontinued operations, net of tax—
 —
 —
 1.0
 (3.6)
Net income (loss)320.0
 (888.2) (1,409.7) 250.7
 115.5
Less: Net income (loss) from continuing operations attributable to the non-controlling interest107.2
 (428.2) (1,054.5) 126.7
 —
Net income (loss) attributable to EnLink Midstream, LLC$212.8
 $(460.0) $(355.2) $124.0
 $115.5
Predecessor interest in net income$—
 $—
 $—
 $35.5
 $—
Devon investment interest in net income (loss)$—
 $—
 $1.8
 $(2.0) $—
EnLink Midstream, LLC interest in net income (loss)$212.8
 $(460.0) $(357.0) $90.5
 $—
Net income (loss) attributable to EnLink Midstream, LLC per unit:         
Basic common unit$1.18
 $(2.56) $(2.17) $0.55
 $—
Diluted common unit$1.17
 $(2.56) $(2.17) $0.55
 $—
Distributions declared per common unit$1.024
 $1.020
 $1.005
 $0.865
 $0.520
(1)Includes related party cost of sales of $211.0 million, $150.1 million, $141.3 million, $354.3 million and $1,588.2 million for the years ended December 31, 2017, 2016, 2015, 2014 and 2013, respectively.
(2)Includes related party operating expense of $0.6 million, $0.5 million, $0.5 million, $5.9 million and $36.2 million for the years ended December 31, 2017, 2016, 2015, 2014 and 2013, respectively.
(3)Includes related party general and administrative expenses of $11.6 million and $45.1 million for the years ended December 31, 2014 and 2013, respectively. Related party general and administrative expenses, if any, subsequent to December 31, 2014, were not material.
(4)Prior to March 7, 2014, our financial results only included the assets, liabilities and operations of the Predecessor. Beginning on March 7, 2014, our financial results also consolidated the assets, liabilities and operations of the legacy business of ENLK prior to giving effect to the Business Combination.


 EnLink Midstream, LLC
 Year Ended December 31,
 2017 2016 2015 2014 2013
 (In millions)
Balance Sheet Data (end of period):         
Property and equipment, net$6,587.0
 $6,256.7
 $5,666.8
 $5,042.8
 $1,768.1
Total assets10,537.8
 10,275.9
 9,541.3
 10,206.7
 2,309.8
Long-term debt (including current maturities)3,542.1
 3,295.3
 3,066.8
 2,022.5
 —
Members' equity including non-controlling interest5,556.7
 5,265.6
 5,424.9
 7,074.8
 —


Item 7. 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 Item 1—Business. Certain items related to the year ended December 31, 2020 and 2019 and year-to-year comparisons of the year ended December 31, 2020 and the year ended December 31, 2019 have been recast to conform to current period presentation, and therefore are shown below. Items that remain unchanged from the discussion in our prior year’s Annual Report on Form 10-K can be found in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7 of ENLC’s Annual Report on Form 10-K for the year ended December 31, 2020.


In this report, the terms “Company” or “Registrant,” as well as the terms “ENLC,” “our,” “we,” “us”“us,” or like terms, are sometimes used as abbreviated references to EnLink Midstream, LLC itself or EnLink Midstream, LLC andtogether with its consolidated subsidiaries, including ENLK and its consolidated subsidiaries. References in this report to “EnLink Midstream Partners, LP,” the “Partnership,” “ENLK”“ENLK,” or like terms refer to EnLink Midstream Partners, LP itself or EnLink Midstream Partners, LP together with its consolidated subsidiaries, including EnLink Midstreamthe Operating LP (the “Operating Partnership”) and EnLink Oklahoma Gas Processing, LP (“EnLink Oklahoma T.O.”). Readers are advised to refer to the context in which terms are used, and to read this report in conjunction with other information concerning our business in “Item 1A. Risk Factors” and otherwise.Partnership.


Overview


We areENLC is a Delaware limited liability company formed in October 2013. OurENLC’s assets consist of equity interests in EnLink Midstream Partners, LP and EnLink Oklahoma T.O. ENLK is a publicly traded limited partnership engaged in the gathering, transmission, processing and marketing of natural gas and natural gas liquids, or NGLs, condensate and crude oil, as well as providing crude oil, condensate and brine services to producers. EnLink Oklahoma T.O., a partnership owned by ENLK and us, is engaged in the gathering and processing of natural gas. Our interests in ENLK and EnLink Oklahoma T.O. consistedall of the following as of December 31, 2017:

88,528,451outstanding common units representing an aggregate 21.7% limited partner interest in ENLK;
100.0% ownership interest in EnLink Midstream GP, LLC, the general partner of ENLK (the “General Partner”), which owns a 0.4% general partner interest and all of the incentive distribution rights in ENLK;membership interests of the General Partner. All of our midstream energy assets are owned and
16.1% limited partner interest in EnLink Oklahoma T.O.

Each of operated by ENLK and EnLink Oklahoma T.O is required by its partnership agreement to distribute all its cash on hand at the end of each quarter, less reserves established by its general partner in its sole discretion to provide for the proper conduct of ENLK’s or EnLink Oklahoma T.O.’s business, as applicable, or to provide for future distributions.

The incentive distribution rights in ENLK entitle us to receive an increasing percentage of cash distributed by ENLK as certain target distribution levels are reached. Specifically, they entitle us to receive 13.0% of all cash distributed in a quarter after each unit has received $0.25 for that quarter, 23.0% of all cash distributed after each unit has received $0.3125 for that quarter and 48.0% of all cash distributed after each unit has received $0.375 for that quarter.

Since we control the General Partner interest in ENLK, we reflect our ownership interest in ENLK on a consolidated basis, which means that our financial results are combined with ENLK’s financial results and the results of our other subsidiaries. Our consolidated results of operations are derived from the results of operations of ENLK and also include our deferred taxes, interest of non-controlling partners in ENLK’s net income, interest income (expense) and general and administrative expenses not reflected in ENLK’s results of operations. Accordingly, the discussion of our financial position and results of operations in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” primarily reflects the operating activities and results of operations of ENLK.

We primarily focus on providing midstream energy services, including:


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


Our midstream energy asset network includes approximately 11,00012,100 miles of pipelines, 2022 natural gas processing plants with approximately 4.85.5 Bcf/d of processing capacity, 7seven fractionators with approximately 260,000320,000 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.

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



Texas Segment.•Permian Segment. The TexasPermian segment includes our natural gas gathering, processing, and transmission activities and our crude oil operations in North Texas and the Midland and Delaware Basins (together, the “Permian Basin”) primarily in West Texas;
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.Segment. The Oklahoma segment includes our natural gas gathering, processing, and transmission activities, in Cana-Woodford, Arkoma-Woodford, Northern Oklahoma Woodford, Sooner Trend Anadarko Basin Canadian and Kingfisher Counties (“STACK”) and Central Northern Oklahoma Woodford Shale (“CNOW”) areas;

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

Crude and Condensate Segment. The Crude and Condensate segment includes our Ohio River Valley (“ORV”) crude oil, condensate, condensate stabilization, natural gas compression and brine disposal activities in the Utica and Marcellus Shales, our crude oil operations in the Permian BasinCana-Woodford, Arkoma-Woodford, northern Oklahoma Woodford, STACK, and Central OklahomaCNOW shale areas;

•North Texas Segment. The North Texas segment includes our natural gas gathering, processing, and our crude oiltransmission activities associated with our Victoria Express Pipelinein North Texas; and related truck terminal and storage assets (“VEX”) located in the Eagle Ford Shale; and


•Corporate Segment.Segment. The Corporate segment includes our unconsolidated affiliate investments in the Cedar Cove joint venture (“Cedar Cove JV”)JV in Oklahoma, our contractual right to the economic benefits and burdens associated with Devon Energy Corporation’s (“Devon”) ownership interest in Gulf Coast Fractionators (“GCF”)GCF in South Texas, and our general corporate propertyassets and expenses. Until March 2017, the Corporate segment included our unconsolidated affiliate investment in Howard Energy Partners (“HEP”), which we divested in March 2017.

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We manage our consolidated operations by focusing on adjusted gross operating 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 each transactionmost of our transactions is the use of our assets to transport a product or provide a processed product to an end-user or other marketer or pipeline at the tailgate of the plant, pipeline, or barge, terminaltruck, or pipeline. We definerail terminal. Adjusted gross operating margin as operating revenue minus cost of sales. Gross operating margin is a non-GAAP financial measure and is explained in greater detail under “Non-GAAP Financial Measures” below. Approximately 94%89% of our adjusted gross operating margin was derived from fee-based contractual arrangements with minimal direct commodity price exposure for the year ended December 31, 2017. We reflect revenue as “Product sales”2021.

Our revenues and “Midstream services” on the consolidated statements of operations.

We generate revenuesadjusted 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.


OurThe following customers individually represented greater than 10% of our consolidated revenues during 2021, 2020, or 2019. These customers represented a significant percentage of our consolidated revenues, and the loss of these customers would have a material adverse impact on our results of operations because the revenues and adjusted gross operating margins are determined primarily bymargin received from transactions with these customers is material to us. No other customers represented greater than 10% of our consolidated revenues during the volumes of:periods presented.


natural gas gathered, transported, purchased and sold through our pipeline systems;
Year Ended December 31,
202120202019
Devon6.7 %14.4 %10.5 %
Dow Hydrocarbons and Resources LLC14.5 %13.2 %10.0 %
Marathon Petroleum Corporation13.4 %12.2 %13.8 %
natural gas processed at our processing facilities;

NGLs handled at our fractionation facilities or transported through our pipeline systems;
crude oil and condensate handled at our crude terminals;
crude oil and condensate gathered, transported, purchased and sold;
condensate stabilized;
brine disposed; and
natural gas, crude oil and NGLs stored.


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 maximumspecified 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.


On occasion, we have entered into certain purchase/sale transactions in which the purchase price is based on a production-area index and the sales price is based on a market-area index, and we capture the difference in the indices (also referred to as “basis spread”), less the transportation expenses from the two areas, as our fee. Changes in the basis spread can increase or decrease our margins or potentially result in losses. For example, we are a party to one contract associated with our North Texas operations with a term to July 2019 to supply approximately 150,000 MMBtu/d of gas. We buy gas for this contract on several different production-area indices and sell the gas into a different market area index. We realize a cash loss on the delivery of gas under this contract each month based on current prices. The fair value of this performance obligation was recorded based on forecasted discounted cash obligations in excess of market prices under this gas delivery contract. As of December 31, 2017, the balance sheet reflects a liability of $26.9 million related to this performance obligation. Narrower basis spreads in recent periods have increased the losses on this contract, and greater losses on this contract could occur in future periods if these conditions persist or become worse.

We typically buy mixed NGLs from our suppliers onto 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 operating margins from product upgrades during periods with higher NGL prices.

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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 deduction,transportation deduction. We then transport and resell the crude oil and condensate at the same market index.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 operating margins from our gathering and processing services primarily through different contractual arrangements: processing margin (“margin”) contracts, percentage of liquids (“POL”)POL contracts, percentage of proceeds (“POP”)POP contracts, fixed-fee componentbased contracts, or a combination of these contractual arrangements. See “Item 7A. 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 only 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 operating margins are higher during periods of high NGL prices relative to natural gas prices. Gross operatingAdjusted 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. Gross operatingAdjusted 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 operating 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 asset. 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 Growth Developments Affecting Industry Conditions and Our Business


Organic GrowthCurrent Market Environment


Central Oklahoma Plants. In 2017,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 completed construction of two new cryogenic gas processing plants, which included the Chisholm II plant completed in April 2017operate and the Chisholm III plant completed in December 2017. Each plant provides 200 MMcf/d of processing capacityvarious factors that affect this production, including commodity prices, capital markets trends, competition, and is connectedregulatory changes. We believe these factors will continue to newaffect production and existing gathering pipelinetherefore the demand for midstream services and compression assetsour business in the STACK playfuture. 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 Oklahoma. The new capacitythis section.

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

There has been, and we believe there will continue to be, volatility in commodity prices and in the relationships among NGL, crude oil, and natural gas prices. Although commodity markets have recovered from the reduction in global demand and low market prices experienced in 2020 due to the COVID-19 pandemic, oil and natural gas prices continue to remain volatile. Natural gas prices, in particular, have risen quickly during 2021, and at the date of this report, the market price is at a level higher than it 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
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and focus on higher investment returns even if it means lower growth. In addition, the ability of companies in the oil and gas industry to access the capital markets on favorable terms has been somewhat negatively impacted. This demand by investors for increased capital discipline from energy companies, as well as the difficulties in accessing capital markets, has led to more modest capital investment by producers, curtailed drilling and production activity, and, accordingly, slower growth for us and other midstream companies during the past few years. This trend was amplified in 2020 by the COVID-19 pandemic, which reduced demand for commodities. Although volumes have now recovered to pre-pandemic levels, global capital investments by oil and natural gas producers remain at relatively low levels compared to historical levels and producers remain cautious, even as crude oil and natural gas prices increased during 2021.

Producers generally focus their drilling activity on certain producing basins depending on commodity price fundamentals and favorable drilling economics. In the last few years, many producers have increasingly focused their activities in the Permian Basin, because of the availability of higher investment returns. Currently, a large percentage of all drilling rigs operating in the 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. In contrast, 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, supported by newregional industrial activity and existing long-term contracts.

In addition, weexport markets. Our activities and, in turn, our financial performance in the Louisiana segment are constructing an additional 200 MMcf/d gas processing plant, referred to as the “Thunderbird plant” to expand our Central Oklahoma processing capacity. We expect to begin operationshighly dependent on the Thunderbird plantavailability 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.”

Extreme Weather Events

From time to time our operations may be affected by extreme weather events. 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 the Company’s facilities and activities across the Company’s footprint, as it did for producers and other midstream companies located in these areas. The severe cold temperatures caused production freeze-offs and also led some producers to proactively shut-in their wells to preserve well integrity. As a result, the Company’s gathering and processing volumes were significantly reduced during this period, with peak volume declines ranging between 44% and 92%, depending on the region. The Company responded to the challenges presented by the storm by taking active steps to ensure the resiliency of the Company’s assets and the protection of the health and well-being of its employees. The Company’s operations and its gathering and processing volumes returned to normal levels by the end of the first quarter of 2019.2021.


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.

During the third quarter of 2021, we experienced a temporary loss of some processing volumes in our Louisiana operations due to the effects of Hurricane Ida, which forced a temporary shut-down of some of our operations and those of our downstream customers. All of our affected operations and those of our downstream customers have now returned to normal levels.

COVID-19 Update

On March 11, 2020, the World Health Organization declared the ongoing coronavirus (COVID-19) outbreak a pandemic and recommended containment and mitigation measures worldwide.

Since the outbreak began, our first priority has been the health and safety of our employees and those of our customers and other business counterparties. Beginning in March 2020, we implemented preventative measures and developed a response plan to minimize unnecessary risk of exposure and prevent infection, while supporting our customers’ operations, and we continue to follow these plans. We also continue to promote heightened awareness and vigilance, hygiene, and implementation of more
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stringent cleaning protocols across our facilities and operations and we continue to evaluate and adjust our preventative measures, response plans and business practices with the 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.

There remains considerable uncertainty regarding how long the COVID-19 pandemic (including variants of the virus) will persist and affect economic conditions and the extent and duration of changes in consumer behavior.

We cannot predict the full impact that the COVID-19 pandemic or the 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) at this time due to numerous uncertainties. The ultimate impacts will depend on future developments, including, among others, the ultimate duration and persistence of the pandemic, the impact of the Delta and Omicron 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 conditionsfully resume. Although crude oil and natural gas prices and production activities have recovered to pre-pandemic levels, producers remain cautious and a decline in commodity prices could affect producers’ exploration and production activities.A sustained significant decline in oil and natural gas exploration and production activities and related reduced demand for our services by our customers, whether due to decreases in consumer demand or reduction in the prices for crude oil, condensate, natural gas, and NGLs or otherwise, would have a material adverse effect on our business, liquidity, financial condition, results of operations, and cash flows (including our ability to make distributions to our unitholders).

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.”

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 2017,15, 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. 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.
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For more information, see our risk factors under “Environmental, Legal Compliance and Regulatory Risk” in Section 1A “Risk Factors.”

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.

Bridgeport CO2 Project. In November 2021, we entered into an agreement with Continental Carbonic Products, Inc., a long-term, fee-based arrangement with Oneok Partners (“Oneok”) under which Oneok transports NGLswholly owned subsidiary of Matheson Tri-Gas, Inc., and member of the Nippon Sanso Holdings Corporation group of companies, to capture and sell CO2 emitted from our ChisholmBridgeport processing facility to the Gulf Coast and our Cajun-Sibon system.plant in North Texas. The agreement allows us to retain control of volumes and preferentially fill our Cajun-Sibon system.

Black Coyote Crude Oil Gathering System. In the fourth quarter of 2017, we began construction of a new crude oil gathering system that we refer to as “Black Coyote,” which will expand our operations in the core of the STACK play in Central Oklahoma. Black Coyote is being built primarily on acreage dedicated from Devon, whichCO2 will be the main shippersold on the system. The systema firm basis for 15 years and will be converted into food-grade products. This project is expected to be operational in the first quarterservice in early 2024. The project makes meaningful progress toward our goal of 2018. a 30% reduction in total CO2-equivalent emissions intensity by 2030, while being modestly profitable.


Lobo Natural Gas Gathering and Processing Facilities. The Lobo facilities are part of our joint venture (the “Delaware Basin JV”) with an affiliate of NGP Natural Resources XI, LP (“NGP”) and are supported by long-term contracts. In the first quarter of 2017,Amarillo Rattler Acquisition. On April 30, 2021, we completed the expansionacquisition of Amarillo Rattler, LLC, the owner of a 75-mile gathering and processing system forlocated in the Midland Basin. In connection with the purchase, we entered into an amended and restated gas gathering and processing agreement with Diamondback Energy, strengthening our Lobo IIdedicated acreage position with that entity. We acquired the system with an upfront payment of $50.0 million, which was paid with cash-on-hand, with an additional $10.0 million to be paid on April 30, 2022, and contingent consideration capped at $15.0 million and payable between 2024 and 2026 based on Diamondback Energy’s drilling activity above historical levels.

Organic Growth

Phantom Processing Plant. In November 2021, we began moving equipment and facilities associated with the Thunderbird processing facility. Inplant in Central Oklahoma to the Midland Basin. This processing plant relocation is expected to increase the processing capacity of our Permian Basin processing facilities by approximately 200 MMcf/d. We expect to complete the relocation in the second quarterhalf of 2017,2022.

War Horse Processing Plant. In December 2020, we began moving equipment and facilities previously associated with the Battle Ridge processing plant in Central Oklahoma to the Permian Basin. The move has been completed and the War Horse processing plant began operations in August 2021. In November 2021, we completed an expansion to the War Horse processing plant, which increased the processing capacity to 95 MMcf/d.

Riptide Processing Plant. The Riptide processing plant is a gas processing plant located in the Midland Basin. In March 2020, we completed an expansion to the Riptide processing plant, which increased the processing capacity to 240 MMcf/d.

Tiger processing plant. The Tiger processing plant is a gas processing plant located in the Delaware Basin. This processing plant is owned by the Delaware Basin JV. In August 2020, we completed the construction of an expansion of the Lobo II processing facility, which provided an additional 60 MMcf/d of processing capacity to the existing 95 MMcf/d provided by the Lobo processing facilities. Furthermore, we are constructing an additional expansion of the Lobo II processing facility, which will increase capacity by 15 MMcf/d and is expected to be completed during the first half of 2018. In 2018, we will also expand our gas processing capacity at our Lobo facilities by 200 MMcf/d through the construction of the Lobo III cryogenic gasTiger processing plant, which expanded our Delaware Basin processing capacity by an additional 240 MMcf/d, to handle expected future processing volume growth.

Long-Term Debt Issuances, Repurchases, and Repayments

Term Loan. In December 2020, May 2021, and September 2021, we repaid $500.0 million, $100.0 million, and $100.0 million, respectively, of the borrowings under the Term Loan. The remaining $150.0 million of the Term Loan was repaid at maturity on December 10, 2021.

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

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

On September 24, 2021, the SPV entered into the second half of 2018. 

Greater Chickadee Crude Oil Gathering System.In March 2017, we completed constructionamendment to the AR Facility that, among other things: (i) increased the AR Facility limit and began operations of a crude oil gathering system in Upton and Midland counties, Texas in the Permian Basin, which we refer to as “Greater Chickadee.” Greater Chickadee includes over 185 miles of high- and low-pressure pipelines that transport crude oil volumes to several major market outlets and other key hub centers in the Midland, Texas area and is supportedlender commitments by long-term contracts. Greater Chickadee also includes multiple central tank batteries, together with pump, truck injection and storage stations to maximize shipping and delivery options for our producer customers.

Marathon Petroleum Joint Venture. In April 2017, we completed construction and began operating a new NGL pipeline, which is part of our 50/50 joint venture with a subsidiary of Marathon Petroleum Company (“Marathon Petroleum”). This joint venture, Ascension Pipeline Company, LLC (the “Ascension JV”), is a bolt-on project to our Cajun-Sibon NGL system and is supported by long-term, fee-based contracts with Marathon Petroleum.

Sale of Non-Core Assets

In March 2017, we completed the sale of our ownership interest in HEP for net proceeds of $189.7 million. For the year ended December 31, 2016, we recorded an impairment loss of $20.1$50.0 million to reduce$350.0 million, (ii) extended the carrying valuescheduled termination date of our investmentthe facility from October 20, 2023 to September 24, 2024, and (iii) reduced the expected sales price. Uponeffective drawn fee to 1.10% rather than the sale of HEP in March 2017, we recorded an additional loss of $3.4 million for the year ended December 31, 2017 based on the adjusted sales price at closing.previous 1.25%.


Redemption of ENLK Senior Unsecured Notes due 2022

Notes. On June 1, 2017, ENLK redeemed $162.5 million in aggregate principal amount of its 7.125% senior unsecured notes (the “2022 Notes”) at 103.6% of the principal amount, plus accrued unpaid interest, for aggregate cash consideration of $174.1 million, which resulted in a gain on extinguishment of debt of $9.0 million for the year ended December 31, 2017.


Issuance of ENLK Senior Notes

On May 11, 2017, ENLK14, 2020, ENLC issued $500.0 million in aggregate principal amount of its 5.450%ENLC’s 5.625% senior unsecured notes due June 1, 2047January 15, 2028 (the “2047“2028 Notes”) at a price to the public of 99.981%100% of their face value. Interest payments on the 2047 Notes are payable on June 1 and December 1 of each year. Net proceeds of approximately $495.2 million were used to repay outstanding borrowings under ENLK’s credit facility (the “ENLK Credit Facility”) and for general partnership purposes.

On July 14, 2016, ENLK issued $500.0 million in aggregate principal amount of 4.850% senior notes due 2026 (the “2026 Notes”) at a price to the public of 99.859% of their face value. The 2026 Notes mature on July 15, 2026. Interest payments on the 20262028 Notes are payable on January 15 and July 15 of each year. The 2028 Notes are fully and unconditionally guaranteed by ENLK. Net proceeds of approximately $495.7$494.7 million were used to repay outstandinga portion of the borrowings under the ENLK Credit Facility and for general partnership purposes.Term Loan, which matured in December 2021.


Equity Issuances

Issuance of ENLK Common Units. In November 2014, ENLK entered into an Equity Distribution Agreement (the “2014 EDA”) with BMO Capital Markets Corp. and other sales agents to sell up to $350.0 million in aggregate gross sales of ENLK common units from time to time through an “at the market” equity offering program. In August 2017, ENLK ceased trading under the 2014 EDA and entered into an Equity Distribution Agreement (the “2017 EDA”) with UBS Securities LLC and other sales agents (collectively, the “Sales Agents”) to sell up to $600.0 million in aggregate gross sales of ENLK common units from time to time through an “at the market” equity offering program. ENLK may also sell common units to any Sales Agent as principal for the Sales Agent’s own account at a price agreed upon at the time of sale. ENLK has no obligation to sell any ENLK common units under the 2017 EDA and may at any time suspend solicitation and offers under the 2017 EDA.

For the year ended December 31, 2017,2020, we and ENLK sold anmade aggregate payments to partially repurchase the 2024, 2025, 2026, and 2029 Notes in open market transactions. For the year ended December 31, 2021, we and ENLK did not repurchase any senior notes. Activity related to the 2020 partial repurchases of approximately 6.2 million ENLK common units underour outstanding debt consisted of the 2014 EDAfollowing (in millions):
Year Ended December 31, 2020
Debt repurchased$67.7 
Aggregate payments(36.0)
Net discount on repurchased debt(0.3)
Accrued interest on repurchased debt0.6 
Gain on extinguishment of debt$32.0 

See “Item 8. Financial Statements and Supplementary Data—Note 6” for more information regarding the Term Loan, the AR Facility, and the 2017 EDA, generating proceedssenior unsecured notes.

Common Unit Repurchase Program

In November 2020, the board of approximately $106.9 million (netdirectors of approximately $1.1the Managing Member authorized a common unit repurchase program for the repurchase of up to $100.0 million of commissions and $0.2 million of registration fees). ENLK used the net proceeds for general partnership purposes. As of December 31, 2017, approximately $565.4 million remains available to be issued under the 2017 EDA.

Issuance of Series C Preferred Units. In September 2017, ENLK issued 400,000Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the “Series C Preferred Units”) representing ENLK limited partner interests at a price to the public of $1,000 per unit. ENLK used the net proceeds of $394.0 million for capital expenditures, general partnership purposes and to repay borrowings under the ENLK Credit Facility. The Series C Preferred Units represent perpetual equity interests in ENLK and, unlike ENLK’s indebtedness, will not give rise to a claim for payment of a principal amount at a particular date. As to the payment of distributions and amounts payable on a liquidation event, the Series C Preferred Units rank senior to ENLK’soutstanding 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 each other class$100.0 million effective January 1, 2022.

For the year ended December 31, 2021, ENLC repurchased 6,091,001 outstanding ENLC common units for an aggregate cost, including commissions, of limited partner interests$40.1 million, or other equity securities established afteran average of $6.59 per common unit. For the issue dateyear ended December 31, 2020, ENLC repurchased 383,614 outstanding ENLC common units for an aggregate cost, including commissions, of the$1.2 million, or an average of $3.02 per common unit.

Redemption of Series CB Preferred Units that is not expressly made senior or on parity with the Series C Preferred Units. The Series C Preferred Units rank junior to the

In December 2021, we redeemed 3,300,330 Series B Preferred Units with respect to the paymentfor total consideration of distributions, and junior to the$50.0 million plus accrued distributions. In addition, upon such redemption, a corresponding number of ENLC Class C Common Units were automatically cancelled. In January 2022, we redeemed an additional 3,333,334 Series B Preferred Units for total consideration of $50.5 million plus accrued distributions and, all current and future indebtedness with respect to amounts payable upon such redemption, a liquidation event.

At any time on or after December 15, 2022, ENLK may redeem, at its option, in whole or in part, the Seriescorresponding number of ENLC Class C PreferredCommon Units at awere automatically cancelled. The redemption price in cash equal to $1,000 per Series C Preferred Unit plus an amount equal to all accumulatedfor both the December 2021 and unpaid distributions, whether or not declared. ENLK may undertake multiple partial redemptions. In addition, at any time within 120 days after the conclusion of any review or appeal process instituted by ENLK following certain rating agency events, ENLK may redeem, at its option, the Series C Preferred Units in whole at a redemption price in cash per unit equal to $1,020 plus an amount equal to all accumulated and unpaid distributions, whether or not declared.

Distributions on the Series C Preferred Units accrue and are cumulative from the date of original issue and payable semi-annually in arrears on the 15th day of June and December of each year through and including December 15,January 2022 and, thereafter, quarterly in arrears on the 15th day of March, June, September and December of each year, in each case, if and when declared by ENLK’s general partner out of legally available funds for such purpose. The initial distribution rate for the Series C Preferred Units from and including the date of original issue to, but not including, December 15, 2022 is 6.0% per annum. On and after December 15, 2022, distributions on the Series C Preferred Units will accumulate for each distribution period at a percentageredemptions was 101% of the $1,000 liquidation preference per unit equal to an annual floating rate of the three-month LIBOR plus a spread of 4.11%.
Issuance of Series B Preferred Units. preferred units’ par value. In January 2016, ENLK issued an aggregate of 50,000,000 Series B Preferred Units representing ENLK’s limited partner interests to Enfield Holdings, L.P. (“Enfield”) in a private placement for a cash purchase

price of $15.00 perconnection with these Series B Preferred Unit (the “Issue Price”), resulting in net proceeds of approximately $724.1 million after fees and deductions. Proceeds from the private placement were used to partially fund ENLK’s portion of the purchase price payable in connectionredemptions, we have agreed with the acquisition of our EnLink Oklahoma T.O. assets. Affiliates of the Goldman Sachs Group, Inc. and affiliates of TPG Global, LLC own interests in the general partner of Enfield. The Series B Preferred Units are convertible into ENLK common units on a one-for-one basis, subject to certain adjustments, (a) in full, at ENLK’s option, if the volume weighted average price of a common unit over the 30-trading day period ending two trading days prior to the conversion date (the “Conversion VWAP”) is greater than 150% of the Issue Price or (b) in full or in part, at Enfield’s option. In addition, upon certain events involving a change of control of the General Partner or the Managing Member of ENLC, allholders of the Series B Preferred Units that we will automatically convert intopay cash in lieu of making a numberquarterly PIK distribution through the distribution declared for the fourth quarter of ENLK common units equal2022. See “Item 8. Financial Statements and Supplementary Data—Note 8” for more information regarding distributions with respect to the greater of (i) the number of ENLK common units into which the Series B Preferred Units would then convert and (ii) the numberUnits.
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For each of the calendar quarters between March 31, 2016 through June 30, 2017, Enfield received a quarterly distribution equal to an annual rate of 8.5% on the Issue Price payable in-kind in the form of additional Series B Preferred Units. For the quarter ended September 30, 2017 and each subsequent quarter, Enfield received or is entitled to receive a quarterly distribution, subject to certain adjustments, equal to an annual rate of 7.5% on the Issue Price payable in cash (the “Cash Distribution Component”) plus an in-kind distribution equal to the greater of (A) 0.0025 Series B Preferred Units per Series B Preferred Unit and (B) an amount equal to (i) the excess, if any, of the distribution that would have been payable had the Series B Preferred Units converted into ENLK common units over the Cash Distribution Component, divided by (ii) the Issue Price.

Acquisitions, Organic Growth and Asset Sales in 2015 and 2016

In January 2015, we acquired 100% of the voting equity interests of LPC Crude Oil Marketing LLC (“LPC”), which has crude oil gathering, transportation and marketing operations in the Permian Basin, for approximately $108.1 million.Contents

In March 2015, we acquired 100% of the voting equity interests in Coronado Midstream Holdings LLC (“Coronado”), which owns natural gas gathering and processing facilities in the Permian Basin, for approximately $600.3 million.

In April 2015, we acquired VEX, located in the Eagle Ford Shale in South Texas, together with 100% of the voting equity interests (the “VEX interests”) in certain entities, from Devon in a drop down transaction (the “VEX Drop Down”) for $166.7 million in cash and approximately $9.0 million in ENLK common units. Additionally, we assumed $40.0 million in construction costs related to VEX.

In October 2015, we acquired 100% of the voting equity interests in a subsidiary of Matador Resources Company (“Matador”), which has gathering and processing operations in the Delaware Basin, for approximately $141.3 million.

Prior to November 2015, we co-owned the Deadwood natural gas processing plant with a subsidiary of Apache Corporation (“Apache”). In November 2015, we acquired Apache’s 50% ownership interest in the Deadwood natural gas processing facility for approximately $40.1 million. We now own 100% of the Deadwood processing plant.

In 2015, Acacia contributed the remaining 50% interest in Midstream Holdings to ENLK in exchange for 68.2 million ENLK common units in two separate drop down transactions, with 25% contributed in February 2015 and 25% contributed in May 2015 (the “EMH Drop Downs”). After giving effect to the EMH Drop Downs, ENLK owns 100% of Midstream Holdings.

In January 2016, ENLK and ENLC acquired an 83.9% and 16.1% interest, respectively, in EnLink Oklahoma T.O. for aggregate consideration of approximately $1.4 billion. The EnLink Oklahoma T.O. assets serve gathering and processing needs in the growing STACK and CNOW plays in Central Oklahoma and are supported by long-term, fixed-fee contracts with acreage dedications that, at the time of acquisition, had a weighted-average term of approximately 15 years.

In April 2016, we completed construction of the 100 MMcf/d Riptide processing plant in the Permian Basin.

In August 2016, we formed the Delaware Basin JV with NGP to operate and expand our natural gas, natural gas liquids and crude oil midstream assets in the Delaware Basin. The Delaware Basin JV is owned 50.1% by us and 49.9% by NGP.


In October 2016, we completed construction of the initial phase of the 60 MMcf/d Lobo II processing facilities.

In November 2016, we formed the Cedar Cove JV with Kinder Morgan, Inc., which consists of gathering and compression assets in Blaine County, Oklahoma, located in the heart of the STACK play. The gathering system has a capacity of 25 MMcf/d with over 50,000 gross acres of dedications and ties into our existing Oklahoma assets. All gas gathered by the Cedar Cove JV is processed at our Central Oklahoma processing system. We hold a 30% ownership interest of the Cedar Cove JV, and Kinder Morgan, Inc. holds the remaining 70% ownership interest.

In December 2016, we sold the North Texas Pipeline (the “NTPL”), a 140-mile natural gas transportation pipeline, for $84.6 million. We maintain capacity on the NTPL at competitive rates and at levels sufficient to support current and expected operations. As a result of the sale, we recorded a loss of $13.4 million for the year ended December 31, 2016.


Non-GAAP Financial Measures


We includeTo assist management in assessing our business, we use the following non-GAAP financial measures: cash available for distributionadjusted gross margin; adjusted earnings before interest, taxes, and gross operating margin.

Cash Available for Distribution

We calculate cash available for distribution as distributions due to us from ENLK, plus our interest in EnLink Oklahoma T.O. depreciation and amortization (“adjusted EBITDA (as defined herein)EBITDA”); and our interest in Midstream Holdings adjusted EBITDA (as defined herein) prior to the EMH Drop Downs, less our share of maintenance capital attributable to our interest in EnLink Oklahoma T.O., our specific general and administrative costs as a separate public reporting entity, the interest costs associated with our debt and current taxes attributable to our earnings. ENLC’s share of EnLink Oklahoma T.O. growth capital expenditures are funded by borrowings under ENLC’s revolving credit facility (the “ENLC Credit Facility”) and not considered in determining ENLC’sfree cash flow available for distribution.after distributions.

We also calculate cash available for distribution as net income (loss) of ENLC less the net income (loss) attributable to ENLK, which is consolidated into ENLC’s net income (loss), plus ENLC's (i) share of distributions from ENLK, (ii) share of EnLink Oklahoma T.O.’s non-cash expenses, (iii) deferred income tax (benefit) expense, (iv) interest in the adjusted EBITDA of Midstream Holdings prior to the EMH Drop Downs, (v) corporate goodwill impairment and (vi) acquisition transaction costs attributable to its share of the EnLink Oklahoma T.O. acquisition, less ENLC’s interest in maintenance capital expenditures of EnLink Oklahoma T.O. and Midstream Holdings and less third-party non-controlling interest share of net income (loss) from consolidated affiliates.

Cash available for distribution is a supplemental performance measure used by us and by external users of our financial statements, such as investors, commercial banks, research analysts and others to measure ENLC’s profitability and performance in creating value for its unitholders. As ENLC is a holding company without any direct operations, ENLC primarily generates value for its unitholders by generating returns on its investments in other entities and subsequently distributing these returns in cash to its unitholders. Therefore, cash available for distribution serves as an important measure of ENLC’s profitability and serves as an indicator of ENLC’s success in providing a cash return on its investments to its unitholders.

Maintenance capital expenditures include capital expenditures made to replace partially or fully depreciated assets in order to maintain the existing operating capacity of the assets and to extend their useful lives. Examples of maintenance capital expenditures are expenditures to refurbish and replace pipelines and other gathering, well connection, compression and processing assets up to their original operating capacity, to maintain equipment reliability, integrity and safety and to address environmental laws and regulations.
The GAAP measure most directly comparable to cash available for distribution is net income (loss). Cash available for distribution should not be considered as an alternative to GAAP net income (loss). Cash available for distribution is not a presentation made in accordance with GAAP and has important limitations as an analytical tool. Investors should not consider cash available for distribution in isolation or as a substitute for analysis of our results as reported under GAAP. Because cash available for distribution excludes some items that affect net income (loss) and is defined differently by different companies in our industry, our definition of cash available for distribution may not be comparable to similarly-titled measures of other companies, thereby diminishing its utility.


The following is a calculation of our cash available for distribution (in millions):
 Year Ended December 31,
 2017 2016 2015
Distribution declared by ENLK associated with (1):     
General partner interest$2.5
 $2.1
 $2.4
Incentive distribution rights58.9
 56.8
 47.5
ENLK common units owned138.1
 138.1
 104.5
Total share of ENLK distributions declared$199.5
 $197.0
 $154.4
Transferred interest EBITDA (2)—
 —
 53.7
Adjusted EBITDA of EnLink Oklahoma T.O. (3)22.3
 9.0
 —
Transaction costs (4)—
 0.6
 —
Total cash available$221.8
 $206.6
 $208.1
Uses of cash:     
General and administrative expenses(4.8) (2.8) (4.1)
Current income taxes (5)2.2
 (0.6) 0.1
Interest expense(2.5) (1.4) (0.8)
Maintenance capital expenditures (6)(0.2) (0.1) (4.0)
Total cash used$(5.3) $(4.9) $(8.8)
ENLC cash available for distribution$216.5
 $201.7
 $199.3
(1)
Represents distributions paid to ENLC on February 13, 2018, November 13, 2017, August 11, 2017, May 12, 2017, February 13, 2017, November 11, 2016, August 11, 2016, May 12, 2016, February 11, 2016, November 12, 2015, August 13, 2015 and May 14, 2015.
(2)
Represents our interest in Midstream Holdings adjusted EBITDA, which was disbursed to ENLC by Midstream Holdings on a monthly basis prior to the transfer of all interests in Midstream Holdings to the Partnership in the EMH Drop Downs. Midstream Holdings’ adjusted EBITDA is defined as net income (loss) plus interest expense, provision for income taxes, depreciation and amortization expense, impairment expense, unit-based compensation, (gain) loss on non-cash derivatives, (gain) loss on disposition of assets, successful acquisition transaction costs, accretion expense associated with asset retirement obligations, reimbursed employee costs, non-cash rent, and distributions from unconsolidated affiliate investments, less payments under onerous performance obligations, non-controlling interest, and income (loss) from unconsolidated affiliate investments.
(3)Represents ENLC’s interest in EnLink Oklahoma T.O. adjusted EBITDA, which is disbursed to ENLC by EnLink Oklahoma T.O. on a monthly basis. EnLink Oklahoma T.O. adjusted EBITDA is defined as earnings before depreciation and amortization and provision for income taxes and includes allocated expenses from ENLK.
(4)
Represents acquisition transaction costs attributable to ENLC’s 16.1% interest in EnLink Oklahoma T.O, which are considered growth capital expenditures as part of the cost of the assets acquired.
(5)
Represents ENLC’s stand-alone current tax expense or benefit.
(6)
Represents ENLC’s interest in EnLink Oklahoma T.O.’s maintenance capital expenditures, which is netted against the monthly disbursement of EnLink Oklahoma T.O.s’ adjusted EBITDA per (3) above for the years ended December 31, 2017 and 2016, and ENLC’s interest in Midstream Holdings’ maintenance capital expenditures prior to the EMH Drop Downs for the year ended December 31, 2015.


The following table provides a reconciliation our net income from continuing operations to our cash available for distribution (in millions):
 Year Ended December 31,
 2017 2016 2015
Net income (loss) of ENLC$320.0
 $(888.2) $(1,409.7)
Less: Net income (loss) attributable to ENLK148.9
 (565.2) (1,377.8)
Net income (loss) of ENLC excluding ENLK171.1
 (323.0) (31.9)
ENLC's share of distributions from ENLK (1)199.5
 197.0
 154.4
ENLC's interest in EnLink Oklahoma T.O.'s non-cash expenses (2)17.4
 14.3
 —
ENLC deferred income tax (benefit) expense (3)(170.6) 2.8
 26.2
Transferred interest EBITDA (4)—
 —
 53.7
ENLC corporate goodwill impairment—
 307.0
 —
Non-controlling interest share of ENLK's net (income) loss (5)(1.1) 2.6
 0.4
Other items (6)0.2
 1.0
 (3.5)
ENLC cash available for distribution$216.5
 $201.7
 $199.3

(1)Represents distributions paid to ENLC on February 13, 2018, November 13, 2017, August 11, 2017, May 12, 2017, February 13, 2017, November 11, 2016, August 11, 2016, May 12, 2016, February 11, 2016, November 12, 2015, August 13, 2015 and May 14, 2015.
(2)
Includes depreciation and amortization and unit-based compensation expense allocated to EnLink Oklahoma T.O. for the year ended December 31, 2017, and depreciation and amortization for the year ended December 31, 2016.
(3)
Represents ENLC’s stand-alone deferred taxes. The deferred income tax benefit for the year ended December 31, 2017 included an adjustment to deferred income tax expense of $185.7 million related to a reduction in ENLC’s federal statutory rate from 35% to 21%.
(4)
Represents our interest in Midstream Holdings adjusted EBITDA, which was disbursed to ENLC by Midstream Holdings on a monthly basis prior to the transfer of all interests in Midstream Holdings to the Partnership in the EMH Drop Downs. Midstream Holdings’ adjusted EBITDA is defined as net income (loss) plus interest expense, provision for income taxes, depreciation and amortization expense, impairment expense, unit-based compensation, (gain) loss on non-cash derivatives, (gain) loss on disposition of assets, successful acquisition transaction costs, accretion expense associated with asset retirement obligations, reimbursed employee costs, non-cash rent, and distributions from unconsolidated affiliate investments, less payments under onerous performance obligations, non-controlling interest, and income (loss) from unconsolidated affiliate investments.
(5)
Represents NGP’s 49.9% share of adjusted EBITDA from the Delaware Basin JV, which was formed in August 2016, Marathon Petroleum’s 50% share of adjusted EBITDA from the Ascension JV, which began operations in April 2017, and other minor non-controlling interests.
(6)Represents ENLC’s interest in EnLink Oklahoma T.O.s’ maintenance capital expenditures (which is netted against the monthly disbursement of EnLink Oklahoma T.O.s’ adjusted EBITDA) for the years ended December 31, 2017 and December 31, 2016, transaction costs attributable to ENLC’s share of the acquisition of EnLink Oklahoma T.O. for the year ended December 31, 2016, ENLC’s interest in maintenance capital expenditures of Midstream Holdings prior to the EMH Drop Downs for the year ended December 31, 2015 and other non-cash items not included in cash available for distribution.


Adjusted Gross Operating Margin


We define adjusted gross operating margin as revenues less cost of sales.sales, exclusive of operating expenses and depreciation and amortization. We present adjusted gross operating margin by segment in “Results of Operations.” We disclose adjusted gross operating margin in addition to total revenuegross margin as defined by GAAP because it is the primary performance measure used by our management.management to evaluate consolidated operations. We believe adjusted gross operating margin is an important measure because, in general, our business is to gather, process, transport, or market natural gas, NGLs, condensate, and crude oil and condensate 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 do not deductexclude all operating expenses and depreciation and amortization from total revenue in calculatingadjusted gross operating 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 operating margin is operating income (loss). Gross operatinggross margin. Adjusted gross margin should not be considered an alternative to, or more meaningful than, operating income (loss)gross margin as determined in accordance with GAAP. Gross operatingAdjusted gross margin has important limitations because it excludes all operating costsexpenses and depreciation and amortization that affect operating income (loss) except cost of sales.gross margin. Our adjusted gross operating margin may not be comparable to similarly-titledsimilarly titled measures of other companies because other entities may not calculate these amounts in the same manner.

The following table provides a reconciliation of operating income (loss)reconciles total revenues and gross margin to adjusted gross operating margin (in millions):

Year Ended December 31,
20212020
Total revenues$6,685.9 $3,893.8 
Cost of sales, exclusive of operating expenses and depreciation and amortization(5,189.9)(2,388.5)
Operating expenses(362.9)(373.8)
Depreciation and amortization(607.5)(638.6)
Gross margin525.6 492.9 
Operating expenses362.9 373.8 
Depreciation and amortization607.5 638.6 
Adjusted gross margin$1,496.0 $1,505.3 


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Table of Contents
 Year Ended December 31,
 2017 2016 2015
Operating income (loss)$294.4
 $(674.5) $(1,301.9)
      
Add (deduct):     
Operating expenses418.7
 398.5
 419.9
General and administrative expenses128.6
 122.5
 136.9
Loss on disposition of assets—
 13.2
 1.2
Depreciation and amortization545.3
 503.9
 387.3
Impairments17.1
 873.3
 1,563.4
Gain on litigation settlement(26.0) —
 —
Gross operating margin$1,378.1
 $1,236.9
 $1,206.8
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:
Results
•the financial performance of Operationsour 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 table below sets forth certainGAAP 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 operating data for the periods indicated. We managedepreciation 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 focusing on gross operating margin, which we defineactivities as revenue less costdetermined under GAAP, as well as adjusted EBITDA, to evaluate our overall performance.
72
Table of sales as reflected in theContents
The following table belowreconciles net income (loss) to adjusted EBITDA (in millions, except volumes)millions):

Year Ended December 31,
20212020
Net income (loss)$142.9 $(315.6)
Interest expense, net of interest income238.7 223.3 
Depreciation and amortization607.5 638.6 
Impairments0.8 362.8 
(Income) loss from unconsolidated affiliate investments11.5 (0.6)
Distributions from unconsolidated affiliate investments3.9 2.1 
(Gain) loss on disposition of assets(1.5)8.8 
Gain on extinguishment of debt— (32.0)
Unit-based compensation25.3 28.4 
Income tax expense25.4 143.2 
Unrealized loss on commodity swaps12.4 10.5 
Costs associated with the relocation of processing facilities (1)28.3 0.8 
Other (2)(0.6)(1.1)
Adjusted EBITDA before non-controlling interest1,094.6 1,069.2 
Non-controlling interest share of adjusted EBITDA from joint ventures (3)(44.9)(30.7)
Adjusted EBITDA, net to ENLC$1,049.7 $1,038.5 
____________________________
 Year Ended December 31,
 2017 2016 2015
Texas Segment     
Revenues$1,365.9
 $1,068.3
 $1,000.2
Cost of sales(772.3) (483.4) (412.2)
Total gross operating margin$593.6
 $584.9
 $588.0
Louisiana Segment     
Revenues$2,931.6
 $2,001.5
 $1,840.3
Cost of sales(2,618.1) (1,729.0) (1,567.6)
Total gross operating margin$313.5
 $272.5
 $272.7
Oklahoma Segment     
Revenues$874.8
 $437.0
 $187.0
Cost of sales(522.9) (184.9) (17.9)
Total gross operating margin$351.9
 $252.1
 $169.1
Crude and Condensate Segment     
Revenues$1,453.6
 $1,176.5
 $1,498.2
Cost of sales(1,330.3) (1,038.0) (1,330.6)
Total gross operating margin$123.3
 $138.5
 $167.6
Corporate     
Revenues$(886.3) $(430.9) $(73.6)
Cost of sales882.1
 419.8
 83.0
Total gross operating margin$(4.2) $(11.1) $9.4
Total     
Revenues$5,739.6
 $4,252.4
 $4,452.1
Cost of sales(4,361.5) (3,015.5) (3,245.3)
Total gross operating margin$1,378.1
 $1,236.9
 $1,206.8
      
Midstream Volumes:     
Texas     
Gathering and Transportation (MMBtu/d)2,262,900
 2,622,600
 2,849,600
Processing (MMBtu/d)1,184,400
 1,173,100
 1,222,700
Louisiana     
Gathering and Transportation (MMBtu/d)1,995,800
 1,676,600
 1,468,300
Processing (MMBtu/d)453,300
 490,300
 506,100
NGL Fractionation (Gals/d)5,772,800
 5,197,100
 5,771,500
Oklahoma     
Gathering and Transportation (MMBtu/d)829,300
 626,300
 428,600
Processing (MMBtu/d)810,300
 574,900
 359,600
Crude and Condensate     
Crude Oil Handling (Bbls/d)108,200
 94,000
 131,500
Brine Disposal (Bbls/d)4,200
 3,600
 3,900


Year Ended December 31, 2017 Compared to Year Ended December 31, 2016

Gross Operating Margin. Gross operating margin was $1,378.1 million for the year ended December 31, 2017 compared to $1,236.9 million for the year ended December 31, 2016, an increase of $141.2 million, or 11.4%, due(1)Represents cost incurred related to the following:

Texas Segment. Gross operating margin inrelocation of equipment and facilities from the Texas segment increased $8.7 million, which was primarily due to a $25.9 million increase in gross operating margin due to higher volumes from our expansion in the Permian Basin. This increase was partially offset by a $17.2 million decrease in gross operating margin from our North TexasThunderbird processing gatheringplant and transmission assets due to volume declines across our North Texas system, including an $11.5 million decrease due to the sale of the NTPL assets in December 2016. Although we experienced volume declines for certain of our Barnett-Shale assets, the impact of these volume declines on gross operating margin was offset by an increase in revenue earned from minimum volume commitments (“MVC” or “MVCs”) (as discussed in more detail below) under our contracts with Devon. For the year ended December 31, 2017 the shortfall revenue from Devon-related MVCs was $59.2 million compared to $26.4 million for the year ended December 31, 2016.

Louisiana Segment. Gross operating margin in the Louisiana segment increased $41.0 million, which was primarily due to a $34.2 million increase in gross operating margin from our NGL transmission and fractionation assets and a $6.8 million increase in gross operating margin from our Louisiana gathering and transmission assets. The increase from our NGL business was primarily due to additional NGL volumes fractionated, including volumes received from our Oklahoma and Permian Basin assets, together with a $9.3 million gross operating margin contribution from fees earned on our Ascension JV assets, which commenced operations in April 2017. The increase from our transmission assets was primarily due to volume increases on our Louisiana Intrastate Gas and Gulf Coast pipeline systems.

Oklahoma Segment. Gross operating marginBattle Ridge processing plant, in the Oklahoma segment, increased $99.8 million, which was primarily driven by a $104.8 million increase from our Central Oklahoma assets as a result of higher volumes due to continued producer development in Oklahoma. This increase was partially offset by a $5.1 million decrease in gross operating margin from our Northridge gathering and processing assets due to price and volume reductions under a third-party contract.

Crude and Condensate Segment. Gross operating margin in the Crude and Condensate segment decreased $15.2 million, which was primarily due to a $12.8 million decrease as a result of condensate stabilization volume declines and transportation rate decreases on our ORV assets and a decrease of $8.4 million as a result of volume declines in our Midland Basin trucking business. The volume and rate declines throughout our Crude and Condensate segment were primarily attributable to increased competition due to lower crude prices. These declines were partially offset by a $4.8 million increase due to the Greater Chickadee gathering system, which became fully operational in the first quarter of 2017.

Corporate Segment. Gross operating margin in the CorporatePermian segment increased $6.9 million, which was due to the changes in fair value that are not part of our commodity swaps between periods. For the year ended December 31, 2017, there were unrealized gainsongoing operations. The relocation of $4.7 million, offset by realized losses of $8.9 million. For the year ended December 31, 2016, there were unrealized losses of $20.1 million, partially offset by realized gains of $9.0 million.

Certain gatheringequipment and processing agreements in our Texas, Oklahoma and Crude and Condensate segments provide for quarterly or annual MVCs, including MVCs from Devon from certain of our Barnett Shale assets in North Texas and our Cana plant in Oklahoma. Under these agreements, our customers agree to ship and/or process a minimum volume of production on our systems over an agreed time period. If a customer under such an agreement fails to meet its MVC for a specified period, the customer is obligated to pay a contractually-determined fee based upon the shortfall between actual production volumes and the MVC for that period. Some of these agreements also contain make-up right provisions that allow a customer to utilize gathering or processing fees in excess of the MVC in subsequent periods to offset shortfall amounts in previous periods. We record revenue under MVC contracts during periods of shortfall when it is known that the customer cannot, or will not, make up the deficiency in subsequent periods.


Revenue recorded for the shortfall between actual production volumes and the MVC were as follows (in millions):
 Texas Oklahoma Crude and Condensate Total
Year Ended December 31, 2017       
Midstream services$0.8
 $16.1
 $—
 $16.9
Midstream services—related parties59.2
 13.8
 8.9
 81.9
Total$60.0
 $29.9
 $8.9
 $98.8
        
Year Ended December 31, 2016       
Midstream services$1.9
 $9.5
 $—
 $11.4
Midstream services—related parties26.4
 10.8
 9.0
 46.2
Total$28.3
 $20.3
 $9.0
 $57.6

On January 1, 2019, certain Devon MVC agreements in the Texas and Oklahoma segments will expire. These expiring MVC agreements generated $72.6 million in shortfall revenue for the year ended December 31, 2017. In 2018, expiring MVC agreements in North Texas and Oklahoma are projected to generate approximately $80-90 million in shortfall revenue. For additional information, refer to “Item 1. Business—Our Contractual Relationship with Devon.”

Operating Expenses. Operating expenses were $418.7 million for the year ended December 31, 2017 compared to $398.5 million for the year ended December 31, 2016, an increase of $20.2 million, or 5.1%. The primary contributors to the total increase by segment were as follows (in millions):

 Year Ended December 31, Change
 2017 2016 $ %
Texas Segment$172.7
 $168.5
 $4.2
 2.5 %
Louisiana Segment101.3
 96.6
 4.7
 4.9 %
Oklahoma Segment64.6
 52.1
 12.5
 24.0 %
Crude and Condensate Segment80.1
 81.3
 (1.2) (1.5)%
Total$418.7
 $398.5
 $20.2
 5.1 %

Louisiana Segment. Operating expenses in the Louisiana segment increased $4.7 million primarily due to increases in materials and supplies expense of $2.7 million, labor and benefits expense of $1.7 million, utilities expense of $1.3 million and regulatory expense of $1.0 million as a result of increased activity on our Louisiana systems, partially offset by reduced compressor rental expenses of $2.2 million resultingfacilities from the purchase of compressors.

Oklahoma Segment. Operating expenses in the Oklahoma segment increased $12.5 million primarily due to increased property insurance costs of $5.4 million, increased labor and benefits expense of $3.5 million attributable to higher headcount and to increased materials and supplies expense of $3.7 million as a result of expanded operations.

General and Administrative Expenses. General and administrative expenses were $128.6 million for the year ended December 31, 2017 compared to $122.5 million for the year ended December 31, 2016, an increase of $6.1 million, or 5.0%. The primary contributors to the increase were as follows:

Unit-based compensation expense increased $13.7 million due to bonuses paid in the form of units, which vested immediately in March 2017, and the accrual of annual bonuses for 2017;
Transaction costs decreased $4.4 million and transition service fees decreased $1.5 million due to the costs incurred during 2016 related to the EnLink Oklahoma T.O. acquisition, with no transaction or transition costs incurred for the year ended December 31, 2017;
Wages and salaries expense decreased $3.6 million due to severance payments made during 2016 and a decrease in bonus expenses for the year ended December 31, 2017; and
We received a $1.9 million franchise tax refund for the year ended December 31, 2016.

Loss on Disposition of Assets. For the year ended December 31, 2016, we recorded a loss on disposition of assets of $13.2 million, whichBattle Ridge processing plant was primarily attributable to a $13.4 million loss on sale of the NTPL.

Depreciation and Amortization. Depreciation and amortization expenses were $545.3 million for the year ended December 31, 2017 compared to $503.9 million for the year ended December 31, 2016, an increase of $41.4 million, or 8.2%. Of this increase, $18.8 million was attributable to the plant expansion of our Permian Basin gathering and processing assets; $15.8 million was attributable to the expansion of our Central Oklahoma assets; $4.7 million was attributable to the Greater Chickadee gathering system; $3.4 million was attributable to the acceleration of depreciation for some North Texas compressor stations decommissioned during 2017; and $2.6 million was attributable to the Ascension JV assets. These increases were partially offset by a $4.3 million decrease in depreciation expense related to the sale of NTPL in December 2016.

Impairments. Impairment expense was $17.1 million for the year ended December 31, 2017, compared to $873.3 million for the year ended December 31, 2016, a decrease of $856.2 million, or 98.0%. In the first quarter of 2016, we recognized an impairment of goodwill of $566.3 million related to our Texas and Crude and Condensate segments, as well as $307.0 million related to our Corporate segment. For the year ended December 31, 2017, we recognized property and equipment impairments of $17.1 million, which related to the carrying values of rights-of-way that we are no longer using and an abandoned brine disposal well.

Gain on Litigation Settlement. We recognized a gain on litigation settlement of $26.0 million for the year ended December 31, 2017. See “Item 8. Financial Statements—Note 15” for additional information.

Gain on Extinguishment of Debt. We recognized a gain on extinguishment of debt of $9.0 million for the year ended December 31, 2017 due to the redemption of the 2022 Notes. See “Item 8. Financial Statements—Note 6” for additional information.

Interest Expense. Interest expense was $190.4 million for the year ended December 31, 2017 compared to $189.5 million for the year ended December 31, 2016, a decrease of $0.9 million, or 0.5%. Net interest expense consisted of the following (in millions):

    
 Year Ended December 31,
 2017 2016
ENLK senior notes$155.0
 $131.1
ENLK Credit Facility9.5
 11.7
ENLC Credit Facility2.2
 1.1
Capitalized interest(6.3) (7.2)
Amortization of debt issue costs and net discount29.3
 53.4
Cash settlements on interest rate swaps—
 (0.4)
Mandatory redeemable non-controlling interest

—
 0.3
Other0.7
 (0.5)
Total interest expense, net of interest income$190.4
 $189.5

Income (loss) from Unconsolidated Affiliate Investments. Income from unconsolidated affiliate investments was$9.6 million for the year ended December 31, 2017 compared to a loss of $19.9 million for the year ended December 31, 2016, an increase of $29.5 million. The increase was primarily due to a $23.3 million loss from our investment in HEP for the year ended December 31, 2016 compared to a $3.4 million loss from the sale of HEP for the year ended December 31, 2017. The loss from our investment in HEP for the year ended December 31, 2016 was primarily due to the $20.1 million impairment of our investment in HEP in the fourth quarter of 2016 to reduce the carrying value of our investment to the expected sale price. In addition, we generated increased income of $9.2 million from our GCF investment for the year ended December 31, 2017 compared to the year ended December 31, 2016 due to higher fractionation revenues and lower operating expenses.

Income Tax Benefit (Expense). Income tax benefit was $196.8 million for the year ended December 31, 2017 compared to income tax expense of $4.6 million for the year ended December 31, 2016. The income tax benefit for the year ended December 31, 2017 was primarily due to an adjustment to deferred taxes related to a reduction in ENLC’s federal statutory rate from 35% to 21% as a result of tax reform. See “Item 8. Financial Statements—Note 7” for additional information.

Net Income (Loss) Attributable to Non-controlling Interest. Net income attributable to non-controlling interest was $107.2 million for the year ended December 31, 2017 compared to a net loss of $428.2 million for the year ended December 31, 2016,

an increase of $535.4 million. The increase was primarily due to higher impairment expense at ENLK for the year ended December 31, 2016.

Year Ended December 31, 2016 Compared to Year Ended December 31, 2015

Gross Operating Margin. Gross operating margin was $1,236.9 million for the year ended December 31, 2016 compared to $1,206.8 million for the year ended December 31, 2015, an increase of $30.1 million, or 2.5%, due to the following:

Texas Segment. Gross operating margin in the Texas segment decreased $3.1 million, which was primarily due to a $34.1 million decrease in gross operating margin as a result of volume declines and expirations of certain higher margin contracts for our North Texas processing, gathering, and transportation assets. The gross operating margin decline due to volumes included MVC revenue from our contracts with Devon of $26.4 million for the year ended December 31, 2016 as compared to $3.8 million for the year ended December 31, 2015. This decrease from our North Texas assets was partially offset by gross operating margin contributions totaling $20.5 million from 2015 acquisitions on the MEGA system. In addition, volume growth in the MEGA system resulted in an additional $10.7 million increase in gross operating margin between periods.

Louisiana Segment. Gross operating margin in the Louisiana segment decreased $0.2 million. The Louisiana segment realized a 1.0% decrease in gross operating margin from its NGL business as a result of declines in pipeline throughput and fractionation volumes, substantially offset by an increase in gross operating margin from the Louisiana gas business.

Oklahoma Segment. Gross operating margin in the Oklahoma segment increased $83.0 million, which was driven by a gross operating margin contribution of $82.0 million from the EnLink Oklahoma T.O. assets acquired in January 2016. In addition, our gross operating margin from our Cana gathering and processing assets increased by $5.8 million between periods primarily due to increased volumes from Devon, including MVC revenue from Devon of $10.8 million for the year ended December 31, 2016 compared to $20.1 million for the year ended December 31, 2015. This increase was partially offset by a decline in gross operating margin of $5.4 million at our Northridge gathering and processing assets as a result of a decline in volumes and a rate reduction on a third-party contract.

Crude and Condensate Segment. Gross operating margin in the Crude and Condensate segment decreased $29.1 million. A decrease of $24.7 million resulted from the termination of a customer contract during the second quarter of 2015 and included a $10.3 million early termination payment from the customer in 2015. The remaining decrease was primarily the result of volume declines throughout the Crude and Condensate segment.

Corporate Segment. The Corporate segment included a loss from derivative activity of $11.1 million for the year ended December 31, 2016 compared to a gain of $9.4 million for the year ended December 31, 2015 related to the changes in fair value of our commodity swaps between periods. For the year ended December 31, 2016, there were realized gains of $9.0 million offset by unrealized losses of $20.1 million. For the year ended December 31, 2015, there were realized gains of $17.1 million partially offset by unrealized losses of $7.7 million.

Revenue recorded for the shortfall between actual production volumes and the MVC were as follows (in millions):
 Texas Oklahoma Crude and Condensate Total
Year Ended December 31, 2016       
Midstream services$1.9
 $9.5
 $—
 $11.4
Midstream services—related parties26.4
 10.8
 9.0
 46.2
Total$28.3
 $20.3
 $9.0
 $57.6
        
Year Ended December 31, 2015       
Midstream services$0.5
 $—
 $—
 $0.5
Midstream services—related parties3.8
 20.1
 0.5
 24.4
Total$4.3
 $20.1
 $0.5
 $24.9


Operating Expenses. Operating expenses were $398.5 million for the year ended December 31, 2016 compared to $419.9 million for the year ended December 31, 2015, a decrease of $21.4 million, or 5.1%. The primary contributors to the total decrease by segment were as follows (in millions):
 Year Ended December 31, Change
 2016 2015 $ %
Texas Segment$168.5
 $181.8
 $(13.3) (7.3)%
Louisiana Segment96.6
 105.9
 (9.3) (8.8)%
Oklahoma Segment52.1
 30.3
 21.8
 71.9 %
Crude and Condensate Segment81.3
 101.9
 (20.6) (20.2)%
Total$398.5
 $419.9
 $(21.4) (5.1)%

Texas Segment. Operating expenses in the Texas segment decreased $13.3 million primarily due to lower operating costs of $18.3 million resulting from overall cost reduction measures and lower rental expense on compressors. These decreases were partially offset by a $8.0 million increase in operating expenses attributable to the acquisitions in the MEGA system.

Louisiana Segment. Operating expenses in the Louisiana segment decreased $9.3 million primarily due to overall cost reduction measures, including cost savings from materials and supplies, construction fees and services and labor. In addition, rental expense decreased $1.0 million due to rental equipment that was returned in the first quarter of 2016.

Oklahoma Segment. Operating expenses in the Oklahoma segment increased $21.8 million primarily due to the EnLink Oklahoma T.O. acquisition in January 2016.

Crude and Condensate Segment. Operating expenses in the Crude and Condensate segment decreased $20.6 million primarily due to decreased trucking volumes, which decreased labor, fuel and contractor costs, in addition to overall cost reduction measures.

General and Administrative Expenses. General and administrative expenses were $122.5 million for the year ended December 31, 2016 compared to $136.9 million for the year ended December 31, 2015, a decrease of $14.4 million, or 10.5%. The primary contributors to the decrease are as follows:

Unit-based compensation expense decreased $7.3 million primarily due to bonuses being paid in the form of units that immediately vested in March 2015;
Wages and salaries decreased $2.9 million due to a decrease in bonus expense;
Software consulting fees decreased $2.0 million due to completed implementation of new software;
Bad debt expense decreased $2.1 million;
Transition service fees related to acquisitions decreased $1.0 million;
Transaction costs related to acquisitions decreased $1.3 million;
Travel and training expense decreased $1.0 million; and
Rent expense increased $4.9 million related to new office leases that commenced during 2016.

Loss on Disposition of Assets. Loss on disposition of assets was $13.2 million for the year ended December 31, 2016 compared to a loss on disposition of assets of $1.2 million for the year ended December 31, 2015. The loss on disposition of assets for the year ended December 31, 2016 was primarily attributable to a $13.4 million loss on sale of the NTPL. The loss on disposition of assets for the year ended December 31, 2015 related to the retirement of a compressor due to fire damage.

Depreciation and Amortization. Depreciation and amortization expenses were $503.9 million for the year ended December 31, 2016 compared to $387.3 million for the year ended December 31, 2015, an increase of $116.6 million, or 30.1%. Of this increase, $88.6 million was attributable to the acquisition of the EnLink Oklahoma T.O. assets; $11.5 million was attributable to additional assets on the MEGA system; and $7.4 million was attributable to the Lobo plants. These increases were partially offset by a $14.4 million decrease in amortization attributable to the impairment of ORV intangible assets in the third quarter of 2015. The remaining increase2021 and we expect to complete the relocation of equipment and facilities from the Thunderbird processing plant in depreciation2022.
(2)Includes accretion expense associated with asset retirement obligations; transaction costs; and amortizationnon-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, Marathon Petroleum Corporation’s 50% share of adjusted EBITDA from the Ascension JV, and other minor non-controlling interests.

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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, was primarily attributablenet 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 assets placed in service.


Impairments. Impairment expense was $873.3 million for the year ended December 31, 2016 compared to impairment expense of $1,563.4 million for the year ended December 31, 2015, a decrease of $690.1 million, or 44.1%. In the first quarter of 2016, we recognized an impairment of goodwill of $566.3 million related to our Texas and Crude and Condensate segments, as well as $307.0 million related to our Corporate segment. For the year ended December 31, 2015, we recognized an impairment on goodwill of $1,328.2 million related to our Louisiana, Texas, and Crude and Condensate segments and an impairment on intangible assets of $223.1 million in our Crude and Condensate segment. For the year ended December 31, 2015, we also recognized an impairment on property and equipment of $12.1 million primarily related to costsbe paid); (costs associated with the cancellationrelocation of various projects. For more information, see the “Critical Accounting Policies” section below.

Interest Expense. Interest expense was $189.5 million for the year ended December 31, 2015 comparedprocessing facilities); non-cash interest (income)/expense; (payments to $103.3 million for the year ended December 31, 2015, an increase of $86.2 million, or 83.4%. Netterminate interest expense consisted of the following (in millions):

       
  Year Ended
  December 31,
  2016 2015
ENLK senior notes $131.1 $106.0
ENLK Credit Facility  11.7  7.9
ENLC Credit Facility  1.1  0.6
Capitalized interest  (7.2)  (7.7)
Amortization of debt issue costs and net discount (premium)  53.4  0.4
Cash settlements on interest rate swaps  (0.4)  (3.6)
Redeemable non-controlling interest  0.3  (1.8)
Other  (0.5)  1.5
Total interest expense, net of interest income $189.5 $103.3

The increase in interest expense of $86.2 million was primarily due to an increase of $52.3 million attributable to the non-cash amortization of the discount related to the EnLink Oklahoma T.O. acquisition installment payments in 2016rate swaps); (current income taxes); and an increase of $25.1 million attributable to the issuance of $900.0 million aggregate principal amount of unsecured senior notes in May 2015 and the issuance of $500.0 million in aggregate principal amount of unsecured senior notes in July 2016.

Income (loss) from Unconsolidated Affiliate Investments. Loss from unconsolidated affiliate investments was $19.9 million for the year ended December 31, 2016 compared to income of $20.4 million for the year ended December 31, 2015, a decrease of $40.3 million. This decrease was primarily due to a $23.3 million loss from our investment in HEP for the year ended December 31, 2016 compared to $7.4 million in income for the year ended December 31, 2015. The loss from our investment in HEP for the year ended December 31, 2016 was primarily due to the $20.1 million impairment of our investment in HEP in the fourth quarter of 2016 to reduce the carrying value of our investment to its expected sales price. In December 2016, we entered into an agreement to sell our ownership interest in HEP, and the sale closed in the first quarter of 2017. In addition, income from our investment in GCF also decreased $9.2 million due to lower revenues as a result of lower pipeline and fractionator feed volumes, together with increased operating costs for major scheduled fractionator maintenance during the first quarter of 2016.

Income Tax Expense. Income tax expense was $4.6 million for the year ended December 31, 2016 compared to income tax expense of $25.7 million for the year ended December 31, 2015, a decrease of $21.1 million. The decrease in income tax expense was due to a decrease in taxable income between periods. Although we realized losses before income taxes for the years ended December 31, 2016 and 2015, we did not realize tax benefits associated with these losses because substantially all of the losses were the result of goodwill impairments, which are treated as permanent differences for tax. See “Item 8. Financial Statements and Supplementary Data—Note 7” for further details.

Net Income (Loss) Attributable to Non-controlling Interest. Net loss attributable to non-controlling interest was $428.2 million for the year ended December 31, 2016 compared to a net loss of $1,054.5 million for the year ended December 31, 2015, a decrease of $626.3 million. The decrease in net loss attributable to non-controlling interests is primarily due to narrowing net losses in 2016 and 2015 at ENLK driven by lower impairment expense.


Critical Accounting Policies

The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as the accounting rules have developed. Accounting rules generally do not involve a selection among alternatives, but involve an implementation and interpretation of existing rules and the use of judgment to the specific set of circumstances existing in our business. Compliance with the rules involves reducing a number of very subjective judgments to a quantifiable accounting entry or valuation. We make every effort to properly comply with all applicable rules on or before their adoption, and we believe the proper implementation and consistent application of the accounting rules is critical.

Our critical accounting policies are discussed below. See “Item 8. Financial Statements and Supplementary Data— Note 2” for further details on our accounting policies.

Revenue Recognition. In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”), which established Accounting Standards Codification (“ASC”) Topic 606, Revenue from Contracts with Customers (“ASC 606”). ASC 606 will replace existing revenue recognition requirements in Generally Accepted Accounting Principles (“GAAP”) and will require entities to recognize revenue at an amount that reflects the consideration to which they expect to be entitled in exchange for transferring goods or services to a customer. ASC 606 will also require significantly expanded disclosures containing qualitative and quantitative information regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. In May 2016, the FASB issued ASU 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients (“ASU 2016-12”), which updated ASU 2014-09. ASU 2016-12 clarifies certain core recognition principles, including collectability, sales tax presentation, noncash consideration, contract modifications and completed contracts at transition and disclosures no longer required if the full retrospective transition method is adopted. ASU 2014-09 and ASU 2016-12 are effective for annual reporting periods beginning after December 15, 2017, including interim periods within those annual periods, and are to be applied using the modified retrospective or full retrospective transition methods, with early application permitted for annual reporting periods beginning after December 15, 2016. We will adopt ASC 606 using the modified retrospective method for annual and interim reporting periods beginning January 1, 2018.

We have aggregated and reviewed our contracts that are within the scope of ASC 606. Based on our evaluation to date, we do not anticipate the adoption of ASC 606 will have a material impact on our results of operations, financial condition or cash flows. However, ASC 606 will affect how certain transactions are recorded in the financial statements. For each contract with a customer, we will need to identify our performance obligations, of which the identification includes careful evaluation of when control and the economic benefits of the commodities transfer to us. The evaluation of control will change the way we account for certain transactions, specifically those in which there is both a commodity purchase component and a service component. For contracts where control of commodities transfers to us before we perform our services, we generally have no performance obligation for our services, and accordingly, we will not consider these revenue-generating contracts. Based on that determination, all fees or fee-equivalent deductions stated in such contracts would reduce the cost to purchase commodities. Alternatively, for contracts where control of commodities transfers to us after we perform our services, we have performance obligations for our services. Accordingly, we will consider the satisfaction of these performance obligations as revenue-generating and recognize these fees as midstream service revenues at the time we satisfy our performance obligations. For contracts where control of commodities never transfers to us and we simply earn a fee for our services, we will recognize these fees as midstream services revenues at the time we satisfy our performance obligations. Based on our review of our performance obligations in our contracts with customers, we will change the statement of operations classification for certain transactions from revenue to cost of sales or from cost of sales to revenue. We estimate that the reclassification of revenues and costs will result in a net decrease in revenue of approximately 6-10%, although this estimate is based on historical information and could change based on commodity prices going forward. This reclassification of revenues and costs will have no effect on operating income and gross operating margin.

Our performance obligations represent promises to transfer a series of distinct goods or services that are satisfied over time and that are substantially the same to the customer. As permitted by ASC 606, we will utilize the practical expedient that allows an entity to recognize revenue in the amount to which the entity has a right to invoice, if an entity has a right to consideration from a customer in an amount that corresponds directly with the value to the customer of the entity’s performance completed to date. Accordingly, we will continue to recognize revenue at the time commodities are delivered or services are performed, so ASC 606 will not significantly affect the timing of revenue and expense recognition on our statements of operations.

Impairment of Long-Lived Assets. In accordance with ASC 360, Property, Plant and Equipment, we evaluate long-lived assets, including related intangibles, of identifiable business activities for potential impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable. The carrying amount of a long-lived asset is not

recoverable when it exceeds the undiscounted sum of the future cash flows expected to result from the use and eventual disposition of the asset. Estimates of expected future cash flows represent management’s best estimate based on reasonable and supportable assumptions. When the carrying amount of a long-lived asset is not recoverable, an impairment loss is recognized equal to the excess of the asset’s carrying value over its fair value.

When determining whether impairment of our long-lived assets has occurred, we must estimate the undiscounted cash flows attributable to the asset. Our estimate of cash flows is based on assumptions regarding:

the future fee-based rate of new business or contract renewals;
the purchase and resale margins on natural gas, NGLs, crude oil and condensate;
the volume of natural gas, NGLs, crude oil and condensate available to the asset;
markets available to the asset;
operating expenses; and
future natural gas, NGLs, crude oil and condensate prices.

The amount of availability of natural gas, NGLs, crude oil and condensate to an asset is sometimes based on assumptions regarding future drilling activity, which may be dependent in part on natural gas, NGL, crude oil and condensate prices. Projections of natural gas, NGL, crude oil and condensate volumes and future commodity prices are inherently subjective and contingent upon a number of variable factors, including but not limited to:

changes in general economic conditions in regions in which our markets are located;
the availability and prices of natural gas, NGLs, crude oil and condensate supply;
our ability to negotiate favorable sales agreements;
the risks that natural gas, NGLs, crude oil and condensate exploration and production activities will not occur or be successful;
our dependence on certain significant customers, producers and transporters of natural gas, NGLs, crude oil and condensate; and
competition from other midstream companies, including major energy companies.

Any significant variance in any of the above assumptions or factors could materially affect our cash flows, which could require us to record an impairment of an asset.

For 2016 and 2015, we reviewed our various assets groups for impairment due to the triggering events described in the goodwill impairment analysis below. We utilized Level 3 fair value measurements in our impairment analysis, which included discounted cash flow assumptions by management consistent with those utilized in our goodwill impairment analysis. During 2016, the undiscounted cash flows of our assets exceeded their carrying values, and no impairment was recorded. During 2015, the undiscounted cash flows related to one of our asset groups in the Crude and Condensate segment were not in excess of its related carrying value. We estimated the fair value of this reporting unit and determined the fair values of certain intangible assets were not in excess of their carrying values. This resulted in a $223.1 million impairment of intangible assets in our Crude and Condensate segment, and this non-cash impairment charge was included as an impairment loss on the consolidated statement of operations for the year ended December 31, 2015.

For the year ended December 31, 2017, we recognized impairments on property and equipment of $17.1 million, which related to the carrying values of rights-of-way that we are no longer using and an abandoned brine disposal well. For the year ended December 31, 2015, we recognized a $12.1 million impairment on property and equipment, primarily related to costs associated with the cancellation of various capital projects in our Texas, Louisiana, and Crude and Condensate segments.

Impairment of Goodwill. Goodwill is the cost of an acquisition less the fair value of the net identifiable assets of the acquired business. We evaluate goodwill for impairment annually as of October 31 and whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount. We first assess qualitative factors to evaluate whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as the basis for determining whether it is necessary to perform a goodwill impairment test. We may elect to perform a goodwill impairment test without completing a qualitative assessment.

We perform our goodwill assessments at the reporting unit level for all reporting units. We use a discounted cash flow analysis to perform the assessments. Key assumptions in the analysis include the use of an appropriate discount rate, terminal year multiples and estimated future cash flows, including volume and price forecasts and estimated operating and general and administrative costs. In estimating cash flows, we incorporate current and historical market and financial information, among

other factors. Impairment determinations involve significant assumptions and judgments, and differing assumptions regarding any of these inputs could have a significant effect on the various valuations. If actual results are not consistent with our assumptions and estimates, or our assumptions and estimates change due to new information, we may be exposed to goodwill impairment charges, which would be recognized in the period in which the carrying value exceeds fair value.

Prior to January 2017, if a goodwill impairment test was elected or required, we performed a two-step goodwill impairment test. The first step involved comparing the fair value of the reporting unit to its carrying amount. If the carrying amount of a reporting unit exceeded its fair value, the second step of the process involved comparing the implied fair value to the carrying value of the goodwill for that reporting unit. If the carrying value of the goodwill of a reporting unit exceeded the implied fair value of that goodwill, the excess of the carrying value over the implied fair value was recognized as an impairment loss.

Effective January 2017, we elected to early adopt ASU 2017-04, Intangibles—Goodwill and Other (Topic 350)— Simplifying the Test for Goodwill Impairment, which simplified the accounting for goodwill impairments by eliminating the requirement to compare the implied fair value of goodwill with its carrying amount as part of step two of the goodwill impairment test referenced in ASC 350, Intangibles—Goodwill and Other. As a result, an entity should perform its annual or interim goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount. An impairment charge should be recognized for the amount by which the carrying amount exceeds the reporting unit’s fair value. However, the impairment loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. Therefore, our annual impairment test as of October 31, 2017 was performed according to ASU 2017-04.

During the third quarter of 2015, we determined that sustained weakness in the overall energy sector, driven by low commodity prices together with a decline in our unit price, caused a change in circumstances warranting an interim impairment test. We also performed our annual impairment analysis during the fourth quarter of 2015. Although our established annual effective date for this goodwill analysis is October 31, we updated the effective date for this impairment analysis for the 2015 annual period to December 31, 2015 due to continued declines in commodity prices and our unit price during the fourth quarter of 2015.

Using the fair value approaches described above, in step one of the goodwill impairment test, we determined that the estimated fair values of our Louisiana, Texas and Crude and Condensate reporting units were less than their carrying amounts, primarily related to commodity prices, volume forecasts and discount rates. Based on that determination, we performed the second step of the goodwill impairment test by measuring the amount of impairment loss and allocating the estimated fair value of the reporting unit among all of the assets and liabilities of the reporting unit as if the reporting unit had been acquired in a business combination. Based on this analysis, a goodwill impairment loss for our Louisiana, Texas, and Crude and Condensate reporting units in the amount of $1,328.2 million was recognized for the year ended December 31, 2015 and is included as an impairment loss in the consolidated statement of operations.

During February 2016, we determined that continued further weakness in the overall energy sector, driven by low commodity prices together with a further decline in our unit price subsequent to year-end, caused a change in circumstances warranting an interim impairment test. Based on these triggering events, we performed a goodwill impairment analysis in the first quarter of 2016 on all reporting units. Based on this analysis, a goodwill impairment loss for our Texas, Crude and Condensate, and Corporate reporting units in the amount of $873.3 million was recognized in the first quarter of 2016 and is included as an impairment loss in the consolidated statement of operations for the year ended December 31, 2016.

As of December 31, 2017, we had $1,119.9 million of goodwill related to our investment in ENLK that is included in our Corporate segment. We utilize the publicly traded market value of our common units, adjusted for our estimated control premium, in our Corporate level goodwill assessment.

For each of the aforementioned impairment testing periods during 2015 and 2016, we concluded that the fair value of our Oklahoma reporting unit exceeded its carrying value, and the amount of goodwill disclosed on the consolidated balance sheet associated with this reporting unit was recoverable. Therefore, no goodwill impairment was identified or recorded for this reporting unit as a result of our goodwill impairment analyses.

During our annual impairment tests for 2016 and 2017 performed as of October 31 of each year, we determined that no further impairments were required for the years ended December 31, 2017 and 2016.


Liquidity and Capital Resources

Cash Flows from Operating Activities. Net cash provided by operating activities was $700.1 million, $666.4 million and $628.4 million for the years ended December 31, 2017, 2016 and 2015 respectively. Operating cash flows and changes in working capital for comparative periods were as follows (in millions):

 Year Ended December 31,
 2017 2016 2015
Operating cash flows before working capital$750.9
 $633.5
 $609.0
Changes in working capital(50.8) 32.9
 19.4

Operating cash flows before changes in working capital increased $117.4 million for the year ended December 31, 2017 compared to the year ended December 31, 2016. This increase was primarily due to a $134.3 million increase in gross operating margin, excluding gains and losses on derivative activity, and a $26.0 million gain on litigation settlement, partially offset by a $25.0 million increase in interest expense, excluding amortization of debt issue costs and net discounts, and a $21.7 million decrease in cash received on derivative settlements.

Operating cash flows before changes in working capital increased $24.5 million for the year ended December 31, 2016 compared to the year ended December 31, 2015 primarily due to an increase in gross operating margin in our Oklahoma segment from the acquisition of the EnLink Oklahoma T.O. assets, which was partially offset by a decrease in gross operating margin in our Crude and Condensate segment due to lower volumes and the termination of a customer contract during the second quarter of 2015.

The changes in working capital for the years ended December 31, 2017, 2016 and 2015 were primarily due to fluctuations in trade receivable and payable balances due to timing of collection and payments and changes in inventory balances attributable to normal operating fluctuations.

As of December 31, 2017, we had $259.4 million of federal net operating loss carryforwards. Historically, we have had net operating losses that eliminated substantially all of our taxable income, and thus, we have not historically paid significant amounts of income taxes. We anticipate generating net operating losses for tax purposes during 2018, and as a result, do not expect to incur material amounts of federal and state income tax liabilities. In the event we do generate taxable income that exceeds our net operating loss carryforwards, federal and state income tax liabilities will increase cash taxes paid.

Cash Flows from Investing Activities. Net cash used in investing activities was $610.8 million, $1,380.3 million and $1,097.3 million for the years ended December 31, 2017, 2016 and 2015, respectively. Our primary investing cash flows were as follows (in millions):
 Year Ended December 31,
 2017 2016 2015
Growth capital expenditures$(758.4) $(632.5) $(530.0)
Maintenance capital expenditures(32.4) (30.5) (42.3)
Acquisition of business, net of cash acquired—
 (791.5) (524.2)
Proceeds from sale of unconsolidated affiliate investment189.7
 —
 —
Proceeds from sale of property2.3
 93.1
 1.0
Investment in unconsolidated affiliates(12.6) (73.8) (25.8)
Distribution from unconsolidated affiliates in excess of earnings0.2
 54.6
 21.1

Growth capital expenditures increased $125.9 million for the year ended December 31, 2017 compared to the year ended December 31, 2016. The increase was primarily due to capital expenditures related to the expansion of the Central Oklahoma assets and the Lobo processing facilities, as well as expenditures for the Greater Chickadee crude oil gathering system in the Permian Basin and the Ascension JV assets in Louisiana. Growth capital expenditures increased $102.5 million for the year ended December 31, 2016 compared to the year ended December 31, 2015. The increase was primarily due to gas processing and gathering expansion projects for our Central Oklahoma assets and the construction of the Lobo II processing facility, which is owned by the Delaware Basin JV.

Maintenance capital expenditures increased slightly by $1.9 million for the year ended December 31, 2017 compared to the year ended December 31, 2016. Maintenance capital expenditures decreased $11.8 million for the year ended December 31, 2016 compared to the year ended December 31, 2015. The decrease was primarily due to decreases in compressor overhauls in our Texas segment and decreases in other repairs in our Oklahoma and Louisiana segments.

Acquisition expenditures increased $267.3 million for the year ended December 31, 2016 compared to the year ended December 31, 2015. For the year ended December 31, 2016, we acquired the EnLink Oklahoma T.O. assets. For the year ended December 31, 2015, we acquired LPC, Coronado, Matador and Deadwood.

In December 2016, we entered into an agreement to sell our ownership interest in HEP. We finalized the sale in March 2017 and received net proceeds of $189.7 million.

We received proceeds from sale of property of $93.1 million for the year ended December 31, 2016. These proceeds were primarily from the sale of the NTPL in December 2016 for $84.6 million.equipment and land.


Investments andFree cash flow after distributions from unconsolidated affiliate investments are determined by our contribution and distribution activity with our GCF, HEP and Cedar Cove JV investments for the years ended December 31, 2017, 2016 and 2015. We formed the Cedar Cove JV with Kinder Morgan, Inc. during November 2016 and sold our ownership interest in our HEP investment during March 2017. See “Item 8. Financial Statements—Note 11” for investment and distribution activity.

Cash Flows from Financing Activities. Net cash used in financing activities was $69.8 million for the year ended December 31, 2017, and net cash provided by financing activities was $707.6 million and $418.5 million for the years ended December 31, 2016 and 2015, respectively. Our primary financing activities consisted of the following (in millions):

 Year Ended December 31,
 2017 2016 2015
Net repayments (borrowings) on the ENLK Credit Facility$(120.0) $(294.2) $176.8
Net repayments (borrowings) on the ENLC Credit Facility46.8
 27.8
 —
ENLK unsecured senior notes borrowings, net of notes extinguished331.6
 499.3
 893.3
Proceeds from issuance of ENLK common units106.9
 167.5
 24.4
Contributions by non-controlling interest57.3
 167.9
 16.4
Payment of installment payable for EnLink Oklahoma T.O. acquisition(250.0) —
 —
Proceeds from issuance of ENLK Series C Preferred Units394.0
 —
 —
Proceeds from issuance of ENLK Series B Preferred Units—
 724.1
 —
Contribution from Devon1.3
 1.5
 27.8

On May 11, 2017, ENLK issued $500.0 million in aggregate principal amount of 5.450% senior unsecured notes due 2047 at a price to the public of 99.981% of their face value. Interest payments on the 2047 Notes are payable on June 1 and December 1 of each year, beginning December 1, 2017. Net proceeds of approximately $495.2 million were used to repay outstanding borrowings under the ENLK Credit Facility and for general partnership purposes. For the year ended December 31, 2017, ENLK redeemed $162.5 million in aggregate principal amount of the 2022 Notes at 103.6% ofis the principal amount, plus accrued unpaid interest, for aggregate cash consideration of $174.1 million, which included payments for accrued interest of $5.8 million.

On July 14, 2016, ENLK issued $500.0 million in aggregate principal amount of 4.850% senior notes due 2026 (the “2026 Notes”) at a price toflow metric used by the public of 99.859% of their face value. The 2026 Notes mature on July 15, 2026. Interest payments on the 2026 Notes are payable on January 15 and July 15 of each year. Net proceeds of approximately $495.7 million were used to repay outstanding borrowings under the ENLK Credit Facility and for general partnership purposes.

On May 12, 2015, ENLK issued $900.0 million aggregate principal amount of unsecured senior notes, consisting of $750.0 million aggregate principal amount of our 4.150% senior notes due 2025 (the “2025 Notes”) and an additional $150.0 million aggregate principal amount of 2045 Notes at prices to the public of 99.827% and 96.381%, respectively, of their face value. The 2025 Notes mature on June 1, 2025. Interest payments on the 2025 Notes are due semi-annually in arrears in June and December. The new 2045 Notes were offered as an additional issue of our outstanding 2045 Notes issued on November 12,

2014. The 2045 Notes issued on November 12, 2014 and May 12, 2015 are treated as a single class of debt securities and have identical terms, other than the issue date.

For the year ended December 31, 2017, ENLK sold an aggregate of 6.2 million ENLK common units under the 2014 EDA and 2017 EDA, generating net proceeds of $106.9 million. For the year ended December 31, 2016, ENLK sold an aggregate of 10.0 million ENLK common units under the 2014 EDA, generating net proceeds of $167.5 million. For the year ended December 31, 2015, ENLK sold an aggregate of 1.3 million ENLK common units under the 2014 EDA, generating net proceeds of $24.4 million.

In September 2017, ENLK issued 400,000 Series C Preferred Units for net proceeds of $394.0 million. See “Item 8. Financial Statements—Note 8” for additional information.

In January 2016, ENLK issued an aggregate of 50,000,000 Series B Preferred Units for net proceeds of $724.1 million. See “Item 8. Financial Statements—Note 8” for additional information.

For the year ended December 31, 2017, contributions by non-controlling interests included $54.4 million from NGP to the Delaware Basin JV and $2.9 million from Marathon Petroleum to the Ascension JV. For the year ended December 31, 2016, contributions by non-controlling partners included $144.4 million in contributions from NGP to the Delaware Basin JV, which consisted of an initial contribution of $114.3 million that the Delaware Basin JV distributed to us at the formation of the joint venture to reimburse us for capital spent to the date of formation on existing assets, as well as $30.1 million for NGP’s share of ongoing projects. Contributions by non-controlling interests also included $23.5 million from Marathon Petroleum to the Ascension JV. For the year ended December 31, 2015, contributions by non-controlling partners included $12.5 million from Marathon Petroleum to the Ascension JV, and $3.9 million from other non-controlling interests.

For the year ended December 31, 2017, ENLK paid $250.0 million for the second installment payable obligation related to the EnLink Oklahoma T.O. acquisition.

Distributions to unitholders, Devon and our non-controlling interests also represent a primary use ofCompany. Free cash in financing activities. Total cashflow after distributions made for the year ended December 31, 2017, 2016 and 2015 were as follows (in millions):

 Year Ended December 31,
 2017 2016 2015
Distributions to members$186.0
 $185.4
 $162.8
Distributions to non-controlling interest433.7
 384.2
 359.5
Distributions to Devon for net assets acquired (1)—
 —
 166.7
(1)
Represents distributions to Devon related to VEX.

Series B Preferred Unit distributions for 2016 and for the first two quarters for 2017 were paid in-kind in the form of additional Series B Preferred Units. As these were non-cash distributions, they were not reflected in our financing cash flows for the years ended December 31, 2017 and 2016. Beginning with the quarter ended September 30, 2017, ENLK paid Series B Preferred Unit distributions in cash at an amount per quarter equal to $0.28125 per Series B Preferred Unit (the “Cash Distribution Component”) plus an in-kind distribution equal to the greater of (a) 0.0025 Series B Preferred Units per Series B Preferred Unit and (b) an amount equal to (i) the excess, if any, of the distributions that would have been payable had the Series B Preferred Units converted into common units for that quarter over the Cash Distribution Component, divided by (ii) the issue price of $15.00. For the year ended December 31, 2017, distributions to non-controlling interests included $15.9 million from the issuance of Series B Preferred Units.

Distributions on the Series C Preferred Units accrue and are cumulative from the date of original issue and payable semi-annually in arrears on the 15th day of June and December of each year through and including December 15, 2022 and, thereafter, quarterly in arrears on the 15th day of March, June, September and December of each year, in each case, if and when declared by our general partner out of legally available funds for such purpose. The initial distribution rate for the Series C Preferred Units from and including the date of original issue to, but not including, December 15, 2022 is 6.0% per annum. On and after December 15, 2022, distributions on the Series C Preferred Units will accumulate for each distribution period at a percentage of the $1,000 liquidation preference per unit equal to an annual floating rate of the three-month LIBOR plus a spread of 4.11%. For the year ended December 31, 2017, distributions to non-controlling interests included $5.6 million from the issuance of Series C Preferred Units.

Distributions to non-controlling interest also include distributions paid on ENLK common units and distributions made to our joint venture partners. For the year ended December 31, 2017, distributions to non-controlling interest includes distributions to NGP for our Delaware Basin JV, distributions to Marathon Petroleum for our Ascension JV and distributions to the non-controlling interest in one of the E2 entities. Formetrics used in our short-term incentive program for compensating employees. It is also used as a supplemental liquidity measure by our management and by external users of our financial statements, such as investors, commercial banks, research analysts, and others, to assess the year ended December 31, 2016,ability of our assets to generate cash sufficient to pay interest costs, pay back our indebtedness, make cash distributions, to non-controlling interests includes distributions to redeem the non-controlling interest in one of the E2 entities.

Uncertainties. Our operations could be subject to changing environmental rules and regulations, the outcomes of which are currently unknown. See “Item 1. Business—Environmental Matters” for additional information.

Capital Requirements. We consider a number of factors in determining whether our capital expenditures are growth capital expenditures or maintenancemake capital expenditures.

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

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

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


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The following table reconciles net cash provided by operating activities to adjusted EBITDA and free cash flow after distributions (in millions):
Year Ended December 31,
20212020
Net cash provided by operating activities$857.3 $731.1 
Interest expense (1)221.0 218.2 
Utility credits, net of usage (2)32.6 — 
Payments to terminate interest rate swaps (3)1.8 10.9 
Accruals for settled commodity swap transactions2.1 (4.3)
Distributions from unconsolidated affiliate investment in excess of earnings3.9 0.5 
Costs associated with the relocation of processing facilities (4)28.3 0.8 
Other (5)2.4 0.8 
Changes in operating assets and liabilities which (provided) used cash:
Accounts receivable, accrued revenues, inventories, and other273.5 6.4 
Accounts payable, accrued product purchases, and other accrued liabilities(328.3)104.8 
Adjusted EBITDA before non-controlling interest1,094.6 1,069.2 
Non-controlling interest share of adjusted EBITDA from joint ventures (6)(44.9)(30.7)
Adjusted EBITDA, net to ENLC1,049.7 1,038.5 
Interest expense, net of interest income(238.7)(223.3)
Growth capital expenditures, net to ENLC (7)(165.3)(187.2)
Maintenance capital expenditures, net to ENLC (7)(26.1)(32.1)
Distributions declared on common units(195.2)(186.0)
ENLK preferred unit accrued cash distributions (8)(94.3)(91.4)
Costs associated with the relocation of processing facilities (4)(28.3)(0.8)
Non-cash interest expense9.5 0.2 
Payments to terminate interest rate swaps (3)(1.8)(10.9)
Other (9)4.1 3.5 
Free cash flow after distributions$313.6 $310.5 
____________________________
(1)Net of amortization of debt issuance costs, net discount of senior unsecured notes, and designated cash flow hedge, which are included in interest expense but not included in net cash provided by operating activities, and non-cash interest income, which is netted against interest expense but not included in adjusted EBITDA.
(2)Under our utility agreements, we are entitled to a base load of electricity and pay or receive credits, based on market pricing, when we exceed or do not use the base load amounts. Due to Winter Storm Uri, we received credits from our utility providers based on market rates for our unused electricity. These utility credits are recorded as “Other current assets” or “Other assets, net” on our consolidated balance sheets depending on the timing of their expected usage, and amortized as we incur utility expenses.
(3)Represents cash paid for the early terminations of our interest rate swaps due to the partial repayments of the Term Loan in May and September 2021 and December 2020. See “Item 8. Financial Statements and Supplementary Data—Note 12” for information on the partial terminations of our interest rate swaps.
(4)Represents cost incurred 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 that are not part of our ongoing operations. The relocation of equipment and facilities from the Battle Ridge processing plant was completed in the third quarter of 2021 and we expect our 2018to complete the relocation of equipment and facilities from the Thunderbird processing plant in 2022.
(5)Includes current income tax expense; transaction costs; and non-cash rent, which relates to lease incentives pro-rated over the lease term.
(6)Non-controlling interest share of adjusted EBITDA from joint ventures includes NGP’s 49.9% share of adjusted EBITDA from the Delaware Basin JV, Marathon Petroleum Corporation’s 50% share of adjusted EBITDA from the Ascension JV, and other minor non-controlling interests.
(7)Excludes capital expenditures that were contributed by other entities and relate to the non-controlling interest share of our consolidated entities.
(8)Represents the cash distributions earned by the Series B Preferred Units and Series C Preferred Units. See “Item 8. Financial Statements and Supplementary Data—Note 8” for information on the cash distributions earned by holders of the Series B Preferred Units and Series C Preferred Units. Cash distributions to be paid to holders of the Series B Preferred Units and Series C Preferred Units are not available to common unitholders.
(9)Includes current income tax expense and proceeds from the sale of surplus or unused equipment and land, which occurred in the normal operation of our business.

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Results of Operations

The tables below set forth certain financial and operating data for the periods indicated. We evaluate the performance of our consolidated operations by focusing on adjusted gross margin, while we evaluate the performance of our operating segments based on segment profit and adjusted gross margin, as reflected in the tables below (in millions, except volumes):
PermianLouisianaOklahomaNorth TexasCorporateTotals
Year Ended December 31, 2021
Gross margin$89.8 $183.9 $123.3 $136.6 $(8.0)$525.6 
Depreciation and amortization139.9 141.0 204.3 114.3 8.0 607.5 
Segment profit229.7 324.9 327.6 250.9 — 1,133.1 
Operating expenses81.5 123.7 80.0 77.7 — 362.9 
Adjusted gross margin$311.2 $448.6 $407.6 $328.6 $— $1,496.0 

PermianLouisianaOklahomaNorth TexasCorporateTotals
Year Ended December 31, 2020
Gross margin$44.9 $139.8 $188.5 $127.0 $(7.3)$492.9 
Depreciation and amortization125.2 145.8 216.9 143.4 7.3 638.6 
Segment profit170.1 285.6 405.4 270.4 — 1,131.5 
Operating expenses94.2 120.0 82.2 77.4 — 373.8 
Adjusted gross margin$264.3 $405.6 $487.6 $347.8 $— $1,505.3 

PermianLouisianaOklahomaNorth TexasCorporateTotals
Year Ended December 31, 2019
Gross margin$36.6 $143.1 $255.2 $149.8 $(8.4)$576.3 
Depreciation and amortization119.8 154.1 194.9 139.8 8.4 617.0 
Segment profit156.4 297.2 450.1 289.6 — 1,193.3 
Operating expenses112.9 147.3 104.0 102.9 — 467.1 
Adjusted gross margin$269.3 $444.5 $554.1 $392.5 $— $1,660.4 

Year Ended December 31,
202120202019
Midstream Volumes:
Permian Segment
Gathering and Transportation (MMbtu/d)1,067,000 890,800 723,400 
Processing (MMbtu/d)1,010,000 899,000 771,400 
Crude Oil Handling (Bbls/d)134,600 116,200 132,000 
Louisiana Segment
Gathering and Transportation (MMbtu/d)2,160,800 1,993,900 2,050,000 
Crude Oil Handling (Bbls/d)15,900 16,900 18,900 
NGL Fractionation (Gals/d)7,455,600 7,597,800 7,341,700 
Brine Disposal (Bbls/d)2,700 1,300 2,700 
Oklahoma Segment
Gathering and Transportation (MMbtu/d)992,400 1,116,500 1,302,200 
Processing (MMbtu/d)1,010,300 1,105,900 1,276,700 
Crude Oil Handling (Bbls/d)20,200 28,700 47,300 
North Texas Segment
Gathering and Transportation (MMbtu/d)1,377,400 1,478,200 1,651,900 
Processing (MMbtu/d)631,500 671,000 750,500 

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Year Ended December 31, 2021 Compared to Year Ended December 31, 2020

Gross Margin. Gross margin was $525.6 million for the year ended December 31, 2021 compared to $492.9 million for the year ended December 31, 2020, an increase of $32.7 million. The primary contributors to the total increase were as follows:
•Permian Segment. Gross margin was $89.8 million for the year ended December 31, 2021 compared to $44.9 million for the year ended December 31, 2020, an increase of $44.9 million primarily due to the following:

◦Adjusted gross margin in the Permian segment increased $46.9 million, which was primarily driven by:

•A $44.1 million increase to adjusted gross margin associated with our Permian gas assets. Adjusted gross margin, excluding derivative activity, increased $127.9 million, which was primarily due to higher volumes and significantly favorable commodity prices on gas sales during Winter Storm Uri. Derivative activity associated with our Permian gas assets decreased margin by $83.8 million, which included $81.5 million from increased realized losses, primarily due to Winter Storm Uri, and $2.3 million from increased unrealized losses.
•A $2.8 million increase to adjusted gross margin associated with our Permian crude assets. Adjusted gross margin, excluding derivative activity, increased $2.3 million, which was primarily due to higher volumes from existing customers and was partially offset by weather disruptions from Winter Storm Uri and storage fees earned in April of 2020, but not in 2021. Derivative activity associated with our Permian crude assets increased margin by $0.5 million, which included $7.0 million from increased realized gains and was partially offset by $6.5 million from increased unrealized losses.

◦Operating expenses in the Permian segment decreased $12.7 million primarily due to lower utility costs as a result of approximately $46.5 million of utility credits that we received because our electricity usage was below our contractual base load amounts during Winter Storm Uri, which entitled us to credits based on market rates for our unused electricity. These credits can and have been used to offset future utility payments. Operating expenses also decreased due to lower labor and benefits expense as a result of reductions in workforce in April 2020. These decreases were partially offset by $24.9 million of increases in construction fees and services related to the relocation of the War Horse and Phantom processing plants, increases in materials and supplies expense and compressor rentals due to higher volumes, and increases in sales and use taxes as a result of tax refunds in the first half of 2020.

◦Depreciation and amortization in the Permian segment increased $14.7 million primarily due to new assets placed into service, including capital contributionsthe Tiger processing plant in August 2020 and acquisition of the Amarillo Rattler, LLC gathering and processing system in April 2021.

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•Louisiana Segment. Gross margin was $183.9 million for the year ended December 31, 2021 compared to $139.8 million for the year ended December 31, 2020, an increase of $44.1 million primarily due to the following:

◦Adjusted gross margin in the Louisiana segment increased $43.0 million, resulting from:

•A $39.3 million increase to adjusted gross margin associated with our Louisiana NGL transmission and fractionation assets. Adjusted gross margin, excluding derivative activity, increased $56.4 million, which was primarily due to favorable market prices on NGL sales. Derivative activity associated with our Louisiana NGL transmission and fractionation assets decreased margin by $17.1 million, which included $27.1 million from increased realized losses partially offset by $10.0 million from decreased unrealized losses.
•A $5.8 million increase to adjusted gross margin associated with our Louisiana gas assets. Adjusted gross margin, excluding derivative activity, increased $21.3 million, which was primarily due to increased gathering and transportation fees as a result of higher volumes transported in addition to increased storage and hub fees following the acquisition of the Jefferson Island storage facility in December 2020. Derivative activity associated with our Louisiana gas assets decreased margin by $15.5 million, which included $11.6 million from increased realized losses and $3.9 million from increased unrealized losses.
•A $2.1 million decrease to adjusted gross margin associated with our ORV crude assets. Adjusted gross margin, excluding derivative activity, decreased $5.6 million, which was primarily due to lower volumes. Derivative activity associated with our ORV crude assets increased margin by $3.5 million due to $2.4 million from decreased realized losses and $1.1 million from increased unrealized gains.

◦Operating expenses in the Louisiana segment increased $3.7 million primarily due to increased materials and supplies expense and utilities. This increase was partially offset by lower labor and benefits expense as a result of reductions in workforce in April 2020 and ad valorem taxes.

◦Depreciation and amortization in the Louisiana segment decreased $4.8 million primarily due to the impairment of assets in the first quarter of 2020.

•Oklahoma Segment. Gross margin was $123.3 million for the year ended December 31, 2021 compared to $188.5 million for the year ended December 31, 2020, a decrease of $65.2 million primarily due to the following:

◦Adjusted gross margin in the Oklahoma segment decreased $80.0 million, resulting from:

•A $79.0 million decrease to adjusted gross margin associated with our Oklahoma gas assets. Adjusted gross margin, excluding derivative activity, decreased $61.7 million, which was primarily due to lower volumes from our existing customers, including weather disruptions from Winter Storm Uri, and a $56.2 million decrease in adjusted gross margin resulting from the expiration of the MVC provision of a gathering and processing contract at the end of 2020. Derivative activity associated with our Oklahoma gas assets decreased margin by $17.3 million, which included $19.3 million from increased realized losses and was partially offset by $2.0 million from decreased unrealized losses.
•A $1.0 million decrease to adjusted gross margin associated with our Oklahoma crude assets. Adjusted gross margin, excluding derivative activity, decreased $4.6 million, which was primarily due to lower volumes from our existing customers and partially as a result of weather disruptions from Winter Storm Uri. Derivative activity associated with our Oklahoma crude assets increased margin by $3.6 million, which included $1.1 million from increased realized gains and $2.5 million from increased unrealized gains.

◦Operating expenses in the Oklahoma segment decreased $2.2 million primarily due to reductions in compressor rentals and lower labor and benefits expense as a result of reductions in workforce in April 2020. These decreases were partially offset by higher costs in 2021 to decommission equipment from the Battle Ridge processing plant to move to the War Horse processing plant.

◦Depreciation and amortization in the Oklahoma segment decreased $12.6 million primarily due to the relocation of the Battle Ridge processing plant to the War Horse processing plant.

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•North Texas Segment. Gross margin was $136.6 million for the year ended December 31, 2021 compared to $127.0 million for the year ended December 31, 2020, an increase of $9.6 million primarily due to the following:

◦Adjusted gross margin in the North Texas segment decreased $19.2 million. Adjusted gross margin, excluding derivative activity, decreased $8.2 million, which was primarily due to lower volumes from our existing customers. Derivative activity associated with our North Texas segment decreased margin by $11.0 million, which included $6.2 million from increased realized losses and $4.8 million from increased unrealized losses.

◦Operating expenses in the North Texas segment increased $0.3 million primarily due to reductions in compressor rentals, reductions to labor and benefits expense as a result of reductions in workforce in April 2020 and reductions to utility costs. These decreases were partially offset by increases in materials and supplies expense, operation and maintenance costs, and increases in sales and use taxes as a result of tax refunds in the first half of 2020.

◦Depreciation and amortization in the North Texas segment decreased $29.1 million primarily due to a change in the estimated useful lives of certain non-core assets that were fully depreciated at the end of 2020.

•Corporate Segment. Gross margin was negative $8.0 million for the year ended December 31, 2021 compared to negative $7.3 million for the year ended December 31, 2020, a decrease of $0.7 million. Corporate gross margin consists of depreciation and amortization of corporate assets.

Impairments. Impairment expense is composed of the following amounts (in millions):
Year Ended December 31,
20212020
Goodwill impairment$— $184.6 
Property and equipment impairment0.6 168.0 
Lease right-of-use asset impairment0.2 6.8 
Cancelled projects— 3.4 
Total impairments$0.8 $362.8 

Gain (loss) on disposition of assets. For the year ended December 31, 2021, we recorded an $1.5 million gain on disposition of assets primarily related to the sale of various non-core assets. For the year ended December 31, 2020, we recorded a $8.8 million loss on disposition of assets primarily related to the sale of our non-core crude pipeline assets in South Texas.

General and administrative expenses. General and administrative expenses were $107.8 million for the year ended December 31, 2021 compared to $103.3 million for the year ended December 31, 2020, an increase of $4.5 million. The increase was primarily due to labor and benefits costs, which increased $3.4 million; transaction and transition costs, which increased $1.0 million primarily due to the Amarillo Rattler, LLC acquisition in April 2021; franchise taxes, which increased $0.6 million primarily due to franchise tax refunds in the first half of 2020; and consulting fees and services, which increased $1.8 million. These increases were partially offset by a $2.6 million decrease to unit-based compensation costs.

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Interest Expense. Interest expense was $238.7 million for the year ended December 31, 2021 compared to $223.3 million for the year ended December 31, 2020, an increase of $15.4 million, or 6.9%. Net interest expense consisted of the following (in millions):
Year Ended December 31,
20212020
ENLK and ENLC Senior Notes$201.1 $175.0 
Term Loan4.2 17.5 
Consolidated Credit Facility5.8 13.9 
AR Facility4.1 0.9 
Capitalized interest(0.3)(3.4)
Amortization of debt issuance costs and net discount of senior unsecured notes5.2 4.6 
Interest rate swaps - realized18.3 14.5 
Other0.3 0.3 
Total interest expense, net of interest income$238.7 $223.3 

Gain on Extinguishment of Debt. We recognized a gain on extinguishment of debt of $32.0 million for the year ended December 31, 2020 due to repurchases of the 2024, 2025, 2026, and 2029 Notes in open market transactions. For the year ended December 31, 2021, we and ENLK did not repurchase any senior notes. See “Item 8. Financial Statements and Supplementary Data—Note 6” for additional information.

Income (Loss) from Unconsolidated Affiliate Investments. Loss from unconsolidated affiliate investments was$11.5 million for the year ended December 31, 2021 compared to income of $0.6 million for the year ended December 31, 2020, a decrease in income of $12.1 million. The decrease was attributable to a reduction of income of $12.1 million from our GCF investment, as a result of the GCF assets being temporarily idled beginning in January 2021. See “Item 8. Financial Statements and Supplementary Data—Note 10” for additional information.

Income Tax Benefit (Expense). Income tax expense was $25.4 million for the year ended December 31, 2021 compared to income tax expense of $143.2 million for the year ended December 31, 2020, a decrease of tax expense of $117.8 million primarily due to a change in the valuation allowance recorded on our deferred tax assets. See “Item 8. Financial Statements and Supplementary Data—Note 7” for additional information.

Net Income (Loss) Attributable to Non-Controlling Interest. Net income attributable to non-controlling interest was $120.5 million for the year ended December 31, 2021 compared to net income of $105.9 million for the year ended December 31, 2020, an increase of $14.6 million. ENLC’s non-controlling interest is comprised of Series B Preferred Units, Series C Preferred Units, NGP’s 49.9% share of the Delaware Basin JV, and Marathon Petroleum Corporation’s 50% share of the Ascension JV. The increase in income was primarily due to a $7.1 million increase attributable to NGP’s 49.9% share of the Delaware Basin JV, a $4.1 million increase from the Series B Preferred Units, and a $3.4 million increase attributable to Marathon Petroleum Corporation’s 50% share of the Ascension JV.

Year Ended December 31, 2020 Compared to Year Ended December 31, 2019

Gross Margin. Gross margin was $492.9 million for the year ended December 31, 2020 compared to $576.3 million for the year ended December 31, 2019, a decrease of $83.4 million. The primary contributors to the decrease were as follows:

•Permian Segment. Gross margin was $44.9 million for the year ended December 31, 2020 compared to $36.6 million for the year ended December 31, 2019, an increase of $8.3 million primarily due to the following:

◦Adjusted gross margin in the Permian segment decreased $5.0 million, which was primarily driven by:

•A $17.2 million decrease to adjusted gross margin associated with our Permian crude assets. Adjusted gross margin, excluding derivative activity, decreased $9.8 million, which was primarily due to a $15.8 million decrease on our South Texas assets primarily due to the expiration of an MVC provision in one of our contracts in July 2019 and the sale of the VEX assets in October 2020. This decrease was partially offset by a $5.9 million increase due to volume growth in our Delaware Basin crude assets. Derivative activity associated with our Permian crude assets decreased margin by $7.4
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million, which included $10.8 million from decreased realized gains and was partially offset by $3.4 million from increased unrealized gains.
•A $12.2 million increase to adjusted gross margin associated with our Permian gas assets. Adjusted gross margin, excluding derivative activity, increased $15.7 million, which was primarily due to volume growth from additional well connects. Derivative activity associated with our Permian gas assets decreased margin by $3.5 million, which included $3.8 million from increased unrealized losses and $0.3 million from decreased realized losses.

◦Operating expenses in the Permian segment decreased $18.7 million primarily due to decreased labor and benefits expense as a result of reductions in workforce and reductions in materials and supplies expense, construction fees and services, vehicle expenses, and sales and use tax.

◦Depreciation and amortization in the Permian segment increased $5.4 million primarily due to new assets placed into service, including the expansion to our Riptide processing plant and the completed construction of our Tiger processing plant.

•Louisiana Segment. Gross margin was $139.8 million for the year ended December 31, 2020 compared to $143.1 million for the year ended December 31, 2019, a decrease of $3.3 million primarily due to the following:

◦Adjusted gross margin in the Louisiana segment decreased $38.9 million, resulting from:

•A $20.2 million decrease to adjusted gross margin associated with our ORV crude assets. Adjusted gross margin, excluding derivative activity, decreased $16.9 million, which was primarily due to lower volumes. Realized losses on derivative activity associated with our ORV crude assets decreased margin by $3.3 million.
•A $14.8 million decrease to adjusted gross margin associated with our Louisiana gas assets. Adjusted gross margin, excluding derivative activity, decreased $12.8 million, which was primarily due to the expiration of certain firm transportation contracts, and decreased gathering and transportation volumes. Derivative activity associated with our Louisiana gas assets decreased margin by $2.0 million, which included $1.8 million from increased unrealized losses and $0.2 million from increased realized losses.
•A $3.9 million decrease to adjusted gross margin associated with our Louisiana NGL transmission and fractionation assets. Adjusted gross margin, excluding derivative activity, increased $6.6 million, which was primarily due to higher volumes that resulted from the completion of the Cajun-Sibon pipeline expansion in April 2019 and a settlement payment received as the result of a contract dispute in the amount of $5.5 million. Derivative activity associated with our Louisiana NGL transmission and fractionation assets decreased margin by $10.5 million, which included $7.6 million from increased realized losses and $2.9 million from increased unrealized losses.

◦Operating expenses in the Louisiana segment decreased $27.3 million primarily due to decreased labor and benefits expense as a result of reductions in workforce and reductions in materials and supplies expense, utilities, construction fees and services, compressor rentals, and vehicle expenses.

◦Depreciation and amortization in the Louisiana segment decreased $8.3 million primarily due to the impairment of Louisiana segment assets in the first quarter of 2020.

•Oklahoma Segment. Gross margin was $188.5 million for the year ended December 31, 2020 compared to $255.2 million for the year ended December 31, 2019, a decrease of $66.7 million primarily due to the following:

◦Adjusted gross margin in the Oklahoma segment decreased $66.5 million, resulting from:

•A $59.7 million decrease to adjusted gross margin associated with our Oklahoma gas assets. Adjusted gross margin, excluding derivative activity, decreased $51.7 million, which was primarily due to volume decline in our Oklahoma gas assets resulting from lower volumes from our existing customers. Derivative activity associated with our Oklahoma gas assets decreased margin by $8.0 million, which included $4.5 million from increased unrealized losses and $3.5 million from increased realized losses.
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•A $6.8 million decrease to adjusted gross margin associated with our Oklahoma crude assets. Adjusted gross margin, excluding derivative activity, decreased $5.9 million, which was primarily due to volume decline in our Oklahoma crude assets primarily due to lower volumes from our existing customers. Realized losses on derivative activity associated with our Oklahoma crude assets decreased margin by $0.9 million.

◦Operating expenses in the Oklahoma segment decreased $21.8 million primarily due to decreased labor and benefits expense as a result of reductions in workforce and reductions in materials and supplies expense, construction fees and services, and compressor rentals.

◦Depreciation and amortization in the Oklahoma segment increased $22.0 million primarily due to the Thunderbird processing plant, which was operational in June 2019, as well as a change in the estimated useful lives of certain non-core assets.

•North Texas Segment. Gross margin was $127.0 million for the year ended December 31, 2020 compared to $149.8 million for the year ended December 31, 2019, a decrease of $22.8 million primarily due to the following:

◦Adjusted gross margin in the North Texas segment decreased $44.7 million. Adjusted gross margin, excluding derivative activity, decreased $43.9 million, which was primarily due to volume declines resulting from limited new drilling in the region. Unrealized losses on derivative activity associated with our North Texas segment decreased margin by $0.8 million.

◦Operating expenses in the North Texas segment decreased $25.5 million primarily due to decreased labor and benefits expense as a result of reductions in workforce and reductions in materials and supplies expense, operations and maintenance, fees and services, sales and use tax, ad valorem taxes, and compressor rentals.

◦Depreciation and amortization in the North Texas segment increased $3.6 million primarily due to a change in the estimated useful lives of certain non-core assets and the conclusion of a finance lease in 2019.

•Corporate Segment. Gross margin was negative $7.3 million for the year ended December 31, 2020 compared to negative $8.4 million for the year ended December 31, 2019. Corporate gross margin consists of depreciation and amortization of corporate assets.

Critical Accounting Policies

The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as the accounting rules have developed. Accounting rules generally do not involve a selection among alternatives but involve an interpretation and implementation of existing rules and the use of judgment to the specific set of circumstances existing in our business. Compliance with the rules involves reducing a number of very subjective judgments to a quantifiable accounting entry or valuation. We make every effort to properly comply with all applicable rules on or before their adoption, and we believe the proper implementation and consistent application of the accounting rules is critical.

Our critical accounting policies are discussed below. See “Item 8. Financial Statements and Supplementary Data—Note 2” for further details on our accounting policies and future accounting standards to be adopted.

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Impairment of Long-Lived Assets

We evaluate long-lived assets, including property and equipment, intangible assets, equity method investments, and lease right-of-use assets, for potential impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable. The carrying amount of a long-lived asset is not recoverable when it exceeds the undiscounted sum of the future cash flows expected to result from the use and eventual disposition of the asset. Estimates of expected future cash flows represent management’s best estimate based on reasonable and supportable assumptions. Management’s estimate of future cash flows are subject to uncertainty due to the changing business environment, volatility of commodity prices, and a number of other factors that are beyond our ability to consistently predict. Management updates their estimated future cash flows throughout the year and a potential impairment is highly sensitive to unfavorable changes in the underlying estimated cash flows. When the carrying amount of a long-lived asset is not recoverable, an impairment is recognized equal to the excess of the asset’s carrying value over its fair value, which is based on inputs that are not observable in the market, and thus represent Level 3 inputs. For additional information about our long-lived asset impairment tests, refer to “Item 8. Financial Statements and Supplementary Data—Note 2.”

Property and Equipment Impairments. For the year ended December 31, 2021, we recognized a $0.6 million impairment on property and equipment.

Right-of-Use Asset Impairment. During the fourth quarter of 2021, we entered into a sublease agreement for a portion of our Houston office that will be effective in 2022. We evaluated the related right-of-use asset for impairment by comparing the estimated fair value of the right-of-use asset to its carrying value. The estimated fair value was calculated using a discounted cash flow analysis that utilized Level 3 inputs, which included future cash flows based on the terms of the sublease and a discount rate derived from market data. As the carrying value of the right-of-use asset exceeded the estimated fair value, we have recognized impairment expense of $0.2 million for the year ended December 31, 2021.

To the extent conditions further deteriorate in the current worldwide economic and commodity price environment, we may identify additional triggering events that may require future evaluations of the recoverability of the carrying value of our long-lived assets, which could result in further impairment charges.

Liquidity and Capital Resources

Cash Flows from Operating Activities. Net cash provided by operating activities was $857.3 million for the year ended December 31, 2021 compared to $731.1 million for the year ended December 31, 2020. Operating cash flows and changes in working capital for comparative periods were as follows (in millions):
Year Ended December 31,
20212020
Operating cash flows before working capital$802.5 $842.3 
Changes in working capital54.8 (111.2)

Operating cash flows before changes in working capital decreased $39.8 million for the year ended December 31, 2021 compared to the year ended December 31, 2020. The primary contributors to the decrease in operating cash flows were as follows:

•Gross margin; excluding depreciation and amortization; non-cash commodity swap activity; utility credits, net of usage; and unit-based compensation, decreased $36.0 million. For more information regarding the changes in gross margin for the year ended December 31, 2021 compared to the year ended December 31, 2020, see “Results of Operations.”

•General and administrative expenses, excluding unit-based compensation, increased $7.1 million. For more information, see “Results of Operations.”

•Interest expense, excluding amortization of debt issuance costs, net discount of senior unsecured notes, and designated cash flow hedge, increased $2.8 million.

•Distribution of earnings from unconsolidated affiliates, excluding distributions in excess of earnings which are classified as investing cash flows, decreased $1.6 million.

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2018
Growth Capital Expenditures
Texas segment$210 - 250
Louisiana segment105 - 125
Oklahoma segment (1)340 - 420
Crude and Condensate segment40 - 50
Corporate segment5 - 15
Total growth capital expenditures$700 - 860
Less: Growth capital expenditures funded by joint venture partners (2)(70 - 90)
Growth capital expenditures, attributable to ENLC$630 - 770
Maintenance Capital Expenditures$55 - 60
These changes to operating cash flows were offset by the following:
(1)
Includes projected growth capital contributions related to our non-controlling interest share of the Cedar Cove JV.
(2)Includes growth capital expenditures that will be contributed by other entities and relate to the non-controlling interest share of our consolidated entities. These contributions include contributions by NGP to the Delaware Basin JV and contributions by Marathon Petroleum to the Ascension JV.


•Cash payments for the early termination of our interest rate swaps, due to the partial repayments of the Term Loan, decreased $9.1 million.

The changes in working capital for the years ended December 31, 2021 and 2020 were primarily due to fluctuations in trade receivable and payable balances due to timing of collection and payments, changes in inventory balances attributable to normal operating fluctuations, and fluctuations in accrued revenue and accrued cost of sales.

Historically, we have had net operating losses that eliminated substantially all of our taxable income, and thus, we have not historically paid significant amounts of income taxes. We anticipate generating net operating losses for tax purposes during 2022, and as a result, do not expect to incur material amounts of federal and state income tax liabilities. In the event that we do generate taxable income that exceeds our utilizable net operating loss carryforwards, federal and state income tax liabilities will increase cash taxes paid. Refer to “Item 8. Financial Statements and Supplementary Data—Note 7” for additional information.

Cash Flows from Investing Activities. Net cash used in investing activities was $231.4 million for the year ended December 31, 2021 compared to $317.7 million for the year ended December 31, 2020. Our primary investing activities consisted of the following (in millions):
Year Ended December 31,
20212020
Additions to property and equipment (1)$(184.0)$(302.2)
Acquisition of assets (2)(56.7)(32.3)
Proceeds from sale of property (3)4.8 17.6 
____________________________
(1)The decrease in capital expenditures was primarily due to the completion of major projects in 2020.
(2)Acquisition of assets for the year ended December 31, 2020 included the acquisition of the Jefferson Island storage facility. Acquisition of assets for the year ended December 31, 2021 included the acquisition of Amarillo Rattler assets and other minor acquisitions.
(3)Proceeds from the sale of assets related to the sale of non-core assets.

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Cash Flows from Financing Activities. Net cash used in financing activities was $639.3 million for the year ended December 31, 2021 compared to $451.2 million for the year ended December 31, 2020. Our primary financing activities consisted of the following (in millions):
Year Ended December 31,
20212020
Net repayments on the Term Loan (1)$(350.0)$(500.0)
Net borrowings on the AR Facility (1)100.0 250.0 
Net borrowings (repayments) on the Consolidated Credit Facility (1)15.0 (350.0)
Net borrowings on ENLC senior unsecured notes (1)— 499.2 
Net repurchases on ENLK’s senior unsecured notes (1)— (35.2)
Distributions to members(186.8)(232.7)
Distributions to Series B and Series C Preferred unitholders (2)(92.9)(91.3)
Distributions to joint venture partners (3)(37.9)(29.9)
Redemption of Series B Preferred units (2)(50.0)— 
Common unit repurchases (4)(40.1)(1.2)
Contributions by non-controlling interest (5)3.2 52.6 
Conversion of restricted units, net of units withheld for taxes(2.0)(4.7)
Debt financing costs(0.3)(7.7)
____________________________
(1)See “Item 8. Financial Statements and Supplementary Data—Note 6” for more information regarding the Term Loan, the AR Facility, the Consolidated Credit Facility, and the senior unsecured notes.
(2)See “Item 8. Financial Statements and Supplementary Data—Note 8” for information on distributions to holders of the Series B Preferred Units and Series C Preferred Units and information on the partial redemption of Series B Preferred Units.
(3)Represents distributions to NGP for its ownership in the Delaware Basin JV, distributions to Marathon Petroleum Corporation for its ownership in the Ascension JV, and distributions to other non-controlling interests.
(4)See “Item 8. Financial Statements and Supplementary Data—Note 9” for more information regarding the ENLC common unit repurchase program.
(5)Represents contributions from NGP to the Delaware Basin JV.

Capital Requirements. We expect our total capital expenditures and expenses related to the relocation of equipment and facilities, which are recorded as operating expenses, to range between $285 million to $325 million for 2022. Our primary capital projects for 20182022 include the constructionrelocation of the ThunderbirdPhantom processing plant, in Central Oklahoma, the Lobo III processing plant in the Delaware Basin and thecontinued development of additional gatheringour existing systems through well connects, and compression assets in Central Oklahoma and the Permian Basin. See “Recent Developments” for further details.

other low-cost development projects. We expect to fund growthour remaining 2022 capital expenditures from the proceeds of borrowings under the ENLK Credit Facilityoperating cash flows and proceeds from other debt and equity sources, including capital contributions by joint venture partners that relate to the non-controlling interest share of our consolidated entities. We expect to fund our maintenance capital expenditures from operating cash flows. In 2018, it

It is possible that not all of theour planned projects will be commenced or completed. Our ability to pay distributions to our unitholders, to fund planned capital expenditures, and to make acquisitions will depend upon our future operating performance, which will be affected by prevailing economic conditions in the industry, financial, business, and other factors, some of which are beyond our control.



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

Off-Balance Sheet Arrangements. We had no off-balance sheet arrangements as of December 31, 2017, 20162021 and 2015.2020.


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Total Contractual Cash Obligations. A summary of our total contractual cash obligations as of December 31, 20172021 is as follows (in millions):
Payments Due by Period
Total20222023202420252026Thereafter
ENLC’s & ENLK’s senior unsecured notes$4,032.3 $— $— $521.8 $720.8 $491.0 $2,298.7 
Consolidated Credit Facility (1)15.0 — — 15.0 — — — 
AR Facility (2)350.0 — — 350.0 — — — 
Acquisition installment payable (3)10.0 10.0 — — — — — 
Acquisition contingent consideration (4)6.9 — — 2.3 2.4 2.2 — 
Interest payable on fixed long-term debt obligations2,334.9 201.2 201.2 189.7 163.3 148.3 1,431.2 
Operating lease obligations115.6 21.1 15.3 10.1 9.8 8.9 50.4 
Purchase obligations4.9 4.9 — — — — — 
Pipeline and trucking capacity and deficiency agreements (5)316.0 50.9 54.6 50.9 39.4 30.9 89.3 
Inactive easement commitment (6)10.0 10.0 — — — — — 
Total contractual obligations$7,195.6 $298.1 $271.1 $1,139.8 $935.7 $681.3 $3,869.6 
 Payments Due by Period
 Total 2018 2019 2020 2021 2022 Thereafter
Long-term debt obligations$3,500.0
 $—
 $400.0
 $—
 $—
 $—
 $3,100.0
ENLC Credit Facility74.6
 —
 74.6
 —
 —
 —
 —
Interest payable on fixed long-term debt obligations2,573.4
 159.9
 154.5
 149.2
 149.2
 149.2
 1,811.4
Installment payable obligations (1)250.0
 250.0
 —
 —
 —
 —
 —
Capital lease obligations4.4
 1.5
 1.5
 1.4
 —
 —
 —
Operating lease obligations109.6
 14.3
 10.9
 8.6
 8.6
 8.6
 58.6
Purchase obligations2.7
 2.7
 —
 —
 —
 —
 —
Delivery contract obligation26.9
 17.9
 9.0
 —
 —
 —
 —
Pipeline capacity and deficiency agreements (2)91.7
 19.3
 14.3
 8.9
 8.8
 8.8
 31.6
Inactive easement commitment (3)10.0
 —
 —
 —
 —
 10.0
 —
Total contractual obligations$6,643.3
 $465.6
 $664.8
 $168.1
 $166.6
 $176.6
 $5,001.6
____________________________
(1)Amounts relate to the final installment payable that was paid in January 2018 for the acquisition of the EnLink Oklahoma T.O. assets.
(2)
Consists of pipeline capacity payments for firm transportation and deficiency agreements.
(3)
Amounts related to inactive easements paid as utilized by us with balance due in 2022 if not utilized.

(1)The Consolidated Credit Facility will mature on January 25, 2024.
(2)The AR Facility will terminate on September 24, 2024, unless extended or earlier terminated in accordance with its terms.
(3)Amount related to the consideration of the Amarillo Rattler, LLC acquisition due on April 30, 2022.
(4)The estimated fair value of the Amarillo Rattler, LLC contingent consideration was calculated in accordance with the fair value guidance contained in ASC 820. There are a number of assumptions and estimates factored into these fair values and actual contingent consideration payments could differ from these estimated fair values. See “Item 8. Financial Statements and Supplementary Data—Note 13” for additional information.
(5)Consists of pipeline capacity payments for firm transportation and deficiency agreements.
(6)Amount related to inactive easements paid as utilized by us with the balance due in August 2022 if not utilized.

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


The interest payable underrelated to the ENLKConsolidated Credit Facility and the ENLC CreditAR Facility are not reflected in the above table because such amounts depend on the respective outstanding balances and interest rates of the Consolidated Credit Facility and the AR Facility, which vary from time to time. However, given the same borrowing amounts and rates in effect on December 31, 2017, the cash obligation for interest expense on the ENLC Credit Facility would be approximately $2.4 million per year.


In January 2018, ENLK paid the final $250.0 million installment payable obligation related to the EnLink Oklahoma T.O. acquisition. ENLK funded this installment payment using various sources, including proceeds from the Series C Preferred Units issued in September 2017, proceeds from ENLK common unit issuances under the 2017 EDA and borrowings under the ENLK Credit Facility. Our contractual cash obligations for the remainder of 20182022 are expected to be funded from cash flows generated from our operations proceeds from ENLK common unit issuancesand the available capacity under the 2017 EDA, asset sales and borrowings under the ENLKConsolidated Credit Facility or other debt sources.

Indebtedness

In October 2020, we entered into the AR Facility, which was originally a three-year committed accounts receivable securitization facility in the amount of up to $250.0 million. During 2021, we entered into two amendments to the Receivables Financing Agreement, which amended the AR Facility to, among other things, increase the facility limit and ENLC Credit Facility.

Indebtedness

The ENLK Credit Facility is a $1.5 billion unsecured revolving credit facility that matures on March 6, 2020,lender commitments to $350.0 million and includes a $500.0 million letter of credit subfacility.extend the scheduled termination date to September 24, 2024. As of December 31, 2017,2021, the AR Facility had a borrowing base of $350.0 million and there were $9.8 million in outstanding letters of credit and no outstanding borrowings under the ENLK Credit Facility, leaving approximately $1.5 billion available for future borrowing.

The ENLC Credit Facility is a $250.0 million revolving credit facility that matures on March 7, 2019 and includes a $125.0 million letter of credit subfacility. As of December 31, 2017, there were no outstanding letters of credit and $74.6was $350.0 million in outstanding borrowings under the ENLC Credit Facility, leaving approximately $175.4 million available for future borrowing.AR Facility.


In addition, ENLK has $3.5as of December 31, 2021, we have $4.0 billion in aggregate principal amount of outstanding unsecured senior notes maturing from 2024 to 2047. There was $15.0 million in outstanding borrowings under the Consolidated Credit Facility and $41.3 million outstanding letters of credit as of December 31, 2017 with $400.0 million maturing in April 20192021.

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Guarantees. The amounts outstanding on our senior unsecured notes and the remaining maturities beginningConsolidated Credit Facility are guaranteed in 2024full by our subsidiary ENLK, including 105% of any letters of credit outstanding on the Consolidated Credit Facility. ENLK’s guarantees of these amounts are full, irrevocable, unconditional, and endingabsolute, and cover all payment obligations arising under the senior unsecured notes and the Consolidated Credit Facility. Liabilities under the guarantees rank equally in 2047. right of payment with all existing and future senior unsecured indebtedness of ENLK.

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

As of December 31, 2021, ENLC records, on a stand-alone basis, transactions that do not occur at ENLK, which are primarily related to taxation of ENLC and the elimination of intercompany borrowings.

See “Item 8. Financial Statements—Statements and Supplementary Data—Note 6” for more information on our outstanding debt instruments.debt.

Credit Risk


Risks of nonpayment and nonperformance by our customers are a major concern in our business. We are subject to risks of loss resulting from nonpayment or nonperformance by our customers and other counterparties, such as our lenders and hedging counterparties. Any increase in the nonpayment and nonperformance by our customers could adversely affect our results of operations and reduce our ability to make distributions to our unitholders.


Inflation


Inflation in the United States has been relatively low in recent yearsyears. However, the annual U.S. inflation rate has accelerated throughout 2021 and this trend is expected to continue in 2022. In addition, base interest rates are expected to rise in 2022. Although we do not expect inflation to have a material effect on our results, the economy as a whole. The midstream natural gas industry’s labor and material costs remained relatively unchanged in 2015, 2016 and 2017. Although the impact ofincreased inflation has been insignificant in recent years, it is still a factor in the United States economy and may increase the cost to acquire or replace property and equipment and may increase the costs of labor and supplies. To the extent permitted by competition, regulation, and our existing agreements, we have and will continue to pass along increased costs to our customers in the form of higher fees. Additionally, certain of our revenue generating contracts contain clauses that increase our fees based on changes in inflation metrics.


Environmental


Our operations are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which these operations are conducted. We believe we are in material compliance with all applicable laws and regulations. For a more complete discussion of the environmental laws and regulations that impact us, see “Item 1. Business—Environmental Matters.”


Contingencies


See “Item 8. Financial Statements and Supplementary Data—Note 15.14.”


Recent Accounting Pronouncements


See “Item 8. Financial Statements and Supplementary Data—Note 2” in our Annual Report on Form 10-K for morethe year ended December 31, 2020 filed with the Commission on February 17, 2021 for information on recently issued and adopted accounting pronouncements.


Disclosure Regarding Forward-Looking Statements


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


Item 7A. Quantitative and Qualitative Disclosures about Market Risk


Market risk is the risk of loss arising from adverse changes in market rates and prices. Our primary market risk is the risk related to changes in the prices of natural gas, NGLs, condensate, and crude oil. In addition, we are also exposed to the risk of changes in interest rates on floating rate debt.
 
Comprehensive financial reform legislation was signed into law by the President on July 21, 2010. The legislation calls for the U.S. Commodity Futures Trading Commission (“CFTC”)CFTC to regulate certain markets for derivative products, including over-the-counter (“OTC”)OTC derivatives. The CFTC has issued several new relevant regulations, and other rulemakings are pending at the CFTC, the product of which would be rules that mandate that certainimplement the mandates in the legislation to cause significant portions of derivatives products be subjectmarkets to margin requirements, cleared at a clearinghouse or executed on an exchange.clear through clearinghouses. While some of these rules have been finalized, some have not, and, as a result, the final form and timing of the implementation of the new regulatory regime affecting commodity derivatives remains uncertain.

 
In particular, on October 18, 2011, the CFTC adopted final rules under the Dodd-Frank Act establishing position limits for certain energy commodity futures and options contracts and economically equivalent swaps, futures and options. The CFTC’s original position limits rule was challenged in court by two industry associations and was vacated and remanded by a federal district court. The CFTC has withdrawn its appeal of the court order vacating the original position limits rule. However, in November 2013, the CFTC proposed new rules that would place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. In December 2016, the CFTC modified and reproposed its positions limits rules. The CFTC has sought comment on the position limits rule as reproposed, but these new position limit rules are not yet final and the impact of those provisions on us is uncertain at this time.
The legislation and potential new regulations may also require counterparties to our derivative instruments to spin off or result in such counterparties spinning off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. The new legislation and any future new regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures and to generate sufficient cash flow to pay quarterly distributions at current levels or at all. Our revenues could be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material, adverse effect on us, our financial condition, and our results of operations.


On January 14, 2021, the CFTC published final rules under the Dodd-Frank Act establishing position limit levels for certain energy commodity futures contracts, options and contracts on futures contracts directly or indirectly linked to core
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referenced futures contracts, and economically equivalent swaps. The position limit levels set the maximum position that a trader may own or control separately or in combination, net long or short, subject to exceptions for certain bona fide hedging transactions. These rules came into effect on March 15, 2021 with compliance dates starting from January 1, 2022. We do not expect these position limit rules will have a material effect on us.

Commodity Price Risk


TheCommodity prices of crude oil, condensate, natural gas and NGLs were volatile during 2017.2021. Crude oil andprices increased 58%, weighted average NGL prices increased 15%77%, and 21%, respectively, while natural gas prices decreased 11%increased 45% from January 1, 20172021 to December 31, 2017.2021. We expect continued volatility in these commodity prices. For example, see the table below for the range of closing prices for crude oil, NGL, and natural gas during 2021.
CommodityClosing PriceDate
Crude oil (high) (1)$84.65 October 26, 2021
Crude oil (low) (1)$47.62 January 4, 2021
Crude oil (average) (1)(4)$68.11 Not applicable
NGL (high) (2)$1.02 November 1, 2021
NGL (low) (2)$0.46 January 4, 2021
NGL (average) (2)(4)$0.71 Not applicable
Natural gas (high) (3)$6.31 October 5, 2021
Natural gas (low) (3)$2.45 January 22, 2021
Natural gas (average) (3)(4)$3.72 Not applicable
____________________________
(1)Crude oil closing prices (basedbased on the NYMEX futures daily close prices for the prompt month) in 2017 ranged from a high of $60.42 per Bbl in December 2017 to a low of $42.53 per Bbl in June 2017. prices.
(2)Weighted average NGL gas closing prices in 2017 (basedbased on the Oil Price Information Service (“OPIS”) Napoleonville daily average spot liquids prices) ranged from a high of $0.78 per gallon in February 2017 to a low of $0.41 per gallon in January 2017. prices.
(3)Natural gas closing prices (basedbased on Gas Daily Henry Hub closing prices)prices.
(4)The average closing price was computed by taking the sum of the closing prices of each trading day divided by the number of trading days during 2017 ranged from a high of $3.42 per MMBtu in May 2017 to a low of $2.56 per MMBtu in February 2017.the period presented.


Changes in commodity prices may indirectly impact our profitability by influencing drilling activity and well operations, and thus the volume of gas, NGLs, crude oil, and condensate connected to or near our assets and on our fees earned for transportation between certain market centers. Low prices for these products could reduce the demand for our services and volumes in our systems. The volatility in commodity prices may cause our adjusted gross operating margin and cash flows to vary widely from period to period. Our hedging strategies may not be sufficient to offset price volatility risk and, in any event, do not cover all of our throughput volumes.


We are also subject to direct risks due to fluctuations in commodity prices. Approximately 94%While approximately 89% of our adjusted gross operating margin for the year ended December 31, 20172021 was generated from arrangements with fee-based structures with minimal direct commodity price exposure, the remainder is subject to more direct commodity price exposure. Our exposure to these commodity price fluctuations is primarily in the gas processing component of our business. We currently process gasearn adjusted gross margin under four main types of contractual arrangements (or a combination of these types of contractual arrangements) as summarized below.


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

1.Fee-based contracts: Under fee-based contracts, we earn our fees through (1) stated fixed-fee arrangements in which we are paid a fixed fee per unit of volume or (2) arrangements where we purchase and resell commodities in connection with providing the related service and earn a net margin through a fee-like deduction subtracted from the purchase price of the commodities. We may also purchase and resell commodities in arrangements under which we are subject to commodity price fluctuations. Although historically this has not been a material component of our adjusted gross margin, Winter Storm Uri caused sudden and significant price and volume fluctuations that resulted in increased adjusted gross margin that is exposed to commodity price fluctuations. For more information on Winter Storm Uri and its impact on the Company, see the discussion at “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Recent Developments Affecting Industry Conditions and Our Business—Extreme Weather Events” in this Report. For the year ended December 31, 2021, approximately 5% of our adjusted gross margin was generated from purchase and resell arrangements under which we are subject to commodity price fluctuations. This amount was substantially offset by derivative losses.
2.
Processing margin contracts:

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2.Processing margin contracts: Under these contracts, we pay the producer for the full amount of inlet gas to the plant, and we make a margin based on the difference between the value of liquids recovered from the processed natural gas as compared to the value of the natural gas volumes lost and the cost of fuel used in processing. The shrink and fuel losses are referred to as plant thermal reduction, or PTR. Our margins from these contracts are high during periods of high liquids prices relative to natural gas prices and can be negative during periods of high natural gas prices relative to liquids prices. However, we mitigate our risk of processing natural gas when margins are negative primarily through our ability to bypass processing when it is not profitable for us or by contracts that revert to a minimum fee for the full amount of inlet gas to the plant, and we make a margin based on the difference between the value of liquids recovered from the processed natural gas as compared to the value of the natural gas volumes lost and the cost of fuel used in processing. The shrink and fuel losses are referred to as plant thermal reduction, or PTR. Our margins from these contracts are high during periods of high liquids prices relative to natural gas prices and can be negative during periods of high natural gas prices relative to liquids prices. However, we mitigate our risk of processing natural gas when margins are negative primarily through our ability to bypass processing when it is not profitable for us or by contracts that revert to a minimum fee for

processing if the natural gas must be processed to meet pipeline quality specifications. For the year ended December 31, 2017, approximately 1.3%2021, less than 1% of our contracts, based onadjusted gross operating margin were underwas generated from processing margin contracts.

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

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


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

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

For the year ended December 31, 2017,2021, approximately 3.4%6% of our contracts, based onadjusted gross operating margin were processed under percent of liquidswas generated from POL or percent of proceedsPOP contracts.


Our primary commodity risk management objective is to reduce volatility in our cash flows. We maintain a risk management committee, including members of senior management, which oversees all hedging activity. We enter into hedges for natural gas, crude and condensate, and NGLs using over-the-counterOTC derivative financial instruments with only certain well-capitalized counterparties, which have been approved byin accordance with our commodity risk management committee.policy.


We have hedged our exposure to fluctuations in prices for natural gas, NGLs, and NGLcrude oil volumes produced for our account. We hedge our exposure based on volumes we consider hedgeable (volumes committed under contracts that are long term in nature) versus total volumes that include volumes that may fluctuate due to contractual terms, such as contracts with month-to-month processing options. Further, we have tailored our hedges to generally match the NGL product composition and the NGL and natural gas delivery points to those of our physical equity volumes. The NGL hedges cover specific NGL products based upon our expected equity NGL composition.


The following table sets forth certain information related to derivative instruments outstanding at December 31, 2017 mitigating2021. These derivative instruments mitigate the risks associated with the gas processing and fractionation components of our business. The relevant payment index price for liquids is the monthly average of the daily closing price for deliveries of commodities into Mont Belvieu, Texas as reported by OPIS.Oil Price Information Service. The relevant index price for natural gas is Henry Hub Gas Daily as defined by the pricing dates in the swap contracts.
PeriodUnderlyingNotional VolumeWe PayWe Receive (1)Net Fair Value
Asset/(Liability)
(In millions)
January 2022 - September 2022Propane1,235 (MBbls)Index$1.063/Gal$(8.1)
January 2022 - September 2022Normal butane265 (MBbls)Index$1.248/Gal(2.5)
January 2022 - October 2022Natural gas56,625 (MMbtu/d)Index$3.8406/MMbtu(5.1)
January 2022 - January 2023Crude and condensate7,715 (MBbls)Index$75.82/Bbl1.2 
$(14.5)
____________________________

Period Underlying Notional Volume We Pay We Receive (1) 
Fair Value
Asset/(Liability)(In millions)
January 2018 - December 2018 Ethane 384 (MBbls) $0.2639/gal Index $(0.2)
January 2018 - December 2018 Propane 681 (MBbls) Index $0.8758/gal (3.7)
January 2018 - December 2018 Normal Butane 362 (MBbls) Index $0.9235/gal 0.7
January 2018 - December 2018 Natural Gasoline 89 (MBbls) Index $1.3759/gal (0.6)
January 2018 - January 2019 Natural Gas 122,629 (MMBtu/d) Index $2.5664/MMBtu 2.2
          $(1.6)
(1)Weighted average.


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


The use of financial instruments may expose us to the risk of financial loss in certain circumstances, including instances when (1) sales volumes are less than expected requiring market purchases to meet commitments or (2) counterparties fail to purchase the contracted quantities of natural gas or otherwise fail to perform. To the extent that we engage in hedging activities,

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we may be prevented from realizing the benefits of favorable price changes in the physical market. However, we are similarly insulated against unfavorable changes in such prices.


As of December 31, 2017,2021, outstanding natural gas swap agreements, NGL swap agreements, swing swap agreements, storage swap agreements, and other derivative instruments werehad a net fair value liability of $1.6$14.5 million. The aggregate effect of a hypothetical 10% change, increase or decrease, in gas, crude and condensate, and NGL prices would result in an immateriala change of approximately $4.5 million in the approximate net fair value of these contracts as of December 31, 2017.2021.


Interest Rate Risk


We are exposed to interest rate risk fromon the ENLCConsolidated Credit Facility and the ENLK CreditAR Facility. At December 31, 2017, the ENLC Credit Facility2021, we had $74.6$15.0 million and $350.0 million in outstanding borrowings under the Consolidated Credit Facility and the ENLK CreditAR Facility, had no outstanding borrowings.respectively. A 1%1.0% increase or decrease in interest rates would change the annualour annualized interest expense for the ENLC Credit Facility by approximately $0.7$0.2 million and $3.5 million for the year.Consolidated Credit Facility and the AR Facility, respectively.


Amounts drawn on the Consolidated Credit Facility and the AR Facility currently bear interest at rates based on LIBOR, which is beginning to be phased out. Both the Consolidated Credit Facility and the AR Facility include mechanisms to amend the facilities to reflect the establishment of an alternative to LIBOR, and the AR Facility has been amended to include a specific replacement reference rate alternative. However, the replacement rate for the AR Facility could result in a higher interest rate than LIBOR. If no such contractual alternative is established for the Consolidated Credit Facility before the LIBOR phase out is complete, it would bear interest at the prime rate, which would be higher than LIBOR, until a contractual alternative is established.

We are not exposed to changes in interest rates with respect to ENLK’s senior unsecured notes due in 2019, 2024, 2025, 2026, 2044, 2045, or 2047 or our senior unsecured notes due in 2028 and 2029 as these are fixed-rate obligations. TheAs of December 31, 2021, the estimated fair value of ENLK’sthe senior unsecured notes was approximately $3,575.6$4,155.0 million, as of December 31, 2017, based on the market prices of similarENLK’s and our publicly traded debt at December 31, 2017.2021. Market risk is estimated as the potential decrease in fair value of our long-term debt resulting from a hypothetical increase of 1%1.0% in interest rates. Such an increase in interest rates would result in an approximate $290.3$255.4 million decrease in fair value of ENLK’sthe senior unsecured notes at December 31, 2017.2021. See “Item 8. Financial Statements and Supplementary Data—Note 6” for more information on our outstanding indebtedness.



Beginning on December 15, 2022, distributions on ENLK’s Series C Preferred Units will be based on a floating rate tied to LIBOR rather than a fixed rate and, therefore, the amount paid by ENLK as a distribution will be more sensitive to changes in interest rates.
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Item 8. Financial Statements and Supplementary Data


INDEX TO FINANCIAL STATEMENTS


EnLink Midstream, LLC and Subsidiaries Financial Statements:
EnLink Midstream, LLC Financial Statements:
Management’s Report on Internal Control Over Financial Reporting
9293
Report of Independent Registered Public Accounting Firm (KPMG LLP, Dallas, TX, Auditor Firm ID: 185)
9394
Consolidated Balance Sheets as of December 31, 20172021 and 20162020
9596
Consolidated Statements of Operations for the years ended December 31, 2017, 20162021, 2020, and 20152019
9697
Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2017, 20162021, 2020, and 20152019
9798
Consolidated Statements of Changes in Members’ Equity for the years ended December 31, 2017, 20162021, 2020, and 20152019
9899
Consolidated Statements of Cash Flows for the years ended December 31, 2017, 20162021, 2020, and 20152019
100101
Notes to Consolidated Financial Statements
101102



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MANAGEMENT’S REPORT ON
INTERNAL CONTROL OVER FINANCIAL REPORTING


Management of EnLink Midstream Manager, LLC, the Managing Member, is responsible for establishing and maintaining adequate internal control over financial reporting and for the assessment of the effectiveness of internal control over financial reporting for EnLink Midstream, LLC (the “Company”). As defined by the Securities and Exchange Commission (Rule 13a-15(f) under the Securities Exchange Act of 1934, as amended), internal control over financial reporting is a process designed by, or under the supervision of EnLink Midstream Manager, LLC’s principal executive and principal financial officers and effected by its Board of Directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the consolidated financial statements in accordance with U.S. generally accepted accounting principles.GAAP.


The Company’s internal control over financial reporting is supported by written policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the Company’s transactions and dispositions of the Company’s assets; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of the consolidated financial statements in accordance with U.S. generally accepted accounting principles,GAAP, and that receipts and expenditures of the Company are being made only in accordance with authorization of the EnLink Midstream Manager, LLC’s management and directors; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the consolidated financial statements.


Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.


In connection with the preparation of the Company’s annual consolidated financial statements, management has undertaken an assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2017,2021, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO Framework). Management’s assessment included an evaluation of the design of the Company’s internal control over financial reporting and testing of the operational effectiveness of those controls.


Based on this assessment, management has concluded that as of December 31, 2017,2021, the Company’s internal control over financial reporting was effective to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. generally accepted accounting principles.GAAP.


KPMG LLP, the independent registered public accounting firm that audited the Company’s consolidated financial statements included in this report, has issued an attestation report on the Company’s internal control over financial reporting, a copy of which appears on the following page of this annual reportAnnual Report on Form 10-K.



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Report of Independent Registered Public Accounting Firm


TheTo the Members of EnLink Midstream, LLC
and Board of Directors
of EnLink Midstream Manager, LLC:


Opinions on the Consolidated Financial Statements and Internal Control Over Financial Reporting


We have audited the accompanying consolidated balance sheets of EnLink Midstream, LLC (a Delaware limited liability corporation) and subsidiaries (the Company) as of December 31, 20172021 and 2016,December 31, 2020, the related consolidated statements of operations, comprehensive income (loss), changes in members’ equity, and cash flows for each of the years in the three-year period ended December 31, 2017,2021, and the related notes (collectively, the “consolidatedconsolidated financial statements”)statements). We also have audited EnLink Midstream, LLC’sthe Company’s internal control over financial reporting as of December 31, 2017,2021, based on criteria established in Internal Control—Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.


In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of EnLink Midstream, LLCthe Company as of December 31, 20172021 and 2016,December 31, 2020, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2017,2021, in conformity with U.S. generally accepted accounting principles. Also in our opinion, EnLink Midstream, LLCthe Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017,2021 based on criteria established in Internal Control—Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.


Basis for OpinionOpinions


EnLink Midstream, LLC’sThe Company’s management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control overOver Financial Reporting. Our responsibility is to express an opinion on EnLink Midstream, LLC’sthe Company’s consolidated financial statements and an opinion on EnLink Midstream, LLC’sthe Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”)(PCAOB) and are required to be independent with respect to EnLink Midstream, LLCthe Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.


We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.


Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.


Definition and Limitations of Internal Control Over Financial Reporting


A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.


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Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.


Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of a critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Evaluation of long-lived assets for impairment triggering events

As discussed in Note 2 to the consolidated financial statements, the Company evaluates property, plant, and equipment and intangible assets (collectively, long-lived assets) for potential impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable (triggering events). Triggering events include significant changes in the use of the asset group, current and/or historical operating results that are significantly less than forecasted results, negative industry or economic trends including changes in commodity prices, significant adverse changes in legal or regulatory factors, or an expectation that it is more likely than not that an asset group will be sold before the end of its useful life. The carrying value of property, plant, and equipment and intangible assets as of December 31, 2021 was $6.39 billion and $1.05 billion, respectively.

We identified the evaluation of long-lived assets for impairment triggering events as a critical audit matter. A higher degree of subjective auditor judgment was required to evaluate the impact of forecasted prices for oil, natural gas, and natural gas liquids (NGL) on the recoverability of the Company’s long-lived assets as sustained declines in commodity prices could result in decreases in volumes gathered, processed, fractionated, and transported by the Company.

The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls over the Company’s process to evaluate triggering events related to the impairment of long-lived assets. This included controls related to the Company’s selection of forecasted prices for oil, natural gas, and NGL and the identification and assessment of the potential impacts of such prices on oil, natural gas, and NGL volumes available to the Company. We examined the Company’s analysis of potential triggering events for long-lived assets and evaluated the Company’s responses to the factors identified by inspecting publicly available information regarding rig counts and producer drilling outlook. We involved valuation professionals with specialized skills and knowledge, who assisted in evaluating the forecasted prices for oil, natural gas, and NGL used in the Company’s analysis by comparing such prices to commodity price curves prepared by third parties.

/s/ KPMG LLP


We have served as EnLink Midstream, LLC’sthe Company’s auditor since 2013.

Dallas, Texas
February 21, 201816, 2022


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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES
Consolidated Balance Sheets
(In millions, except unit data)
December 31, 2021December 31, 2020
ASSETS
Current assets:
Cash and cash equivalents$26.2 $39.6 
Accounts receivable:
Trade, net of allowance for bad debt of $0.3 and $0.5, respectively94.9 80.6 
Accrued revenue and other693.3 447.5 
Fair value of derivative assets22.4 25.0 
Other current assets83.6 58.7 
Total current assets920.4 651.4 
Property and equipment, net of accumulated depreciation of $4,332.0 and $3,863.0, respectively6,388.3 6,652.1 
Intangible assets, net of accumulated amortization of $795.1 and $668.8, respectively1,049.7 1,125.4 
Investment in unconsolidated affiliates28.0 41.6 
Fair value of derivative assets0.2 4.9 
Other assets, net96.6 75.5 
Total assets$8,483.2 $8,550.9 
LIABILITIES AND MEMBERS’ EQUITY
Current liabilities:
Accounts payable and drafts payable$139.6 $60.5 
Accrued gas, NGLs, condensate, and crude oil purchases (1)521.5 291.5 
Fair value of derivative liabilities34.9 37.1 
Current maturities of long-term debt— 349.8 
Other current liabilities202.9 149.1 
Total current liabilities898.9 888.0 
Long-term debt4,363.7 4,244.0 
Other long-term liabilities93.9 94.8 
Deferred tax liability, net137.5 108.6 
Fair value of derivative liabilities2.2 2.5 
Members’ equity:
Members’ equity (484,277,258 and 489,381,149 units issued and outstanding, respectively)1,325.8 1,508.8 
Accumulated other comprehensive loss(1.4)(15.3)
Non-controlling interest1,662.6 1,719.5 
Total members’ equity2,987.0 3,213.0 
Commitments and contingencies (Note 14)00
Total liabilities and members’ equity$8,483.2 $8,550.9 
 December 31, 2017 December 31, 2016
ASSETS   
Current assets:   
Cash and cash equivalents$31.2
 $11.7
Accounts receivable:   
Trade, net of allowance for bad debt of $0.3 and $0.1, respectively50.1
 63.9
Accrued revenue and other576.6
 369.6
Related party102.8
 100.2
Fair value of derivative assets6.8
 1.3
Natural gas and NGLs inventory, prepaid expenses and other41.2
 33.5
Investment in unconsolidated affiliates—current—
 193.1
Total current assets808.7
 773.3
Property and equipment, net of accumulated depreciation of $2,533.0 and $2,124.1, respectively6,587.0
 6,256.7
Intangible assets, net of accumulated amortization of $298.7 and $171.6, respectively1,497.1
 1,624.2
Goodwill1,542.2
 1,542.2
Investment in unconsolidated affiliates—non-current89.4
 77.3
Other assets, net13.4
 2.2
Total assets$10,537.8
 $10,275.9
LIABILITIES AND MEMBERS’ EQUITY   
Current liabilities:   
Accounts payable and drafts payable$66.9
 $69.2
Accounts payable to related party16.3
 10.4
Accrued gas, NGLs, condensate and crude oil purchases476.1
 333.3
Fair value of derivative liabilities8.4
 7.6
Installment payable, net of discount of $0.5 and $0.5, respectively249.5
 249.5
Other current liabilities222.9
 217.5
Total current liabilities1,040.1
 887.5
Long-term debt3,542.1
 3,295.3
Asset retirement obligations14.2
 13.5
Installment payable, net of discount of $26.3 at December 31, 2016—
 223.7
Other long-term liabilities33.9
 42.5
Deferred tax liability346.2
 542.6
    
Redeemable non-controlling interest4.6
 5.2
    
Members’ equity:   
Members’ equity (180,600,728 and 180,049,316 units issued and outstanding, respectively)1,924.2
 1,880.9
Accumulated other comprehensive loss(2.0) —
Non-controlling interest3,634.5
 3,384.7
Total members’ equity5,556.7
 5,265.6
Commitments and contingencies (Note 15)

 

Total liabilities and members’ equity$10,537.8
 $10,275.9
____________________________

(1)Includes related party accounts payable balances of $1.6 million and $1.0 million at December 31, 2021 and December 31, 2020, respectively.









See accompanying notes to consolidated financial statements.

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES
Consolidated Statements of Operations
(In millions, except per unit data)

Year Ended December 31,
202120202019
Revenues:
Product sales$5,994.0 $2,977.5 $5,030.1 
Midstream services851.0 938.3 1,008.4 
Gain (loss) on derivative activity(159.1)(22.0)14.4 
Total revenues6,685.9 3,893.8 6,052.9 
Operating costs and expenses:
Cost of sales, exclusive of operating expenses and depreciation and amortization (1)5,189.9 2,388.5 4,392.5 
Operating expenses362.9 373.8 467.1 
Depreciation and amortization607.5 638.6 617.0 
Impairments0.8 362.8 1,133.5 
(Gain) loss on disposition of assets(1.5)8.8 (1.9)
General and administrative107.8 103.3 152.6 
Loss on secured term loan receivable— — 52.9 
Total operating costs and expenses6,267.4 3,875.8 6,813.7 
Operating income (loss)418.5 18.0 (760.8)
Other income (expense):
Interest expense, net of interest income(238.7)(223.3)(216.0)
Gain on extinguishment of debt— 32.0 — 
Income (loss) from unconsolidated affiliates(11.5)0.6 (16.8)
Other income— 0.3 0.9 
Total other expense(250.2)(190.4)(231.9)
Income (loss) before non-controlling interest and income taxes168.3 (172.4)(992.7)
Income tax expense(25.4)(143.2)(6.9)
Net income (loss)142.9 (315.6)(999.6)
Net income attributable to non-controlling interest120.5 105.9 119.7 
Net income (loss) attributable to ENLC$22.4 $(421.5)$(1,119.3)
Net income (loss) attributable to ENLC per unit:
Basic common unit$0.05 $(0.86)$(2.41)
Diluted common unit$0.05 $(0.86)$(2.41)
____________________________

 Year Ended December 31,
 2017 2016 2015
Revenues:     
Product sales$4,358.4
 $3,008.9
 $3,253.7
Product sales—related parties144.9
 134.3
 119.4
Midstream services552.3
 467.2
 451.0
Midstream services—related parties688.2
 653.1
 618.6
Gain (loss) on derivative activity(4.2) (11.1) 9.4
Total revenues5,739.6
 4,252.4
 4,452.1
Operating costs and expenses:     
Cost of sales (1)4,361.5
 3,015.5
 3,245.3
Operating expenses418.7
 398.5
 419.9
General and administrative128.6
 122.5
 136.9
Loss on disposition of assets—
 13.2
 1.2
Depreciation and amortization545.3
 503.9
 387.3
Impairments17.1
 873.3
 1,563.4
Gain on litigation settlement(26.0) —
 —
Total operating costs and expenses5,445.2
 4,926.9
 5,754.0
Operating income (loss)294.4
 (674.5) (1,301.9)
Other income (expense):     
Interest expense, net of interest income(190.4) (189.5) (103.3)
Gain on extinguishment of debt9.0
 —
 —
Income (loss) from unconsolidated affiliates9.6
 (19.9) 20.4
Other income0.6
 0.3
 0.8
Total other expense(171.2) (209.1) (82.1)
Income (loss) before non-controlling interest and income taxes123.2
 (883.6) (1,384.0)
Income tax benefit (provision)196.8
 (4.6) (25.7)
Net income (loss)320.0
 (888.2) (1,409.7)
Net income (loss) attributable to non-controlling interest107.2
 (428.2) (1,054.5)
Net income (loss) attributable to EnLink Midstream, LLC212.8
 (460.0) (355.2)
Devon investment interest in net income—
 —
 1.8
EnLink Midstream, LLC interest in net income (loss)$212.8
 $(460.0) $(357.0)
Net income (loss) attributable to EnLink Midstream, LLC per unit:     
Basic common unit$1.18
 $(2.56) $(2.17)
Diluted common unit$1.17
 $(2.56) $(2.17)
(1)Includes related party cost of sales of $17.9 million, $8.7 million, and $21.7 million for the years ended December 31, 2021, 2020, and 2019, respectively.


(1)
Includes related party cost of sales of $211.0 million, $150.1 million and $141.3 million for the years ended December 31, 2017, 2016 and 2015, respectively.
























See accompanying notes to consolidated financial statements.

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES
Consolidated Statements of Comprehensive Income (Loss)
(In millions)
Year Ended December 31,
202120202019
Net income (loss)$142.9 $(315.6)$(999.6)
Unrealized gain (loss) on designated cash flow hedge (1)13.9 (4.3)(9.0)
Comprehensive income (loss)156.8 (319.9)(1,008.6)
Comprehensive income attributable to non-controlling interest120.5 105.9 119.7 
Comprehensive income (loss) attributable to ENLC$36.3 $(425.8)$(1,128.3)
 Year Ended December 31,
 2017 2016 2015
Net income (loss)$320.0
 $(888.2) $(1,409.7)
Loss on designated cash flow hedge, net of tax benefit and amortization to interest expense (1)(2.0) —
 —
Comprehensive income (loss)318.0
 (888.2) (1,409.7)
Comprehensive income (loss) attributable to non-controlling interest105.6
 (428.2) (1,054.5)
Comprehensive income (loss) attributable to EnLink Midstream, LLC$212.4
 $(460.0) $(355.2)
____________________________
(1)Includes a tax expense of $4.3 million for the year ended December 31, 2021 and a tax benefit of $1.3 million and $3.4 million for the years ended December 31, 2020 and 2019, respectively.



(1)The loss on designated cash flow hedge recorded in accumulated other comprehensive loss for the year ended December 31, 2017 was net of a tax benefit of $0.2 million. For the year ended December 31, 2017, we amortized an immaterial amount of the loss into interest expense.
















































































See accompanying notes to consolidated financial statements.

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Consolidated Statements of Changes in Members’ Equity
(In millions)
Common UnitsAccumulated Other Comprehensive LossNon-Controlling InterestTotalRedeemable Non-controlling interest (Temporary Equity)
$Units$$$$
Balance, December 31, 2018$1,730.9 181.3 $(2.0)$3,245.3 $4,974.2 $9.3 
Adoption of ASC 8420.3 — — — 0.3 — 
Balance, January 1, 20191,731.2 181.3 (2.0)3,245.3 4,974.5 9.3 
Issuance of common units for ENLK public common units related to the Merger1,958.1 304.9 — (1,559.1)399.0 — 
Conversion of restricted units for common units, net of units withheld for taxes(7.8)1.6 — (2.8)(10.6)— 
Unit-based compensation37.5 — — 1.4 38.9 — 
Contributions from non-controlling interests— — — 97.5 97.5 — 
Distributions(467.2)— — (220.2)(687.4)(0.3)
Unrealized loss on designated cash flow hedge (1)— — (9.0)— (9.0)— 
Fair value adjustment related to redeemable non-controlling interest3.0 — — — 3.0 (4.0)
Net income (loss)(1,119.3)— — 119.5 (999.8)0.2 
Balance, December 31, 20192,135.5 487.8 (11.0)1,681.6 3,806.1 5.2 
Conversion of restricted units for common units, net of units withheld for taxes(4.7)2.0 — — (4.7)— 
Unit-based compensation33.0 — — — 33.0 — 
Contributions from non-controlling interests— — — 52.6 52.6 — 
Distributions(232.7)— — (120.6)(353.3)(0.6)
Unrealized loss on designated cash flow hedge (2)— — (4.3)— (4.3)— 
Fair value adjustment related to redeemable non-controlling interest0.4 — — — 0.4 (0.6)
Redemption of non-controlling interest— — — — — (4.0)
Common units repurchased(1.2)(0.4)— — (1.2)— 
Net income (loss)(421.5)— — 105.9 (315.6)— 
Balance, December 31, 2020$1,508.8 489.4 $(15.3)$1,719.5 $3,213.0 $— 
  Common Units Net Devon
Investment		 Accumulated Other Comprehensive Loss Non-Controlling
Interest		 Total Redeemable Non-Controlling Interest (Temporary Equity)
  $ Units $ $ $ $ $
Balance, December 31, 2014 $2,774.3
 164.1

$103.7
 $—
 $4,196.8

$7,074.8
 $—
Issuance of common units by ENLK —
 —
 —
 —
 384.4
 384.4
 —
Conversion of restricted units for common units, net of units withheld for taxes (2.9) 0.1
 —
 —
 —
 (2.9) —
Non-controlling interest’s impact of conversion of restricted units —
 —
 —
 —
 (2.5) (2.5) —
Unit-based compensation 18.5
 —
 —
 —
 17.6
 36.1
 —
Change in equity due to issuance of units by ENLK 8.5
 —
 —
 —
 (13.7) (5.2) —
Non-controlling interest distributions —
 —
 —
 —
 (359.5) (359.5) —
Non-controlling interest contribution —
 —
 —
 —
 16.4
 16.4
 —
Distributions to members (162.8) —
 —
 —
 —
 (162.8) —
Adjustment related to mandatory redemption of E2 non-controlling interest —
 —
 —
 —
 (5.4) (5.4) —
Redeemable non-controlling interest —
 —
 —
 —
 (7.0) (7.0) 7.0
Contribution from Devon to ENLC 7.1
 —
 —
 —
 —
 7.1
 —
Contribution from Devon to ENLK —
 —
 25.6
 —
 2.2
 27.8
 —
Distribution attributable to VEX interests transferred (Note 3) —
 —
 (131.1) —
 (35.6) (166.7) —
Net income (loss) (357.0) —
 1.8
 —
 (1,054.5) (1,409.7) —
Balance, December 31, 2015 $2,285.7
 164.2
 $—
 $—
 $3,139.2
 $5,424.9
 $7.0
Issuance of common units by ENLK —
 —
 —
 —
 167.5
 167.5
 —
Issuance of Series B Preferred Units by ENLK —
 —
 —
 —
 724.1
 724.1
 —
Issuance of common units 214.9
 15.6
 —
 —
 —
 214.9
 —
Conversion of restricted units for common units, net of units withheld for taxes (1.2) 0.2
 —
 —
 —
 (1.2) —
Non-controlling interest’s impact of conversion of restricted units —
 —
 —
 —
 (1.2) (1.2) —
Unit-based compensation 15.1
 —
 —
 —
 15.2
 30.3
 —
Change in equity due to issuance of units by ENLK 11.8
 —
 —
 —
 (18.9) (7.1) —
Non-controlling interest distributions —
 —
 —
 —
 (382.4) (382.4) —
Non-controlling interest contribution —
 —
 —
 —
 167.9
 167.9
 —
Distributions to members (185.4) —
 —
 —
 —
 (185.4) —
Distributions to redeemable non-controlling interest —
 —
 —
 —
 —
 —
 (1.8)
Contribution from Devon to ENLK —
 —
 —
 —
 1.5
 1.5
 —
Net loss (460.0) —
 —
 —
 (428.2) (888.2) —
Balance, December 31, 2016 $1,880.9
 180.0
 $—
 $—
 $3,384.7
 $5,265.6
 $5.2
____________________________

(1)Includes a tax benefit of $3.4 million.

(2)Includes a tax benefit of $1.3 million.
























See accompanying notes to consolidated financial statements.

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Consolidated Statements of Changes in Members’ Equity (continued)(Continued)
(In millions)

  Common Units Net Devon
Investment		 Accumulated Other Comprehensive Loss Non-Controlling
Interest		 Total Redeemable Non-Controlling Interest (Temporary Equity)
  $ Units $ $ $ $ $
Balance, December 31, 2016 $1,880.9
 180.0
 $—
 $—
 $3,384.7
 $5,265.6
 $5.2
Issuance of common units by ENLK —
 —
 —
 —
 106.9
 106.9
 —
Issuance of Series C Preferred Units by ENLK —
 —
 —
 —
 394.0
 394.0
 —
Conversion of restricted units for common units, net of units withheld for taxes (4.8) 0.6
 —
 —
 —
 (4.8) —
Non-controlling interest’s impact of conversion of restricted units —
 —
 —
 —
 (5.3) (5.3) —
Unit-based compensation 21.3
 —
 —
 —
 21.4
 42.7
 —
Change in equity due to issuance of units by ENLK —
 —
 —
 —
 0.1
 0.1
 —
Non-controlling interest distributions —
 —
 —
 —
 (433.1) (433.1) —
Non-controlling interest contribution —
 —
 —
 —
 57.3
 57.3
 —
Distributions to members (186.0) —
 —
 —
 —
 (186.0) —
Distributions to redeemable non-controlling interest —
 —
 —
 —
 —
 —
 (0.6)
Contribution from Devon to ENLK —
 —
 —
 —
 1.3
 1.3
 —
Loss on designated cash flow hedge, net of tax benefit and amortization to interest expense —
 —
 —
 (2.0) —
 (2.0) —
Net income 212.8
 —
 —
 —
 107.2
 320.0
 —
Balance, December 31, 2017 $1,924.2
 180.6
 $—
 $(2.0) $3,634.5
 $5,556.7
 $4.6
Common UnitsAccumulated Other Comprehensive LossNon-Controlling InterestTotalRedeemable Non-controlling interest (Temporary Equity)
$Units$$$$
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(2.0)1.0 — — (2.0)— 
Unit-based compensation23.6 — — — 23.6 — 
Contributions from non-controlling interests— — — 3.2 3.2 — 
Distributions(186.8)— — (130.6)(317.4)(0.2)
Unrealized gain on designated cash flow hedge (1)— — 13.9 — 13.9 — 
Fair value adjustment related to redeemable non-controlling interest(0.1)— — — (0.1)0.2 
Redemption of Series B Preferred Units— — — (50.0)(50.0)— 
Common units repurchased(40.1)(6.1)— — (40.1)— 
Net income22.4 — — 120.5 142.9 — 
Balance, December 31, 2021$1,325.8 484.3 $(1.4)$1,662.6 $2,987.0 $— 

____________________________

(1)Includes a tax expense of $4.3 million.





























































See accompanying notes to consolidated financial statements.

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Consolidated Statements of Cash Flows
(In millions);
 Year Ended December 31,
 2017 2016 2015
Cash flows from operating activities:     
Net income (loss)$320.0
 $(888.2) $(1,409.7)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:     
Impairments17.1
 873.3
 1,563.4
Depreciation and amortization545.3
 503.9
 387.3
Loss on disposition of assets—
 13.2
 1.2
Gain on extinguishment of debt(9.0) —
 —
Deferred tax expense (benefit)(197.2) 2.1
 22.6
Non-cash unit-based compensation48.1
 30.3
 36.1
(Gain) loss on derivatives recognized in net income (loss)4.2
 11.1
 (9.4)
Cash settlements on derivatives(11.2) 10.5
 17.1
Amortization of debt issue costs, net (premium) discount of notes and installment payable29.3
 53.4
 0.4
Distribution of earnings from unconsolidated affiliates13.3
 3.1
 21.6
(Income) loss from unconsolidated affiliates(9.6) 19.9
 (20.4)
Other operating activities0.6
 0.9
 (1.2)
Changes in assets and liabilities net of assets acquired and liabilities assumed:     
Accounts receivable, accrued revenue and other(189.4) (118.1) 197.5
Natural gas and NGLs inventory, prepaid expenses and other(23.5) 18.7
 (6.7)
Accounts payable, accrued gas and crude oil purchases and other accrued liabilities162.1
 132.3
 (171.4)
Net cash provided by operating activities700.1
 666.4
 628.4
Cash flows from investing activities, net of assets acquired and liabilities assumed:     
Additions to property and equipment(790.8) (663.0) (572.3)
Acquisition of business, net of cash acquired—
 (791.5) (524.2)
Proceeds from insurance settlement0.4
 0.3
 2.9
Proceeds from sale of unconsolidated affiliate investment189.7
 —
 —
Proceeds from sale of property2.3
 93.1
 1.0
Investment in unconsolidated affiliates(12.6) (73.8) (25.8)
Distribution from unconsolidated affiliates in excess of earnings0.2
 54.6
 21.1
Net cash used in investing activities(610.8) (1,380.3) (1,097.3)
Cash flows from financing activities:     
Proceeds from borrowings2,381.8
 2,150.4
 3,204.4
Payments on borrowings(2,123.4) (1,917.5) (2,134.3)
Payment of installment payable for EnLink Oklahoma T.O. acquisition(250.0) —
 —
Debt financing costs(5.5) (4.7) (9.6)
Proceeds from issuance of ENLK common units106.9
 167.5
 24.4
Distributions to non-controlling interest(433.7) (384.2) (359.5)
Distribution to members(186.0) (185.4) (162.8)
Proceeds from issuance of ENLK Series B Preferred Units—
 724.1
 —
Proceeds from issuance of ENLK Series C Preferred Units394.0
 —
 —
Distribution to Devon for VEX interests transferred (Note 3)—
 —
 (166.7)
Contributions by non-controlling interest57.3
 167.9
 16.4
Contribution from Devon1.3
 1.5
 27.8
Other financing activities(12.5) (12.0) (21.6)
Net cash provided by (used in) financing activities(69.8) 707.6
 418.5
Net increase (decrease) in cash and cash equivalents19.5
 (6.3) (50.4)
Cash and cash equivalents, beginning of period11.7
 18.0
 68.4
Cash and cash equivalents, end of period$31.2
 $11.7
 $18.0
Cash paid for interest$165.9
 $133.7
 $110.0
Cash paid (refunded) for income taxes$3.3
 $(7.0) $13.7
Year Ended December 31,
202120202019
Cash flows from operating activities:
Net income (loss)$142.9 $(315.6)$(999.6)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization607.5 638.6 617.0 
Impairments0.8 362.8 1,133.5 
(Gain) loss on disposition of assets(1.5)8.8 (1.9)
Loss on secured term loan receivable— — 52.9 
Non-cash unit-based compensation25.3 28.4 39.4 
Utility credits, net of usage(32.6)— — 
Non-cash loss on derivatives recognized in net income (loss)10.3 14.8 2.5 
Gain on extinguishment of debt— (32.0)— 
Amortization of debt issuance costs and net discount of senior unsecured notes5.2 4.6 4.9 
Amortization of designated cash flow hedge12.5 0.5 0.1 
Payments to terminate interest rate swaps(1.8)(10.9)— 
Deferred income tax expense24.6 142.1 6.9 
Distribution of earnings from unconsolidated affiliates— 1.6 16.5 
(Income) loss from unconsolidated affiliates11.5 (0.6)16.8 
Other operating activities(2.2)(0.8)(2.3)
Changes in assets and liabilities:
Accounts receivable, accrued revenue, and other(259.9)(21.5)337.1 
Natural gas and NGLs inventory, prepaid expenses, and other(13.6)15.1 13.6 
Accounts payable, accrued product purchases, and other accrued liabilities328.3 (104.8)(245.5)
Net cash provided by operating activities857.3 731.1 991.9 
Cash flows from investing activities:
Additions to property and equipment(184.0)(302.2)(754.9)
Acquisition of assets(56.7)(32.3)— 
Proceeds from sale of property4.8 17.6 14.3 
Distribution from unconsolidated affiliates in excess of earnings3.9 0.5 3.7 
Other investing activities0.6 (1.3)(4.6)
Net cash used in investing activities(231.4)(317.7)(741.5)
Cash flows from financing activities:
Proceeds from borrowings1,234.5 1,650.0 3,310.0 
Payments on borrowings(1,469.5)(1,786.0)(2,971.4)
Distribution to members(186.8)(232.7)(467.2)
Distributions to non-controlling interests(130.8)(121.2)(220.5)
Redemption of Series B Preferred Units(50.0)— — 
Common unit repurchases(40.1)(1.2)— 
Contributions by non-controlling interests3.2 52.6 97.5 
Conversion of restricted units, net of units withheld for taxes(2.0)(4.7)(7.8)
Debt financing costs(0.3)(7.7)(10.0)
Other financing activities2.5 (0.3)(4.0)
Net cash used in financing activities(639.3)(451.2)(273.4)
Net decrease in cash and cash equivalents(13.4)(37.8)(23.0)
Cash and cash equivalents, beginning of period39.6 77.4 100.4 
Cash and cash equivalents, end of period$26.2 $39.6 $77.4 







See accompanying notes to consolidated financial statements.

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES
Notes to Consolidated Financial Statements



(1) Organization and SummaryNature of Significant AgreementsBusiness


(a) Organization of Business and Nature of Business


EnLink Midstream, LLC (“ENLC”)ENLC is a publicly traded Delaware limited liability company formed in October 2013. Effective as of March 7, 2014, EnLink Midstream, Inc. (“EMI”) merged with and into a wholly-owned subsidiary of the Company and Acacia Natural Gas Corp I, Inc. (“Acacia”), formerly a wholly-owned subsidiary of Devon Energy Corporation (“Devon”), merged with and into a wholly-owned subsidiary of the Company (collectively, the “Mergers”). Pursuant to the Mergers, each of EMI and New Acacia became wholly-owned subsidiaries of the Company and the Company became publicly held. EMI owns common units representing an approximate 5.0% limited partner interest in EnLink Midstream Partners, LP (the “Partnership” or “ENLK”) as of December 31, 2017 and also owns EnLink Midstream GP, LLC (the “General Partner”). Acacia directly owned a 50% limited partner interest in Midstream Holdings, which was formerly a wholly-owned subsidiary of Devon. Upon closing of the Business Combination (as defined below), ENLC issued 115,495,669 units to a wholly-owned subsidiary of Devon, represent approximately 64.0% of the outstanding limited liability company interests in ENLC as of December 31, 2017. Concurrently with the consummation of the Mergers, a wholly-owned subsidiary of ENLK acquired the remaining 50% of the outstanding limited partner interest in Midstream Holdings and all of the outstanding equity interests in EnLink Midstream Holdings GP, LLC, the general partner of Midstream Holdings (together with the Mergers, the “Business Combination”). 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.


Devon Transaction

In 2015, Acacia2014, we completed a series of transactions with Devon pursuant to which Devon contributed the remaining 50% interest in Midstream Holdingscertain subsidiaries and assets to ENLKus in exchange for 68.2 milliona majority interest in us (the “Devon Transaction”).

GIP Transaction

On July 18, 2018, subsidiaries of Devon closed a transaction to sell all of their equity interests in ENLK, common units in two separate drop down transactions, with 25% contributed in February 2015ENLC, and 25% contributed in May 2015 (the “EMH Drop Downs”). After giving effectthe Managing Member to the EMH Drop Downs, ENLK owns 100% of Midstream Holdings.GIP. As a result of the EMH Drop Downs, Acacia ownedtransaction:

•GIP, through GIP III Stetson I, L.P., acquired all of the equity interests held by subsidiaries of Devon in ENLK and the Managing Member, which, as of the closing date, amounted to 100% of the outstanding limited liability company interests in the Managing Member and approximately 16.7%23.1% of the outstanding limited partner interests in ENLKENLK;

•GIP, through GIP III Stetson II, L.P., acquired all of the equity interests held by subsidiaries of Devon in ENLC, which, as of December 31, 2017, which brings ENLC’s total ownership, through its wholly-owned subsidiaries, of limited partner interests in ENLKthe closing date, amounted to 21.7% as of December 31, 2017.

In addition, in April 2015, ENLK acquired the Victoria Express Pipeline and related truck terminal and storage assets located in the Eagle Ford Shale in South Texas (VEX”), together with 100% of the voting equity interests (the “VEX interests”) in certain entities, from Devon in a drop down transaction (the “VEX Drop Down”).

Effective as of January 7, 2016, ENLK acquired 83.9%approximately 63.8% of the outstanding equitylimited liability company interests in EnLink Oklahoma T.O.,ENLC; and

•Through this transaction, GIP acquired control of (i) the Managing Member, (ii) ENLC, acquiredand (iii) ENLK, as a result of ENLC’s ownership of the remaining 16.1% equity interests in EnLink Oklahoma T.O. SinceGeneral Partner.

Simplification of the Corporate Structure

On January 25, 2019, we control EnLink Oklahoma T.O., we reflect our ownership in EnLink Oklahoma T.O. oncompleted the Merger, an internal reorganization pursuant to which ENLC owns all of the outstanding common units of ENLK. As a consolidated basisresult of the Merger:

•Each issued and outstanding ENLK common unit (except for ENLK common units held by ENLC and its subsidiaries) was converted into 1.15 ENLC common units, which resulted in the consolidated financial statements and related disclosures.issuance of 304,822,035 ENLC common units.

•The General Partner’s incentive distribution rights in ENLK were eliminated.

•Certain terms of the Series B Preferred Units were modified pursuant to an amended partnership agreement of ENLK. See “Note 3—Acquisitions”8—Certain Provisions of the Partnership Agreement” for further discussion.additional information regarding the modified terms of the Series B Preferred Units.


Our assets consist•ENLC issued to the holder of equity intereststhe Series B Preferred Units, for no additional consideration, ENLC Class C Common Units equal to the number of Series B Preferred Units held immediately prior to the effective time of the Merger, in order to provide Series B Preferred Unit holders with certain voting rights with respect to ENLC. ENLC also agreed to issue an additional ENLC Class C Common Unit to the applicable holder of each Series B Preferred Unit for each additional Series B Preferred Unit issued by ENLK in quarterly in-kind distributions. In addition, for each Series B Preferred Unit that is exchanged into an ENLC common unit or repurchased, an ENLC Class C Common Unit will be canceled.

•Each unit-based award issued and outstanding immediately prior to the effective time of the Merger under the GP Plan was converted into 1.15 awards with respect to ENLC common units with substantially similar terms as were in effect immediately prior to the effective time.

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Notes to Consolidated Financial Statements (continued)
•Each unit-based award with performance-based vesting conditions issued and outstanding immediately prior to the effective time of the Merger under the GP Plan and the 2014 Plan was modified such that the performance metric for any then outstanding performance award relates (on a weighted average basis) to (i) the combined performance of ENLC and ENLK for periods preceding the effective time of the Merger and (ii) the performance of ENLC for periods on and after the effective time of the Merger.

•ENLC assumed the outstanding debt under the Term Loan and ENLK became a guarantor thereof. See “Note 6—Long-Term Debt” for additional information regarding the Term Loan.

•We refinanced our existing revolving credit facilities at ENLK and EnLink Oklahoma T.O.ENLC. In connection with the Merger, we entered into the Consolidated Credit Facility, with respect to which ENLK is a Delaware publicly traded limited partnership formed on July 12, 2002 and is engagedguarantor. See “Note 6—Long-Term Debt” for additional information regarding the Consolidated Credit Facility.

•We were required to allocate the goodwill in the gathering, transmission, processing and marketing of natural gas and natural gas liquids, or natural gas liquids (“NGLs”), condensate and crude oil, as well as providing crude oil, condensate and brine services to producers. EnLink Oklahoma T.O. is a partnership held by us and ENLK, and is engaged in the gathering and processing of natural gas. As of December 31, 2017, our interests in ENLK consisted of the following:

88,528,451 common units representing an aggregate 21.7% limited partner interest in ENLK;
100.0% ownership interest in EnLink Midstream GP, LLC, the general partner of ENLK (the “General Partner”), which owns a 0.4% general partner interest and all ofCorporate reporting unit previously associated with the incentive distribution rights in ENLK;ENLK granted to the General Partner which were created in connection with the Devon Transaction, to the Permian, Louisiana, Oklahoma, and North Texas reporting units.
16.1% limited partner interest
•We reduced our deferred tax liability by $399.0 million related to ENLC’s step-up in EnLink Oklahoma T.O.basis of ENLK’s underlying assets with the offsetting credit in members’ equity. See “Note 7—Income Taxes” for more information on the deferred tax liabilities.


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


Our midstream energy asset network includes approximately 11,00012,100 miles of pipelines, 2022 natural gas processing plants with approximately 4.85.5 Bcf/d of processing capacity, 7 fractionators with approximately 260,000320,000 Bbls/d of fractionation

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Notes to Consolidated Financial Statements (Continued)

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.


We connectOur natural gas business includes connecting the wells of producers in our market areas to our gathering systems. Our gathering systems which 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, other marketsmarketers, 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, and ourplants. 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 mayalso purchase crude oil and condensate from producers and other supply sources and sell that crude oil and condensate through our terminal facilities that provide market access.to various markets.

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Notes to Consolidated Financial Statements (continued)

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


(2) Significant Accounting Policies


(a)Basis of Presentation


The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally acceptedGAAP. All significant intercompany balances and transactions have been eliminated in consolidation. Certain reclassifications were made to the United Statesfinancial statements for the prior period to conform to current period presentation. The effect of America (“GAAP”) for complete financial statements. these reclassifications had no impact on previously reported members’ equity or net income (loss).


(b)Management’s Use of Estimates


The preparation of financial statements in accordance with US GAAP requires our management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the period. Actual results could differ from these estimates.



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(c)Revenue Recognition


We generate the majority of our revenues from midstream energy services, including gathering, transmission, processing, fractionation, storage, condensate stabilization, brine services, and marketing, through various contractual arrangements, which include fee-based contract arrangements or arrangements where we purchase and resell commodities in connection with providing the related service and earn a net margin for our fee. While our transactions vary in form, the essential element of each transactionmost 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, terminaltruck, or pipeline. We reflect revenue asrail terminal. Revenues from both “Product sales” and “Midstream services” revenuerepresent revenues from contracts with customers and are reflected on the consolidated statements of operations as follows:


•Product sales—ProductProduct sales represent the sale of natural gas, NGLs, crude oil, and condensate where the product is purchased and resold in connection with providing our midstream services as outlined above.


•Midstream services—Midstream services represent all other revenue generated as a result of performing our midstream services outlined above.

Evaluation of Our Contractual Performance Obligations

Performance obligations in our contracts with customers include:

•promises to perform midstream services for our customers over a specified contractual term and/or for a specified volume of commodities; and

•promises to sell a specified volume of commodities to our customers.

The identification of performance obligations under our contracts requires a contract-by-contract evaluation of when control, including the economic benefit, of commodities transfers to and from us (if at all). For contracts where control of commodities transfers to us before we perform our services, we generally have no performance obligation for our services, and accordingly, we do not consider these revenue-generating contracts. Based on the control determination, all contractually-stated fees that are deducted from our payments to producers or other suppliers for commodities purchased are reflected as a reduction in the cost of such commodity purchases. Alternatively, for contracts where control of commodities transfers to us after we perform our services, we consider these contracts to contain performance obligations for our services. Accordingly, we consider the satisfaction of these performance obligations as revenue-generating and recognize the fees received for satisfying them as
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Notes to Consolidated Financial Statements (continued)

midstream services revenues over time as we satisfy our performance obligations. For contracts where control of commodities never transfers to us and we simply earn a fee for our services, we recognize these fees as midstream services revenues over time as we satisfy our performance obligations.

We also evaluate our contractual arrangements that contain a purchase and sale of commodities under the principal/agent provisions in ASC 606. For contracts where we possess control of the commodity and act as principal in the purchase and sale, we record product sales revenue at the price at which the commodities are sold, with a corresponding cost of sales equal to the cost of the commodities when purchased. For contracts in which we do not possess control of the commodity and are acting as an agent, our consolidated statements of operations only reflect midstream services revenues that we earn based on the fees contained in the applicable contract.

Accounting Methodology for Certain Contracts

For NGL contracts in which we purchase raw mix NGLs and subsequently transport, fractionate, and market the NGLs, we consider the contractually-stated fees to serve as pricing mechanisms that reduce the cost of the commodities purchased. We account for the contractually-stated fees on the consolidated statements of operations as a reduction of cost of sales of such commodities purchased upon receipt of the raw mix NGLs, because we determined that the control, including the economic benefit, of commodities has passed to us once the raw mix NGLs have been purchased from the customer. Upon sale of the NGLs to a third-party customer, we record product sales revenue at the price at which the commodities are sold, with a corresponding cost of sales equal to the cost of the commodities purchased.

For our crude oil and condensate service contracts in which we purchase the commodity, we utilize a similar approach under as outlined above for NGL contracts.

For our natural gas gathering and processing contracts in which we perform midstream services and also purchase the natural gas, we determine if economic control of the commodities has passed from the producer to us before or after we perform our services (if at all). Control is assessed on a contract-by-contract basis by analyzing each contract’s provisions, which can include provisions for: the customer to take its residue gas and/or NGLs in-kind; fixed or actual NGL or keep-whole recovery; commodity purchase prices at weighted average sales price or market index-based pricing; and various other contract-specific considerations. Based on this control assessment, our gathering and processing contracts fall into two primary categories:

•For gathering and processing contracts in which there is a commodity purchase and analysis of the contract provisions indicates that control, including the economic benefit, of the natural gas passes to us when the natural gas is brought into our system, we do not consider these contracts to contain performance obligations for our services. As control of the natural gas passes to us prior to performing our gathering and processing services, we are, in effect, performing our services for our own benefit. Based on this control determination, we consider the contractually-stated fees to serve as pricing mechanisms that reduce the cost of such commodity purchased upon receipt of the natural gas, rather than being recorded as midstream services revenue. Upon sale of the residue gas and/or NGLs to a third-party customer, we record product sales revenue at the price at which the commodities are sold, with a corresponding cost of sales equal to the cost of the commodities purchased, net of fees.

•For gathering and processing contracts in which there is a commodity purchase and analysis of the contract provisions indicates that control, including the economic benefit, of the natural gas does not pass to us until after the natural gas has been gathered and processed, we consider these contracts to contain performance obligations for our services. Accordingly, we consider the satisfaction of these performance obligations as revenue-generating, and we recognize the fees received for satisfying these performance obligations as midstream services revenues over time as we satisfy our performance obligations.

For midstream service contracts related to NGL, crude oil, or natural gas gathering and processing in which there is no commodity purchase or control of the commodity never passes to us and we simply earn a fee for our services, we consider these contracts to contain performance obligations for our services. Accordingly, we consider the satisfaction of these performance obligations as revenue-generating, and we recognize the fees received for satisfying these performance obligations as midstream services revenue over time as we satisfy our performance obligations.

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Notes to Consolidated Financial Statements (continued)
For our natural gas transmission contracts, we determined that control of the natural gas never transfers to us and we simply earn a fee for our services. Therefore, we recognize these fees as midstream services revenue over time as we satisfy our performance obligations.

We also evaluate our commodity marketing contracts, under which we purchase and sell commodities in connection with our gas, NGL, and crude and condensate midstream services, pursuant to ASC 606, including the principal/agent provisions. For contracts in which we possess control of the commodity and act as principal in the purchase and sale of commodities, we record product sales orrevenue at the price at which the commodities are sold, with a corresponding cost of sales equal to the cost of the commodities when purchased. For contracts in which we do not possess control of the commodity and are acting as agent, our consolidated statements of operations only reflect midstream services revenues that we earn based on the fees contained in the applicable contract.

Satisfaction of Performance Obligations and Recognition of Revenue

For our commodity sales contracts, we satisfy our performance obligations at the point in time at which the commodity transfers from us to the customer. This transfer pattern aligns with our billing methodology. Therefore, we recognize product sales revenue at the time the natural gas, NGLs, crude oil or condensatecommodity is delivered and in the amount to which we have the right to invoice the customer. For our midstream service contracts that contain revenue-generating performance obligations, we satisfy our performance obligations over time as we perform the midstream service and as the customer receives the benefit of these services over the term of the contract. We recognize revenue in the amount to which the entity has a right to invoice, since we have a right to consideration from our customer in an amount that corresponds directly with the value to the customer of our performance completed to date. Accordingly, we continue to recognize revenue over time as our midstream services are delivered or at the time the service is performed at a fixed or determinable price. performed.

We generally accrue one month of sales and the related natural gas, NGL, condensate, and crude oil purchases and reverse these accruals when the sales and purchases are invoiced and recorded in the subsequent month. Actual results could differ from the accrual estimates. ExceptWe typically receive payment for fixed-feeinvoiced amounts within one month, depending on the terms of the contract. Prior to issuing our financial statements, we review our revenue and purchases estimates based arrangements, we act as the principal in these purchase and sale transactions, bearing the risk and reward of ownership, scheduling the transportation of products and assuming credit risk.on available information to determine if adjustments are required. We account for taxes collected from customers attributable to revenue transactions and remitted to government authorities on a net basis (excluded from revenues).


Certain gatheringMinimum Volume Commitments and processing agreementsFirm Transportation Contracts

The following table summarizes the contractually committed fees (in millions) that we expect to recognize in our Texas, Oklahomaconsolidated statements of operations, in either revenue or reductions to cost of sales, from MVC and Crude and Condensate segments provide for quarterly or annual minimum volume commitments (“MVC” or “MVCs”), including MVCs from Devon from certain of our Barnett Shale assets in North Texas and our Cana plant in Oklahoma.firm transportation contractual provisions. Under these agreements, our customers or suppliers agree to ship and/transport or process a minimum volume of productioncommodities on our systemssystem over an agreed time period.If a customer under such an agreementor supplier fails to meet its MVC for athe minimum volume specified period,in such agreement, the customer or supplier is obligated to pay a contractually-determinedcontractually determined fee based upon the shortfall between actual production 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 that period. Someeach period multiplied by the relevant deficiency or reservation fee. Actual amounts could differ due to the timing of these agreements also containrevenue recognition or reductions to cost of sales resulting from make-up right provisions that allow a customerincluded in our agreements, as well as due to utilize gatheringnonpayment or processing fees in excess of the MVC in subsequent periods to offset shortfall amounts in previous periods.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 deficiencydeficiency. These fees do not represent the shortfall amounts we expect to collect under our MVC and firm
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Notes to Consolidated Financial Statements (continued)
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$138.8 
2023126.5 
2024108.9 
202563.8 
202657.8 
Thereafter289.6 
Total$785.4 

(d)Acquisition of Business

On April 30, 2021, we completed the acquisition of Amarillo Rattler, LLC, the owner of a gathering and processing system located in subsequent periods. the Midland Basin. In connection with the purchase, we entered into an amended and restated gas gathering and processing agreement with Diamondback Energy, strengthening our dedicated acreage position with that entity. We acquired the system with an upfront payment of $50.0 million, which was paid with cash-on-hand, with an additional $10.0 million to be paid on April 30, 2022, and contingent consideration capped at $15.0 million and payable between 2024 and 2026 based on Diamondback Energy’s drilling activity above historical levels.


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

Consideration
Cash (including working capital payment)$50.6 
Installment payable10.0 
Contingent consideration fair value (1)6.9 
Total consideration:$67.5 
Purchase price allocation
Assets acquired:
Current assets (including $1.3 million in cash)$1.4 
Property and equipment16.3 
Intangible assets50.6 
Other assets, net (2)0.6 
Liabilities assumed:
Current liabilities(0.8)
Other long-term liabilities (2)(0.6)
Net assets acquired$67.5 
____________________________
(1)The estimated fair value of the Amarillo Rattler, LLC contingent consideration was calculated in accordance with the fair value guidance contained in ASC 820. There are a number of assumptions and estimates factored into these fair values and actual contingent consideration payments could differ from the estimated fair values.
(2)“Other assets, net” and “Other long-term liabilities” consist of the right-of-use asset and lease liability, respectively, recorded through the acquisition of Amarillo Rattler, LLC.

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Notes to Consolidated Financial Statements (continued)
(e)Loss on Secured Term Loan Receivable

In late May 2019, White Star, the counterparty to our $58.0 million second lien secured term loan receivable, filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code. White Star defaulted on its May 2019 installment payment prior to filing for reorganization under Chapter 11 of the U.S. Bankruptcy Code. In November 2019, White Star sold its assets and we did not recover any amounts then owed to us under the second lien secured term loan. As a result, we have recorded a $52.9 million loss in our consolidated statement of operations for the year ended December 31, 2019, which represents a full write-down of the second lien secured term loan.

(f)Gas Imbalance Accounting


Quantities of natural gas and NGLs over-delivered or under-delivered related to imbalance agreements are recorded monthly as receivables or payables using weighted average prices at the time of the imbalance. These imbalances are typically settled with deliveries of natural gas or NGLs. We had imbalance payables of $7.3$16.3 million and $7.1$6.1 million at December 31, 20172021 and 2016,2020, respectively, which approximate the fair value of these imbalances. We had imbalance receivables of $5.8$14.5 million and $3.9$7.5 million at December 31, 20172021 and 2016,2020, respectively, which are carried at the lower of cost or market value. Imbalance receivables and imbalance payables are included in the line items “Accrued revenue and other” and “Accrued gas, NGLs, condensate, and crude oil purchases,” respectively, on the consolidated balance sheets.


(e) (g)Cash and Cash Equivalents


We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents.



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(f) (h)Income Taxes

Certain of our operations are subject to income taxes assessed by the federal and various state jurisdictions in the U.S. Additionally, certain of our operations are subject to tax assessed by the state of Texas that is computed based on modified gross margin as defined by the State of Texas. The Texas franchise tax is presented as income tax expense in the accompanying statements of operations.


We account for deferred income taxes related to the federal and state jurisdictions using the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases. Deferred tax assets are also recognized for the future tax benefits attributable to the expected utilization of existing tax net operating loss carryforwards and other types of carryforwards. If the future utilization of some portion of carryforwards is determined to be unlikely, a valuation allowance is provided to reduce the recorded tax benefits from such assets. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. In the event interest or penalties are incurred with respect to income tax matters, our policy will be to include such items in income tax expense. We record deferred tax assets and liabilities on a net basis on the consolidated balance sheets, with deferred tax assets included in “Other assets, net” and deferred tax liabilities included in “Deferred tax liability, net.”


(g) (i)Natural Gas, Natural Gas Liquids, Crude Oil, and Condensate Inventory


Our inventories of products consist of natural gas, NGLs, crude oil, and condensate. We report these assets at the lower of cost or market value which is determined by using the first-in, first-out method.


(h) (j)Property and Equipment


Property and equipment are stated at historical cost less accumulated depreciation. Assets acquired in a business combination are recorded at fair value. RepairsRoutine repairs and maintenance are charged against income when incurred. Renewals and betterments, whichimprovements that extend the useful life or improve the function of the properties are capitalized. Interest costs for material projects are capitalized to property and equipment during the period the assets are undergoing preparation for intended use.


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Notes to Consolidated Financial Statements (continued)
The components of property and equipment, net of accumulated depreciation are as follows (in millions):
Year Ended December 31,
20212020
Transmission assets$1,442.2 $1,410.5 
Gathering systems4,903.8 4,782.9 
Gas processing plants4,119.1 4,082.1 
Other property and equipment161.0 161.0 
Construction in process94.2 78.6 
Property and equipment10,720.3 10,515.1 
Accumulated depreciation(4,332.0)(3,863.0)
Property and equipment, net of accumulated depreciation$6,388.3 $6,652.1 
 Year Ended December 31,
 2017 2016
Transmission assets$1,338.7
 $1,191.7
Gathering systems4,040.9
 3,530.9
Gas processing plants3,401.8
 3,163.0
Other property and equipment157.8
 149.5
Construction in process180.8
 345.7
Property and equipment$9,120.0
 $8,380.8
Accumulated depreciation(2,533.0) (2,124.1)
Property and equipment, net of accumulated depreciation$6,587.0
 $6,256.7


Depreciation Expense. Depreciation is calculated using the straight-line method based on the estimated useful life of each asset, as follows:
Useful Lives
Useful Lives
Transmission assets20 - 25 years
Gathering systems20 - 25 years
Gas processing plants20 - 25 years
Other property and equipment3 - 1525 years


Depreciation expense of $418.2 million, $386.9 million and $331.3 million was recorded for the years ended December 31, 2017, 2016 and 2015, respectively.


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Gain or Loss on Disposition. Upon the disposition or retirement of property and equipment, any gain or loss is recognized in operating income in the statementconsolidated statements of operations. For the yearyears ended December 31, 2017, we disposed of assets with a net book value of $8.4 million,2021, 2020, and these2019, dispositions primarily related to the retirement of compressors due to fire damage. This decrease in book value was offset by $6.1 million in expected insurance settlements and $2.3 million of proceeds from the sale of property, resulting in no gain or loss on disposition of assets in the consolidated statement of operations for the year ended December 31, 2017.

For the year ended December 31, 2016, we retired or sold net property and equipment of $106.6 million, which was offset by $0.3 million of insurance settlements and $93.1 million of proceeds from the sale of property, resulting in a loss on disposition of assets of $13.2 million. The loss on disposition of assets primarily related to the sale of the North Texas Pipeline System (“NPTL”), a 140-mile natural gas transportation pipeline, that resulted in net proceeds of $84.6 million and a loss on sale of $13.4 million.

For the year ended December 31, 2015, we retired net property and equipment of $5.1 million, which was offset by $2.9 million of insurance settlements and $1.0 million of proceeds from the sale of property. This resulted in acertain non-core assets. The (gain) loss on disposition of assets of $1.2 million, which primarily relates to the retirement of a compressor due to fire damage. Additionally, we collected $2.4 million of business interruption proceeds from our insurance carrier that was presented in the “Midstream services” revenue line item in the consolidated statement of operations for the year ended December 31, 2015.are as follows (in millions):

Year Ended December 31,
202120202019
Net book value of assets disposed$3.3 $36.4 $12.4 
Less:
Proceeds from sales(4.8)(27.6)(14.3)
(Gain) loss on disposition of assets$(1.5)$8.8 $(1.9)

Impairment Review. In accordance with ASC 360, Property, Plant, and Equipment, we evaluate long-lived assets of identifiable business activities for potential impairment whenever events or changes in circumstances, or triggering events, indicate that their carrying value may not be recoverable. Triggering events include, but are not limited to, significant changes in the use of the asset group, current operating results that are significantly less than forecasted results, negative industry or economic trends including changes in commodity prices, significant adverse changes in legal or regulatory factors, or an expectation that it is more likely than not that an asset group will be sold before the end of its useful life. The carrying amount of a long-lived asset is not recoverable when it exceeds the undiscounted sum of the future cash flows expected to result from the use and eventual disposition of the asset. Estimates of expected future cash flows represent management’s best estimate based on reasonable and supportable assumptions. When the carrying amount of a long-lived asset is not recoverable, an impairment loss is recognized equal to the excess of the asset’s carrying value over its fair value. value, which is based on inputs that are not observable in the market, and thus represent Level 3 inputs.


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Notes to Consolidated Financial Statements (continued)
When determining whether impairment of our long-lived assets has occurred, we must estimate the undiscounted cash flows attributable to the asset. Our estimate of cash flows is based on assumptions regarding:


•the future fee-based rate of new business or contract renewals;
•the purchase and resale margins on natural gas, NGLs, crude oil, and condensate;
•the volume of natural gas, NGLs, crude oil, and condensate available to the asset;
•markets available to the asset;
•operating expenses; and
•future natural gas, NGLs, crude oil, and condensate prices.


The amount of availability of natural gas, NGLs, crude oil, and condensate to an asset is sometimes based on assumptions regarding future drilling activity, which may be dependent in part on natural gas, NGL, crude oil, and condensate prices. Projections of natural gas, NGL, crude oil, and condensate volumes and future commodity prices are inherently subjective and contingent upon a number of variable factors, including but not limited to:


•changes in general economic conditions in regions in which our markets are located;
•the availability and prices of natural gas, NGLs, crude oil, and condensate supply;
•our ability to negotiate favorable sales agreements;
•the risks that natural gas, NGLs, crude oil, and condensate exploration and production activities will not occur or be successful;
•our dependence on certain significant customers, producers, and transporters of natural gas, NGLs, crude oil, and condensate; and
•competition from other midstream companies, including major energy companies.


For the year ended December 31, 2017,2021, we recognized impairmentsa $0.6 million impairment on property and equipment of $17.1 million, which related to the carrying values of rights-of-way that we are no longer using and an abandoned brine disposal well. equipment.

For the year ended December 31, 2015,2020, we recognized a $12.1$168.0 million impairment on property and equipment primarily related to costs associated witha portion of our Louisiana reporting segment because the cancellationcarrying amounts were not recoverable based on our expected future cash flows, and $3.4 million of various capital projects in our Texas, Louisiana,impairments related to certain cancelled projects.

For the year ended December 31, 2019, we recognized a $7.9 million impairment on property and Crudeequipment related to certain decommissioned and Condensate segments.removed non-core assets.



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(i) (k)Comprehensive Income (Loss)


Comprehensive income (loss) is composedcomprised of net income (loss), which consists of and the effective portion of gains or losses on derivative financial instruments that qualify as cash flow hedges pursuant to ASC 815, Derivatives and Hedging (“ASC 815”).815. For additional information about the year ended December 31, 2017, we reclassified an immaterial amounteffect of losses from accumulated otherfinancial instruments on comprehensive income (loss) to earnings. For additional information,, see “Note 13—Derivatives.12—Derivatives.”


(j) (l)Equity Method of Accounting


We account for investments where we do not control the investment but have the ability to exercise significant influence using the equity method of accounting. Under this method, unconsolidated affiliate investments are initially carried at the acquisition cost, increased by our proportionate share of the investee’s net income and by contributions made, and decreased by our proportionate share of the investee’s net losses and by distributions received.


We evaluate our unconsolidated affiliate investments for potential impairment whenever events or changes in circumstances indicate that the carrying amount of the investments may not be recoverable. We recognize impairments of our investments as a loss from unconsolidated affiliates on our consolidated statements of operations.

We recognized a $31.4 million loss for the year ended December 31, 2019 related to the impairment of the carrying value of the Cedar Cove JV, as we determined that the carrying value of our investment was not recoverable based on the forecasted cash flows from the Cedar Cove JV.

For additional information, see “Note 11—10—Investment in Unconsolidated Affiliates.”


(k) Goodwill
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(m)Non-controlling Interests

We account for investments where we control the investment using the consolidation method of accounting. Under this method, we consolidate all the assets and liabilities of an investment on our consolidated balance sheets and record non-controlling interest for the portion of the investment that we do not own. We include all of an investment’s results of operations on our consolidated statements of operations and record income attributable to non-controlling interests for the portion of the investment that we do not own.

Our non-controlling interests for the years ended December 31, 2021, 2020, and 2019 relate to the Series B Preferred Units, the Series C Preferred Units, NGP’s 49.9% ownership of the Delaware Basin JV, and Marathon Petroleum Corporation’s 50.0% ownership interest in the Ascension JV. For periods prior to the Merger, our non-controlling interests also included ENLK’s public common unitholders.

(n)Goodwill

Goodwill is the cost of an acquisition less the fair value of the net identifiable assets of the acquired business. We evaluateevaluated goodwill for impairment annually as of October 31 and whenever events or changes in circumstances indicateindicated it iswas more likely than not that the fair value of a reporting unit is less than its carrying amount. For additional information regarding our assessmentprevious assessments of goodwill for impairment, see “Note 4—3—Goodwill and Intangible Assets.”


(l) (o)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 range from ten to twenty years. In accordance with ASC 350, Intangibles—Goodwill and Other, we evaluate intangibles for potential impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable. For additional information regarding our intangible assets, including our assessment of intangible assets for impairment, see “Note 4—3—Goodwill and Intangible Assets.”


(m) (p)Asset Retirement Obligations


We recognize liabilities for retirement obligations associated with our pipelines and processing and fractionation facilities. Such liabilities are recognized when there is a legal obligation associated with the retirement of the assets and the amount can be reasonably estimated. The initial measurement of an asset retirement obligation is recorded as a liability at its fair value, with an offsetting asset retirement cost recorded as an increase to the associated property and equipment. If the fair value of a recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the asset retirement cost. Our retirement obligations include estimated environmental remediation costs that arise from normal operations and are associated with the retirement of the long-lived assets. The asset retirement cost is depreciated using the straight-line depreciation method similar to that used for the associated property and equipment.

(q)Leases

Effective January 1, 2019, we adopted ASC 842 using the modified retrospective approach whereby we recognized leases on our consolidated balance sheet by recording a right-of-use asset and lease liability. We applied certain practical expedients that were allowed in the adoption of ASC 842, including not reassessing existing contracts for lease arrangements, not reassessing existing lease classification, not recording a right-of-use asset or lease liability for leases of twelve months or less, and not separating lease and non-lease components of a lease arrangement.

We evaluate new contracts at inception to determine if the contract conveys the right to control the use of an identified asset for a period of time in exchange for periodic payments. A lease exists if we obtain substantially all of the economic benefits of an asset, and we have the right to direct the use of that asset. When a lease exists, we record a right-of-use asset that represents our right to use the asset over the lease term and a lease liability that represents our obligation to make payments over the lease term. Lease liabilities are recorded at the sum of future lease payments discounted by the collateralized rate we could obtain to lease a similar asset over a similar period, and right-of-use assets are recorded equal to the corresponding lease liability, plus any prepaid or direct costs incurred to enter the lease, less the cost of any incentives received from the lessor. For additionalmore information, see “Note 10—Asset Retirement Obligations.5—Leases.”

(n) Other Long-Term Liabilities

Other current and long-term liabilities include a liability related to an onerous performance obligation assumed in the Business Combination of $26.9 million and $44.8 million as of December 31, 2017 and 2016, respectively. We have one delivery contract that requires us to deliver a specified volume of gas each month at an indexed base price with a term to mid-2019. We realize a loss on the delivery of gas under this contract each month based on current prices. The fair value of this onerous performance obligation was based on forecasted discounted cash obligations in excess of market under this gas delivery contract in March 2014. The liability is reduced each month as delivery is made over the remaining life of the contract with an offsetting reduction in purchased gas costs.



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(r)Derivatives
(o) Derivatives

We use derivative instruments to hedge against changes in cash flows related to product price. We generally determine the fair value of swap contracts based on the difference between the derivative’s fixed contract price and the underlying market price at the determination date. The asset or liability related to the derivative instruments is recorded on the balance sheet at the fair value of derivative assets or liabilities in accordance with ASC 815, Derivatives and Hedging (“ASC 815”).815. Changes in fair value of derivative instruments are recorded in gain or loss on derivative activity in the period of change.


Realized gains and losses on commodity-related derivatives are recorded as gain or loss on derivative activity within revenues in the consolidated statements of operations in the period incurred. Settlements of derivatives are included in cash flows from operating activities.


We periodically enter into interest rate swaps in connection with new debt issuances. During the debt issuance process, we are exposedissuances to hedge variability in future long-term debt interest payments that may result from changes in the benchmark interest rate (commonly the U.S. Treasury yield) prior to the debt being issued. In order to hedge this variability, we enter into interest rate swaps torates and effectively lock in the benchmark interest rate at the inception of the swap. Prior to 2017,

In April 2019, we did not designateentered into $850.0 million of interest rate swaps as hedges and, therefore, includedto manage the associated settlement gains and losses as interest expense on the consolidated statements of operations.

In May 2017, we entered into an interest rate swaprisk associated with our floating-rate, LIBOR-based borrowings. Under this arrangement, we paid a fixed interest rate of 2.28% in exchange for LIBOR-based variable interest through December 2021. These interest rate swaps expired on December 10, 2021. There was no ineffectiveness related to this hedge.

During 2021 and 2020, we terminated the interest rate swaps in several increments in connection with repayments of the issuanceTerm Loan, which was one of our senior unsecured notes due June 1, 2047 (the “2047 Notes”). In accordance with ASC 815, we designated this swap as a cash flow hedge. Upon settlement offloating-rate, LIBOR-based borrowings. The following table presents the interest rate swap in May 2017, we recordedswaps terminations and the associated $2.2 million settlement loss in accumulated other comprehensive loss on the consolidated balance sheets. We will amortize the settlement loss into interest expense on the consolidated statements of operations over the term of the 2047 Notes.cash payments during 2021 and 2020 (in millions):

Interest Rate Swaps TerminationsCash Payments Associated with Interest Rate Swaps Terminations
December 2021$150.0 $— 
September 2021100.0 0.5 
May 2021100.0 1.3 
December 2020500.0 10.9 
Total termination of interest rate swaps$850.0 $12.7 

For additional information, see “Note 13—12—Derivatives.”


(p) (s)Concentrations of Credit Risk


Financial instruments, which potentially subject us to concentrations of credit risk, consist primarily of trade accounts receivable and commodity financial instruments. Management believes the risk is limited, other than our exposure to Devonsignificant customers discussed below, since our customers represent a broad and diverse group of energy marketers and end users. In addition, we

The following customers individually represented greater than 10% of our consolidated revenues during 2021, 2020, or 2019. These customers represented a significant percentage of our consolidated revenues, and 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.
Year Ended December 31,
202120202019
Devon6.7 %14.4 %10.5 %
Dow Hydrocarbons and Resources LLC14.5 %13.2 %10.0 %
Marathon Petroleum Corporation13.4 %12.2 %13.8 %

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We continually monitor and review the credit exposure of our marketing counter-parties based on various credit quality indicators and metrics. We obtain letters of credit or other appropriate security are obtained when considered necessary to limit the risk of loss. We record reserves for uncollectible accounts on a specific identification basis since there is not a large volume of late paying customers. Wecustomers and we do not expect to experience significant levels of default on our trade accounts receivable. As of December 31, 2021 and 2020, we had a reserve for uncollectible receivables of $0.3 million and $0.1$0.5 million, as of December 31, 2017 and 2016, respectively.


For the years ended December 31, 2017, 2016 and 2015, we had two customers that individually represented greater than 10.0% of our consolidated revenues. Dow Hydrocarbons & Resources LLC (“Dow Hydrocarbons”) is located in the Louisiana segment and represented 11.2%, 10.8% and 11.7% of our consolidated revenues for the years ended December 31, 2017, 2016 and 2015, respectively. The affiliate transactions with Devon represented 14.4%, 18.5% and 16.6% of our consolidated revenues for the years ended December 31, 2017, 2016 and 2015, respectively. Devon and Dow Hydrocarbons represent a significant percentage of revenues, and the loss of either as a customer would have a material adverse impact on our results of operations because the gross operating margin received from transactions with these customers is material to us.

(q) (t)Environmental Costs


Environmental expenditures are expensed or capitalized depending on the nature of the expenditures and the future economic benefit. Expenditures that relate to an existing condition caused by past operations that do not contribute to current or future revenue generation are expensed. Liabilities for these expenditures are recorded on an undiscounted basis (or a discounted basis when the obligation can be settled at fixed and determinable amounts) when environmental assessments or clean-ups are probable and the costs can be reasonably estimated. Environmental expenditures were $0.9 million and $3.5 millionnot material for the years ended December 31, 20172021, 2020, and 2015. For the year ended December 31, 2016, such expenditures were not material.2019.



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(r) (u)Unit-Based Awards


We recognize compensation cost related to all unit-based awards in our consolidated financial statements in accordance with ASC 718, Compensation—Stock Compensation (“ASC 718”). We and ENLK each have similar unit-based payment plans for employees.718. Unit-based compensation associated with ENLC’s unit-based compensation plansplan awarded to directors, officers, and employees of our general partner arethe General Partner is recorded by usENLK since ENLC has no substantial or managed operating activities other than its interests in us and EnLink Oklahoma T.O.ENLK. For additional information, see “Note 12—11—Employee Incentive Plans.”


(s) (v)Commitments and Contingencies


Liabilities for loss contingencies arising from claims, assessments, litigation, or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Legal costs incurred in connection with a loss contingency are expensed as incurred. For additional information, see “Note 15—14—Commitments and Contingencies.”


(t) (w)Debt Issuance Costs


Costs incurred in connection with the issuance of long-term debt are deferred and recorded asamortized into interest expense using the straight-line method over the term of the related debt. Gains or losses on debt repurchases, redemptions, and debt extinguishments include any associated unamortized debt issue costs. Unamortized debt issuance costs totaling $26.2$27.8 million and $24.6$32.6 million as of December 31, 20172021 and 2016,2020, respectively, are included in “Long-term debt” or “Current maturities of long-term debt,” as applicable, on the consolidated balance sheets as a direct reduction from the carrying amount of long-termthe debt. Debt issuance costs are amortized into interest expense using the straight-line method over the term of the related debt issuance.


(u) Legal Costs Expected to be Incurred in Connection with a Loss Contingency

Legal costs incurred in connection with a loss contingency are expensed as incurred.

(v) (x)Redeemable Non-Controlling Interest


Non-controlling interests that contain an option for the non-controlling interest holder to require us to buy outpurchase such interests for cash are considered to be redeemable non-controlling interests because the redemption feature is not deemed to be a freestanding financial instrument and because the redemption is not solely within our control. Redeemable non-controlling interest isinterests are not considered to be a component of partners’members’ equity and isare reported as temporary equity in the mezzanine section on the consolidated balance sheets. The amount recorded as redeemable non-controlling interest at each balance sheet date is the greater of the redemption value and the carrying value of the redeemable non-controlling interest (the initial carrying value increased or decreased for the non-controlling interest holder’s share of net income or loss and distributions). When the redemption feature is exercised the redemption value of the non-controlling interest is reclassified to a liability on the consolidated balance sheets.


(w) Adopted Accounting Standards

In March 2016,During the Financial Accounting Standards Board (“FASB”) issued ASU 2016-09, Improvementsfirst quarter of 2020, the non-controlling interest holder in one of our non-wholly owned subsidiaries exercised its option to Employee Share-Based Payment Accounting, which amends ASC Topic 718, Compensation — Stock Compensation (“ASU 2016-09”), which simplifies several aspectsrequire us to purchase its remaining interest. We have recorded an estimated $4.0 million related to the accounting for share-based payment transactions. Effective January 1, 2017, we adopted ASU 2016-09. We prospectively adoptedredemption of the guidance that requires excess tax benefits and deficiencies be recognizednon-controlling interest included in “Other current liabilities” on the income statement. The cash flow statement guidance requires the presentationconsolidated balance sheets as of excess tax benefits and deficiencies as an operating activity and the presentation of cash paid by an employer when directly withholding shares for tax-withholding purposes as a financing activity, and this treatment is consistent with our historical accounting treatment. Finally, we elected to estimate the number of awards that are expected to vest, which is consistent with our historical accounting treatment. The adoption of ASU 2016-09 did not materially affect the consolidated statement of operations for the year ended December 31, 2017.2021 and 2020, but we have not yet agreed to a redemption value with the non-controlling interest holder.

In January 2017, the FASB issued ASU 2017-04, Intangibles—Goodwill and Other (Topic 350)— Simplifying the Test for Goodwill Impairment (“ASU 2017-04”). ASU 2017-04 simplifies the accounting for goodwill impairments by eliminating the requirement to compare the implied fair value of goodwill with its carrying amount as part of step two of the goodwill impairment test referenced in ASC 350. As a result, an entity should perform its annual or interim goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount. An impairment charge should be recognized for the amount by which the carrying amount exceeds the reporting unit’s fair value. However, the impairment loss recognized should


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not exceed the total amount of goodwill allocated to that reporting unit. ASU 2017-04 is effective for annual reporting periods beginning after December 15, 2019, including any interim impairment tests within those annual periods, with early application permitted for interim or annual goodwill tests performed on testing dates after January 1, 2017. In January 2017, we elected to early adopt ASU 2017-04, and the adoption had no impact on our consolidated financial statements.

(x) Accounting Standards to be Adopted in Future Periods

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842)—Amendments to the FASB Accounting Standards Codification (“ASU 2016-02”). Lessees will need to recognize virtually all of their leases on the balance sheet by recording a right-of-use asset and lease liability. Lessor accounting is similar to the current model, but updated to align with certain changes to the lessee model and the new revenue recognition standard. Existing sale-leaseback guidance is replaced with a new model applicable to both lessees and lessors. Additional revisions have been made to embedded leases, reassessment requirements and lease term assessments including variable lease payment, discount rate and lease incentives. ASU 2016-02 is effective for annual reporting periods beginning after December 15, 2018, including interim periods within those annual periods. Early adoption is permitted. Entities are required to adopt ASU 2016-02 using a modified retrospective transition. We are currently assessing the impact of adopting ASU 2016-02. This assessment includes the gathering and evaluation of our current lease contracts and the analysis of contracts that may contain lease components. While we cannot currently estimate the quantitative effect that ASU 2016-02 will have on our consolidated financial statements, the adoption of ASU 2016-02 will increase our asset and liability balances on the consolidated balance sheets due to the required recognition of right-of-use assets and corresponding lease liabilities for all lease obligations that are currently classified as operating leases. In addition, there are industry-specific concerns with the implementation of ASU 2016-02 that will require further evaluation before we are able to fully assess the impact on our consolidated financial statements.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”), which established ASC Topic 606, Revenue from Contracts with Customers (“ASC 606”). ASC 606 will replace existing revenue recognition requirements in GAAP and will require entities to recognize revenue at an amount that reflects the consideration to which they expect to be entitled in exchange for transferring goods or services to a customer. ASC 606 will also require significantly expanded disclosures containing qualitative and quantitative information regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. In May 2016, the FASB issued ASU 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients (“ASU 2016-12”), which updated ASU 2014-09. ASU 2016-12 clarifies certain core recognition principles, including collectability, sales tax presentation, noncash consideration, contract modifications and completed contracts at transition and disclosures no longer required if the full retrospective transition method is adopted. ASU 2014-09 and ASU 2016-12 are effective for annual reporting periods beginning after December 15, 2017, including interim periods within those annual periods, and are to be applied using the modified retrospective or full retrospective transition methods, with early application permitted for annual reporting periods beginning after December 15, 2016. We will adopt ASC 606 using the modified retrospective method for annual and interim reporting periods beginning January 1, 2018.

We have aggregated and reviewed our contracts that are within the scope of ASC 606. Based on our evaluation to date, we do not anticipate the adoption of ASC 606 will have a material impact on our results of operations, financial condition or cash flows. However, ASC 606 will affect how certain transactions are recorded in the financial statements. For each contract with a customer, we will need to identify our performance obligations, of which the identification includes careful evaluation of when control and the economic benefits of the commodities transfer to us. The evaluation of control will change the way we account for certain transactions, specifically those in which there is both a commodity purchase component and a service component. For contracts where control of commodities transfers to us before we perform our services, we generally have no performance obligation for our services, and accordingly, we will not consider these revenue-generating contracts. Based on that determination, all fees or fee-equivalent deductions stated in such contracts would reduce the cost to purchase commodities. Alternatively, for contracts where control of commodities transfers to us after we perform our services, we have performance obligations for our services. Accordingly, we will consider the satisfaction of these performance obligations as revenue-generating and recognize these fees as midstream service revenues at the time we satisfy our performance obligations. For contracts where control of commodities never transfers to us and we simply earn a fee for our services, we will recognize these fees as midstream services revenues at the time we satisfy our performance obligations. Based on our review of our performance obligations in our contracts with customers, we will change the statement of operations classification for certain transactions from revenue to cost of sales or from cost of sales to revenue. We estimate that the reclassification of revenues and costs will result in a net decrease in revenue of approximately 6-10%, although this estimate is based on historical information

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and could change based on commodity prices going forward. This reclassification of revenues and costs will have no effect on operating income and gross operating margin.

Our performance obligations represent promises to transfer a series of distinct goods or services that are satisfied over time and that are substantially the same to the customer. As permitted by ASC 606, we will utilize the practical expedient that allows an entity to recognize revenue in the amount to which the entity has a right to invoice, if an entity has a right to consideration from a customer in an amount that corresponds directly with the value to the customer of the entity’s performance completed to date. Accordingly, we will continue to recognize revenue at the time commodities are delivered or services are performed, so ASC 606 will not significantly affect the timing of revenue and expense recognition on our statements of operations.

Based on the disclosure requirements of ASC 606, upon adoption, we expect to provide expanded disclosures relating to our revenue recognition policies and how these relate to our revenue-generating contractual performance obligations. In addition, we expect to present revenues disaggregated based on the type of good or service in order to more fully depict the nature of our revenues.

(3) Acquisitions

LPC Acquisition

On January 31, 2015, we acquired 100% of the voting equity interests of LPC Crude Oil Marketing LLC (“LPC”), which has crude oil gathering, transportation and marketing operations in the Permian Basin, for approximately $108.1 million. The transaction was accounted for using the acquisition method.

The following table presents the fair value of the identified assets received and liabilities assumed at the acquisition date (in millions):

Purchase Price Allocation: 
Assets acquired: 
Current assets (including $21.1 million in cash)$107.4
Property and equipment29.8
Intangibles43.2
Goodwill29.6
Liabilities assumed: 
Current liabilities(97.9)
Deferred tax liability(4.0)
Total identifiable net assets$108.1

We recognized intangible assets related to customer relationships and trade name. The acquired intangible assets related to customer relationships are amortized on a straight-line basis over the estimated customer life of approximately 10 years. Goodwill recognized from the acquisition primarily related to the value created from additional growth opportunities and greater operating leverage in the Permian Basin. All such goodwill was allocated to our Crude and Condensate segment and was subsequently impaired during the year ended December 31, 2016.

We incurred $0.3 million of direct transaction costs for the year ended December 31, 2015. These costs are included in general and administrative costs in the accompanying consolidated statements of operations.

For the period from January 31, 2015 to December 31, 2015, we recognized $1.1 billion of revenues and $0.9 million of net income related to the assets acquired.

Coronado Acquisition

On March 16, 2015, we acquired 100% of the voting equity interests in Coronado Midstream Holdings LLC (“Coronado”), which owns natural gas gathering and processing facilities in the Permian Basin, for approximately $600.3 million. The

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purchase price consisted of $240.3 million in cash, 6,704,285 ENLK common units and 6,704,285 ENLK Class C Common Units.

The following table presents the fair value of the identified assets received and liabilities assumed at the acquisition date (in millions):

Purchase Price Allocation: 
Assets acquired: 
Current assets (including $1.4 million in cash)$20.8
Property and equipment302.1
Intangibles281.0
Goodwill18.7
Liabilities assumed: 
Current liabilities(22.3)
Total identifiable net assets$600.3

We recognized intangible assets related to customer relationships. The acquired intangible assets are amortized on a straight-line basis over the estimated customer life of approximately 10 to 20 years. Goodwill recognized from the acquisition primarily relates to the value created from additional growth opportunities and greater operating leverage in the Permian Basin. All such goodwill is allocated to our Texas segment.

We incurred $3.1 million of direct transaction costs for the year ended December 31, 2015. These costs are included in general and administrative expenses in the accompanying consolidated statements of operations.

For the period from March 16, 2015 to December 31, 2015, we recognized $182.0 million of revenues and $14.2 million of net loss related to the assets acquired.

Matador Acquisition

On October 1, 2015, we acquired 100% of the voting equity interests in a subsidiary of Matador Resources Company (“Matador”), which has gathering and processing assets operations in the Delaware Basin, for approximately $141.3 million. The transaction was accounted for using the acquisition method.

The following table presents the fair value of the identified assets received and liabilities assumed at the acquisition date (in millions):

Purchase Price Allocation: 
Assets acquired: 
Current assets$1.1
Property and equipment35.5
Intangibles98.8
Goodwill10.7
Liabilities assumed: 
Current liabilities(4.8)
Total identifiable net assets$141.3

We recognized intangible assets related to customer relationships. The acquired intangible assets are amortized on a straight-line basis over the estimated customer life of approximately 15 years. Goodwill recognized from the acquisition primarily relates to the value created from additional growth opportunities and greater operating leverage in the Permian Basin. All such goodwill is allocated to our Texas segment.


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We incurred $0.1 million of direct transaction costs for the year ended December 31, 2015. These costs are included in general and administrative expenses in the accompanying consolidated statements of operations.

For the period from October 1, 2015 to December 31, 2015, we recognized $5.6 million of revenues and $0.7 million of net loss related to the assets acquired.

Deadwood Acquisition

Prior to November 2015, we co-owned the Deadwood natural gas processing plant with a subsidiary of Apache Corporation (“Apache”). On November 16, 2015, we acquired Apache’s 50% ownership interest in the Deadwood natural gas processing facility for approximately $40.1 million, all of which is considered property and equipment. The transaction was accounted for using the acquisition method. Direct transaction costs attributable to this acquisition were less than $0.1 million.

For the period from November 16, 2015 to December 31, 2015, we recognized $3.5 million of revenues and $1.3 million of net income related to the assets acquired.

VEX Pipeline Drop Down

On April 1, 2015, we acquired VEX, located in the Eagle Ford Shale in South Texas, together with 100% of the voting equity interests in certain entities, from Devon in the VEX Drop Down. The aggregate consideration paid by us consisted of $166.7 million in cash, 338,159 ENLK common units representing its limited partner interests with an aggregate value of approximately $9.0 million and our assumption of up to $40.0 million in certain construction costs related to VEX. The acquisition has been accounted for as an acquisition under common control under ASC 805, resulting in the retrospective adjustment of our prior results. As such, the VEX interests were recorded on our books at historical cost on the date of transfer of $131.0 million. The difference between the historical cost of the net assets and consideration given was $35.7 million and is recognized as a distribution to Devon. Construction costs paid by Devon during the first quarter of 2015 totaling $25.6 million are reflected as contributions from Devon to ENLK in our consolidated statements of changes in partners’ equity and consolidated statements of cash flows for the year ended December 31, 2015.

Pro Forma of Acquisitions for the Years Ended 2015

The following unaudited pro forma condensed financial information (in millions, except for per unit data) for the year ended December 31, 2015 gives effect to the January 2015 LPC acquisition, March 2015 Coronado acquisition, October 2015 Matador acquisition and the VEX Drop Down as if they had occurred on January 1, 2015. The unaudited pro forma condensed financial information has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the transactions taken place on the dates indicated and is not intended to be a projection of future results.

 Year Ended December 31, 2015
Pro forma total revenues$4,585.5
Pro forma net loss$(1,413.0)
Pro forma net loss attributable to EnLink Midstream, LLC$(355.5)
Pro forma net loss per common unit: 
Basic$(2.18)
Diluted$(2.18)

EnLink Oklahoma T.O. Acquisition

On January 7, 2016, ENLC and ENLK acquired an 16.1% and 83.9% voting interest, respectively, in EnLink Oklahoma T.O. for aggregate consideration of approximately $1.4 billion. The first installment of $1.02 billion for the acquisition was paid at closing. The second and final installments, each equal to $250.0 million, were paid in January 2017 and January 2018, respectively.


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The first installment of approximately $1.02 billion was funded by (a) approximately $783.6 million in cash paid by ENLK, which was primarily derived from the issuance of Series B Cumulative Convertible Preferred Units (“Series B Preferred Units”), (b) 15,564,009 common units representing limited liability company interests in ENLC issued directly by ENLC and (c) approximately $22.2 million in cash paid by ENLC. The transaction was accounted for using the acquisition method.

The following table presents the considerations ENLC and ENLK paid and the fair value of the identified assets received and liabilities assumed at the acquisition date (in millions):

Consideration: 
Cash$805.8
Issuance of ENLC common units214.9
ENLK’s total installment payable, net of discount of $79.1 million420.9
Total consideration$1,441.6
  
Purchase Price Allocation: 
Assets acquired: 
Current assets (including $12.8 million in cash)$23.0
Property and equipment406.1
Intangibles1,051.3
Liabilities assumed: 
Current liabilities(38.8)
Total identifiable net assets$1,441.6

The fair value of assets acquired and liabilities assumed are based on inputs that are not observable in the market and thus represent Level 3 inputs. We recognized intangible assets related to customer relationships and determined their fair value using the income approach. The acquired intangible assets are amortized on a straight-line basis over the estimated customer life of approximately 15 years.

We incurred a total of $4.4 million and $0.4 million of direct transaction costs for the year ended December 31, 2016 and December 31, 2015, respectively. These costs are incurred in general and administrative costs in the accompanying consolidated statements of operations.

For the period from January 7, 2016 to December 31, 2016, we recognized $246.1 million of revenues and $34.1 million of net loss related to the assets acquired.

Pro Forma of the EnLink Oklahoma T.O. Acquisition

The following unaudited pro forma condensed financial information (in millions, except for per unit data) for the year ended December 31, 2016 and 2015 gives effect to the January 2016 acquisition of EnLink Oklahoma T.O as if it had occurred on January 1, 2015. The unaudited pro forma condensed financial information has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the transaction taken place on the dates indicated and is not intended to be a projection of future results.
 Year Ended December 31,
 2016 2015
Pro forma total revenues$4,254.4
 $4,647.8
Pro forma net loss$(879.9) $(1,471.8)
Pro forma net loss attributable to EnLink Midstream, LLC$(451.3) $(368.4)
Pro forma net loss per common unit:   
Basic$(2.51) $(2.05)
Diluted$(2.51) $(2.05)

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(4) Goodwill and Intangible Assets

Goodwill


Goodwill is the cost of an acquisition less the fair value of the net identifiable assets of the acquired business. The fair value of goodwill is based on inputs that are not observable in the market and thus represent Level 3 inputs.Impairments


The table below provides a summary of our change in carrying amount of goodwill (in millions) for the year ended December 31, 2016, by assigned reporting unit:
 Texas Oklahoma Crude and Condensate Corporate Totals
Year Ended December 31, 2016         
Balance, beginning of period$703.5
 $190.3
 $93.2
 $1,426.9
 $2,413.9
Impairment(473.1) —
 (93.2) (307.0) (873.3)
Acquisition adjustment1.6
 —
 —
 —
 1.6
Balance, end of period$232.0
 $190.3
 $—
 $1,119.9
 $1,542.2

For the year ended December 31, 2017, there were no changes to the carrying amount of goodwill.

We evaluate goodwill for impairment annually as of October 31 and whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount. We first assess qualitative factors to evaluate whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as the basis for determining whether it is necessary to perform a goodwill impairment test. We may elect to perform a goodwill impairment test without completing a qualitative assessment.

We perform our goodwill assessments at the reporting unit level for all reporting units. We use a discounted cash flow analysis to perform the assessments. Key assumptions in the analysis include the use of an appropriate discount rate, terminal year multiples and estimated future cash flows, including volume and price forecasts and estimated operating and general and administrative costs. In estimating cash flows, we incorporate current and historical market and financial information, among other factors. Impairment determinations involve significant assumptions and judgments, and differing assumptions regarding any of these inputs could have a significant effect on the various valuations. If actual results are not consistent with our assumptions and estimates, or our assumptions and estimates change due to new information, we may be exposed to goodwill impairment charges, which would be recognized in the period in which the carrying value exceeds fair value.

Prior to January 2017, if a goodwill impairment test was elected or required, we performed a two-step goodwill impairment test. The first step involved comparing the fair value of the reporting unit to its carrying amount. If the carrying amount of a reporting unit exceeded its fair value, the second step of the process involved comparing the implied fair value to the carrying value of the goodwill for that reporting unit. If the carrying value of the goodwill of a reporting unit exceeded the implied fair value of that goodwill, the excess of the carrying value over the implied fair value was recognized as an impairment loss.

Effective January 2017, we elected to early adopt ASU 2017-04, Intangibles—Goodwill and Other (Topic 350)— Simplifying the Test for Goodwill Impairment, which simplified the accounting for goodwill impairments by eliminating the requirement to compare the implied fair value of goodwill with its carrying amount as part of step two of the goodwill impairment test referenced in ASC 350. Therefore, our annual impairment test as of October 31, 2017 was performed according to ASU 2017-04.

Impairment Analysis for the Year Ended December 31, 20152020

During the thirdfirst quarter of 2015,2020, we determined that a sustained decline in our unit price and weakness in the overall energy sector, driven by low commodity prices together with a decline in our unit price, caused a change in circumstances warranting an interim impairment test. We also performed our annual impairment analysis during the fourth quarter of 2015. Although our established annual effective date for this goodwill analysis is October 31, we updated the effective date for this impairment analysis for the 2015 annual period to December 31, 2015and lower consumer demand due to continued declines in commodity prices and our unit price during the fourth quarter of 2015.

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Using the fair value approaches described above, in step one of the goodwill impairment test, we determined that the estimated fair values of our Louisiana, Texas and Crude and Condensate reporting units were less than their carrying amounts, primarily related to commodity prices, volume forecasts and discount rates. Based on that determination, we performed the second step of the goodwill impairment test by measuring the amount of impairment loss and allocating the estimated fair value of the reporting unit among all of the assets and liabilities of the reporting unit as if the reporting unit had been acquired in a business combination. Based on this analysis, a goodwill impairment loss for our Louisiana, Texas, and Crude and Condensate reporting units in the amount of $1,328.2 million was recognized for the year ended December 31, 2015 and is included as an impairment loss in the consolidated statement of operations.
We concluded that the fair value of goodwill for our Oklahoma reporting unit exceeded its carrying value, and the amount of goodwill disclosed on the consolidated balance sheet associated with this reporting unit was recoverable. Therefore, no goodwill impairment was identified or recorded for this reporting unit as a result of our annual goodwill assessment.

Impairment Analysis for the Year Ended December 31, 2016

During February 2016, we determined that continued further weakness in the overall energy sector, driven by low commodity prices together with a further decline in our unit price subsequent to year-end,COVID-19 pandemic, caused a change in circumstances warranting an interim impairment test. Based on these triggering events, we performed a quantitative goodwill impairment analysis on the remaining goodwill in the first quarter of 2016 on allPermian reporting units.unit. Based on this analysis, a goodwill impairment loss for our Texas, Crude and Condensate, and CorporatePermian reporting unitsunit in the amount of $873.3$184.6 million was recognized inas an impairment loss on the consolidated statement of operations for the year ended December 31, 2020. As a result of this impairment loss, we have 0 goodwill remaining as of December 31, 2020.

Goodwill Impairment Analysis for the Year Ended December 31, 2019

During the first quarter of 20162019, we recognized a $186.5 million goodwill impairment related to goodwill that had been reallocated from our Corporate reporting unit to our Louisiana reporting unit as a result of the Merger.

During the fourth quarter of 2019, we performed a quantitative analysis as of October 31, 2019 for our annual goodwill impairment test. Subsequent to October 31, 2019, we determined that due to a significant decline in our common unit price and is included asthe expected reduction in our cash distribution paid to common unitholders, which was announced in January 2020, a change in circumstances had occurred that warranted an additional quantitative impairment test. We recorded a goodwill impairment loss of $125.7 million and $813.4 million in our North Texas and Oklahoma reporting units, respectively. These amounts are
included in impairments in the consolidated statement of operations for the year ended December 31, 2016.

We concluded that the fair value of2019. The goodwill for our North Texas and Oklahoma reporting unit exceeded its carrying value, andunits primarily related to the amount of goodwill disclosed on the consolidated balance sheet associated with this reporting unit was recoverable. Therefore, no goodwill impairment was identified or recorded for thisreallocated from our Corporate reporting unit as a result of our goodwill impairment analysis.the Merger in January 2019.


During our annual impairment test for 2016 performed as
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Impairment Analysis for the Year Ended December 31, 2017Notes to Consolidated Financial Statements (continued)

During our annual impairment test for 2017 performed as of October 31, 2017, we determined that no impairments were required for the year ended December 31, 2017. The estimated fair value of our reporting units may be impacted in the future by a decline in our unit price or a prolonged period of lower commodity prices which may adversely affect our estimate of future cash flows, both of which could result in future goodwill impairment charges for our reporting units.

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 range from 10 to 20 years. The weighted average amortization period for intangible assets is 14.9 years.

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

Gross Carrying AmountAccumulated AmortizationNet Carrying Amount
Year Ended December 31, 2021
Customer relationships, beginning of period$1,794.2 $(668.8)$1,125.4 
Customer relationships obtained from acquisition of business50.6 — 50.6 
Amortization expense— (126.3)(126.3)
Customer relationships, end of period$1,844.8 $(795.1)$1,049.7 
Year Ended December 31, 2020
Customer relationships, beginning of period$1,795.8 $(545.9)$1,249.9 
Amortization expense— (123.5)(123.5)
Retirements (1)(1.6)0.6 (1.0)
Customer relationships, end of period$1,794.2 $(668.8)$1,125.4 
Year Ended December 31, 2019
Customer relationships, beginning of period$1,795.8 $(422.2)$1,373.6 
Amortization expense— (123.7)(123.7)
Customer relationships, end of period$1,795.8 $(545.9)$1,249.9 
____________________________
 Gross Carrying Amount Accumulated Amortization Net Carrying Amount
Year Ended December 31, 2017     
Customer relationships, beginning of period$1,795.8
 $(171.6) $1,624.2
Amortization expense—
 (127.1) (127.1)
Customer relationships, end of period$1,795.8
 $(298.7) $1,497.1
      
Year Ended December 31, 2016     
Customer relationships, beginning of period$744.5
 $(54.6) $689.9
Acquisitions1,051.3
 —
 1,051.3
Amortization expense—
 (117.0) (117.0)
Customer relationships, end of period$1,795.8
 $(171.6) $1,624.2

For 2016 and 2015, we reviewed our various(1)Intangible assets groups for impairment due toretired as a result of the triggering events described in the goodwill impairment analysis above. We utilized Level 3 fair value measurements in our impairment analysis, which included discounted cash flow assumptions by management consistent with those utilized in our goodwill impairment analysis. During 2016, the undiscounted cash flows of our assets exceeded their carrying values, and no impairment was recorded. During 2015, the undiscounted cash flows related to one of our asset groups in the Crude and Condensate segment were not in excess of its related carrying value. We estimated the fair value of this reporting unit and determined the fair valuesdisposition of certain intangible assets were not in excess of their carrying values. This resulted in a $223.1 million impairment of intangible assets in our Crude and Condensate segment, and this non-cash impairment charge was included as an impairment loss on the consolidated statement of operations for the year ended December 31, 2015. For the year ended December 31, 2017, we determined that no triggering events existed that would indicate an impairment of our intangiblesnon-core assets.

The weighted average amortization period for intangible assets is 15.0 years. Amortization expense was approximately $127.1 million, $117.0 million, and $56.0 million for the years ended December 31, 2017, 2016 and 2015, respectively.


The following table summarizes our estimated aggregate amortization expense for the next five years and thereafter (in millions):
2022$127.6 
2023127.6 
2024127.6 
2025110.3 
2026106.4 
Thereafter450.2 
Total$1,049.7 


2018$123.4
2019123.4
2020123.4
2021123.4
2022123.4
Thereafter880.1
Total$1,497.1


(5)(4) Related Party Transactions


We engage in various transactions(a)Transactions with Devon and other related parties. Cedar Cove JV

For the years ended December 31, 2017, 20162021, 2020, and 2015, Devon was a significant customer to us. Devon accounted for 14.4%, 18.5% and 16.6% of our revenues for the years ended December 31, 2017, 2016 and 2015, respectively. We had an accounts receivable balance related to transactions with Devon of $102.7 million and $100.2 million as of December 31, 2017 and 2016, respectively. Additionally, we had an accounts payable balance related to transactions with Devon of $16.3 million and $10.4 million as of December 31, 2017 and 2016, respectively. Management believes these transactions are executed on terms that are fair and reasonable. The amounts from related party transactions are specified in the accompanying financial statements.


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Notes to Consolidated Financial Statements (Continued)

Gathering, Processing and Transportation Agreements Associated with Our Business Combination with Devon

As described in “Note 1—Organization and Summary of Significant Agreements,” Midstream Holdings was previously a wholly-owned subsidiary of Devon, and all of its assets were contributed to it by Devon. On January 1, 2014, in connection with the consummation of the Business Combination, EnLink Midstream Services, LLC, a wholly-owned subsidiary of Midstream Holdings (“EnLink Midstream Services”), entered into 10-year gathering and processing agreements with Devon pursuant to which EnLink Midstream Services provides gathering, treating, compression, dehydration, stabilization, processing and fractionation services, as applicable, for natural gas delivered by Devon Gas Services, L.P., a subsidiary of Devon (“Gas Services”), to Midstream Holdings’ gathering and processing systems in the Barnett, Cana-Woodford and Arkoma-Woodford Shales. On January 1, 2014, SWG Pipeline, L.L.C. (“SWG Pipeline”), another wholly-owned subsidiary of Midstream Holdings, entered into a 10-year gathering agreement with Devon pursuant to which SWG Pipeline provides gathering, treating, compression, dehydration and redelivery services, as applicable, for natural gas delivered by Gas Services to another of our gathering systems in the Barnett Shale.

These agreements provide Midstream Holdings with dedication of all of the natural gas owned or controlled by Devon and produced from or attributable to existing and future wells located on certain oil, natural gas and mineral leases covering land within the acreage dedications, excluding properties previously dedicated to other natural gas gathering systems not owned and operated by Devon. Pursuant to the gathering and processing agreements entered into on January 1, 2014, Devon has committed to deliver specified minimum daily volumes of natural gas to Midstream Holdings’ gathering systems in the Barnett, Cana-Woodford and Arkoma-Woodford Shales during each calendar quarter. We recognized revenue under these agreements of $615.5 million, $611.8 million and $596.3 million for the years ended December 31, 2017, 2016 and 2015, respectively. Included in these amounts of revenue recognized is revenue from MVCs attributable to Devon of $81.9 million, $46.2 million, and $24.4 million for the years ended December 31, 2017, 2016 and 2015, respectively. Devon is entitled to firm service, meaning that if capacity on a system is curtailed or reduced, or capacity is otherwise insufficient, Midstream Holdings will take delivery of as much Devon natural gas as is permitted in accordance with applicable law.

The gathering and processing agreements are fee-based, and Midstream Holdings is paid a specified fee per MMBtu for natural gas gathered on Midstream Holdings’ gathering systems and a specified fee per MMBtu for natural gas processed. The particular fees, all of which are subject to an automatic annual inflation escalator at the beginning of each year, differ from one system to another and do not contain a fee redetermination clause.

In connection with the closing of the Business Combination, Midstream Holdings entered into an agreement with a wholly-owned subsidiary of Devon pursuant to which Midstream Holdings provides transportation services to Devon on its Acacia pipeline.

EnLink Oklahoma T.O. Gathering and Processing Agreement with Devon

In January 2016, in connection with the acquisition of EnLink Oklahoma T.O., we acquired a gas gathering and processing agreement with Devon Energy Production Company, L.P. (“DEPC”) pursuant to which EnLink Oklahoma T.O. provides gathering, treating, compression, dehydration, stabilization, processing and fractionation services, as applicable, for natural gas delivered by DEPC. The agreement has an MVC that will remain in place during each calendar quarter for four years and an overall term of approximately 15 years. Additionally, the agreement provides EnLink Oklahoma T.O. with dedication of all of the natural gas owned or controlled by DEPC and produced from or attributable to existing and future wells located on certain oil, natural gas and mineral leases covering land within the acreage dedications, excluding properties previously dedicated to other natural gas gathering systems not owned and operated by DEPC. DEPC is entitled to firm service, meaning a level of gathering and processing service in which DEPC’s reserved capacity may not be interrupted, except due to force majeure, and may not be displaced by another customer or class of service. This agreement accounted for approximately $100.4 million and $34.4 million of our combined revenues for the years ended December 31, 2017 and 2016, respectively.

Cedar Cove Joint Venture
On November 9, 2016, we formed a joint venture (the “Cedar Cove JV”) with Kinder Morgan, Inc. consisting of gathering and compression assets in Blaine County, Oklahoma. Under a 15-year, fixed-fee agreement, all gas gathered by the Cedar Cove JV will be processed at our Central Oklahoma processing system. For the period from November 9, 2016 through December 31, 2016, revenue generated from processing gas from the Cedar Cove JV was immaterial. For the year ended December 31, 2017, we recorded service revenue of $5.4 million that is recorded as “Midstream services—related parties” on

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

the consolidated statements of operations. In addition, for the year ended December 31, 2017,2019, we recorded cost of sales of $30.6$17.9 million, $8.7 million, $21.7 million, respectively, related to our purchase of residue gas and NGLs from the Cedar Cove JV subsequent to processing at our Central Oklahoma processing facilities.

Other Commercial Relationships Additionally, we had accounts payable balances related to transactions with Devon

As noted above, we continue to maintain a customer relationship with Devon originally established prior to the Business Combination pursuant to which we provide gathering, transportation, processing and gas lift services to Devon in exchange for fee-based compensation under several agreements with Devon. The termsCedar Cove JV of these agreements vary, but the agreements began to expire in January 2016 and continue to expire through July 2021, renewing automatically for month-to-month or year-to-year periods unless canceled by Devon prior to expiration. In addition, we have agreements with Devon pursuant to which we purchase and sell NGLs, gas and crude oil and pay or receive, as applicable, a margin-based fee. These NGL, gas and crude oil purchase and sale agreements have month-to-month terms. These historical agreements collectively comprise $78.0 million, $107.2$1.6 million and $107.5$1.0 million of our combined revenue for the years endedat December 31, 2017, 2016,2021 and 2015,2020, respectively.

VEX Transportation Agreement

In connection with the VEX Drop Down, we became party to a five-year transportation services agreement with Devon pursuant to which we provide transportation services to Devon on the VEX pipeline. This agreement includes a five-year MVC with Devon. The MVC was executed in June 2014, and the initial term expires July 2019. This agreement accounted for approximately $17.8 million, $18.7 million and $17.8 million of service revenues for the years ended December 31, 2017, 2016 and 2015, respectively.

Acacia Transportation Agreement

In connection with the consummation of the Business Combination, we entered into an agreement with a wholly-owned subsidiary of Devon pursuant to which we provide transportation services to Devon on its Acacia line. This agreement accounted for approximately $13.8 million, $15.2 million and $16.4 million of our combined revenues for the years ended December 31, 2017, 2016 and 2015, respectively.

GCF Agreement

In connection with the consummation of the Business Combination, we entered into an agreement with a wholly-owned subsidiary of Devon pursuant to which Devon agreed, from and after the closing of the Business Combination, to hold for the benefit of Midstream Holdings the economic benefits and burdens of Devon’s 38.75% general partner interest in Gulf Coast Fractionators in Mont Belvieu, Texas. This agreement contributed approximately $12.6 million, $3.4 million and $13.0 million to our income from unconsolidated affiliate investment for the years ended December 31, 2017, 2016 and 2015, respectively.

Transactions with ENLK

We paid ENLK $2.4 million, $2.3 million and $2.1 million as reimbursement during the years ended December 31, 2017, 2016, and 2015, respectively, to cover our portion of administrative and compensation costs for officers and employees that perform services for ENLC. This reimbursement is evaluated on an annual basis. Officers and employees that perform services for us provide an estimate of the portion of their time devoted to such services. A portion of their annual compensation (including bonuses, payroll taxes and other benefit costs) is allocated to ENLC for reimbursement based on these estimates. In addition, an administrative burden is added to such costs to reimburse ENLK for additional support costs, including, but not limited to, consideration for rent, office support and information service support.

We paid ENLK $48.4 million and $31.5 million for our interest in EnLink Oklahoma T.O.s’ capital expenditures for the years ended December 31, 2017 and 2016, respectively. We pay our contribution for EnLink Oklahoma T.O.’s capital expenditures to ENLK monthly, net of EnLink Oklahoma T.O.’s adjusted EBITDA distributable to us, which is defined as earnings before depreciation and amortization and provision for income taxes and includes allocated expenses from ENLK.

On October 29, 2015, ENLK issued 2,849,100 common units at an offering price of $17.55 per common unit to a subsidiary of ours for aggregate consideration of approximately $50.0 million in a private placement transaction.


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Notes to Consolidated Financial Statements (Continued)(continued)

(b)Transactions with GIP


Tax Sharing AgreementFor the years endedDecember 31, 2021 and 2020, we recorded general and administrative expenses of $0.5 million and $0.2 million, respectively, related to personnel secondment services provided by GIP. We did not record any expenses related to transactions with GIP for the year ended December 31, 2019.


In connection(c)Transactions with ENLK

On January 25, 2019, we completed the consummationMerger, an internal reorganization pursuant to which ENLC owns all of the Business Combination,outstanding common units of ENLK. See “Note 1—Organization and Nature of Business” for more information on the Merger and related transactions.

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.

(5) Leases

The majority of our leases are for the following types of assets:

•Office space. Our primary offices are in Dallas, Houston, and Midland, with smaller offices in other locations near our assets. Our office leases are long-term in nature and represent $51.8 million of our lease liability and $27.9 million of our right-of-use asset as of December 31, 2021. Our office leases represented $57.6 million of our lease liability and $32.4 million of our right-of-use asset as of December 31, 2020. These office leases typically include variable lease costs related to utility expenses, which are determined based on our pro-rata share of the building expenses each month and expensed as incurred.

•Compression and other field equipment. We pay third parties to provide compressors or other field equipment for our assets. Under these agreements, a third party installs and operates compressor units based on specifications set by us to meet our compression needs at specific locations. While the third party determines which compressors to install and operates and maintains the units, we ENLKhave the right to control the use of the compressors and Devon,are the sole economic beneficiary of the identified assets. These agreements are typically for an initial term of one to three years but will automatically renew from month to month until canceled by us or the lessor. Compression and other field equipment rentals represent $17.7 million of our lease liability and $19.5 million of our right-of-use asset as of December 31, 2021. Compression and other field equipment rentals represented $14.6 million of our lease liability and $14.6 million of our right-of-use asset as of December 31, 2020. Under certain agreements, we may incur variable lease costs related to incidental services provided by the equipment lessor, which are expensed as incurred.

•Land and land easements. We make periodic payments to lease land or to have access to our assets. Land leases and easements are typically long-term to match the expected useful life of the corresponding asset and represent $15.6 million of our lease liability and $12.6 million of our right-of-use asset as of December 31, 2021. Land and land easement leases represented $15.1 million of our lease liability and $12.5 million of our right-of-use asset as of December 31, 2020.

•Other. We rent office equipment and other items that represent $0.1 million of our lease liability and $0.1 million of our right-of-use asset as of December 31, 2021. Office equipment and other items represented $0.3 million of our lease liability and $0.3 million of our right-of-use asset as of December 31, 2020.
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Notes to Consolidated Financial Statements (continued)

Lease balances are recorded on the consolidated balance sheets as follows (in millions):
Operating leases:December 31, 2021December 31, 2020
Other assets, net$60.1 $59.8 
Other current liabilities$18.1 $16.3 
Other long-term liabilities$67.1 $71.3 
Other lease information
Weighted-average remaining lease term—Operating leases10.3 years11.1 years
Weighted-average discount rate—Operating leases4.9 %5.1 %

Certain of our lease agreements have options to extend the lease for a certain period after the expiration of the initial term. We recognize the cost of a lease over the expected total term of the lease, including optional renewal periods that we can reasonably expect to exercise. We do not have material obligations whereby we guarantee a residual value on assets we lease, nor do our lease agreements impose restrictions or covenants that could affect our ability to make distributions.

Lease expense is recognized on the consolidated statements of operations as “Operating expenses” and “General and administrative” depending on the nature of the leased asset. Impairments of right-of-use assets are recognized in “Impairments” on the consolidated statements of operations. The components of total lease expense are as follows (in millions):
Year Ended December 31,
202120202019
Finance lease expense:
Amortization of right-of-use asset$— $— $5.2 
Interest on lease liability— — 0.1 
Operating lease expense:
Long-term operating lease expense21.7 23.1 28.7 
Short-term lease expense17.5 22.1 32.0 
Variable lease expense15.6 11.8 7.7 
Impairments0.2 6.8 — 
Total lease expense$55.0 $63.8 $68.4 

Impairments

Right-of-Use Asset Impairment Analysis for the Year Ended December 31, 2021

During the fourth quarter of 2021, we entered into a tax sharingsublease agreement providingfor a portion of our Houston office that will be effective in 2022. We evaluated the related right-of-use asset for impairment by comparing the estimated fair value of the right-of-use asset to its carrying value. The estimated fair value was calculated using a discounted cash flow analysis that utilized Level 3 inputs, which included future cash flows based on the terms of the sublease and a discount rate derived from market data. As the carrying value of the right-of-use asset exceeded the estimated fair value, we have recognized impairment expense of $0.2 million for the allocation of responsibilities, liabilities and benefits relating to any tax for which a combined tax return is due. For the yearsyear ended December 31, 2017, 20162021.

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Notes to Consolidated Financial Statements (continued)
Right-of-Use Asset Impairment Analysis for the Year Ended December 31, 2020

During the fourth quarter of 2020, we determined that we would cease using a portion of our Dallas, Houston, and 2015Midland offices. We are attempting to sublease the vacated space; however, as we incurred approximately $1.2believe the terms of a sublease would be below our current rental rates, we evaluated the related right-of-use assets for impairment by comparing the estimated fair values of the right-of-use assets to their carrying values. Estimated fair values were calculated using a discounted cash flow analysis that utilized Level 3 inputs, which included estimated future cash flows and a discount rate derived from market data. As the carrying value of each right-of-use asset exceeded its estimated fair value, we recognized impairment expense of $6.8 million $2.3 million and $3.0 million, respectively, in taxes that are subject tofor the tax sharing agreement. year ended December 31, 2020.


Lease Maturities

The following table summarizes the maturity of our lease liability as of December 31, 2021 (in millions):
Total20222023202420252026Thereafter
Undiscounted operating lease liability$115.6 $21.1 $15.3 $10.1 $9.8 $8.9 $50.4 
Reduction due to present value(30.4)(3.7)(3.2)(2.8)(2.4)(2.0)(16.3)
Operating lease liability$85.2 $17.4 $12.1 $7.3 $7.4 $6.9 $34.1 

(6) Long-Term Debt


As of December 31, 20172021 and 2016,2020, long-term debt consisted of the following (in millions):

December 31, 2021December 31, 2020
Outstanding PrincipalPremium (Discount)Long-Term DebtOutstanding PrincipalPremium (Discount)Long-Term Debt
Term Loan due 2021 (1)$— $— $— $350.0 $— $350.0 
Consolidated Credit Facility due 2024 (2)15.0 — 15.0 — — — 
AR Facility due 2024 (3)350.0 — 350.0 250.0 — 250.0 
ENLK’s 4.40% Senior unsecured notes due 2024521.8 0.7 522.5 521.8 1.1 522.9 
ENLK’s 4.15% Senior unsecured notes due 2025720.8 (0.4)720.4 720.8 (0.6)720.2 
ENLK’s 4.85% Senior unsecured notes due 2026491.0 (0.3)490.7 491.0 (0.4)490.6 
ENLC’s 5.625% Senior unsecured notes due 2028500.0 — 500.0 500.0 — 500.0 
ENLC’s 5.375% Senior unsecured notes due 2029498.7 — 498.7 498.7 — 498.7 
ENLK’s 5.60% Senior unsecured notes due 2044350.0 (0.2)349.8 350.0 (0.2)349.8 
ENLK’s 5.05% Senior unsecured notes due 2045450.0 (5.5)444.5 450.0 (5.7)444.3 
ENLK’s 5.45% Senior unsecured notes due 2047500.0 (0.1)499.9 500.0 (0.1)499.9 
Debt classified as long-term$4,397.3 $(5.8)4,391.5 $4,632.3 $(5.9)4,626.4 
Debt issuance costs (4)(27.8)(32.6)
Less: Current maturities of long-term debt (1)— (349.8)
Long-term debt, net of unamortized issuance cost$4,363.7 $4,244.0 
____________________________
(1)Bore interest prior to its maturity based on Prime and/or LIBOR plus an applicable margin. The effective interest rate was 1.7% at December 31, 2020. The Term Loan was repaid at maturity on December 10, 2021. The outstanding principal balance, net of debt issuance costs, was classified as “Current maturities of long-term debt” on the consolidated balance sheet as of December 31, 2020.
(2)Bears interest based on Prime and/or LIBOR plus an applicable margin. The effective interest rate was 3.9% at December 31, 2021.
(3)Bears interest based on LMIR and/or LIBOR plus an applicable margin. The effective interest rate was 1.2% and 2.0% at December 31, 2021 and 2020, respectively.
(4)Net of accumulated amortization of $18.4 million and $14.1 million at December 31, 2021 and 2020, respectively.

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  December 31, 2017 December 31, 2016
  Outstanding Principal Premium (Discount) Long-Term Debt Outstanding Principal Premium (Discount) Long-Term Debt
ENLK credit facility, due 2020 (1) $—
 $—
 $—
 $120.0
 $—
 $120.0
ENLC credit facility, due 2019 (2) 74.6
 —
 74.6
 27.8
 —
 27.8
2.70% Senior unsecured notes due 2019 400.0
 (0.1) 399.9
 400.0
 (0.3) 399.7
7.125% Senior unsecured notes due 2022 —
 —
 —
 162.5
 16.0
 178.5
4.40% Senior unsecured notes due 2024 550.0
 2.2
 552.2
 550.0
 2.5
 552.5
4.15% Senior unsecured notes due 2025 750.0
 (1.0) 749.0
 750.0
 (1.1) 748.9
4.85% Senior unsecured notes due 2026 500.0
 (0.6) 499.4
 500.0
 (0.7) 499.3
5.60% Senior unsecured notes due 2044 350.0
 (0.2) 349.8
 350.0
 (0.2) 349.8
5.05% Senior unsecured notes due 2045 450.0
 (6.5) 443.5
 450.0
 (6.6) 443.4
5.45% Senior unsecured notes due 2047 500.0
 (0.1) 499.9
 —
 —
 —
Debt classified as long-term $3,574.6
 $(6.3) 3,568.3
 $3,310.3
 $9.6
 3,319.9
Debt issuance cost (3)     (26.2)     (24.6)
Long-term debt, net of unamortized issuance cost     $3,542.1
     $3,295.3
ENLINK MIDSTREAM, LLC AND SUBSIDIARIES
(1)
Bears interest based on Prime and/or LIBOR plus an applicable margin. The effective interest rate was 2.3% at December 31, 2016.
Notes to Consolidated Financial Statements (continued)
(2)
Bears interest based on Prime and/or LIBOR plus an applicable margin. The effective interest rate was 3.2%and 3.4% at December 31, 2017 and 2016, respectively.
(3)
Net of amortization of $12.9 million and $9.0 million at December 31, 2017 and 2016, respectively.

Maturities


Maturities for the long-term debt as of December 31, 20172021 are as follows (in millions):
2022$— 
2023— 
2024886.8 
2025720.8 
2026491.0 
Thereafter2,298.7 
Subtotal4,397.3 
Less: net discount(5.8)
Less: debt issuance cost(27.8)
Long-term debt, net of unamortized issuance cost$4,363.7 
2018$—
2019474.6
2020—
2021—
2022—
Thereafter3,100.0
Subtotal3,574.6
Less: net discount(6.3)
Less: debt issuance cost(26.2)
Long-term debt, net of unamortized issuance cost$3,542.1


Term Loan


119
TableOn December 11, 2018, ENLK entered into the Term Loan with Bank of ContentsAmerica, 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. In December 2020, May 2021, and September 2021, we repaid $500.0 million, $100.0 million, and $100.0 million, respectively, of the borrowings under the Term Loan. The remaining $150.0 million of the Term Loan was repaid at maturity on December 10, 2021.
ENLINK MIDSTREAM, LLC
Notes to Consolidated Financial Statements (Continued)

ENLC Credit Facility


 We haveThe Consolidated Credit Facility permits ENLC to borrow up to $1.75 billion on a $250.0 million revolving credit facility that matures on March 7, 2019basis and includes a $125.0$500.0 million letter of credit subfacility (the “ENLCsubfacility. The Consolidated Credit Facility”). OurFacility became available for borrowings and letters of credit upon closing of the Merger. In addition, ENLK became a guarantor under the Consolidated Credit Facility upon the closing of the Merger. In the event that ENLC’s obligations under the ENLCConsolidated Credit Facility are guaranteed by twoaccelerated due to a default, ENLK will be liable for the entire outstanding balance and 105% of our wholly-owned subsidiariesthe outstanding letters of credit under the Consolidated Credit Facility. There was $15.0 million in outstanding borrowings under the Consolidated Credit Facility and secured by first priority liens$41.3 million outstanding letters of credit as of December 31, 2021.

The Consolidated Credit Facility will mature on (i) 88,528,451 ENLK common unitsJanuary 25, 2024, unless ENLC requests, and the 100% membership interest in the General Partner indirectly held by us, (ii) the 100% equity interest in each of our wholly-owned subsidiaries held by us and (iii) any additional equity interests subsequently pledged as collateral under the ENLC Credit Facility.

requisite lenders agree, to extend it pursuant to its terms. The ENLCConsolidated Credit Facility contains certain financial, operational, and legal covenants. The financial covenants are tested on a quarterly basis, based on the rolling four-quarter period that ends on the last day of each fiscal quarter, andquarter. The financial covenants include (i) maintaining a maximumratio of consolidated leverage ratioEBITDA (as defined in the ENLCConsolidated Credit Facility, but generally computed as the ratio of consolidated funded indebtedness to consolidated earnings before interest, taxes, depreciation, amortization andwhich term includes projected EBITDA from certain other non-cash charges) of 4.00 to 1.00, provided that the maximum consolidated leverage ratio is 4.50 to 1.00 during an acquisition period (as defined in the ENLC Credit Facility) and (ii) maintaining a minimum consolidated interest coverage ratio (as defined in the ENLC Credit Facility, but generally computed as the ratio of consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash chargescapital expansion projects) to consolidated interest charges)charges of 2.50no less than 2.5 to 1.00 unless1.0 at all times prior to the occurrence of an investment grade event (as defined in the ENLCConsolidated Credit Facility) occurs.and (ii) maintaining a ratio of consolidated indebtedness to consolidated EBITDA of no more than 5.0 to 1.0.


Under the terms of the Consolidated Credit Facility, if we consummate an acquisition in which the aggregate purchase price is $50.0 million or more, we can elect to increase the maximum allowed ratio of consolidated indebtedness to consolidated EBITDA to 5.5 to 1.0 for the quarter in which the acquisition occurs and the three subsequent quarters. In April 2021, we completed the acquisition of Amarillo Rattler, LLC with an aggregate purchase price in excess of $50.0 million and elected to increase the maximum allowed ratio of consolidated indebtedness to consolidated EBITDA to 5.5 to 1.0 through the first quarter of 2022.

Borrowings under the ENLCConsolidated Credit Facility bear interest at ourENLC’s option at the Eurodollar Rate (the LIBOR Rate)(LIBOR) plus an applicable margin (ranging from 1.75%1.125% to 2.50%2.00%) or the Base Rate (the highest of the Federal Funds Rate plus 0.50%, the 30-day Eurodollar Rate plus 1.0% or the administrative agent’s prime rate) plus an applicable margin (ranging from 0.75% percent 0.125%
to 1.50%1.00%). The applicable margins vary depending on our leverage ratio.ENLC’s debt rating. Upon breach by usENLC of certain covenants governing the ENLCConsolidated Credit Facility, amounts outstanding under the ENLCConsolidated Credit Facility, if any, may become due and payable immediately and the liens securing the ENLC Credit Facility could be foreclosed upon. immediately.
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Notes to Consolidated Financial Statements (continued)

At December 31, 2017, ENLC was2021, we were in compliance with and expectsexpect to be in compliance with the financial covenants inof the ENLCConsolidated Credit Facility for at least the next twelve months.


AR Facility

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

On February 26, 2021, the SPV entered into the first amendment to the AR Facility that, among other things: (i) increased the AR Facility limit and lender commitments by $50.0 million to $300.0 million, (ii) reduced the Adjusted LIBOR and LMIR (each as defined in the AR Facility) minimum floor to 0, rather than the previous 0.375%, and (iii) reduced the effective drawn fee to 1.25% rather than the previous 1.625%.

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

Since our investment in the SPV is not sufficient to finance its activities without additional support from us, the SPV is a variable interest entity. We are the primary beneficiary of the SPV because we have the power to direct the activities that most significantly affect its economic performance and we are obligated to absorb its losses or receive its benefits from operations. Since we are the primary beneficiary of the SPV, we consolidate its assets and liabilities, which consist primarily of billed and unbilled accounts receivable of $773.6 million and long-term debt of $350.0 million as of December 31, 2021.

The amount available for borrowings at any one time under the AR Facility is limited to a borrowing base amount calculated based on the outstanding balance of eligible receivables held as collateral, subject to certain reserves, concentration limits, and other limitations. As of December 31, 2017, there were no outstanding letters2021, the AR Facility had a borrowing base of credit and $74.6 million in outstanding borrowings$350.0 million. Borrowings under the ENLC CreditAR Facility leaving approximately $175.4 million available for future borrowing.

ENLK Credit Facility

ENLK has a $1.5 billion unsecured revolving credit facility that maturesbear interest (based on March 6, 2020, and includes a $500.0 million letter of credit subfacility (the “ENLK Credit Facility”). Under the ENLK Credit Facility, ENLK is permitted to (1) subject to certain conditions and the receipt of additional commitments by oneLIBOR or more lenders, increase the aggregate commitments under the ENLK Credit Facility by an additional amount not to exceed $500.0 million, and (2) subject to certain conditions and the consent of the requisite lenders, on two separate occasions, extend the maturity date of the ENLK Credit Facility by one year on each occasion. The ENLK Credit Facility contains certain financial, operational and legal covenants. Among other things, these covenants include maintaining a ratio of consolidated indebtedness to consolidated EBITDA (which isLMIR (as defined in the ENLK CreditAR Facility) or after a benchmark transition event, the applicable SOFR (as defined in the AR Facility) plus a benchmark replacement adjustment) plus a drawn fee in the amount of 1.10% at December 31, 2021. The SPV also pays a fee on the undrawn committed amount of the AR Facility. Interest and fees payable by the SPV under the AR Facility are due monthly.

The AR Facility is scheduled to terminate on September 24, 2024, unless extended or earlier terminated in accordance with its terms, at which time no further advances will be available and includes projected EBITDA from certain capital expansion projects) ofthe obligations under the AR Facility must be repaid in full by no morelater than 5.0 to 1.0. If ENLK consummates one(i) the date that is ninety (90) days following such date or more acquisitions in(ii) such earlier date on which the aggregate purchase price is $50.0 million or more, ENLK can elect to increase the maximum allowed ratio of consolidated indebtedness to consolidated EBITDA to 5.5 to 1.0 for the quarter of the acquisition and the three following quarters.

Borrowingsloans under the ENLK CreditAR Facility bear interest at ENLK’s option at the Eurodollar Rate (the LIBOR Rate) plus an applicable margin (ranging from 1.00% to 1.75%) or the Base Rate (the highest of the Federal Funds Rate plus 0.50%, the 30-day Eurodollar Rate plus 1.0% or the administrative agent’s prime rate) plus an applicable margin (ranging from 0.0% to 0.75%). The applicable margins vary depending on ENLK’s credit rating. If ENLK breaches certain covenants governing the ENLK Credit Facility, amounts outstanding under the ENLK Credit Facility, if any, may become due and payable immediately. payable.

The AR Facility includes covenants, indemnification provisions, and events of default, including those providing for termination of the AR Facility and the acceleration of amounts owed by the SPV under the AR Facility if, among other things, a borrowing base deficiency exists, there is an event of default under the Consolidated Credit Facility or certain other indebtedness, certain events negatively affecting the overall credit quality of the receivables held as collateral occur, a change of control occurs, or if the consolidated leverage ratio of ENLC exceeds limits identical to those in the Consolidated Credit Facility.

At December 31, 2017, ENLK was2021, we were in compliance with and expect to be in compliance with the financial covenants inof the ENLK Credit ARFacility for at least the next twelve months.


As of December 31, 2017, there were $9.8 million in outstanding letters of credit and no outstanding borrowings under the ENLK Credit Facility, leaving approximately $1.5 billion available for future borrowing.


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Issuances and Redemptions of Senior Unsecured Notes


On March 7, 2014, ENLK recorded $196.5 million in aggregate principal amount of 7.125% senior unsecured notes (the “2022 Notes”) due on June 1, 2022 in the Business Combination. The interest payments on the 2022 Notes were due semi-annually in arrears in June and December. As a result of the Business Combination, the 2022 Notes were recorded at fair value in accordance with acquisition accounting at an amount of $226.0 million, including a premium of $29.5 million. On July 20, 2014, ENLK redeemed $18.5 million aggregate principal amount of the 2022 Notes for $20.0 million, including accrued interest. On September 20, 2014, ENLK redeemed an additional $15.5 million aggregate principal amount of the 2022 Notes for $17.0 million, including accrued interest. On June 1, 2017, ENLK redeemed the remaining $162.5 million in aggregate principal amount of its 2022 Notes at 103.6% of the principal amount, plus accrued unpaid interest, for aggregate cash consideration of $174.1 million, which resulted in a gain on extinguishment of debt of $9.0 million for the year ended December 31, 2017.

On March 19, 2014, ENLK issued $1.2 billion aggregate principal amount of unsecured senior notes, consisting of $400.0 million aggregate principal amount of its 2.700% senior notes due 2019 (the “2019 Notes”), $450.0 million aggregate principal amount of its 4.400% senior notes due 2024 (the “2024 Notes”) and $350.0 million aggregate principal amount of its 5.600% senior notes due 2044 (the “2044 Notes”), at prices to the public of 99.850%, 99.830% and 99.925%, respectively, of their face value. The 2019 Notes mature on April 1, 2019; the 2024 Notes mature on April 1, 2024; and the 2044 Notes mature on April 1, 2044. The interest payments on the 2019 Notes, 2024 Notes and 2044 Notes are due semi-annually in arrears in April and October.

On November 12, 2014, ENLK issued an additional $100.0 million aggregate principal amount of the 2024 Notes and $300.0 million aggregate principal amount of its 5.050% senior notes due 2045 (the “2045 Notes”), at prices to the public of 104.007% and 99.452%, respectively, of their face value. The new 2024 Notes were offered as an additional issue of ENLK’s outstanding 2024 Notes issued on March 19, 2014. The 2024 Notes issued on March 19, 2014 and November 12, 2014 are treated as a single class of debt securities and have identical terms, other than the issue date. The 2045 Notes mature on April 1, 2045, and interest payments on the 2045 Notes are due semi-annually in arrears in April and October.

On May 12, 2015, ENLK issued $900.0 million aggregate principal amount of unsecured senior notes, consisting of $750.0 million aggregate principal amount of its 4.150% senior notes due 2025 (the “2025 Notes”) and an additional $150.0 million aggregate principal amount of 2045 Notes at prices to the public of 99.827% and 96.381%, respectively, of their face value. The 2025 Notes mature on June 1, 2025. Interest payments on the 2025 Notes are due semi-annually in arrears in June and December. The new 2045 Notes were offered as an additional issue of ENLK’s outstanding 2045 Notes issued on November 12, 2014. The 2045 Notes issued on November 12, 2014 and May 12, 2015 are treated as a single class of debt securities and have identical terms, other than the issue date.

On July 14, 2016, ENLK2020, ENLC issued $500.0 million in aggregate principal amount of 4.850%ENLC’s 5.625% senior unsecured notes due 2026January 15, 2028 (the “2026“2028 Notes”) at a price to the public of 99.859%100% of their face value. The 2026 Notes mature on July 15, 2026. Interest payments on the 20262028 Notes are payable on January 15 and July 15 of each year. The 2028 Notes are fully and unconditionally guaranteed by ENLK. Net proceeds of approximately $495.7$494.7 million were used to repay outstandinga portion of the borrowings under the ENLK Credit Facility andTerm Loan, which matured in December 2021.

All interest payments for general partnership purposes.

On May 11, 2017, ENLK issued $500.0 million in aggregate principal amount of 5.450% senior unsecured notes are due June 1, 2047 (the “2047 Notes”) at a pricesemi-annually, in arrears.
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Notes to the public of 99.981% of their face value. Interest payments on the 2047 Notes are payable on June 1 and December 1 of each year, beginning December 1, 2017. Net proceeds of approximately $495.2 million were used to repay outstanding borrowings under the ENLK Credit Facility and for general partnership purposes.Consolidated Financial Statements (continued)


Senior Unsecured NoteNotes Redemption Provisions


Each issuance of the senior unsecured notes may be fully or partially redeemed prior to an early redemption date (see "Early“Early Redemption Date"Date” in table below) at a redemption price equal to the greater of: (i) 100% of the principal amount of the notes to be redeemed; or (ii) the sum of the remaining scheduled payments of principal and interest on the respective notes to be redeemed that would be due after the related redemption date but for such redemption (exclusive of interest accrued to, but excluding the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the applicable Treasury Rate plus a specified basis point premium (see "Basis“Basis Point Premium"Premium” in the table below); plus accrued and unpaid interest to, but excluding, the redemption date. At any time on or after the Early Redemption Date, the senior unsecured notes may be fully or partially redeemed at a redemption price equal to 100% of the

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Notes to Consolidated Financial Statements (Continued)

principal amount of the applicable notes to be redeemed plus accrued and unpaid interest to, but excluding, the redemption date. See applicable redemption provision terms below:


IssuanceMaturity Date of NotesEarly Redemption DateBasis Point Premium
IssuanceMaturity Date of NotesEarly Redemption DateBasis Point Premium
2019 NotesApril 1, 2019Prior to March 1, 201920 Basis Points
2024 NotesApril 1, 2024Prior to January 1, 202425 Basis Points
2025 NotesJune 1, 2025Prior to March 1, 202530 Basis Points
2026 NotesJuly 15, 2026Prior to April 15, 202650 Basis Points
2028 NotesJanuary 15, 2028Prior to July 15, 202750 Basis Points
2029 NotesJune 1, 2029Prior to March 1, 202950 Basis Points
2044 NotesApril 1, 2044Prior to October 1, 204330 Basis Points
2045 NotesApril 1, 2045Prior to October 1, 204430 Basis Points
2047 NotesJune 1, 2047Prior to JuneDecember 1, 2047204640 Basis Points


Senior Unsecured NoteNotes Indentures


The indentures governing the senior unsecured notes contain covenants that, among other things, limit ENLC’s and ENLK’s ability to create or incur certain liens or consolidate, merge, or transfer all or substantially all of ENLC’s and ENLK’s assets.


The indenture governing the 2028 Notes provides that if a Change of Control Triggering Event (as defined in the indenture) occurs, ENLC must offer to repurchase the 2028 Notes at a price equal to 101% of the principal amount of the 2028 Notes, plus accrued and unpaid interest to, but excluding, the date of repurchase.

Each of the following is an event of default under the indentures:


•failure to pay any principal or interest when due;
•failure to observe any other agreement, obligation, or other covenant in the indenture, subject to the cure periods for certain failures; and
•bankruptcy or other insolvency events involving ENLC and ENLK.


If an event of default relating to bankruptcy or other insolvency events occurs, the senior unsecured notes will immediately become due and payable. If any other event of default exists under the indenture, the trustee under the indenture or the holders of the senior unsecured notes may accelerate the maturity of the senior unsecured notes and exercise other rights and remedies. At December 31, 2017,2021, ENLC and ENLK waswere in compliance and expectsexpect to be in compliance with the covenants in the senior unsecured notes for at least the next twelve months.


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Notes to Consolidated Financial Statements (continued)
Senior Unsecured Notes Repurchases

For the year ended December 31, 2020, we and ENLK made aggregate payments to partially repurchase the 2024, 2025, 2026, and 2029 Notes in open market transactions. For the year ended December 31, 2021, we and ENLK did not repurchase any senior notes. Activity related to the 2020 partial repurchases of our outstanding debt consisted of the following (in millions):
Year Ended December 31, 2020
Debt repurchased$67.7 
Aggregate payments(36.0)
Net discount on repurchased debt(0.3)
Accrued interest on repurchased debt0.6 
Gain on extinguishment of debt$32.0 

(7) Income Taxes


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

Year Ended December 31,
202120202019
Current income tax expense$(0.8)$(1.1)$— 
Deferred tax expense(24.6)(142.1)(6.9)
Total income tax expense$(25.4)$(143.2)$(6.9)
 Year Ended December 31,
 2017 2016 2015
Current income tax provision$0.4
 $2.5
 $3.1
Deferred tax provision (benefit)(197.2) 2.1
 22.6
Total income tax provision (benefit)$(196.8) $4.6
 $25.7


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Notes to Consolidated Financial Statements (Continued)


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

Year Ended December 31,
202120202019
Expected income tax benefit (expense) based on federal statutory tax rate$(10.0)$58.5 $233.6 
State income tax benefit (expense), net of federal benefit(1.4)6.5 27.0 
Unit-based compensation (1)(3.1)(6.0)(2.2)
Non-deductible expense related to impairments— (43.4)(264.5)
Statutory rate changes (2)(3)(10.2)— — 
Change in valuation allowance (3)1.7 (153.3)— 
Other(2.4)(5.5)(0.8)
Total income tax expense$(25.4)$(143.2)$(6.9)
____________________________
(1)Related to book-to-tax differences recorded upon the vesting of restricted incentive units.
(2)Effective January 1, 2022, Oklahoma House Bill 2960 resulted in a change in the corporate income tax rate from 6% to 4% and Louisiana Senate Bill No. 159 resulted in a change in the corporate income tax rate from 8% to 7.5%. Accordingly, we recorded deferred tax expense related to our Oklahoma and Louisiana operations in the amount of $7.6 million and $2.6 million, respectively, for the year ended December 31, 2021 due to a remeasurement of deferred tax assets.
(3)Includes the remeasurement of the state deferred tax liabilities, but were partially offset by a change in state apportionment, and its impact on the valuation allowance for the year ended December 31, 2021.

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 Year Ended December 31,
 2017 2016 2015
Expected income tax provision (benefit) based on federal statutory rate of 35%$5.6
 $(159.4) $(116.0)
State income taxes, net of federal benefit0.4
 (11.4) (8.3)
Statutory rate change (1)(210.6) —
 —
Income tax expense from partnership0.9
 1.2
 (0.5)
Unit-based compensation (2)2.9
 —
 —
Non-deductible expense related to asset impairment—
 173.8
 149.4
Other4.0
 0.4
 1.1
Total income tax provision (benefit)$(196.8) $4.6
 $25.7
ENLINK MIDSTREAM, LLC AND SUBSIDIARIES
(1)On December 22, 2017, the Tax Cuts and Jobs Act was signed into legislation which resulted in a change in the federal statutory corporate rate from 35% to 21%, effective January 1, 2018. Accordingly, we have recorded a total tax benefit of $210.6 million due to a remeasurement of deferred tax liabilities. Of this amount, $185.7 million was related to ENLC’s standalone deferred tax liabilities, and $24.9 million was related to ENLK’s re-measurement of deferred tax liabilities of its wholly-owned corporate subsidiaries.
(2)Related to tax deficiencies recorded upon the vesting of restricted incentive units, which were recognized in accordance with the adoption of ASU 2016-09. For additional information on ASU 2016-09, see “Note 2—Significant Accounting Policies.”

Notes to Consolidated Financial Statements (continued)
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. Our deferred income tax assets and liabilities as of December 31, 20172021 and 20162020 are as follows (in millions):

December 31, 2021December 31, 2020
Deferred income tax assets:
Federal net operating loss carryforward$573.6 $488.3 
State net operating loss carryforward59.6 61.0 
Total deferred tax assets, gross633.2 549.3 
Valuation allowance(151.6)(153.3)
Total deferred tax assets, net of valuation allowance481.6 396.0 
Deferred tax liabilities:
Property, plant, equipment, and intangible assets (1)(619.1)(504.6)
Total deferred tax liabilities(619.1)(504.6)
Deferred tax liability, net$(137.5)$(108.6)
____________________________
 December 31, 2017 December 31, 2016
Deferred income tax assets:   
Federal net operating loss carryforward$54.5
 $59.5
State net operating loss carryforward14.2
 6.5
Asset retirement obligations and other—
 0.9
Total deferred tax assets68.7
 66.9
Deferred tax liabilities:   
Property, equipment, and intangible assets (1)(414.9) (609.5)
Deferred tax liability, net$(346.2) $(542.6)
(1)Includes our investment in ENLK and primarily relates to differences between the book and tax bases of property and equipment.

(1)
Includes our investment in ENLK and primarily relates to differences between the book and tax bases of property and equipment.

As a result of the Merger, we acquired all issued and outstanding ENLK common units that were not already held by us or our subsidiaries in exchange for the issuance of ENLC common units. This was a taxable exchange to our unitholders, and we received a step-up in tax basis of the underlying assets acquired. In accordance with ASC 810, Consolidation, the step-up in our basis reduced our deferred tax liability by $399.0 million at the time of the Merger.

As of December 31, 2017,2021, we had federal net operating loss (“NOL”) carryforwards of $259.4 million$2.7 billion that represent a net deferred tax asset of $54.5$573.6 million. As of December 31, 2017,2021, we had state net operating lossNOL carryforwards of $262.7 million$1.3 billion that represent a net deferred tax asset of $14.2$59.6 million. These carryforwards will begin expiring in 2028 through 2036. Management2040. Federal NOLs incurred in 2018 and in future years (approximately $2.5 billion of our federal NOL carryforwards) may be carried forward indefinitely, but the deductibility of such federal NOLs is limited, while federal NOLs incurred prior to 2018 (approximately $0.2 billion of our NOL carryforwards) may be carried forward for only twenty years, but the deductibility of such NOL carryforwards generally is not limited unless we were to undergo a Section 382 “ownership change.”

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 established a valuation allowance of $153.3 million as of December 31, 2020, primarily related to federal and state tax operating loss carryforwards for which we do not believe a tax benefit is more likely than not to be realized. For the year ended December 31, 2021, we recorded a $1.7 million valuation allowance adjustment. As of December 31, 2021, management believes that it is more likely than not that the future results of operationsCompany will generate sufficient taxable income to utilize these net operating loss carryforwards before they expire.


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A reconciliationrealize the benefits of the beginningdeferred tax assets, net of valuation allowance.

For the years ended December 31, 2021 and ending amount of2020, there was 0 recorded unrecognized tax benefits is as follows (in millions):

 Year Ended December 31,
 2017 2016 2015
Beginning Balance, January 1$—
 $1.5
 $2.0
Decrease due to prior year tax positions—
 (1.5) (0.5)
Ending Balance, December 31$—
 $—
 $1.5

benefit. Per our accounting policy election, penalties and interest related to unrecognized tax benefits are recorded to income tax expense. As of December 31, 2017,2021, tax years 20132017 through 20172021 remain subject to examination by various taxing authorities.


(8) Certain Provisions of the Partnership Agreement


(a) Issuance of ENLK Common Units

In November 2014, ENLK entered into an Equity Distribution Agreement (the “2014 EDA”) with BMO Capital Markets Corp., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Citigroup Global Markets Inc., Jefferies LLC, Raymond James & Associates, Inc. and RBC Capital Markets, LLC to sell up to $350.0 million in aggregate gross sales of ENLK’s common units from time to time through an “at the market” equity offering program.

For the year ended December 31, 2015, ENLK sold an aggregate of 1.3 million common units under the 2014 EDA, generating proceeds of approximately $24.4 million (net of approximately $0.3 million of commissions). For the year ended December 31, 2016, ENLK sold an aggregate of 10.0 million common units under the 2014 EDA, generating proceeds of approximately $167.5 million (net of approximately $1.7 million of commissions).

In August 2017, ENLK ceased trading under the 2014 EDA and entered into an Equity Distribution Agreement (the “2017 EDA”) with UBS Securities LLC, Barclays Capital Inc., BMO Capital Markets Corp., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Citigroup Markets Inc., Jefferies LLC, Mizuho Securities USA LLC, RBC Capital Markets, LLC, SunTrust Robinson Humphrey, Inc. and Wells Fargo Securities, LLC (collectively, the “Sales Agents”) to sell up to $600.0 million in aggregate gross sales of ENLK’s common units from time to time through an “at the market” equity offering program. ENLK may also sell common units to any Sales Agent as principal for the Sales Agent’s own account at a price agreed upon at the time of sale. ENLK has no obligation to sell any of the common units under the 2017 EDA and may at any time suspend solicitation and offers under the 2017 EDA.

For the year ended December 31, 2017, ENLK sold an aggregate of approximately 6.2 million common units under the 2014 EDA and the 2017 EDA, generating proceeds of approximately $106.9 million (net of approximately $1.1 million of commissions and $0.2 million of registration fees). ENLK used the net proceeds for general partnership purposes. As of December 31, 2017, approximately $565.4 million remains available to be issued under the 2017 EDA.

On October 29, 2015, ENLK issued 2,849,100 common units at an offering price of $17.55 per unit to a subsidiary of ENLC for aggregate consideration of approximately $50.0 million in a private placement transaction.

As explained in “Note 1—Organization and Summary of Significant Agreements,” in 2015, Acacia contributed its remaining 50% interest in Midstream Holdings to ENLK in exchange for 68.2 million units of ENLK common units in the EMH Drop Downs.

(b) Class C Common Units

In March 2015, ENLK issued 6,704,285 Class C Common Units representing a new class of limited partner interests as partial consideration for the acquisition of Coronado. The Class C Common Units were substantially similar in all respects to ENLK’s common units, except that distributions paid on the Class C Common Units could be paid in cash or in additional Class C Common Units issued in kind, as determined by our general partner in its sole discretion. Distributions on the Class C Common Units for the three months ended March 31, 2015, June 30, 2015, and September 30, 2015 were paid-in-kind through the issuance of 99,794, 120,622, and 150,732 Class C Common Units on May 14, 2015, August 13, 2015, and November 12, 2015, respectively. Distributions on the Class C Common Units for the three months ended December 31, 2015 and March 31,

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2016 were paid-in-kind through the issuance of 209,044 and 233,107 Class C Common Units on February 11, 2016 and May 12, 2016, respectively. All of the outstanding Class C Common Units were converted into common units on a one-for-one basis on May 13, 2016.

(c) ENLK Series B Preferred Units


Issuance and Ownership

In January 2016, ENLK issued an aggregate of 50,000,000 Series B Preferred Units representing ENLK limited partner interests to Enfield Holdings, L.P. (“Enfield”) in a private placement for a cash purchase price of $15.00 per Series B Preferred Unit (the “Issue Price”), resulting. On August 4, 2021, Enfield Holdings, L.P. (“Enfield”) sold all of its Series B Preferred Units and ENLC Class C Common
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Notes to Consolidated Financial Statements (continued)
Units representing limited liability company interests in net proceedsENLC to Brookfield Infrastructure Partners L.P. and funds managed by Oaktree Capital Management, L.P.

Redemption

In December 2021, we redeemed 3,300,330 Series B Preferred Units for total consideration of approximately $724.1$50.0 million after fees and deductions. Proceeds from the private placementplus accrued distributions. In addition, upon such redemption, a corresponding number of ENLC Class C Common Units were used to partially fund ENLK’s portionautomatically cancelled. The redemption price represents 101% of the purchase price payable inpreferred units’ par value. In connection with the acquisition of our EnLink Oklahoma T.O. assets. AffiliatesSeries B Preferred Unit redemption, we have agreed with the holders of the Goldman Sachs Group, Inc.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.

Conversion and affiliates of TPG Global, LLC own interests in the general partner of Enfield. The Distributions

Series B Preferred Units are convertible into ENLKexchangeable for ENLC common units on a one-for-one basis,in an amount equal to the number of outstanding Series B Preferred Units outstanding multiplied by the exchange ratio of 1.15, subject to certain adjustments (a) in full, at(the “Series B Exchange Ratio”). The exchange is subject to ENLK’s option ifto pay cash instead of issuing additional ENLC common units, and can occur in whole or in part at the volume weightedoption of the holder of the Series B Preferred Units at any time, or in whole at our option, provided the daily volume-weighted average closing price of athe ENLC common unit overunits for the 30-trading day period30 trading days ending two trading days prior to the conversion date (the “Conversion VWAP”)exchange is greater than 150% of the Issue Price or (b) in full or in part, at Enfield’s option. In addition, upon certain events involving a changedivided by the conversion ratio of control of ENLK’s general partner or the managing member of ENLC, all1.15.

The holder of the Series B Preferred Units will automatically convert into a number of ENLK common units equalis entitled to the greater of (i) the number of ENLK common units into which the Series B Preferred Units would then convertquarterly cash distributions and (ii) the number of Series B Preferred Units to be converted multiplied by an amount equal to (x) 140% of the Issue Price divided by (y) the Conversion VWAP.

For each of the calendar quarters between March 31, 2016 through June 30, 2017, Enfield received a quarterly distribution equal to an annual rate of 8.5% on the Issue Price payabledistributions in-kind in the form of additional Series B Preferred Units. For the quarter ended September 30, 2017 and each subsequent quarter, Enfield received or is entitled to receive aThe quarterly distribution, subject to certain adjustments, equal to an annual rate of 7.5% on the Issue Price payable in cash (the “Cash Distribution Component”) plus an in-kind distribution equal to(the “Series B PIK Distribution”) equals the greater of (A) 0.0025 Series B Preferred Units per Series B Preferred Unit and (B) an amountthe number of Series B Preferred Units equal to (i)the quotient of (x) the excess if any,(if any) of (1) the distribution that would have been payable by ENLC had the Series B Preferred Units converted into ENLKbeen exchanged for ENLC common units but applying a one-to-one exchange ratio (subject to certain adjustments) instead of the Series B Exchange Ratio, over (2) $0.28125 per Series B Preferred Unit (the “Cash Distribution Component”), divided by (y) the Issue Price. Except as described above with respect to distributions made until the distribution declared for the fourth quarter of 2022, the quarterly cash distribution (the “Series B Cash Distribution”) consists of the Cash Distribution Component divided byplus an amount in cash that will be determined based on a comparison of the value (applying the Issue Price) of (i) the Series B PIK Distribution and (ii) the Issue Price.Series B Preferred Units that would have been distributed in the Series B PIK Distribution if such calculation applied the Series B Exchange Ratio instead of the one-to-one ratio (subject to certain adjustments).


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Notes to Consolidated Financial Statements (continued)
A summary of the distribution activity relating to the Series B Preferred Units for the years ended December 31, 20172021, 2020, and 20162019 is provided below:
Declaration periodDistribution
paid as additional Series B Preferred Units		Cash distribution
(in millions)		Date paid/payable
2021
First Quarter of 2021150,871 $17.0 May 14, 2021
Second Quarter of 2021151,248 $17.0 August 13, 2021
Third Quarter of 2021151,626 $17.1 November 12, 2021
Fourth Quarter of 2021— $19.2 February 11, 2022 (1)
2020
First Quarter of 2020149,371 $16.8 May 13, 2020
Second Quarter of 2020149,745 $16.8 August 13, 2020
Third Quarter of 2020150,119 $16.9 November 13, 2020
Fourth Quarter of 2020150,494 $16.9 February 12, 2021
2019
First Quarter of 2019147,887 $16.7 May 14, 2019
Second Quarter of 2019148,257 $17.1 August 13, 2019
Third Quarter of 2019148,627 $17.1 November 13, 2019
Fourth Quarter of 2019148,999 $16.8 February 13, 2020
Declaration period Distribution
paid as additional Series B Preferred Units		 Cash distribution
(in millions)		 Date paid/payable
2017      
First Quarter of 2017 1,154,147
 $—
 May 12, 2017
Second Quarter of 2017 1,178,672
 $—
 August 11, 2017
Third Quarter of 2017 410,681
 $15.9
 November 13, 2017
Fourth Quarter of 2017 413,658
 $16.1
 February 13, 2018
       
2016      
First Quarter of 2016 992,445
 $—
 May 12, 2016
Second Quarter of 2016 1,083,589
 $—
 August 11, 2016
Third Quarter of 2016 1,106,616
 $—
 November 10, 2016
Fourth Quarter of 2016 1,130,131
 $—
 February 13, 2017
____________________________

(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. The remaining distribution of $17.3 million related to the fourth quarter of 2021 will be payable February 11, 2022. See “Note 18—Subsequent Event” for more information regarding the January 2022 Series B Preferred Unit redemption.


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Notes to Consolidated Financial Statements (Continued)

(d) ENLK(b) Series C Preferred Units


In September 2017, ENLK issued 400,000 Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the “Series C Preferred Units”) representing ENLK limited partner interests at a price to the public of $1,000 per unit. ENLK used the net proceeds of $394.0 million for capital expenditures, general partnership purposes and to repay borrowings under the ENLK Credit Facility. The Series C Preferred Units represent perpetual equity interests in ENLK and, unlike ENLKENLK’s indebtedness, will not give rise to a claim for payment of a principal amount at a particular date. As to the payment of distributions and amounts payable on a liquidation event, the Series C Preferred Units rank senior to ENLK’s common units and to each other class of limited partner interests or other equity securities established after the issue date of the Series C Preferred Units that is not expressly made senior or on parity with the Series C Preferred Units. The Series C Preferred Units rank junior to the Series B Preferred Units with respect to the payment of distributions, and junior to the Series B Preferred Units and all current and future indebtedness with respect to amounts payable upon a liquidation event.


At any time on or after December 15, 2022, ENLK may redeem, at ENLK’s option, in whole or in part, the Series C Preferred Units at a redemption price in cash equal to $1,000 per Series C Preferred Unit plus an amount equal to all accumulated and unpaid distributions, whether or not declared. ENLK may undertake multiple partial redemptions. In addition, at any time within 120 days after the conclusion of any review or appeal process instituted by ENLK following certain rating agency events, ENLK may redeem, at ENLK’s option, the Series C Preferred Units in whole at a redemption price in cash per unit equal to $1,020 plus an amount equal to all accumulated and unpaid distributions, whether or not declared.


Distributions on the Series C Preferred Units accrue and are cumulative from the date of original issue and payable semi-annually in arrears on the 15th day of June and December of each year through and including December 15, 2022 and, thereafter, quarterly in arrears on the 15th day of March, June, September, and December of each year, in each case, if and when declared by ENLK’s general partnerthe General Partner out of legally available funds for such purpose. The initial distribution rate for the Series C Preferred Units from and including the date of original issue to, but not including, December 15, 2022 is 6.0% per annum. On and after December 15, 2022, distributions on the Series C Preferred Units will accumulate for each distribution period at a percentage of the $1,000 liquidation preference per unit equal to an annual floating rate of the three-month LIBOR plus a spread
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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES
Notes to Consolidated Financial Statements (continued)
of 4.11%. For each of the years ended December 31, 2021, 2020, and 2019, ENLK made distributions of $24.0 million to the holders of Series C Preferred Units.

(9) 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 year ended December 31, 2017, ENLK made distributions2021, ENLC repurchased 6,091,001 outstanding ENLC common units for an aggregate cost, including commissions, of $5.6$40.1 million, or an average of $6.59 per common unit. For the year ended December 31, 2020, ENLC repurchased 383,614 outstanding ENLC common units for an aggregate cost, including commissions, of $1.2 million, or an average of $3.02 per common unit.

(b) Issuance of ENLC Common Units related to holders of Series C Preferred Units.the Merger


(e) ENLK Common Unit Distributions

Unless restricted byIn connection with the termsconsummation of the Merger, we issued 304,822,035 ENLC common units in exchange for all of the outstanding ENLK Credit Facility and/orcommon units not previously owned by us.

(c) ENLC Equity Distribution Agreement

On February 22, 2019, ENLC entered into the indentures governing ENLK’s senior unsecured notes, ENLK must make distributions of 100% of available cash, as defined in the partnership agreement, within 45days following the end of each quarter. Distributions are made to the General Partner in accordance with its current percentage interestENLC EDA with the remainderENLC Sales Agents to the common unitholders, subjectsell up to the payment$400.0 million in aggregate gross sales of incentive distributions as described below to the extent that certain target levels of cash distributions are achieved. The General Partner was not entitled to its incentive distributions with respect to the Class C Common Units issued in kind. In addition, the general partner is not entitled to its incentive distributions with respect to (i) distributions on the Series B Preferred Units until such units convert intoENLC common units or (ii)from time to time through an “at the Series C Preferred Units.

The General Partner ownsmarket” equity offering program. Under the general partner interest in ENLK and all of our incentive distribution rights. The General Partner is entitled to receive incentive distributions if the amount ENLK distribute with respectENLC EDA, ENLC may also sell common units to any quarter exceeds levels specified in its partnership agreement. UnderENLC Sales Agent as principal for the quarterly incentive distribution provisions,ENLC Sales Agent’s own account at a price agreed upon at the General Partner is entitledtime of sale. ENLC has no obligation to 13.0%sell any ENLC common units under the ENLC EDA and may at any time suspend solicitation and offers under the ENLC EDA. As of amounts ENLK distributes in excess of $0.25 per unit, 23.0% ofFebruary 9, 2022, ENLC has not sold any common units under the amounts ENLK distributes in excess of $0.3125 per unit and 48.0% of amounts ENLK distributes in excess of $0.375 per unit.ENLC EDA.



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Notes to Consolidated Financial Statements (Continued)(continued)

A summary of ENLK’s distribution activity relating to the common units for the years ended December 31, 2017, 2016 and 2015 is provided below:
Declaration period Distribution/unit Date paid/payable
2017    
First Quarter of 2017 $0.390
 May 12, 2017
Second Quarter of 2017 $0.390
 August 11, 2017
Third Quarter of 2017 $0.390
 November 13, 2017
Fourth Quarter of 2017 $0.390
 February 13, 2018
     
2016    
First Quarter of 2016 $0.390
 May 12, 2016
Second Quarter of 2016 $0.390
 August 11, 2016
Third Quarter of 2016 $0.390
 November 11, 2016
Fourth Quarter of 2016 $0.390
 February 13, 2017
     
2015    
First Quarter of 2015 $0.380
 May 14, 2015
Second Quarter of 2015 $0.385
 August 13, 2015
Third Quarter of 2015 $0.390
 November 12, 2015
Fourth Quarter of 2015 $0.390
 February 11, 2016

(f) Allocation of Partnership Income

Net income is allocated to the General Partner in an amount equal to its incentive distribution rights as described in section “(e) ENLK Common Unit Distributions” above. The General Partner’s share of net income consists of incentive distribution rights to the extent earned, a deduction for unit-based compensation attributable to ENLC’s restricted units and the percentage interest of ENLK’s net income adjusted for ENLC’s unit-based compensation specifically allocated to the General Partner and net income attributable to the drop down transactions described in “Note 1—Organization and Summary of Significant Agreements.” The net income allocated to the General Partner is as follows (in millions):

 Year Ended December 31,
 2017 2016 2015
Income allocation for incentive distributions$58.9
 $56.8
 $47.5
Unit-based compensation attributable to ENLC’s restricted units(21.0) (14.7) (18.3)
General partner share of net income (loss)0.4
 (2.6) (6.7)
General partner interest in drop down transactions—
 —
 35.5
General partner interest in net income$38.3
 $39.5
 $58.0


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Notes to Consolidated Financial Statements (Continued)

(9) Members' Equity

(a)(d) 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):

Year Ended December 31,
202120202019
Distributed earnings allocated to:
Common units (1)$192.5 $183.5 $479.0 
Unvested restricted units (1)4.5 3.1 5.7 
Total distributed earnings$197.0 $186.6 $484.7 
Undistributed loss allocated to:
Common units$(170.6)$(598.4)$(1,584.8)
Unvested restricted units(4.0)(9.7)(19.2)
Total undistributed loss$(174.6)$(608.1)$(1,604.0)
Net income (loss) attributable to ENLC allocated to:
Common units$21.9 $(414.9)$(1,105.8)
Unvested restricted units0.5 (6.6)(13.5)
Total net income (loss) attributable to ENLC$22.4 $(421.5)$(1,119.3)
Basic and diluted net income (loss) per unit attributable to ENLC:
Basic$0.05 $(0.86)$(2.41)
Diluted$0.05 $(0.86)$(2.41)
____________________________
 Year Ended December 31,
 2017 2016 2015
EnLink Midstream, LLC interest in net income (loss)$212.8
 $(460.0) $(357.0)
Distributed earnings allocated to:     
Common units (1)$184.8
 $183.3
 $165.0
Unvested restricted units (1)2.5
 2.2
 1.1
Total distributed earnings$187.3
 $185.5
 $166.1
Undistributed income (loss) allocated to:     
Common units$25.2
 $(638.0) $(519.5)
Unvested restricted units0.3
 (7.5) (3.6)
Total undistributed income (loss)$25.5
 $(645.5) $(523.1)
Net income (loss) allocated to:     
Common units$210.0
 $(454.6) $(354.5)
Unvested restricted units2.8
 (5.4) (2.5)
Total net income (loss)$212.8
 $(460.0) $(357.0)
Basic and diluted net income (loss) per unit:     
Basic$1.18
 $(2.56) $(2.17)
Diluted$1.17
 $(2.56) $(2.17)
(1)Represents distribution activity consistent with the distribution activity table below.
(1)Represents distribution activity consistent with the distribution activity table below.


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

Year Ended December 31,
202120202019
Basic weighted average units outstanding:
Weighted average common units outstanding488.8 489.3 463.9 
Diluted weighted average units outstanding:
Weighted average basic common units outstanding488.8 489.3 463.9 
Dilutive effect of non-vested restricted units (1)5.5 — — 
Total weighted average diluted common units outstanding494.3 489.3 463.9 
____________________________
 Year Ended December 31,
 2017 2016 2015
Basic weighted average units outstanding:     
Weighted average common units outstanding180.5
 179.7
 164.2
      
Diluted weighted average units outstanding:     
Weighted average basic common units outstanding180.5
 179.7
 164.2
Dilutive effect of restricted units issued (1)1.3
 —
 —
Total weighted average diluted common units outstanding181.8
 179.7
 164.2
(1)For the years ended December 31, 2020 and 2019, all common unit equivalents were antidilutive because a net loss existed for those periods.
(1)For the years ended December 31, 2016 and 2015, all common units were antidilutive because 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.



128
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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)(continued)

(b)(e) Distributions


A summary of our distribution activity relatingrelated to the ENLC common units for the years ended December 31, 2017, 20162021, 2020, and 2015,2019, respectively, is provided below:

Declaration periodDistribution/unitDate paid/payable
2021
First Quarter of 2021$0.09375 May 14, 2021
Second Quarter of 2021$0.09375 August 13, 2021
Third Quarter of 2021$0.09375 November 12, 2021
Fourth Quarter of 2021$0.11250 February 11, 2022
2020
First Quarter of 2020$0.09375 May 13, 2020
Second Quarter of 2020$0.09375 August 13, 2020
Third Quarter of 2020$0.09375 November 13, 2020
Fourth Quarter of 2020$0.09375 February 12, 2021
2019
First Quarter of 2019$0.279 May 14, 2019
Second Quarter of 2019$0.283 August 13, 2019
Third Quarter of 2019$0.283 November 13, 2019
Fourth Quarter of 2019$0.1875 February 13, 2020

128
Declaration period Distribution/unit Date paid/payable
2017    
First Quarter of 2017 $0.255
 May 15, 2017
Second Quarter of 2017 $0.255
 August 14, 2017
Third Quarter of 2017 $0.255
 November 14, 2017
Fourth Quarter of 2017 $0.259
 February 14, 2018
     
2016    
First Quarter of 2016 $0.255
 May 13, 2016
Second Quarter of 2016 $0.255
 August 12, 2016
Third Quarter of 2016 $0.255
 November 14, 2016
Fourth Quarter of 2016 $0.255
 February 14, 2017
     
2015    
First Quarter of 2015 $0.245
 May 15, 2015
Second Quarter of 2015 $0.250
 August 14, 2015
Third Quarter of 2015 $0.255
 November 13, 2015
Fourth Quarter of 2015 $0.255
 February 12, 2016

(10) Asset Retirement Obligations

The schedule below summarizes the changes in our asset retirement obligations (in millions):
 Year Ended December 31,
 2017 2016
Balance, beginning of period$13.5
 $14.0
Revisions to the fair values of existing liabilities—
 (0.5)
Accretion expense0.7
 0.6
Liabilities settled—
 (0.6)
Balance, end of period$14.2
 $13.5

Asset retirement obligations of $14.2 million and $13.5 million were included in “Asset retirement obligations” as non-current liabilities on the consolidated balance sheets as of December 31, 2017 and 2016, respectively.

(11) Investment in Unconsolidated Affiliates

Our unconsolidated investments consisted of:

a contractual right to the economic benefits and burdens associated with Devon’s 38.75% ownership interest in GCF at December 31, 2017, 2016 and 2015;

an approximate 30.0% ownership in the Cedar Cove JV at December 31, 2017 and 2016. On November 9, 2016, we formed the Cedar Cove JV with Kinder Morgan, Inc., which consists of gathering and compression assets in Blaine County, Oklahoma, the heart of the Sooner Trend Anadarko Basin Canadian and Kingfisher Counties play; and

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Notes to Consolidated Financial Statements (Continued)(continued)

(10) Investment in Unconsolidated Affiliates


an approximate 31% ownership interest in Howard Energy Partners (“HEP”) atAs of December 31, 20162021, our unconsolidated investments consisted of a 38.75% ownership in GCF and 2015, which was solda 30% ownership in March 2017 for aggregate net proceeds of $189.7 million.

the Cedar Cove JV. The following table shows the activity related to our investment in unconsolidated affiliates for the periods indicated (in millions):
Year Ended December 31,
202120202019
GCF
Distributions$3.5 $1.6 $19.2 
Equity in income (loss)$(9.1)$3.0 $16.5 
Cedar Cove JV
Distributions$0.4 $0.5 $1.0 
Equity in loss (1)$(2.4)$(2.4)$(33.3)
Total
Distributions$3.9 $2.1 $20.2 
Equity in income (loss) (1)$(11.5)$0.6 $(16.8)
  Year Ended December 31,
  2017 2016 2015
Gulf Coast Fractionators      
Contributions $—
 $—
 $—
Distributions $12.7
 $7.5
 $14.5
Equity in income $12.6
 $3.4
 $13.0
       
Howard Energy Partners      
Contributions (1) $—
 $45.0
 $25.8
Distributions (2) $—
 $50.2
 $28.2
Equity in income (loss) (3) $(3.4) $(23.3) $7.4
       
Cedar Cove JV      
Contributions $12.6
 $28.8
 $—
Distributions $0.8
 $—
 $—
Equity in income $0.4
 $—
 $—
       
Total      
Contributions (1) $12.6
 $73.8
 $25.8
Distributions (2) $13.5
 $57.7
 $42.7
Equity in income (loss) (3) $9.6
 $(19.9) $20.4
___________________________
(1)Includes a loss of $31.4 million for the year ended December 31, 2019 related to the impairment of the carrying value of the Cedar Cove JV, as we determined that the carrying value of our investment was not recoverable based on the forecasted cash flows from the Cedar Cove JV.
(1)Contributions for the year ended December 31, 2016 included $32.7 million of contributions to HEP for preferred units issued by HEP. These preferred units were redeemed during the third quarter 2016.
(2)Distributions for the year ended December 31, 2016 included a redemption of $32.7 million of preferred units issued by HEP.
(3)Included losses of $3.4 million and $20.1 million for the years ended December 31, 2017 and 2016, respectively, related to the sale of our HEP interests.


The following table shows the balances related to our investment in unconsolidated affiliates as of December 31, 20172021 and 20162020 (in millions):
December 31, 2021December 31, 2020
GCF$28.0 $40.6 
Cedar Cove JV (1)(1.8)1.0 
Total investment in unconsolidated affiliates$26.2 $41.6 
 December 31, 2017 December 31, 2016
Gulf Coast Fractionators$48.4
 $48.5
Howard Energy Partners (1)—
 193.1
Cedar Cove JV41.0
 28.8
Total investments in unconsolidated affiliates$89.4
 $270.4
___________________________
(1)As of December 31, 2021, our investment in the Cedar Cove JV is classified as “Other long-term liabilities” on the consolidated balance sheet.

(1)
Due to the completion of the sale of our investment in HEP in the first quarter of 2017, the HEP investment balance was classified as “Investment in unconsolidated affiliates—current” on the consolidated balance sheet as of December 31, 2016.


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

(12)(11) Employee Incentive Plans


(a) Long-Term Incentive Plans

ENLC and ENLK each have similar unit-based compensation payment plans for officers and employees. ENLC grants unit-based awards under the EnLink Midstream, LLC 2014 Long-Term Incentive Plan (the “2014 Plan”), and ENLK grants unit-based awards under the amended and restated EnLink Midstream GP, LLC Long-Term Incentive Plan (the “GP Plan”).


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. Unit-based compensation associated with ENLC’s unit-based compensation plan awarded to ourdirectors, officers, and employees of the General Partner is recorded by ENLK since ENLC has no substantial or managed operating activities other than its interestinterests in ENLK and EnLink Oklahoma T.O.ENLK.

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Notes to Consolidated Financial Statements (continued)

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

Year Ended December 31,
202120202019
Cost of unit-based compensation charged to general and administrative expense$18.7 $21.3 $32.7 
Cost of unit-based compensation charged to operating expense6.6 7.1 6.7 
Total unit-based compensation expense$25.3 $28.4 $39.4 
Non-controlling interest in unit-based compensation$— $— $0.5 
Amount of related income tax benefit recognized in net income (loss) (1)$5.9 $6.7 $9.1 
____________________________
  Year Ended December 31,
  2017 2016 2015
Cost of unit-based compensation charged to general and administrative expense $37.4
 $23.7
 $31.1
Cost of unit-based compensation charged to operating expense 10.7
 6.6
 5.0
Total unit-based compensation expense $48.1
 $30.3
 $36.1
Non-controlling interest in unit-based compensation $18.0
 $11.3
 $14.0
Amount of related income tax benefit recognized in net income (1) $11.3
 $7.1
 $8.3
(1)For the years ended December 31, 2021, 2020, and 2019 the amount of related income tax benefit recognized in net income (loss) excluded $3.1 million, $6.0 million, and $2.2 million of income tax expense, respectively, related to book-to-tax differences recorded upon vesting of restricted units.
(1)For the year ended December 31, 2017, the amount of related income tax benefit recognized in net income excluded $2.9 million of income tax expense related to tax deficiencies recorded on vested units.


(b) EnLink Midstream Partners, LP’sENLC Restricted Incentive Units


ENLKENLC restricted incentive units arewere valued at their fair value at the date of grant, which is equal to the market value of the ENLKENLC common units on such date. A summary of the restricted incentive unit activity for the year ended December 31, 20172021 is provided below:

Year Ended December 31, 2021
ENLC Restricted Incentive Units:Number of UnitsWeighted Average Grant-Date Fair Value
Non-vested, beginning of period5,350,086 $8.45 
Granted (1)3,937,301 3.86 
Vested (1)(2)(1,268,801)12.85 
Forfeited(511,115)6.10 
Non-vested, end of period7,507,471 $5.46 
Aggregate intrinsic value, end of period (in millions)$51.7  
____________________________
  Year Ended December 31, 2017
EnLink Midstream Partners, LP Restricted Incentive Units: Number of Units 
Weighted Average
Grant-Date Fair Value
Non-vested, beginning of period 2,024,820
 $19.05
Granted (1) 870,088
 18.38
Vested (1)(2) (873,229) 25.85
Forfeited (41,455) 16.53
Non-vested, end of period 1,980,224
 $15.81
Aggregate intrinsic value, end of period (in millions) $30.4
  
(1)Restricted incentive units typically vest at the end of three years.
(1)
Restricted incentive units typically vest at the end of three years. In March 2017, the General Partner granted 262,288 restricted incentive units with a fair value of $5.1 million to officers and certain employees as bonus payments for 2016, and these restricted incentive units vested immediately and are included in the restricted incentive units granted and vested line items.
(2)
Vested units include 279,827 units withheld for payroll taxes paid on behalf of employees.

(2)Vested units included 382,343 units withheld for payroll taxes paid on behalf of employees.


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Notes to Consolidated Financial Statements (Continued)

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) duringfor the years ended December 31, 2017, 20162021, 2020, and 20152019 is provided below (in millions):

Year Ended December 31,
ENLC Restricted Incentive Units:202120202019
Aggregate intrinsic value of units vested$5.6 $12.1 $17.3 
Fair value of units vested$16.3 $31.5 $22.8 
  Year Ended December 31,
EnLink Midstream Partners, LP Restricted Incentive Units: 2017 2016 2015
Aggregate intrinsic value of units vested $16.6
 $4.1
 $7.5
Fair value of units vested $22.6
 $9.5
 $8.1


As of December 31, 2017,2021, there was $11.6were $13.0 million of unrecognized compensation costcosts that related to non-vested ENLKENLC restricted incentive units. That cost isThese costs are expected to be recognized over a weighted-averageweighted average period of 1.71.6 years.


For restricted incentive unit awards granted to certain officers and employees (the “grantee”), such awards (the “Subject Grants”) generally provide that, subject to the satisfaction of the conditions set forth in the agreement, the Subject Grants will vest on the third anniversary of the vesting commencement date (the “Regular Vesting Date”). The Subject Grants will be forfeited if the grantee’s employment or service with ENLC and its affiliates terminates prior to the Regular Vesting Date except that the Subject Grants will vest in full or on a pro-rated basis for certain terminations of employment or service prior to the Regular Vesting Date. For instance, the Subject Grants will vest on a pro-rated basis for any terminations of the grantee’s employment: (i) due to retirement, (ii) by ENLC or its affiliates without cause, or (iii) by the grantee for good reason (each, a “Covered Termination” and more particularly defined in the Subject Grants agreement) except that the Subject Grants will vest in full if the applicable Covered Termination is a “normal retirement” (as defined in the Subject Grants agreement) or the
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Notes to Consolidated Financial Statements (continued)
applicable Covered Termination occurs after a change of control (if any). The Subject Grants will vest in full if death or a qualifying disability occurs prior to the Regular Vesting Date.

(c) EnLink Midstream Partners, LP’sENLC Performance Units


In 2017, 2016 and 2015, the General Partner grantedENLC grants performance awards under the GP2014 Plan. The performance award agreements provide that the vesting of performance units (i.e., performance-based restricted incentive unitsunits) granted thereunder is dependent on the achievement of certain total shareholder return (“TSR”) performance goals relative to the TSR achievement of a peer group of companies (the “Peer Companies”) over the applicable performance period. The performance award agreements contemplate that the Peer Companies for an individual performance award (the “Subject Award”) are the companies comprising the Alerian MLP Index for Master Limited Partnerships (“AMZ”), excluding ENLK and ENLC, on the grant date for the Subject Award. The performance units will vest based on the percentile ranking of the average of ENLK’s and ENLC’s TSR achievement (“EnLink TSR”) for the applicable performance period relative to the TSR achievement of the Peer Companies.

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 EnLinkextent to which the related performance goals are achieved over the relevant performance period.

Performance Unit Awards Vesting

The vesting of performance units is dependent on (a) the grantee’s continued employment or service with ENLC or its affiliates for all relevant periods and (b) the TSR as comparedperformance of ENLC (the “ENLC TSR”) and a performance goal based on cash flow (“Cash Flow”). At the time of grant, the Board of Directors of the Managing Member (the “Board”) will determine the relative weighting of the two performance goals by including in the award agreement the number of units that will be eligible for vesting depending on the achievement of the TSR performance goals (the “Total TSR Units”) versus the achievement of the Cash Flow performance goals (the “Total CF Units”). These performance awards have four separate performance periods: (i) three performance periods are each of the first, second, and third calendar years that occur following the vesting commencement date of the performance awards and (ii) the fourth performance period is the cumulative three-year period from the vesting commencement date through the third anniversary thereof (the “Cumulative Performance Period”).

One-fourth of the Total TSR Units (the “Tranche TSR Units”) relates to each of the four performance periods described above. Following the end date of a given performance period, the Governance and Compensation Committee (the “Committee”) of the Board will measure and determine the ENLC TSR relative to the TSR performance of a designated group of peer companies (the “Designated Peer Companies”) to determine the Tranche TSR Units that are eligible to vest, subject to the grantee’s continued employment or service with ENLC or its affiliates through the end date of the Peer Companies onCumulative Performance Period. In short, the vesting date. The fair valueTSR for a given performance period is defined as (i)(A) the average closing price of each performance unit is estimated asa common equity security at the end of the daterelevant performance period minus (B) the average closing price of grant using a Monte Carlo simulation withcommon equity security at the following assumptions used for all performance unit grants made under the plan: (i) a risk-free interest rate based on United States Treasury rates asbeginning of the grant date;relevant performance period plus (C) reinvested dividends divided by (ii) the average closing price of a volatility assumption based oncommon equity security at the historical realized price volatility of our common units and the designated Peer Companies securities; (iii) an estimated ranking of us among the Peer Companies; and (iv) the distribution yield. The fair valuebeginning of the relevant performance unit on the date of grant is expensed over a vesting period of approximately three years.period.


The following table presents a summarysets out the levels at which the Tranche TSR Units may vest (using linear interpolation) based on the ENLC TSR percentile ranking for the applicable performance period relative to the TSR achievement of the grant-date fair valuesDesignated Peer Companies:
Performance LevelAchieved ENLC TSR
Position Relative to Designated Peer Companies		Vesting percentage
of the Tranche TSR Units
Below ThresholdLess than 25%0%
ThresholdEqual to 25%50%
TargetEqual to 50%100%
MaximumGreater than or Equal to 75%200%

Approximately one-third of the Total CF Units (the “Tranche CF Units”) relates to each of the first three performance periods described above (i.e., the Cash Flow performance goal does not relate to the Cumulative Performance Period). The Board will establish the Cash Flow performance targets for purposes of the column in the table below titled “ENLC’s Achieved Cash Flow” for each performance period no later than March 31 of the year in which the relevant performance period begins. Following the end date of a given performance period, the Committee will measure and determine the Cash Flow performance of ENLC to determine the Tranche CF Units that are eligible to vest, subject to the grantee’s continued employment or service with ENLC or its affiliates through the end of the Cumulative Performance Period. In short, the Performance-Based Award Agreement defines Cash Flow for a given performance period as (A)(i) ENLC’s adjusted EBITDA minus (ii) interest expense, current taxes and other, maintenance capital expenditures, and preferred unit accrued distributions divided by (B) the time-weighted average number of ENLC’s common units granted andoutstanding during the related assumptions byrelevant performance unit grant date:

period. 
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EnLink Midstream Partners, LP Performance Units: March 2017 October 2016 February 2016 January 2016 March 2015
Beginning TSR price $17.55 $17.71 $14.82 $14.82 $27.68
Risk-free interest rate 1.62% 0.91% 0.89% 1.10% 0.99%
Volatility factor 43.94% 44.62% 42.33% 39.71% 33.01%
Distribution yield 8.70% 8.80% 19.20% 12.10% 5.66%


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Notes to Consolidated Financial Statements (Continued)(continued)


In 2021, the Board adopted the metric free cash flow after distributions (“FCFAD”) as the cash flow performance goal in the Performance-Based Award Agreement rather than the previously used distributable cash flow per unit. The following table sets out the levels at which the Tranche CF Units were eligible to vest (using linear interpolation) based on the FCFAD performance of ENLC for the performance period ending December 31, 2021:
Performance LevelENLC’s Achieved FCFADVesting percentage
of the Tranche CF Units
Below ThresholdLess than $205 million0%
ThresholdEqual to $205 million50%
TargetEqual to $256 million100%
MaximumGreater than or Equal to $300 million200%

The following table presents a summarysets out the levels at which the Tranche CF Units were eligible to vest (using linear interpolation) based on the cash flow performance of ENLC for the performance units:

  Year Ended December 31, 2017
EnLink Midstream Partners, LP Performance Units: Number of Units  Weighted Average Grant-Date Fair Value
Non-vested, beginning of period 408,637
 $18.27
Granted 176,648
 25.73
Forfeited —
 —
Non-vested, end of period 585,285
 $20.52
Aggregate intrinsic value, end of period (in millions) $9.0
  

As ofperiod ending December 31, 2017, there was $4.8 million of unrecognized compensation expense that related to non-vested performance units. That cost is expected to be recognized over a weighted-average period of 1.8 years.2020:

(d) EnLink Midstream, LLC’s Restricted Incentive Units

ENLC restricted incentive units are valued at their fair value at the date of grant, which is equal to the market value of the ENLC common units on such date. A summary of the restricted incentive unit activity for the year ended December 31, 2017 is provided below:

  Year Ended December 31, 2017
EnLink Midstream, LLC Restricted Incentive Units: Number of Units Weighted Average Grant-Date Fair Value
Non-vested, beginning of period 1,897,298
 $19.96
Granted (1) 827,609
 19.20
Vested (1)(2) (795,032) 27.95
Forfeited (40,565) 16.84
Non-vested, end of period 1,889,310
 $21.64
Aggregate intrinsic value, end of period (in millions) $33.3
  
(1)Performance Level
Restricted incentive units typically vest at
ENLC’s Achieved 
Distributable Cash Flow per Unit		Vesting percentage
of the end of three years. In March 2017, ENLC granted 258,606 restricted incentive units with a fair value of $5.0 millionTranche CF Units
Below ThresholdLess than $1.3450%
ThresholdEqual to officers and certain employees as bonus payments for 2016, and these restricted incentive units vested immediately are included in the restricted incentive units granted and vested line items.$1.34550%
TargetEqual to $1.494100%
MaximumGreater than or Equal to $1.643200%

The following table sets out the levels at which the Tranche CF Units were eligible to vest (using linear interpolation) based on the cash flow performance of ENLC for the performance period ending December 31, 2019:
(2)Performance LevelVested units include 243,620 units withheld for payroll taxes paid on behalf ENLC’s Achieved 
Distributable Cash Flow per Unit		Vesting percentage
of employees.the Tranche CF Units
Below ThresholdLess than $1.430%
ThresholdEqual to $1.4350%
TargetEqual to $1.55100%
MaximumGreater than or Equal to $1.72200%

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) during the years ended December 31, 2017, 2016 and 2015 is provided below (in millions):

  Year Ended December 31,
EnLink Midstream, LLC Restricted Incentive Units: 2017 2016 2015
Aggregate intrinsic value of units vested $15.3
 $4.1
 $9.2
Fair value of units vested $22.2
 $12.4
 $9.8

As of December 31, 2017, there was $11.3 million of unrecognized compensation costs related to non-vested ENLC restricted incentive units. That cost is expected to be recognized over a weighted average period of 1.7 years.


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Notes to Consolidated Financial Statements (Continued)

(e) EnLink Midstream, LLC’s Performance Units

In 2017, 2016 and 2015, ENLC granted performance awards under the 2014 Plan. 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 EnLink TSR as compared to the TSR of the Peer Companies on the vesting date. The fair value of each performance unit is estimated as of the date of grant using a Monte Carlo simulation with the following assumptions used for all performance unit grants made under the plan: (i) a risk-free interest rate based on United States Treasury rates as of the grant date; (ii) a volatility assumption based on the historical realized price volatility of ENLC’s common units and the designatedDesignated Peer Companies securities;Companies’ or Peer Companies’ securities as applicable; (iii) an estimated ranking of ENLC (or for outstanding performance units granted prior to the Merger, ENLC and ENLK) among the Designated Peer Companies or Peer Companies, and (iv) the distribution yield. The fair value of the performance unit on the date of grant is expensed over a vesting period of approximately three years.


The following table presents a summary of the grant-date fair values of performance units and the relatedvalue assumptions by performance unit grant date:

ENLC Performance Units:January 2021July 2020March 2020January 2020October 2019June 2019March 2019
Grant-date fair value$4.70 $2.33 $1.13 $7.69 $7.29 $9.92 $13.10 
Beginning TSR price$3.71 $2.52 $1.25 $6.13 $7.42 $9.84 $10.92 
Risk-free interest rate0.17 %0.17 %0.42 %1.62 %1.44 %1.72 %2.42 %
Volatility factor71.00 %67.00 %51.00 %37.00 %35.00 %33.50 %33.86 %

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EnLink Midstream, LLC Performance Units: March 2017 October 2016 February 2016 January 2016 March 2015
Beginning TSR price $18.29 $16.75 $15.38 $15.38 $34.24
Risk-free interest rate 1.62% 0.91% 0.89% 1.10% 0.99%
Volatility factor 52.07% 52.89% 52.05% 46.02% 33.02%
Distribution yield 5.40% 6.10% 14.00% 8.60% 2.98%

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES
Notes to Consolidated Financial Statements (continued)
The following table presents a summary of the performance units:

Year Ended December 31, 2021
ENLC Performance Units:Number of UnitsWeighted Average Grant-Date Fair Value
Non-vested, beginning of period2,351,241 $8.82 
Granted1,388,139 4.70 
Vested (1)(164,553)26.73 
Non-vested, end of period3,574,827 $6.40 
Aggregate intrinsic value, end of period (in millions)$24.6 
____________________________
  Year Ended December 31, 2017
EnLink Midstream, LLC Performance Units: Number of Units Weighted Average Grant-Date Fair Value
Non-vested, beginning of period 384,264
 $19.30
Granted 164,575
 28.77
Forfeited —
 —
Non-vested, end of period 548,839
 $22.14
Aggregate intrinsic value, end of period (in millions) $9.7
  
(1)Vested units included 63,901 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 years ended December 31, 2021, 2020, and 2019 is provided below (in millions).
Year Ended December 31,
ENLC Performance Units:202120202019
Aggregate intrinsic value of units vested$0.6 $0.9 $3.4 
Fair value of units vested$4.4 $5.5 $7.9 

As of December 31, 2017,2021, there was $5.0were $10.4 million of unrecognized compensation expensecosts that related to non-vested ENLC performance units. That cost isThese costs are expected to be recognized over a weighted-average period of 1.81.6 years.


(f)(d) Benefit Plan


ENLK maintains a tax-qualified 401(k) plan whereby it matches 100% of every dollar contributed up to 6% of an employee’s salary plus a 2% non-discretionary contribution (not to exceed the maximum amount permitted by law).eligible compensation. Contributions of $7.6$7.0 million, $7.4$7.2 million, and $7.0$9.4 million were made to the plan for the years ended December 31, 2017, 20162021, 2020, and 2015,2019, respectively.


(13)(12) Derivatives


Interest Rate Swaps


We periodically enterIn April 2019, we entered into $850.0 million of interest rate swaps to manage the interest rate risk associated with our floating-rate, LIBOR-based borrowings. Under this arrangement, we paid a fixed interest rate of 2.28% in exchange for LIBOR-based variable interest through December 2021. These interest rate swaps expired on December 10, 2021. There was no ineffectiveness related to this hedge.

During 2021 and 2020, we terminated the interest rate swaps in several increments in connection with new debt issuances. Duringrepayments of the debt issuance process, we are exposed to variability in future long-term debt interest payments that may result from changes inTerm Loan, which was one of our floating-rate, LIBOR-based borrowings. The following table presents the benchmark interest rate (commonly the U.S. Treasury yield) prior to the debt being issued. In order to hedge this variability, we enter into interest rate swaps to effectively lock interminations and the benchmark interest rate at the inception of the swap. Prior to 2017, we did not designate interestassociated cash payments during 2021 and 2020 (in millions):

Interest Rate Swaps TerminationsCash Payments Associated with Interest Rate Swaps Terminations
December 2021$150.0 $— 
September 2021100.0 0.5 
May 2021100.0 1.3 
December 2020500.0 10.9 
Total termination of interest rate swaps$850.0 $12.7 

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Notes to Consolidated Financial Statements (Continued)(continued)

The components of the unrealized gain (loss) on designated cash flow hedge related to changes in the fair value of our interest rate swaps were as hedges and, therefore, included the associated settlement gains and losses asfollows (in millions):
Year Ended December 31,
202120202019
Change in fair value of interest rate swaps$18.2 $(5.6)$(12.4)
Tax benefit (expense)(4.3)1.3 3.4 
Unrealized gain (loss) on designated cash flow hedge$13.9 $(4.3)$(9.0)

The interest expense, net of interest income on the consolidated statements of operations.

In May 2017, we entered into an interest rate swap in connection with the issuance of ENLK’s 2047 Notes. In accordance with ASC 815, we designated this swap as a cash flow hedge. Upon settlement of the interest rate swap in May 2017, we recorded the associated $2.2 million settlement loss inrecognized from accumulated other comprehensive loss onfrom the consolidated balance sheets. We will amortizemonthly settlement of our interest rate swaps and amortization of the settlement loss into interest expense on thetermination payments, included in our consolidated statements of operations over the term of the 2047 Notes. There was no ineffectiveness related to the hedge. We have no open interest rate swap positionswere as of December 31, 2017. In addition, the settlement loss is included as an operating cash outflow on the consolidated statement of cash flows for the year ended December 31, 2017.follows (in millions):

Year Ended December 31,
202120202019
Interest expense$18.3 $14.5 $0.4 
For the year ended December 31, 2017, we amortized an immaterial amount of the settlement loss into interest expense from accumulated other comprehensive income (loss).
We expect to recognize an additional $0.1 million of interest expense out of accumulated other comprehensive income (loss)loss over the next twelve months.

In July 2016, we entered into an interest rate swap in connection with the issuance of the 2026 Notes. We did not designate this swap as a cash flow hedge. Upon settlement of the interest rate swap in July 2016, we recorded the associated $0.4 million gain on settlement in other income (expense) in the consolidated statement of operations for the year ended December 31, 2016.

In April and May 2015, we entered into an interest rate swap in connection with the issuance of the 2025 Notes. We did not designate this swap as a cash flow hedge. Upon settlement of the interest rate swap, we recorded the associated $3.6 million gain on settlement in other income (expense) in the consolidated statement of operations for the year ended December 31, 2015.


The impactfair value of theour interest rate swaps on net income is included in other income (expense) in theour consolidated statements of operations as part of interest expense, net of interest income,balance sheets were as follows (in millions):
December 31, 2021December 31, 2020
Fair value of derivative liabilities—current$— $(7.6)
 Year Ended December 31,
 2017 2016 2015
Settlement gains on derivatives$—
 $0.4
 $3.6


Commodity Swaps


We manage our exposure to changes in commodity prices by hedging the impact of market fluctuations. Commodity swaps are used both to manage and hedge price and location risk related to these market exposures. Commodity swaps are also usedexposures and to manage margins on offsetting fixed-price purchase or sale commitments for physical quantities of crude, condensate, natural gas, and NGLs. We do not designate commodity swap transactionsswaps as cash flow or fair value hedges for hedge accounting treatment under ASC 815. Therefore, changes in the fair value of our derivatives are recorded in revenue in the period incurred. In addition, our commodity risk management policy does not allow us to take speculative positions with our derivative contracts.


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


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Notes to Consolidated Financial Statements (Continued)

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

 Year Ended December 31,
 2017 2016 2015
Change in fair value of derivatives$4.7
 $(20.1) $(7.7)
Realized gain (loss) on derivatives(8.9) 9.0
 17.1
Gain (loss) on derivative activity$(4.2) $(11.1) $9.4

The fair value of derivative assets and liabilities related to commodity swaps are as follows (in millions):
 December 31, 2017 December 31, 2016
Fair value of derivative assets — current$6.8
 $1.3
Fair value of derivative liabilities — current(8.4) (7.6)
Net fair value of derivatives$(1.6) $(6.3)


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

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Notes to Consolidated Financial Statements (continued)

The components of gain (loss) on derivative activity in the consolidated statements of operations related to commodity swaps are (in millions):
Year Ended December 31,
202120202019
Change in fair value of derivatives$(12.4)$(10.5)$(0.1)
Realized gain (loss) on derivatives(146.7)(11.5)14.5 
Gain (loss) on derivative activity$(159.1)$(22.0)$14.4 

The fair value of derivative assets and liabilities related to commodity swaps are as follows (in millions):
December 31, 2021December 31, 2020
Fair value of derivative assets—current$22.4 $25.0 
Fair value of derivative assets—long-term0.2 4.9 
Fair value of derivative liabilities—current(34.9)(29.5)
Fair value of derivative liabilities—long-term(2.2)(2.5)
Net fair value of commodity swaps$(14.5)$(2.1)

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 December 31, 20172021 (in millions). The remaining term of the contracts extend no later than January 2019.2023.

December 31, 2021
CommodityInstrumentsUnitVolumeNet Fair Value
NGL (short contracts)SwapsGals(63.0)$(10.6)
NGL (long contracts)SwapsGals— — 
Natural gas (short contracts)SwapsMMbtu(7.5)2.7 
Natural gas (long contracts)SwapsMMbtu13.2 (7.8)
Crude and condensate (short contracts)SwapsMMbbls(3.9)(4.4)
Crude and condensate (long contracts)SwapsMMbbls3.9 5.6 
Total fair value of commodity swaps$(14.5)
    December 31, 2017
Commodity Instruments Unit Volume
 Fair Value
NGL (short contracts) Swaps Gallons (40.0) $(5.2)
NGL (long contracts) Swaps Gallons 23.7
 1.4
Natural Gas (short contracts) Swaps MMBtu (6.9) 3.8
Natural Gas (long contracts) Swaps MMBtu 17.3
 (1.6)
Total fair value of derivatives       $(1.6)


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 two types of counterparties, financial institutions and other energy companies, when entering into financial derivatives on commodities. We have entered into Master International Swaps and Derivatives Association Agreements (“ISDAs”)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, ourthe maximum loss on our gross receivable position of $6.8$22.6 million as of December 31, 20172021 would be reduced to $1.6$0.8 million due to the offsetting of gross fair value payables against gross fair value receivables as allowed by the ISDAs.




(14)(13) Fair Value Measurements


ASC 820Fair Value Measurements and Disclosures (“ASC 820”), sets forth a framework for measuring fair value and required disclosures about fair value measurements of assets and liabilities. Fair value under ASC 820 is defined as the price at which an asset could be exchanged in a current transaction between knowledgeable, willing parties. A liability’s fair value is defined as the amount that would be paid to transfer the liability to a new obligor, not the amount that would be paid to settle the liability with the creditor. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, use of unobservable prices or inputs are used to estimate the current fair value, often using an internal valuation model. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the item being valued.


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Notes to Consolidated Financial Statements (Continued)(continued)


ASC 820 established a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value. These tiers include: Level 1, defined as observable inputs such as quoted prices in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions.


Our derivative contracts primarily consist of commodity swap contracts, which are not traded on a public exchange. The fair values of commodity swap contracts are determined using discounted cash flow techniques. The techniques incorporate Level 1 and Level 2 inputs for future commodity prices that are readily available in public markets or can be derived from information available in publicly-quoted markets. These market inputs are utilized in the discounted cash flow calculation considering the instrument’s term, notional amount, discount rate, and credit risk and are classified as Level 2 in hierarchy.


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

Level 2
December 31, 2021December 31, 2020
Interest rate swaps (1)$— $(7.6)
Commodity swaps (2)$(14.5)$(2.1)
____________________________
 Level 2
 December 31, 2017 December 31, 2016
Commodity Swaps (1)$(1.6) $(6.3)
(1)The fair values of the interest rate swaps are estimated based on the difference between expected cash flows calculated at the contracted interest rates and the expected cash flows using observable benchmarks for the variable interest rates.
(2)The fair values of commodity swaps represent the amount at which the instruments could be exchanged in a current arms-length transaction adjusted for our credit risk and/or the counterparty credit risk as required under ASC 820.
(1)The fair value of derivative contracts included in assets or liabilities for risk management activities represents the amount at which the instruments could be exchanged in a current arms-length transaction adjusted for credit risk of us and/or the counterparty 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):

December 31, 2021December 31, 2020
Carrying ValueFair ValueCarrying ValueFair Value
Long-term debt (1)$4,363.7 $4,520.0 $4,593.8 $4,318.2 
Installment payab1e (2)$10.0 $10.0 $— $— 
Contingent consideration (2)$6.9 $6.9 $— $— 
____________________________
 December 31, 2017 December 31, 2016
 Carrying Value Fair Value Carrying Value Fair Value
Long-term debt (1)$3,542.1
 $3,650.2
 $3,295.3
 $3,253.6
Installment Payables$249.5
 $249.6
 $473.2
 $476.6
Obligations under capital lease$4.1
 $3.4
 $6.6
 $6.1
(1)The carrying value of long-term debt as of December 31, 2020 includes current maturities. The carrying value of the long-term debt is reduced by debt issuance costs of $27.8 million and $32.6 million at December 31, 2021 and 2020, respectively. The respective fair values do not factor in debt issuance costs.
(2)Consideration paid for the acquisition of Amarillo Rattler, LLC included $10.0 million to be paid on April 30, 2022 and a contingent consideration capped at $15.0 million and payable between 2024 and 2026 based on Diamondback Energy’s drilling activity above historical levels. Estimated fair values were calculated using a discounted cash flow analysis that utilized Level 3 inputs. For additional information regarding this transaction, refer to “Note 2—Significant Accounting Policies.”
(1)The carrying values of long-term debt are reduced by debt issuance costs of $26.2 million and $24.6 million at December 31, 2017 and 2016, respectively. The respective fair values do not factor in debt issuance costs.

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.


ENLK had no outstanding borrowings under the ENLK Credit Facility as of December 31, 2017 and $120.0 million in outstanding borrowings under the ENLK Credit Facility as of December 31, 2016. ENLC had $74.6 million and $27.8 million in outstanding borrowings under the ENLC Credit Facility as of December 31, 2017 and 2016, respectively. As borrowings under the ENLK Credit Facility and ENLC Credit Facility accrue interest under floating interest rate structures, the carrying value of such indebtedness approximates fair value for the amounts outstanding under the credit facility. As of December 31, 2017 and 2016, ENLK had total borrowings under senior unsecured notes of $3.5 billion and $3.1 billion, respectively with fixed interest rates ranging from 2.7% to 5.6% and 2.7% to 7.1%, respectively, maturing between 2019 and 2047. The fair valuevalues of all senior unsecured notes and installment payables as of December 31, 20172021 and 2016 was2020 were based on Level 2 inputs from third-party market quotations. The fair values of obligations under capital leases were calculated using Level 2 inputs from third-party banks.


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(15)(14) Commitments and Contingencies


(a) Leases—Lessee

We have operating leases for office space, office and field equipment.

The following table summarizes our remaining non-cancelable future payments under operating leases with initial or remaining non-cancelable lease terms in excess of one year (in millions):

2018$14.3
201910.9
20208.6
20218.6
20228.6
Thereafter58.6
Total$109.6

Operating lease rental expense was approximately $54.5 million, $59.6 million and $66.1 million for the years ended December 31, 2017, 2016 and 2015, respectively.

(b) Change of Control and Severance Agreements


Certain members of our management are parties to severance and change of control agreements with the Operating Partnership. The severance and change in control agreements provide those individuals with severance payments in certain circumstances and prohibit such individuals from, among other things, competing with the General Partner or its affiliates
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Notes to Consolidated Financial Statements (continued)
during his or her employment. In addition, the severance and change of control agreements prohibit subject individuals from, among other things, disclosing confidential information about the General Partner or interfering with a client or customer of the General Partner or its affiliates, in each case during his or her employment and for certain periods (including indefinite periods) following the termination of such person’s employment.


(c)(b) Environmental Issues


The operation of pipelines, plants, and other facilities for the gathering, processing, transmitting, stabilizing, fractionating, storing, or disposing of natural gas, NGLs, crude oil, condensate, brine, and other products is subject to stringent and complex laws and regulations pertaining to health, safety, and the environment. As an owner, partner, or operator of these facilities, we must comply with United States laws and regulations at the federal, state, and local levels that relate to air and water quality, hazardous and solid waste management and disposal, oil spill prevention, climate change, endangered species, and other environmental matters. The cost of planning, designing, constructing, and operating pipelines, plants, and other facilities must account for compliance with environmental laws and regulations and safety standards. Federal, state, or local administrative decisions, developments in the federal or state court systems, or other governmental or judicial actions may influence the interpretation and enforcement of environmental laws and regulations and may thereby increase compliance costs. Failure to comply with these laws and regulations may trigger a variety of administrative, civil, and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of injunctions or restrictions on operation. Management believes that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on our results of operations, financial condition, or cash flows. However, we cannot provide assurance that future events, such as changes in existing laws, regulations, or enforcement policies, the promulgation of new laws or regulations, or the discovery or development of new factual circumstances will not cause us to incur material costs. Environmental regulations have historically become more stringent over time, and thus, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation.


As previously disclosed, in February 2016, a spill occurred at our Kill Buck Station in our Ohio operations. State and federal agencies were notified, and clean-up response efforts were promptly executed, which significantly lessened the impact

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of the spill. The state agency determined that the clean-up recovery efforts were completed and issued to us a “No Further Action” notice. We do not anticipate additional fines or penalties by either the state or federal agencies.

(d)(c) Litigation 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, 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.

At times, our subsidiaries acquire pipeline easements and other property rights by exercising rights of eminent domain and common carrier. As a result, We may also be involved from time to time we (or our subsidiaries) are a partyin the future in various proceedings in the normal course of business, including litigation on disputes related to a number of lawsuits under which a court will determinecontracts, property rights, property use or damage (including nuisance claims), personal injury, or the value of pipeline easements or other property interestsrights obtained by our subsidiaries by condemnation. Damage awards in these suits should reflectthrough the valueexercise of the property interest acquired and the diminutioneminent domain or common carrier rights.


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Notes to Consolidated Financial Statements (continued)
(15) Segment Information

Starting in the valuefirst quarter of 2021, we began evaluating the remaining property ownedfinancial performance of our segments by the landowner. However, some landowners have alleged unique damage theories to inflate their damage claims or assert valuation methodologies that could result in damage awards in excess of the amounts anticipated. Although it is not possible to predict the ultimate outcomes of these matters, we do not expect that awards in these matters will have a material adverse impact on our consolidated results of operations, financial condition or cash flows.

We ownincluding realized and operate a high-pressure pipelineunrealized gains and underground natural gas and NGL storage reservoirs and associated facilities near Bayou Corne, Louisiana. In August 2012, a large sinkhole formedlosses resulting from commodity swaps activity in the vicinity of this pipelinePermian, Louisiana, Oklahoma, and underground storage reservoirs, resulting in damage to certain of our facilities. In order to recover our losses from responsible parties, we sued the operator of a failed cavernNorth Texas segments. Commodity swaps activity was previously reported in the area, and its insurers, as well as other parties we alleged toCorporate segment. We have contributedrecast segment information for all presented periods prior to the formationfirst quarter of the sinkhole seeking recovery for these losses. We also filed a claim with our insurers, which our insurers denied. We disputed the denial and sued our insurers, and we subsequently reached settlements regarding the entirety of our claims in both lawsuits. In August 2014, we received a partial settlement with respect2021 to our claims in the amount of $6.1 million. We secured additional settlement payments during 2017, which resulted in the recognition of “Gain on litigation settlement” of $26.0 million on the consolidated statement of operations for the year ended December 31, 2017.

(16) Segment Information

conform to current period presentation. Identification of the majority of our operating segments is based principally upon geographic regions served and the nature of operating activity. Our reportable segments consist of the following:served:

•Permian Segment. The Permian segment includes our natural gas gathering, processing, and transmission activities and fractionationour crude oil operations located in North Texasthe Midland and the Permian Basin primarilyDelaware Basins in West Texas (“Texas”), theand 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, NGL pipelines and fractionation assetsfacilities located in Louisiana (“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, operations located throughoutand transmission activities in North Texas; and

•Corporate Segment. The Corporate segment includes our unconsolidated affiliate investments in the Cedar Cove JV in Oklahoma, (“Oklahoma”) and crude rail, truck, pipeline and barge facilitiesour ownership interest in West Texas,GCF in South Texas, Louisiana and the Ohio River Valley (“Crudeour general corporate assets and Condensate”). Operating activity for intersegment eliminations is shown in the Corporate segment. Our sales are derived from external domestic customers. expenses.

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We evaluate the performance of our operating segments based on segment profits.

Corporate assets consist primarilyprofit and adjusted gross margin. Adjusted gross margin is a non-GAAP financial measure. See “Item 7. Management’s Discussion and Analysis of cash, goodwill, propertyFinancial Condition and equipment, including software,Results of Operations—Non-GAAP Financial Measures” for general corporate support, debt financing costs and unconsolidated affiliate investments in GCF and the Cedar Cove JV as of December 31, 2017 and 2016. As of December 31, 2016, our Corporate assets included our unconsolidated affiliate investment in HEP. In December 31, 2016, we entered into an agreement to sell our ownership interest in HEP, and we finalized the sale in March 2017.

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additional information. Summarized financial information for our reportable segments is shown in the following tables (in millions):
PermianLouisianaOklahomaNorth TexasCorporateTotals
Year Ended December 31, 2021
Natural gas sales$609.4 $693.5 $213.4 $150.0 $— $1,666.3 
NGL sales0.9 3,353.1 2.0 1.1 — 3,357.1 
Crude oil and condensate sales677.4 212.0 81.2 — — 970.6 
Product sales1,287.7 4,258.6 296.6 151.1 — 5,994.0 
NGL sales—related parties1,008.4 129.7 630.8 447.0 (2,215.9)— 
Crude oil and condensate sales—related parties— — 0.1 7.1 (7.2)— 
Product sales—related parties1,008.4 129.7 630.9 454.1 (2,223.1)— 
Gathering and transportation46.8 64.7 186.9 157.0 — 455.4 
Processing29.1 2.4 98.7 108.3 — 238.5 
NGL services— 82.6 — 0.3 — 82.9 
Crude services18.4 39.3 12.8 0.7 — 71.2 
Other services0.2 1.7 0.6 0.5 — 3.0 
Midstream services94.5 190.7 299.0 266.8 — 851.0 
Crude services—related parties— — 0.3 — (0.3)— 
Other services—related parties— 2.4 — — (2.4)— 
Midstream services—related parties— 2.4 0.3 — (2.7)— 
Revenue from contracts with customers2,390.6 4,581.4 1,226.8 872.0 (2,225.8)6,845.0 
Cost of sales, exclusive of operating expenses and depreciation and amortization (1)(1,996.1)(4,091.2)(796.6)(531.8)2,225.8 (5,189.9)
Realized loss on derivatives(75.6)(42.3)(22.6)(6.2)— (146.7)
Change in fair value of derivatives(7.7)0.7 — (5.4)— (12.4)
Adjusted gross margin311.2 448.6 407.6 328.6 — 1,496.0 
Operating expenses(81.5)(123.7)(80.0)(77.7)— (362.9)
Segment profit229.7 324.9 327.6 250.9 — 1,133.1 
Depreciation and amortization(139.9)(141.0)(204.3)(114.3)(8.0)(607.5)
Impairments— (0.6)— — (0.2)(0.8)
Gain on disposition of assets— 1.2 — 0.3 — 1.5 
General and administrative— — — — (107.8)(107.8)
Interest expense, net of interest income— — — — (238.7)(238.7)
Loss from unconsolidated affiliates— — — — (11.5)(11.5)
Income (loss) before non-controlling interest and income taxes$89.8 $184.5 $123.3 $136.9 $(366.2)$168.3 
Capital expenditures$141.6 $9.3 $30.4 $11.9 $2.8 $196.0 
 Texas Louisiana Oklahoma Crude and Condensate Corporate Totals
Year Ended December 31, 2017:           
Product sales$325.0
 $2,529.6
 $128.8
 $1,375.0
 $—
 $4,358.4
Product sales—related parties500.3
 45.0
 349.4
 0.8
 (750.6) 144.9
Midstream services116.3
 220.6
 155.0
 60.4
 —
 552.3
Midstream services—related parties424.3
 136.4
 241.6
 17.4
 (131.5) 688.2
Cost of sales(772.3) (2,618.1) (522.9) (1,330.3) 882.1
 (4,361.5)
Operating expenses(172.7) (101.3) (64.6) (80.1) —
 (418.7)
Loss on derivative activity—
 —
 —
 —
 (4.2) (4.2)
Segment profit (loss)$420.9
 $212.2
 $287.3
 $43.2
 $(4.2) $959.4
Depreciation and amortization$(215.2) $(116.1) $(156.6) $(47.5) $(9.9) $(545.3)
Impairments$—
 $(0.8) $—
 $(16.3) $—
 $(17.1)
Goodwill$232.0
 $—
 $190.3
 $—
 $1,119.9
 $1,542.2
Capital expenditures$145.4
 $75.1
 $442.1
 $79.1
 $26.4
 $768.1
Total assets$3,094.8
 $2,408.5
 $2,836.7
 $929.5
 $1,268.3
 $10,537.8
____________________________

(1)Includes related party cost of sales of $17.9 million for the year ended December 31, 2021.
139
 Texas Louisiana Oklahoma Crude and Condensate Corporate Totals
Year Ended December 31, 2016:           
Product sales$237.2
 $1,632.5
 $48.5
 $1,090.7
 $—
 $3,008.9
Product sales—related parties287.6
 57.8
 120.4
 1.5
 (333.0) 134.3
Midstream services104.2
 215.4
 82.2
 65.4
 —
 467.2
Midstream services—related parties439.3
 95.8
 185.9
 18.9
 (86.8) 653.1
Cost of sales(483.4) (1,729.0) (184.9) (1,038.0) 419.8
 (3,015.5)
Operating expenses(168.5) (96.6) (52.1) (81.3) —
 (398.5)
Loss on derivative activity—
 —
 —
 —
 (11.1) (11.1)
Segment profit (loss)$416.4
 $175.9
 $200.0
 $57.2
 $(11.1) $838.4
Depreciation and amortization$(196.9) $(114.8) $(140.6) $(42.4) $(9.2) $(503.9)
Impairments$(473.1) $—
 $—
 $(93.2) $(307.0) $(873.3)
Goodwill$232.0
 $—
 $190.3
 $—
 $1,119.9
 $1,542.2
Capital expenditures$217.9
 $79.1
 $295.7
 $74.3
 $9.1
 $676.1
Total assets$3,142.6
 $2,349.3
 $2,524.5
 $836.8
 $1,422.7
 $10,275.9


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PermianLouisianaOklahomaNorth TexasCorporateTotals
Year Ended December 31, 2020
Natural gas sales$150.1 $330.5 $153.1 $70.3 $— $704.0 
NGL sales0.2 1,545.4 2.8 — — 1,548.4 
Crude oil and condensate sales558.1 126.7 40.3 — — 725.1 
Product sales708.4 2,002.6 196.2 70.3 — 2,977.5 
NGL sales—related parties312.6 31.4 296.4 115.2 (755.6)— 
Crude oil and condensate sales—related parties0.6 — (0.1)3.6 (4.1)— 
Product sales—related parties313.2 31.4 296.3 118.8 (759.7)— 
Gathering and transportation42.8 46.5 228.7 179.2 — 497.2 
Processing24.1 2.0 123.6 132.6 — 282.3 
NGL services— 75.8 — 0.2 — 76.0 
Crude services16.8 45.2 16.5 0.2 — 78.7 
Other services1.2 1.6 0.4 0.9 — 4.1 
Midstream services84.9 171.1 369.2 313.1 — 938.3 
Crude services—related parties— — 0.3 — (0.3)— 
Midstream services—related parties— — 0.3 — (0.3)— 
Revenue from contracts with customers1,106.5 2,205.1 862.0 502.2 (760.0)3,915.8 
Cost of sales, exclusive of operating expenses and depreciation and amortization (1)(842.2)(1,787.0)(365.5)(153.8)760.0 (2,388.5)
Realized loss on derivatives(1.1)(6.0)(4.4)— — (11.5)
Change in fair value of derivatives1.1 (6.5)(4.5)(0.6)— (10.5)
Adjusted gross margin264.3 405.6 487.6 347.8 — 1,505.3 
Operating expenses(94.2)(120.0)(82.2)(77.4)— (373.8)
Segment profit170.1 285.6 405.4 270.4 — 1,131.5 
Depreciation and amortization(125.2)(145.8)(216.9)(143.4)(7.3)(638.6)
Impairments(184.6)(170.0)(0.7)— (7.5)(362.8)
Gain (loss) on disposition of assets(11.2)0.1 0.3 2.0 — (8.8)
General and administrative— — — — (103.3)(103.3)
Interest expense, net of interest income— — — — (223.3)(223.3)
Gain on extinguishment of debt— — — — 32.0 32.0 
Income from unconsolidated affiliates— — — — 0.6 0.6 
Other income— — — — 0.3 0.3 
Income (loss) before non-controlling interest and income taxes$(150.9)$(30.1)$188.1 $129.0 $(308.5)$(172.4)
Capital expenditures$181.1 $44.6 $17.9 $16.9 $2.1 $262.6 
____________________________
(1)Includes related party cost of sales of $8.7 million for the year ended December 31, 2020.
140
 Texas Louisiana Oklahoma Crude and Condensate Corporate Totals
Year Ended December 31, 2015:           
Product sales$320.0
 $1,527.7
 $5.0
 $1,401.0
 $—
 $3,253.7
Product sales—related parties123.3
 48.5
 13.0
 0.8
 (66.2) 119.4
Midstream services100.2
 244.1
 28.3
 78.4
 —
 451.0
Midstream services—related parties456.7
 20.0
 140.7
 18.0
 (16.8) 618.6
Cost of sales(412.2) (1,567.6) (17.9) (1,330.6) 83.0
 (3,245.3)
Operating expenses(181.8) (105.9) (30.3) (101.9) —
 (419.9)
Gain on derivative activity—
 —
 —
 —
 9.4
 9.4
Segment profit$406.2
 $166.8
 $138.8
 $65.7
 $9.4
 $786.9
Depreciation and amortization$(169.7) $(109.1) $(49.8) $(51.5) $(7.2) $(387.3)
Impairments$(496.3) $(787.3) $(0.6) $(279.2) $—
 $(1,563.4)
Goodwill$703.5
 $—
 $190.3
 $93.2
 $1,426.9
 $2,413.9
Capital expenditures$268.0
 $59.2
 $40.7
 $187.5
 $15.1
 $570.5
Total assets$3,709.5
 $2,309.3
 $873.4
 $898.0
 $1,751.1
 $9,541.3

The following table reconciles the segment profits reported above to the operating income (loss) as reported on the consolidated statements of operations (in millions):

 Year Ended December 31,
 2017 2016 2015
Segment profits$959.4
 $838.4
 $786.9
General and administrative expenses(128.6) (122.5) (136.9)
Depreciation and amortization(545.3) (503.9) (387.3)
Loss on disposition of assets—
 (13.2) (1.2)
Impairments(17.1) (873.3) (1,563.4)
Gain on litigation settlement26.0
 —
 —
Operating income (loss)$294.4
 $(674.5) $(1,301.9)


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(17) Quarterly Financial Data (Unaudited)
PermianLouisianaOklahomaNorth TexasCorporateTotals
Year Ended December 31, 2019
Natural gas sales$94.3 $416.6 $236.4 $129.3 $— $876.6 
NGL sales0.9 1,725.6 19.6 30.9 — 1,777.0 
Crude oil and condensate sales1,975.0 291.9 109.6 — — 2,376.5 
Product sales2,070.2 2,434.1 365.6 160.2 — 5,030.1 
Natural gas sales—related parties0.4 — — — (0.4)— 
NGL sales—related parties347.7 25.7 421.1 94.8 (889.3)— 
Crude oil and condensate sales—related parties13.5 1.7 — 5.5 (20.7)— 
Product sales—related parties361.6 27.4 421.1 100.3 (910.4)— 
Gathering and transportation48.8 58.3 234.5 196.4 — 538.0 
Processing30.5 3.2 138.2 143.0 — 314.9 
NGL services— 50.6 — 0.1 — 50.7 
Crude services19.2 51.9 19.8 — — 90.9 
Other services12.0 0.7 0.1 1.1 — 13.9 
Midstream services110.5 164.7 392.6 340.6 — 1,008.4 
NGL services—related parties— (3.4)— — 3.4 — 
Crude services—related parties— — 1.8 — (1.8)— 
Midstream services—related parties— (3.4)1.8 — 1.6 — 
Revenue from contracts with customers2,542.3 2,622.8 1,181.1 601.1 (908.8)6,038.5 
Cost of sales, exclusive of operating expenses and depreciation and amortization (1)(2,283.9)(2,181.6)(627.0)(208.8)908.8 (4,392.5)
Realized gain on derivatives9.4 5.1 — — — 14.5 
Change in fair value of derivatives1.5 (1.8)— 0.2 — (0.1)
Adjusted gross margin269.3 444.5 554.1 392.5 — 1,660.4 
Operating expenses(112.9)(147.3)(104.0)(102.9)— (467.1)
Segment profit156.4 297.2 450.1 289.6 — 1,193.3 
Depreciation and amortization(119.8)(154.1)(194.9)(139.8)(8.4)(617.0)
Impairments(3.5)(188.7)(813.5)(127.8)— (1,133.5)
Gain (loss) on disposition of assets(0.3)2.6 0.1 (0.5)— 1.9 
General and administrative— — — — (152.6)(152.6)
Loss on secured term loan receivable— — — — (52.9)(52.9)
Interest expense, net of interest income— — — — (216.0)(216.0)
Loss from unconsolidated affiliates— — — — (16.8)(16.8)
Other income— — — — 0.9 0.9 
Income (loss) before non-controlling interest and income taxes$32.8 $(43.0)$(558.2)$21.5 $(445.8)$(992.7)
Capital expenditures$364.5 $99.9 $238.1 $39.0 $6.9 $748.4 
____________________________

Summarized unaudited quarterly financial data is presented below (in millions, except per unit data):

(1)Includes related party cost of sales of $21.7 million for the year ended December 31, 2019.
141
 First Quarter Second Quarter Third Quarter Fourth Quarter Total
2017         
Revenues$1,321.9
 $1,263.6
 $1,397.9
 $1,756.2
 $5,739.6
Impairments$7.0
 $—
 $1.8
 $8.3
 $17.1
Operating income$56.5
 $68.9
 $72.1
 $96.9
 $294.4
Net income (loss) attributable to non-controlling interest$11.2
 $21.2
 $17.9
 $56.9
 $107.2
Net income (loss) attributable to EnLink Midstream, LLC$(1.9) $5.9
 $6.2
 $202.6
 $212.8
Net income (loss) attributable to EnLink Midstream, LLC per unit:         
Basic common unit$(0.01) $0.03
 $0.03
 $1.12
 $1.18
Diluted common unit$(0.01) $0.03
 $0.03
 $1.11
 $1.17

2016         
Revenues$889.7
 $1,033.2
 $1,104.6
 $1,224.9
 $4,252.4
Impairments$873.3
 $—
 $—
 $—
 $873.3
Operating income (loss)$(824.8) $45.2
 $65.9
 $39.2
 $(674.5)
Net income (loss) attributable to non-controlling interest$(413.7) $0.4
 $10.4
 $(25.3) $(428.2)
Net income (loss) attributable to EnLink Midstream, LLC$(457.6) $0.8
 $0.7
 $(3.9) $(460.0)
Net income (loss) attributable to EnLink Midstream, LLC per unit:         
Basic common unit$(2.56) $0.01
 $—
 $(0.02) $(2.56)
Diluted common unit$(2.56) $0.01
 $—
 $(0.02) $(2.56)
2015         
Revenues$940.5
 $1,274.5
 $1,170.6
 $1,066.5
 $4,452.1
Impairments$—
 $—
 $799.2
 $764.2
 $1,563.4
Operating income (loss)$50.5
 $71.4
 $(731.8) $(692.0) $(1,301.9)
Net income (loss) attributable to non-controlling interest$8.0
 $28.4
 $(562.5) $(528.4) $(1,054.5)
Net income (loss) attributable to EnLink Midstream, LLC$17.0
 $16.2
 $(193.4) $(195.0) $(355.2)
Net income (loss) attributable to EnLink Midstream, LLC per unit:         
Basic common unit$0.10
 $0.09
 $(1.18) $(1.18) $(2.17)
Diluted common unit$0.10
 $0.09
 $(1.18) $(1.18) $(2.17)


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

The table below represents information about segment assets as of December 31, 2021 and 2020 (in millions):
(18)
Segment Identifiable Assets:December 31, 2021December 31, 2020
Permian$2,358.6 $2,236.3 
Louisiana2,428.6 2,312.4 
Oklahoma2,619.5 2,847.6 
North Texas896.8 1,008.6 
Corporate (1)179.7 146.0 
Total identifiable assets$8,483.2 $8,550.9 
____________________________
(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.

(16) Supplemental Cash Flow Information


The following schedule summarizes cash paid for interest, cash paid for income taxes, cash paid for finance leases included in cash flows from financing activities, cash paid for operating leases included in cash flows from operating activities, non-cash investing activities, and non-cash financing activities for the periods presented (in millions):

Year Ended December 31,
Supplemental disclosures of cash flow information:202120202019
Cash paid for interest$208.8 $207.3 $218.9 
Cash paid (refunded) for income taxes$0.3 $(0.7)$4.0 
Cash paid for finance leases included in cash flows from financing activities$— $— $1.2 
Cash paid for operating leases included in cash flows from operating activities$24.6 $24.6 $29.8 
Non-cash investing activities:
Non-cash accrual of property and equipment$12.0 $(39.6)$(6.5)
Non-cash right-of-use assets obtained in exchange for operating lease liabilities$18.7 $9.8 $104.1 
Non-cash acquisitions$16.9 $— $— 
Non-cash financing activities:
Receivable from sale of VEX$— $10.0 $— 
Redemption of non-controlling interest$— $(4.0)$— 

142
  Year Ended December 31,
Non-cash financing activities: 2017 2016 2015
Non-cash issuance of common units (1) $—
 $214.9
 $—
Installment payable, net of discount of $79.1 million (2) —
 420.9
 —
Non-cash issuance of ENLK common units (3) —
 —
 180.0
Non-cash issuance of ENLK Class C common units (3) —
 —
 180.0
(1)Non-cash ENLC Common Units were issued as partial consideration for the acquisition of EnLink Oklahoma T.O. assets. See “Note 3—Acquisitions” for further discussion.
(2)ENLK incurred installment purchase obligations, net of discount, payable to the seller in connection with EnLink Oklahoma T.O. assets. ENLK paid the second and final installments during January 2017 and 2018, respectively. See “Note 3—Acquisitions” for further discussion.
(3)Non-cash common units and Class C common units were issued by ENLK as partial consideration for the Coronado acquisition. See “Note 3—Acquisitions” for further discussion.

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES
Notes to Consolidated Financial Statements (continued)
(19)(17) Other Information


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


Other current assets:December 31, 2021December 31, 2020
Natural gas and NGLs inventory$49.4 $44.9 
Prepaid expenses and other34.2 13.8 
Other current assets$83.6 $58.7 

Other current liabilities:December 31, 2021December 31, 2020
Accrued interest$47.2 $35.7 
Accrued wages and benefits, including taxes33.1 22.5 
Accrued ad valorem taxes28.3 26.5 
Capital expenditure accruals23.2 10.6 
Short-term lease liability18.1 16.3 
Installment payable (1)10.0 — 
Inactive easement commitment (2)9.8 — 
Operating expense accruals9.6 8.4 
Other23.6 29.1 
Other current liabilities$202.9 $149.1 
____________________________
(1)Consideration paid for the acquisition of Amarillo Rattler, LLC included an installment payable to be 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.
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Other Current Assets: December 31, 2017 December 31, 2016
Natural gas and NGLs inventory $30.1
 $17.4
Prepaid expenses and other 11.1
 16.1
Natural gas and NGLs inventory, prepaid expenses and other $41.2
 $33.5

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES
Notes to Consolidated Financial Statements (continued)
(18) Subsequent Event

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.
144
Other Current Liabilities: December 31, 2017 December 31, 2016
Accrued interest $35.6
 $34.2
Accrued wages and benefits, including taxes 30.4
 19.0
Accrued ad valorem taxes 27.8
 23.5
Capital expenditure accruals 48.8
 64.6
Onerous performance obligations 15.2
 15.9
Other 65.1
 60.3
Other current liabilities $222.9
 $217.5
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Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure


None.


Item 9A. Controls and Procedures


(a) Evaluation of Disclosure Controls and Procedures


Management of the Managing Member is responsible for establishing and maintaining adequate internal control over financial reporting and for the assessment of the effectiveness of internal control over financial reporting for us. We carried out an evaluation, under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer of EnLink Midstream GP, LLC,the Managing Member, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report pursuant to Exchange Act Rules 13a-15 and 15d-15. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of the period covered by this report (December 31, 2017)2021), our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported, within the time period specified in the applicable rules and forms, and that such information is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding disclosure. KPMG LLP, the independent registered public accounting firm that audited the Company’s consolidated financial statements included in this report, has issued an attestation report on the Company’s internal control over financial reporting, a copy of which appears in “Item 8. Financial Statements and Supplementary Data—Management’s Report on Internal Control over Financial Reporting.”


(b) Changes in Internal Control Over Financial Reporting


There has been no change in our internal control over financial reporting that occurred in the three months ended December 31, 20172021 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.


Internal Control Over Financial Reporting


See “Item 8. Financial Statements and Supplementary Data—Management’s Report on Internal Control over Financial Reporting.”


Item 9B. Other Information


None.Disclosure Pursuant to Item 1.01 of Form 8-K – Entry into a Material Definitive Agreement.



On February 15, 2022, ENLC and each of GIP III Stetson I, L.P. and GIP III Stetson II, L.P., the holders of approximately 41.7%, in the aggregate, of the outstanding ENLC common units (together “GIP Entities”) and, in the case of GIP III Stetson I, L.P., the owner of all of the equity interests in the Managing Member, entered into a Unit Repurchase Agreement (the “Repurchase Agreement”) pursuant to which ENLC agreed to repurchase, on a quarterly basis, a number of ENLC common units held by the GIP Entities (the “GIP Units”) based upon the number of common units repurchased from public unitholders by ENLC during the applicable quarter under ENLC’s common unit repurchase program. Under the Repurchase Agreement, following each fiscal quarter beginning with the quarter ending March 31, 2022, ENLC will repurchase from the GIP Entities a number of GIP Units equal to (i) the aggregate number of common units repurchased by ENLC in the open market during such quarter (or from the period beginning on the execution date of the Repurchase Agreement for the quarter ending March 31, 2022), multiplied by (ii) a percentage such that the GIP Entities’ then-existing economic ownership percentage of outstanding ENLC common units is maintained after the open market repurchases are taken into account. The initial percentage will be adjusted each quarter, as necessary, so that the GIP Entities’ economic ownership interest will remain the same after giving effect to the open market repurchases. The per unit price ENLC will pay for the GIP Units will be the average per unit price paid by ENLC for the common units repurchased from public unitholders during the applicable quarter.

The repurchase of GIP Units by ENLC will occur one business day before ENLC’s reporting of earnings for such quarter. ENLC will disclose in its periodic reports filed with the Commission the number of GIP units purchased by ENLC with respect to each quarter.

The Repurchase Agreement will be terminated after the authorized funds under ENLC’s current $100 million common unit repurchase program have been expended, including funds applied to repurchases under the Repurchase Agreement, or otherwise upon the mutual agreement of the parties thereto.
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The terms of the Repurchase Agreement were unanimously approved by the Board and, based upon the related party nature of the Repurchase Agreement with the GIP Entities, the Conflicts Committee of the Board.

The foregoing description of the Repurchase Agreement does not purport to be complete and is qualified in its entirety by reference to the full text of the Repurchase Agreement, a copy of which is filed as Exhibit 10.20 to this report and is incorporated herein by reference. For more information on ENLC’s common unit repurchase program, see “Item 5—Market for Registrant’s Common Equity, Related Unitholder Matters, and Issuer Purchases of Equity Securities—Purchases of Equity Securities,” in this report.

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PART III


Item 10. Directors, Executive Officers, and Corporate Governance


We are managed by the board of directors and executive officers of the Managing Member. The Managing Member is not elected by our unitholders and will not be subject to re-election by our unitholders in the future. The Managing Member has a board of directors, and our common unitholders are not entitled to elect the directors or to participate directly or indirectly in our management or operations. Our operational personnel are employees of EnLink Midstreamthe Operating LP (the “Operating Partnership”).Partnership. References to our officers, directors, and employees are references to the officers, directors, and employees of the General PartnerManaging Member or the Operating Partnership.


The following table shows information for the members of the boardBoard of directorsDirectors of the Managing Member (the “Board”) and the executive officers of EnLink Midstream Manager, LLC, our managing member (the “Managing Member”).the Managing Member. Executive officers and directors serve until their successors are duly appointed or elected.

NameAgePosition with EnLink Midstream GP,Manager, LLC
Michael J. GarberdingBarry E. Davis4960PresidentChairman and Chief Executive Officer and Director
EricBenjamin D. BatchelderLamb4642Executive Vice President and Chief Operating Officer
Pablo G. Mercado45Executive Vice President and Chief Financial Officer
McMillan (Mac) HummelAlaina K. Brooks5547Executive Vice President, Chief Legal and President of Natural Gas LiquidsAdministrative Officer, and CrudeSecretary
Benjamin D. LambDeborah G. Adams (1)3861Executive Vice President, North Texas and Oklahoma (1)
Alaina K. Brooks43Senior Vice President, General Counsel and Secretary
Barry E. Davis56Director and Executive Chairman of the Board
James C. Crain (2)69Director and Member of the Audit and Conflicts (3)Sustainability (2) Committees
Leldon E. Echols (2)William J. Brilliant6246Director and Member of the Audit Committee (3)
Rolf A. Gafvert (2)64Director and Member of the Conflicts and Governance and Compensation (3) Committees
David A. Hager61Director and Member of the Governance and Compensation Committee
Mary P. Ricciardello (2)Tiffany Thom Cepak (1)6248Director and Member of the Audit Committeeand Conflicts Committees
Kevin D. LaffertyLeldon E. Echols (1)4266Director and Member of the Governance and Compensation and Audit (2) Committees
R. Alan MarcumThomas W. Horton5160Director
Jeff L. RitenourJames K. Lee4440Director
Lyndon TaylorScott E. Telesz5854Director and Member of the Sustainability Committee
Kyle D. Vann (1)74Director and Member of the Conflicts (2) and Governance and Compensation (2) Committees
____________________________
(1) In February 2018, the Board appointed Mr. Lamb toIndependent director.
(2)Chairperson of committee.

Barry E. Davis, Chairman and Chief Executive Vice President, North Texas and Oklahoma. Prior to February 2018, Mr. LambOfficer, has served in this position since August 2019, after serving as Executive Vice President, Corporate Development.
(2) Independent director.
(3) Chairman of committee.

Michael J. Garberding,from January 2018 to August 2019, as Chairman and Chief Executive Officer from September 2016 until January 2018, and as President and Chief Executive Officer from our formation until September 2016. Mr. Davis has held management roles in the energy industry since 1984. Mr. Davis led our predecessor, Crosstex Energy, from its founding in 1996 through its merger with Devon to create ENLC. During this time, Crosstex Energy completed the initial public offerings of Crosstex Energy, L.P. in 2002 and Director, joinedCrosstex Energy, Inc. in 2004. Crosstex Energy was formed in 1996 when Mr. Davis led the General Partner in February 2008.management buyout of the midstream assets of Comstock Natural Gas, Inc., a subsidiary of Comstock Resources, Inc. Prior to the formation of Crosstex Energy, Mr. GarberdingDavis was appointed President and Chief ExecutiveOperating Officer effective January 2, 2018. Previously,of Comstock Natural Gas and founder of Ventana Natural Gas, a gas marketing and pipeline company that was purchased by Comstock Natural Gas. In addition to serving on our Board of Directors, Mr. Garberding assumedDavis is a Trustee of Texas Christian University (TCU) and a board member of the roleKirby Corp. and several other civic and nonprofit organizations. Mr. Davis is a member and former president of Presidentthe Natural Gas and Chief Financial OfficerElectric Power Society, Dallas Wildcat Committee, and the Dallas Petroleum Club, as well as a member of the World Presidents Organization and the National Petroleum Council. Mr. Davis holds a Bachelor of Business Administration in September 2016,Finance from Texas Christian University. Mr. Davis’s leadership skills and experience in the midstream natural gas industry, among other factors, led the Board to conclude that he should serve as a director.

Benjamin D. Lamb, Executive Vice President and Chief FinancialOperating Officer, has served in January 2013 and Senior Vice President and Chief Financial Officerthis position since June 2018. Mr. Lamb previously served in August 2011. Mr. Garberding previously led our finance and business development organization. Mr. Garberding has 25 yearsa number of experience in finance and accounting. From 2002 to 2008, Mr. Garberding held various finance and business development positions at TXU Corporation, including assistant treasurer. In addition, Mr. Garberding worked at Enron North Americaleadership roles, most recently as a Finance Manager and Arthur Andersen LLP as an Audit Manager. He received his Master of Business Administration from the University of Michigan in 1999 and his Bachelor of Business Administration in accounting from Texas A&M University in 1991. Mr. Garberding was selected to serve as a director due to, among other factors, his accounting and financial experience, his leadership skills, and his experience in the midstream industry.

Eric D. Batchelder, Executive Vice President and Chief Financial Officer, joined the General Partner in January 2018. Prior to joining the General Partner, Mr. Batchelder served five years as Managing Director, Energy Investment Banking at RBC Capital Markets. At RBC, he was responsible for maintaining key client relationships, strategic planning, and business development efforts for the bank’s midstream energy advisory business in the United States. Previously, Mr. Batchelder spent 10 years at Goldman Sachs & Co. Prior to that, he spent seven years at Arthur Andersen LLP. Mr. Batchelder has over 15 years

of strategic M&A and capital markets experience in the energy sector. Mr. Batchelder is a Certified Public Accountant. He earned a Bachelor of Arts in economics from Middlebury College, a Master of Science in professional accounting from the University of Hartford and a Master of Business Administration from The Tuck School of Business at Dartmouth.

McMillan (Mac) Hummel, Executive Vice President and President of Natural Gas Liquids and Crude, joined the General Partner in March 2014. Previously, Mr. Hummel served in various positions with The Williams Companies, which he joined in 1985, including Vice President of Commodity Services, Vice President of Natural Gas Liquids and Petchem Services and Vice President of Western Region Gathering and Processing. Mr. Hummel began his career with Williams’ Northwest Pipeline while living in Salt Lake City, Utah. Mr. Hummel also served as Director of Business Development for Williams while living in Calgary, Alberta. Mr. Hummel has been a member of the American Fuel & Petrochemical Manufacturers Petrochemical Committee, the Association of Oil Pipe Lines Pipeline Subcommittee and the board of Aux Sable Liquids Partners. Mr. Hummel earned a Bachelor of Science in accounting and a Master of Business Administration from the University of Utah.

Benjamin D. Lamb, Executive Vice President, President—North Texas and Oklahoma joined the General Partner in December 2012. Mr. Lamb assumed his current role infrom February 2018 havingto June 2018 and previously served as Executive Vice President, President—Corporate Development, Vice President of Finance and Senior Vice President of President—Finance and Corporate Development.Development, and Vice President—Finance from December 2012 to February 2018. Prior to joining the General Partner,December 2012, Mr. Lamb served as a Principal at the investment banking firm Greenhill & Co., which he joined in 2005. In that role, he focused on the evaluation and execution of mergers, acquisitions, and restructuring transactions for clients primarily in the midstream energy, power, and utility industries. Prior to joining Greenhill, he served as an investment banker at
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UBS Investment Bank in its Mergers and Acquisitions Group and in its Global Energy Group, and at Merrill Lynch in its Global Energy and Power Group. Mr. Lamb received his Bachelor of Business Administration from Baylor University in 2000.


Pablo G. Mercado, Executive Vice President and Chief Financial Officer, has served in this position since July 2020. Prior to July 2020, Mr. Mercado served as Senior Vice President and Chief Financial Officer of Forum Energy Technologies, Inc. (“Forum Energy”) from March 2018 to July 2020. Mr. Mercado also previously held various finance and corporate development positions at Forum Energy since joining in November 2011, including Senior Vice President, Finance from June 2017 to March 2018 and Vice President, Operations Finance from August 2015 to June 2017. Prior to Forum Energy, Mr. Mercado was as an investment banker with the Oil and Gas Group of Credit Suisse from 2005 to October 2011. Between 1998 and 2005, Mr. Mercado was an investment banker at UBS Investment Bank and Bank of America Merrill Lynch, working primarily with companies in the oil and gas industry. Mr. Mercado holds a Bachelor of Business Administration and a Bachelor of Arts in Economics from Southern Methodist University and a Master of Business Administration from The University of Chicago Booth School of Business. He currently serves on the Board of Directors of Comfort Systems USA, Inc. as the chair of the Audit Committee and a member of the Governance Committee and on the Board of Directors of the Energy Infrastructure Council, a non-profit trade association for companies that develop and operate energy infrastructure.

Alaina K. Brooks, Executive Vice President, Chief Legal and Administrative Officer, and Secretary, has served in this position since June 2018. Ms. Brooks was appointed as a director of the General Partner in January 2019. Ms. Brooks previously served in a number of our leadership roles, most recently as Senior Vice President, General Counsel and Secretary joined the General Partner in 2008. Ms. Brooks has served in several legal roles within our company, most recentlyfrom September 2014 until June 2018 and as Deputy General Counsel before assuming the role of Senior Vice President, General Counsel and Secretary inuntil September 2014. In Ms. Brooks’ current role, she serves on our SeniorExecutive Leadership Team and leads the legal, regulatory, public and industry affairs, contract administration, and the environmental health and safetyhuman resources functions. Before joining the General Partner inPrior to 2008, Ms. Brooks practiced law at Weil, Gotshal & Manges LLP and Baker Botts LLP,L.L.P., where she counseled clients on matters of complex commercial litigation, risk management, and taxation. Ms. Brooks is a licensed Certified Public Accountant and holds a Juris Doctor from Duke University School of Law and Bachelor of Science and Master of Science in accounting from Oklahoma State University.


Barry E. Davis, Executive Chairman, led the management buyout of the midstream assets of Comstock Natural Gas, Inc. in December 1996, which resulted in the formation of Crosstex Energy, Inc. Mr. Davis was appointed to Executive Chairman effective January 2, 2018. Previously, Mr. Davis served as Chairman and Chief Executive Officer from June 2016 until January 1, 2018 and as President and Chief Executive Officer from our formation until June 2016. Mr. DavisDeborah G. Adams has served as a director of the Managing Member since our initial public offering in December 2002. Mr. Davis was President and Chief Operating Officer of Comstock Natural Gas and founder of Ventana Natural Gas, a gas marketing and pipeline company that was purchased by Comstock Natural Gas. Mr. Davis started Ventana Natural Gas in June 1992. Prior to starting Ventana, he wasFebruary 2020. Ms. Adams served on the Executive Leadership Team at Phillips 66 as Senior Vice President of MarketingHealth, Safety, and Project DevelopmentEnvironment, Projects and Procurement from 2014 until her retirement in October 2016. Ms. Adams previously served as Division President, Transportation for Endevco,Phillips 66 and ConocoPhilipps from 2008 to 2014.Prior to this time, Ms. Adams held various leadership positions at ConocoPhillips, including Chief Procurement Officer, General Manager, International Refining, and Manager, Global Downstream Information Systems.She has also served on several of ConocoPhillips’ joint venture boards. Ms. Adams currently serves as a director of MRC Global, Inc. Before joining Endevco, Mr. Davisand Austin Industries, an employee-owned construction company.Ms. Adams previously served as a director of Gulfport Energy Corporation from March 2018 until May 2021. Ms. Adams has also served as a member of the Oklahoma State University Foundation Board of Trustees and on the University’s Board of Governors. In 2014, she was employed by Enserch Explorationinducted into the Oklahoma State University College of Engineering, Architecture and Technology Hall of Fame, and in 2015, the National Diversity Council named Adams to the list of the Top 50 Most Powerful Women in Oil and Gas. Ms. Adams received a Bachelor of Science in chemical engineering from Oklahoma State University.Ms. Adams was selected to serve as a director due to, among other factors, her extensive experience in the marketing group.energy sector, including midstream, her leadership skills and her business experience, including her expertise in a wide range of operational areas.

William J. Brilliant has served as a director of the Managing Member since July 2018. Mr. DavisBrilliant served as a director of the General Partner from July 2018 until January 2019. Mr. Brilliant is a Partner and leader of GIP’s energy investment business. Mr. Brilliant is a member of GIP’s Investment and Operating Committees and has been a member of GIP’s investment team since 2007. Prior to joining GIP, he was an investment banker at Lehman Brothers. Mr. Brilliant currently serves on the boards of directors of Hess Midstream Partners GP LLC and Hess Infrastructure Partners. He previously served as a director of the general partner of Access Midstream Partners L.P. from June 2012 through July 2014. Mr. Brilliant holds a B.A. from the University of California at Los Angeles and an M.B.A. from the Wharton School of the University of Pennsylvania. Mr. Brilliant was selected to serve as a director due to, among other factors, his energy industry background, particularly his expertise in mergers and acquisitions.

Tiffany Thom Cepak has served as a director of the Managing Member since December 2021. Ms. Cepak most recently served as the Chief Financial Officer of Energy XXI Gulf Coast, Inc., an oil and natural gas development and production company, until its sale in October 2018. She also served as the Chief Financial Officer of KLR Energy Acquisition Corp. (and, subsequent to its business combination, Rosehill Resources Inc.) and as Chief Financial Officer of EPL Oil & Gas, Inc. She previously held a number of other positions with EPL, including Treasurer, Director of Investor Relations, and Director of Corporate Reserves. She began her career as a Senior Reservoir Engineer with Exxon Production Co. and Exxon Mobil Co. with operational roles, including reservoir and subsurface completion engineering. Ms. Cepak currently serves on the board of directors of Ranger Oil Corp., Patterson-UTI Energy, Inc., and California Resources Corp., where she serves as Board Chair,
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and previously served as a director of Yates Petroleum Corp. She holds a Bachelor of Science in engineering from the University of Illinois and a Master of Business Administration in Finance from Texas ChristianTulane University. Mr. Davis’s leadership skills andMs. Cepak was selected to serve as a director due to, among other factors, her extensive experience in the midstream natural gas industry, among other factors, led the Company Board to conclude that he should serve as Executive Chairman of the Board.energy sector and her engineering, operational, and finance experience.


James C. Crain joined Crosstex Energy, Inc. as a director in July 2006 andLeldon E. Echols has served as a director of the Managing Member since March 2014. Mr. Crain retired as president of Marsh Operating Company in July 2013, where he worked since 1984 and currently serves as an advisorEchols joined Crosstex Energy, Inc, the predecessor to Marsh Operating Company and is a private investor. In addition, Mr. Crain servesENLC, as a consultant for Yorktown Partners, LLC, an energy oriented private equity fund, where he advises certain portfolio companiesdirector in connection with their business activities. Prior to Marsh, he was a partner at the law firm of Jenkens & Gilchrist.January 2008. Mr. Crain also serves on the board of Approach Resources, Inc. Mr. CrainEchols served as a director of the General Partner from December 2005 to August 2008. He graduated from the University of Texas at Austin with a B.B.A. degree, a master of professional accounting and a doctor of jurisprudence. Mr. Crain was selected to serve as a director due to his legal background and his experience in the oil and natural gas industry, among other factors.

Leldon E. Echols joined Crosstex Energy, Inc. as a director inMarch 2014 until January 2008. 2019.Mr. Echols is a private investor. Mr. Echols also currently serves as an independent director of Trinity Industries, Inc. and HollyFrontier Corporation, an independent petroleum refiner and marketer.Corporation. Mr. Echols brings over 30 years of financial and business experience to the Board. After 22 years with the accounting firm Arthur Andersen LLP, which included serving as managing partner of the firm’s audit and business advisory practice in North Texas, Colorado, and Oklahoma, Mr. Echols spent six years with Centex Corporation as executive

vice president and chief financial officer. He retired from Centex Corporation in June 2006. Mr. Echols previously served as a member of the board of directors of Roofing Supply Group Holdings, Inc., a private company. He also served on the board of TXU Corporation where he chaired the Audit Committee and was a member of the Strategic Transactions Committee until the completion of the private equity buyout of TXU in October 2007. Mr. Echols earned a Bachelor of Science in accounting from Arkansas State University. He is a member of the American Institute of Certified Public Accountants and the Texas Society of CPAs. Mr. Echols was selected to serve as a director due to his accounting and financial experience and service as the chief financial officer for another public company, among other factors.


Rolf A. GafvertThomas W. Horton has served as a director of the Managing Member since March 7, 2014.August 2019. Mr. GafvertHorton is a Partner at GIP. Prior to joining GIP, Mr. Horton was President, CEOa senior advisor at Warburg Pincus, LLC, a private equity firm from 2015 to 2019. He was the chairman of American Airlines Group Inc. from 2013 to 2014 and chairman, president, and chief executive officer of American Airlines Inc. and AMR Corp. from 2011 to 2013 after being named president of American Airlines in 2010. Previously, he served as executive vice president and chief financial officer of AMR and American Airlines from 2006 to 2010 and vice chairman and chief financial officer of AT&T Corp. from 2002 to 2006. Mr. Horton currently serves as a director of Boardwalk GP, LLP,General Electric Co. and Walmart Inc. He also serves on the general partnerexecutive board of Boardwalk Pipeline Partners, LP from 2007the Cox School of Business at Southern Methodist University. Mr. Horton was selected to 2011. serve as a director due to, among other factors, his extensive executive and financial experience, business expertise, and leadership skills.

James K. Lee has served as a director of the Managing Member since February 2020. Mr. Lee is an Investment Principal at GIP and a key member of GIP’s North American energy investment business. Mr. Lee has been a member of GIP’s investment team since 2009. Prior to that,joining GIP, Mr. GafvertLee was an investment banker at Goldman Sachs & Co. Mr. Lee previously served as Co-Presidenton the Board of Boardwalk GP, LLC from 2005 to 2007.Directors of Competitive Power Ventures, a privately held electric power generation development and asset management company. Mr. Gafvert served as President of Gulf South Pipeline, which became affiliated with Boardwalk Pipeline Partners, LP in 2005, from 2000 to 2011. Mr. Gafvert was involved in Gulf South and its affiliates from 1993 to 2000, including acting as Managing Director of Koch Energy International, VP of Corporate Development for Koch Energy, Inc. and President of Gulf South. HeLee holds a Master’s degree in Agricultural EconomicsBachelor of Commerce (Honors and University Medal) and a Bachelor of Laws from the University of New South Wales. Mr. Lee was selected to serve as a director due to, among other factors, his energy industry background and his banking and financial experience.

Scott E. Telesz has served as a director of the Managing Member since December 2020. Mr. Telesz is an Operating Partner of GIP and has over 25 years of experience in the manufacturing industry. Prior to joining GIP in August 2018, he spent 8 years as an executive at Praxair, an industrial gas manufacturing company, most recently as executive vice president in charge of Praxair’s U.S. atmospheric gases businesses, Praxair Canada and Praxair Surface Technologies from 2014 until May 2018. Before joining Praxair, Mr. Telesz spent 12 years at GE/SABIC where he ran various electrical products and plastics businesses. He currently serves on the board of directors of Hess Midstream GP LLC and of Edinburgh Airport. Mr. Telesz also serves on the Board of Visitors of Duke University’s Pratt School of Engineering. He earned a Bachelor of Science degree in Psychologyelectrical engineering from Iowa State University.Duke University in 1989 and a Master of Business Administration from Harvard Business School in 1994. Mr. GafvertTelesz was selected to serve as a director due to, among other factors, his extensive executive and business expertise, his engineering background, and his leadership skills.

Kyle D. Vann has served as a director of the Managing Member since January 2019 and served as a director of the General Partner from April 2016 until January 2019. Mr. Vann began his career with Exxon Corporation in 1969. After ten years at Exxon, he joined Koch Industries and served in various leadership capacities, including senior vice president from 1995-2000. In 2001, he then took on the role of CEO of Entergy-Koch, LP, an energy trading and transportation company, which was sold in 2004. Mr. Vann consulted with Entergy until 2020 and was an executive advisor to CCMP Capital Advisors, LLC from 2012-2017. He also serves on the board of directors of Ecovyst, Inc. and is on the advisory boards of Texon, L.P. and Refined Technologies, Inc. He also serves as a director on the Boards of Mars Hill Productions and Generous Giving, which are private, charitable non-profits. Mr. Vann graduated from the University of Kansas with a Bachelor of Science in chemical engineering. He is a member of the Board of Advisors for the University of Kansas School of Engineering (where he was a recipient of the Distinguished Engineering Service Award). Mr. Vann was selected to serve as a director due to his knowledge ofextensive experience in the energy businessindustry and his business expertise, among other factors.


David A. Hager has served as the President and Chief Executive officer
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Table of Devon since August 2015. Prior to that, Mr. Hager served as Chief Operating Officer of Devon since June 2013. He joined Devon in 2009 as Executive Vice President of Exploration and Production. Prior to Devon, Mr. Hager held several positions within Kerr-McGee Corp, most recently as Chief Operating Officer in the period just before its merger with Anadarko Petroleum. Mr. Hager was a Director and Chairman of the Reserves Committee on Devon’s Board from 2007 until 2009 and has served as a director for Pride International, Inc. the General Partner and the Managing Member Mr. Hager holds a Bachelor of Science in Geophysics from Purdue University and a Master of Science in Business Administration from Southern Methodist University. Mr. Hager was selected to serve as a director due to his affiliation with Devon, his knowledge of the energy business and his business expertise. Contents

Mary P. Ricciardello was Senior Vice President and Chief Accounting Officer at Reliant Energy Inc., a leading independent power producer and marketer until 2002. She began her career with Reliant in 1982 and served in various financial management positions with the company, including Comptroller, Senior Vice President and Chief Accounting Officer. Ms. Ricciardello has served as a director of the Managing Member and the General Partner since March 2014. Ms. Ricciardello also serves as a director on the boards of Devon and Noble Corporation and has served as a director on the Board of Midstates until March 2015. Ms. Ricciardello is also a NACD Board Leadership Fellow. Ms. Ricciardello holds a Bachelor of Science in Business Administration from the University of South Dakota and a Master of Science in Business Administration with an emphasis in Finance from the University of Houston. She is a licensed Certified Public Accountant. Ms. Ricciardello was selected to serve as a director due to her qualifications as a financial expert and her extensive experience in the energy industry, as well as corporate finance and tax matters.

Kevin D. Lafferty is Senior Vice President of Commercial and U.S. Operations of Devon, a position he has served in since April 2017. Mr. Lafferty oversees Devon’s Marketing, Supply Chain, Strategic Planning and EHS functions along with the North Texas and Southern business units. Mr. Lafferty previously served in roles at Devon of increasing responsibility, most recently as Senior Vice President of U.S. Operations. Prior to joining Devon in 2009, Mr. Lafferty worked for ConocoPhillips and Enbridge Inc. Mr. Lafferty holds a Bachelor of Science in chemical engineering from the University of Kansas. Mr. Lafferty serves on the boards of Youth and Family Services, Inc. and the Oklahoma City Ballet, and on the Advisory Board of the University of Kansas Department of Chemical and Petroleum Engineering. Mr. Lafferty was selected to serve as a director due to his affiliation with Devon, his knowledge of the energy business, and his financial and business expertise.

R. Alan Marcum was elected to the position of Executive Vice President Administration of Devon in 2008, and has been with Devon since 1995. Prior to joining Devon, Mr. Marcum was employed by KPMG Peat Marwick (now KPMG LLP) as a Senior Auditor. He earned a Bachelor of Science in accounting and finance from East Central University. Mr. Marcum is a Certified Public Accountant and a member of the Oklahoma Society of Certified Public Accountants. Mr. Marcum was selected to serve as a director due to his affiliation with Devon, his knowledge of the energy business, and his financial and business expertise.

Jeff L. Ritenour was elected to the position of Executive Vice President and Chief Financial Officer of Devon on April 19, 2017. He has been with Devon since 2001, serving in various leadership roles, including most recently as Senior Vice President Corporate Finance, Investor Relations and Treasurer. Prior to joining Devon, Mr. Ritenour was an auditor with the firm of Ernst & Young. He earned both a Bachelor of Business Administration in accounting and a Master of Business Administration from the University of Oklahoma and is a member of the Oklahoma Society of Certified Public Accountants. Mr. Ritenour was

selected to serve as a director due to his affiliation with Devon, his knowledge of the energy business, and his financial and business expertise.

Lyndon Taylor was elected to the position of executive vice president and general counsel for Devon in February 2007. Mr. Taylor had served as Devon’s deputy general counsel since August 2005. Prior to joining Devon, Taylor was with Skadden, Arps, Slate, Meagher & Flom, LLP for 20 years and served as managing partner of the firm’s Houston office from 1993 to 2005. He is admitted to practice law in Oklahoma and Texas. Taylor received his Bachelor of Science in industrial engineering from Oklahoma State University and his law degree from the University of Oklahoma. Mr. Taylor was selected to serve as a director due to his affiliation with Devon, his knowledge of the energy business, and his financial and business expertise.

Independent Directors


Because we are a “controlled company” within the meaning of the NYSE rules, the NYSE does not require the Board to be composed of a majority of directors who meet the criteria for independence required by the NYSE or to maintain nominating/corporate governance and compensation committees composed entirely of independent directors. Our Board has adopted Governance Guidelines that require at least three members of our Board to be independent directors as defined by the rules of the NYSE.


For a director to be “independent” under the NYSE standards, the Board must affirmatively determine that the director has no material relationship with the Company (either directly or as a partner, shareholder or officer of any organization that has a relationship with the Company, other than in his or her capacity as a director of the Company). In addition, the director must meet certain independence standards specified by the NYSE, including a requirement that the director was not employed by the Managing Member or engaged in certain business dealings with the Managing Member. Using these standards for determining independence, the Board has determined that Messrs. Crain,Vann and Echols Gafvert and Ms. RicciardelloMses. Adams and Cepak qualify as “independent” directors.


In addition, the members of the Audit Committee of our Board each qualify as “independent” under special standards established by the Securities and Exchange Commission (“SEC”) for members of audit committees, and the Audit Committee includes at least one member who is determined by our Board to meet the qualifications of an “audit committee financial expert” in accordance with SECCommission rules, including that the person meets the relevant definition of an “independent” director. Mr. Echols and Ms. Ricciardello are bothis an independent directorsdirector who havehas been determined to be an audit committee financial experts.expert. Unitholders should understand that this designation is a disclosure requirement of the SECCommission related to theirthe experience and understanding of the individual with respect to certain accounting and auditing matters. The designation does not impose on such directorsdirector any duties, obligations, or liabilities that are greater than are generally imposed on themthe director as membersa member of the Audit Committee and the Board, and the designation of a director as an audit committee financial expertsexpert pursuant to this SECCommission requirement does not affect the duties, obligations, or liabilities of any other member of the Audit Committee or the Board. Additionally, the Board has determined that the simultaneous service by Mr. Echols and Ms. Ricciardello on the Audit Committees of three other publicly traded companies on which they serve does not impair their ability to effectively serve on the Audit Committee of the Company.


Board Committees


The Board established threehas four standing committees in March 2014:committees: the Audit Committee, the Conflicts Committee, andthe Governance and Compensation Committee, and the Sustainability Committee. Each member of the Audit Committee is an independent director in accordance with the NYSE standards described above. Each of the Board committees has a written charter approved by the Board. Copies of the charters and our Code of Business Conduct and Ethics are available to any person, free of charge, at our website: www.enlink.com.


The Audit Committee, comprised of Mr. Echols (chair), Mr. Crain and Ms. RicciardelloMses. Adams and Cepak, assists the Board in its general oversight of our financial reporting, internal controls, and audit functions, and is directly responsible for the appointment, retention, compensation, and oversight of the work of our independent auditors.


The Conflicts Committee, comprised of Messrs. CrainMr. Vann (chair) and GafvertMs. Cepak, reviews specific matters that the Board believes may involve conflicts of interest. The Conflicts Committee determines if the resolution of a conflict of interest is fair and reasonable to us. The members of the Conflicts Committee are not directors, officers, or employees of EnLink Midstream GP, LLC.the General Partner. Any matters approved by the Conflicts Committee will be conclusively deemed to be fair and reasonable to us, approved by all of our unitholders, and not a breach by our Managing Member of any duties owed to us or our unitholders.



The Governance and Compensation Committee, is comprised of Messrs. GafvertVann (chair), Brilliant, and Hager. The Governance and Compensation CommitteeEchols, reviews matters involving governance, including assessing the effectiveness of current policies, monitoring industry developments, and overseesoverseeing certain compensation decisions as well as the compensation plans described herein.


The Sustainability Committee, comprised of Ms. Adams (chair) and Mr. Telesz, assists the Board Meetings and Attendance

Our Board met 11 times in 2017. Noneits general oversight of our incumbent directors attended fewer than 75%environmental, social and governance initiatives, including our environmental, health and safety and operational excellence initiatives, and also provides oversight with respect to identifying, evaluating and monitoring of the total numberrisks associated with such matters.

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Table of meetings of our Board and committees of our Board on which they served.Contents

Executive Sessions

The non-management directors meet in executive session without management participation at least quarterly. The non-management directors present at such executive sessions designate a director to preside at such meetings (the “Presiding Non-Management Director”). Unitholders or interested parties may communicate with non-management directors by sending written communications to the following address to the attention of the Presiding Non-Management Director: EnLink Midstream Manager, LLC, 1722 Routh St., Suite 1300, Dallas, Texas 75201.


Code of Ethics and Governance Guidelines


We adopted a Code of Business Conduct and Ethics (the “Code of Ethics”) applicable to all of our employees, officers, and directors with regard to company-related activities. The Code of Ethics incorporates guidelines designed to deter wrongdoing and to promote honest and ethical conduct and compliance with applicable laws and regulations. It also incorporates our expectations of our employees that enable us to provide accurate and timely disclosure in our filings with the SECCommission and other public communications. We also adopted Governance Guidelines (the “Governance Guidelines”) that outline the important policies and practices regarding our governance and provide an effective framework for the functioning of our Board. A copy of the Code of Ethics and the Governance Guidelines are available to any person, free of charge, within the “Governance Documents” subsection of the “Corporate Governance” section of the investors section of our website at www.enlink.com. If any substantive amendments are made to the Code of Ethics or if we grant any waiver, including any implicit waiver, from a provision of the Code of Ethics to any of our executive officers and directors, we will disclose the nature of such amendment or waiver on our website. The information contained on, or connected to, our website is not incorporated by reference into this Annual Report on Form 10-K and should not be considered part of this or any other report that we file with or furnish to the SEC.Commission.


Section 16(a)—Beneficial Ownership Reporting Compliance

Section 16(a) of the Securities Exchange Act of 1934 requires our directors, executive officers and 10% unitholders to file with the SEC reports of ownership and changes in ownership of our equity securities. Based solely upon a review of the copies of the Forms 3, 4 and 5 reports furnished to us and written representations from our directors and executive officers, we believe that during 2017, all of our directors, executive officers and beneficial owners of more than 10% of our common units complied with Section 16(a) filing requirements applicable to them.

Item 11. Executive Compensation


Governance and Compensation Committee Report


Each member ofKyle D. Vann and Leldon E. Echols, who serve on the Governance and Compensation Committee is anof our Managing Member (the “Committee”), are independent directordirectors in accordance with NYSE standards. The Governance and Compensation Committee has reviewed and discussed with management the following section titled “Compensation Discussion and Analysis.” Based upon its review and discussions, the Governance and Compensation Committee has recommended to the Board that the Compensation Discussion and Analysis be included in this Annual Report on Form 10-K.


By the Members of the Governance and Compensation Committee:


Rolf A. Gafvert (Chairman)Kyle D. Vann (chair)


David A. HagerWilliam J. Brilliant


Leldon E. Echols

Compensation Discussion and Analysis


The following Compensation Discussion and Analysis provides an overview of the philosophy and objectives of our executive compensation program. It explains how compensation decisions are linked to performance as comparedwith respect to our

strategic goals and defined targets under the elements of the compensation program. These goals and targets are disclosed in the limited context of our compensation programs and should not be understood to be statements of management’s expectations or estimates of results or other guidance.


Overview


We do not directly employ any of the persons responsible for managing our business. The Managing Member manages our operations and activities, and its board of directors (the “Board”)the Board and officers make decisions on our behalf. The compensation of the named executive officers and directors of the Managing Member is determined by the Board upon the recommendation of its Governance and Compensationthe Committee. Our named executive officers also serve as named executive officers of EnLink Midstream GP, LLC, the General Partner. Therefore, the compensation of the named executive officers discussed below reflects total compensation for services with respect to us and all our subsidiaries. We pay or reimburse all expenses incurred on our behalf, including the costs
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Table of employee, officer and director compensation and benefits, as well as all other expenses necessary or appropriate to the conduct of our business. We currently pay a monthly fee to the General Partner to cover our portion of administrative and compensation costs, including compensation costs relating to the named executive officers.

Based on the information that we track regarding the amount of time spent by each of our named executive officers on business matters relating to ENLC, we estimate that such officers devoted the following percentage of their time to the business of ENLK and ENLC for 2017:

Contents
Executive Officer Percentage of Time Devoted to Business of ENLK Percentage of Time Devoted to Business of ENLC
Michael J. Garberding (1) 60% 40%
Mac Hummel 90% 10%
Benjamin D. Lamb 90% 10%
Barry E. Davis (1) 80% 20%
Steve J. Hoppe (2) 90% 10%
__________________________
(1)In January 2018, the Board appointed Mr. Davis to Executive Chairman of the Board, Mr. Garberding to President and Chief Executive Officer and Mr. Batchelder to Executive Vice President and Chief Financial Officer. Prior to January 2018, Mr. Davis served as Chief Executive Officer and Chairman of the Board, and Mr. Garberding served as President and Chief Financial Officer.
(2)
In January 2018, Mr. Hoppe resigned from his position as Executive Vice President and President of Gas Gathering, Processing and Transmission.


Compensation Philosophy and Principles


Our executive compensation program is designed to attract, retain, and motivate highly qualified executives and align their individual interests with the interests of our unitholders. It is the Governance and Compensation Committee’s responsibility to design and administer compensation programs that achieve these goals, and to make recommendations to the Board to approve and adopt these programs. The total compensation of each of our executives is primarilygenerally comprised of base salary, annual bonus, and60% equity-based awards issued under our long-term incentive plans. The Governanceplan, 20% annual bonus awarded under the Short-Term Incentive Program (the “STI Program”), and Compensation Committee’s philosophy is to generally target the 50th percentile of our Peer Group (discussed below) for20% base salary and bonus (but retain discretion to reduce or increase bonus amounts to address individual performance) and to provide executives the opportunity to earn long-term incentive compensation, in the form of equity, targeted at the 75th percentile of our Peer Group.salary.

The Governance and Compensation Committee considers the following principles in determining the total compensation of the named executive officers:


•Base salary, short-term incentives, and long-term incentives should be competitive with the market in which we compete for executive talent in order to attract, retain, and motivate highly qualified executives;


•Equity-based awards under the long-term incentive plansplan should represent a significant portion of the executive’s total compensation in order to retain and incentivize highly qualified executives and to ensure all executives have a meaningful equity stake in us. Equity-based awards foster a culture of ownership and are a way to align their individual long-term interests with the interests of executives with those of our unitholders;



•The compensation program should be sufficiently flexible to address special circumstances, which include payments underincluding retention plansinitiatives specifically targeted to retain highly qualified executives during challenging times; and


•The compensation program should drive performance and reward contributions in support of our business strategies and achievements.


Compensation Methodology


Annually, the Governance and CompensationThe Committee annually reviews our executive compensation program and each individual element of compensation. The review includes an analysis of the compensation practices of other companies in our industry, the competitive market for executive talent, the evolving demands of the business, the specific challenges that we may face, and individual and group contributions made by our executives to us and the Managing Member. The Governance and Compensation Committee recommendsrecommended to the Board adjustments to the compensation program and to each individual element as determined necessary to achieve our goals. The Governance and Compensation Committee retains a compensation consultantsconsultant to assist in its review and to provide input regarding the compensation program and each individual element.


Role of Compensation Consultant


The Governance and Compensation Committee has retained Meridian Compensation Partners, LLCMercer (US) Inc., (“Meridian”Mercer”) as its independent compensation consultant to conduct a compensation review and advise the Governance and Compensation Committee on certain matters relating to compensation programs applicable to the named executive officers and other employees of the General Partner.Partner during 2021. In particular, Meridian hasMercer assisted in the Governance and Compensation Committee’s decision makingoverall decision-making process with respect to named executive officers and director compensation matters, including providing advice on our executive pay philosophy, compensation peer group, incentive plan design, and employment agreement design, providing competitive market studies, and informing the Governance and Compensation Committee about emerging best practices and changes in the regulatory and governance environment. Meridian provided information to the Governance and Compensation Committee regarding the compensation programs of ENLK and ENLC for 2017. Meridian’sMercer’s work for the Governance and Compensation Committee did not raise any conflicts of interest in 2017.2021.


Role of Peer Group and Benchmarking


For 2017, the Governance and CompensationThe Committee and MeridianMercer collaborated to identify the following companies as our peer companies: Boardwalk Pipelinecompanies in 2021: Crestwood Equity Partners, L.P., Buckeye Partners,DCP Midstream, L.P., Enable Midstream Partners, LP, Enbridge Inc.,Equitrans Midstream Corporation, Genesis Energy, L.P., HollyFrontier Corp., Magellan Midstream Partners, L.P., ONEOK Partners,MPLX, L.P., Pembina Pipeline Corp., Plains All American Pipeline,NuStar Energy L.P., Spectra Energy Corp.ONEOK Inc., Sunoco Logistics Partners, L.P.,and Targa Resources Corp., and Western Gas Partners, L.P. (the “Peer Group”). We believeThe Committee believes the Peer Group is representative of the industry in which we operate. The individual companies were chosen based on a number of factors, including each company’s relative size/market capitalization, relative complexity of its business, similar organizational structure, competition for similar executive talent, and the roles and responsibilities of its named executive officers. The Governance and Compensation Committee considers the Peer Group companies annually, and historically there have been few changes from year to year. Companies are typically added or removed from the Peer Group as the result of a change in organizational structure or relative size/market capitalization as compared to us.


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When evaluating annual compensation levels for each named executive officer, the Governance and Compensation Committee, with the assistance of Meridian,the compensation consultant, reviews compensation surveys and publicly available compensation data for executives in our Peer Group, including data on base salaries, annual bonuses, and long-term equity incentive awards. The Governance and Compensation Committee then uses that information to determine individual elements of compensation for the named executive officers in the context of their roles, levels of responsibility, accountability, and decision-making authority within our organization and in the context of company size relative to the other Peer Group members. In addition, Meridian has providedthe compensation consultant provides guidance on current industry trends and best practices to the Governance and Compensation Committee relating to all aspects of executive compensation.


While compensation surveys and Peer Group data are considered, the Governance and Compensation Committee does not attempt to set compensation elements to meet specific benchmarks. Accordingly, other subjective factors are also considered in setting compensation elements, including, but not limited to, (i) effort and accomplishment on a group and individual basis, (ii) challenges faced and challenges overcome, (iii) unique skills, (iv) contribution to the management team, (v) succession planning and retention of our executive officers, and (vi) the perception of both the Board and the Governance and Compensation Committee of our performance relative to expectations and actual market/business conditions.


Elements of Compensation


For fiscal year 2017,2021, the principal elements of compensation for the named executive officers were the following:


•base salary;
•annual bonus awards;
•long-term incentive plan equity awards;
•retirement and health benefits; and
•severance and change of control benefits.


The Governance and Compensation Committee reviews and makes recommendations regarding the mix of compensation, both among short- and long-term compensation and cash and non-cash compensation, to establish structures that it believes are appropriate for each of the named executive officers. We believe that the mix of base salary, annual bonus awards, long-term incentive plan equity awards, retirement and health benefits, severance and change of control benefits, and perquisites and other compensation fit our overall compensation objectives. We believe this mix of compensation provides opportunities to align and drive performance of our named executive officers in support of our strategic objectives and to attract, retain, and motivate highly qualified talent with the skills and competencies that we require.


Base Salary. The Governance and Compensation Committee recommends base salaries for the named executive officers based on the historical salaries for services rendered to us and our affiliates, Peer Group data provided by Meridian,the compensation consultant, compensation surveys, and performance and responsibilities of the named executive officers. The base salaries approved by the Board and paid to our named executive officers for fiscal year 20172021 (and payable for fiscal 2018)2022 beginning in March) are as follows:

2021 Base SalaryBase Salary Effective
March 2022		Percent Increase (Decrease)
Barry E. Davis$750,000 $784,000 4.5 %
Benjamin D. Lamb$507,000 $530,000 4.5 %
Pablo G. Mercado$465,000 $486,000 4.5 %
Alaina K. Brooks$465,000 $486,000 4.5 %

 Prior Salary Base Salary Effective
For 2018		 Percent Increase (Decrease)
Michael J. Garberding (1)$500,000
 $650,000
 30.0 %
Eric D. Batchelder (1)$—
 $380,000
 — %
Mac Hummel$420,000
 $435,000
 3.6 %
Benjamin D. Lamb (2)$345,000
 $435,000
 26.1 %
Barry E. Davis (1)$695,000
 $525,000
 (24.5)%
Steve J. Hoppe (3)$420,000
 $—
 — %
(1)In January 2018, the Board appointed Mr. Davis to Executive Chairman of the Board, Mr. Garberding to President and Chief Executive Officer and Mr. Batchelder to Executive Vice President and Chief Financial Officer. Prior to January 2018, Mr. Davis served as Chief Executive Officer and Chairman of the Board, and Mr. Garberding served as President and Chief Financial Officer.
(2)In February 2018, the Board appointed Mr. Lamb to Executive Vice President, North Texas and Oklahoma. Prior to February 2018, Mr. Lamb served as Executive Vice President, Corporate Development.
(3)
In January 2018, Mr. Hoppe resigned from his position as Executive Vice President and President of Gas Gathering, Processing and Transmission.

Bonus Awards. On March 3, 2017, the Board and the board of directors of the General Partner (the “ENLK Board”) approved various modifications to our short-term incentive program (as modified, the “STI Program”) based on recommendations from the Compensation Committee of ENLK (the “ENLK Compensation Committee”) and the Governance and Compensation Committee. The Board and the ENLK Board (collectively, the “Boards”) along with the ENLK Compensation Committee and the Governance and Compensation Committee (collectively, the “EnLink Compensation Committees”) oversee the STI Program. All employees, including named executive officers, of ENLK and ENLC, are eligible to receive annual bonuses under the STI Program. Bonuses awarded to employees and named executive officers under the STI Program are based on the achievement of certain metrics established to measure our success and are subject to the discretion of the BoardsBoard and the EnLink Compensation Committees.

Committee. The metrics employed by the STI Program contemplate that bonuses may be
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earned based primarily upon the achievement of certain core goals (collectively, the “Primary Bonus Components”), which may change from year-to-year. For 2021, the STI program included the following Primary Bonus Components:

•Financial. Adjusted EBITDA and free cash flow after distributions (“FCFAD”) to maximize financial performance.

•Capital Projects. Timely and cost-effective capital projects.

•Operational. Efficient use of systems, assets, and equipment for meeting contractual obligations, driving customer service, and maximizing cash flow.

•Safety and Sustainability. Prevention of safety incidents and improvement in safety compliance and training, commitment to environmental compliance, and support of our initiative for more sustainable operations.

As reflected in the table below, a separate weighting and associated threshold/target/maximum is applied for each of the Primary Bonus Components. The weighting for each 2021 Primary Bonus Components for 2017Component and associated information are as follows:


ComponentDescriptionWeightingWeightingThreshold LevelTarget LevelMaximum Level
Financial - Adjusted EBITDA and cost management to maximize financial performance50% Adjusted EBITDA
10% Cost management55%		$867 million$958 million$1,042 million
GrowthFinancial - FCFAD10%$205 million$256 million$300 million
Operational15%Operational Scorecard
Safety and Sustainability15%Safety and Sustainability Scorecard
Capital Projects5%Timely and cost-effective growth pursuant to the Strategic Plan and overarching direction10%capital projects
OperationalTotal WeightingEfficient use of systems, assets and equipment for meeting contractual obligations, driving customer service and maximizing cash flow100%10%
PeopleTrain and develop our workforce10%
Environmental, Health,
& Safety		Prevent safety incidents and improve safety compliance, operations, and training10%


Each year, performance under the Primary Bonus Components will be measured, as applicable, on an interpolated “threshold/target/maximum” basis. Actual performance below the threshold level results in 0% of target, performance at threshold level results in 50% of target, and performance at the maximum level or “does-not-meet/meets/exceeds” basis.higher are capped at 200% of target achievement for that component. Each year, a range of bonus pool values for the STI Program will be established to account for various levels of performance under the Primary Bonus Components, as applied on a weighted average basis. These bonus pool values are a framework and are subject to the application of the discretion of the BoardsBoard and the EnLink Compensation Committees,Committee to determine the bonus amounts that are ultimately payable under the STI Program, including to ourthe named executive officers, as further described below.


The EnLink Compensation CommitteesCommittee and the Boards,Board, with input from management, set the annual weightings for each Primary Bonus Component, and any additional weightings that apply with respect to the features comprising a particular Primary Bonus Component. In addition, the EnLink Compensation CommitteesComponent, and the Boards, with input from management, set, as applicable, the “threshold/target/maximum” and the “does-not-meet/meets/exceeds” standardsstandard that applyapplies to the Primary Bonus Components. These standards areThis standard is based on a number of considerations, including, but not limited to, reasonable market expectations, internal company forecasts, available growth opportunities, company performance, leading indicators, and industry standards.

The Boards,Board, based on recommendations of the EnLink Compensation Committees,Committee, initially establishestablishes the target bonus awards that may be earned and ultimately determinedetermines the final bonus amounts, if any, that are payable under the STI Program for ourthe named executive officers. Initial bonus award amounts for consideration by the EnLink Compensation CommitteesCommittee and the BoardsBoard for the named executive officers will be established by multiplying (x)(i) the relevant named executive officer’s target bonus percentage by (y)(ii) the relevant named executive officer’s base salary earnings for the applicable year (subject to certain adjustments to account for, among other things, mid-year changes in base salary or a mid-year hiring or termination) by (z) an(iii) the achievement percentage for the relevant year.


The EnLink Compensation Committees believeCommittee believes that a portion of executive compensation for named executive officers must remain discretionary. Therefore, the STI Program contemplates that the EnLink Compensation CommitteesCommittee and the BoardsBoard retain discretion with respect to target bonus awards and the final bonus amounts for named executive officers. In this regard, the EnLink Compensation CommitteesCommittee may exercise such discretion to recommend to the BoardsBoard a reduction or increase of the target bonus or the final bonus amounts for a particular named executive officer to reward or address extraordinary individual performance, challenges, and opportunities not reasonably foreseeable at the beginning of a performance period, internal equities, and external competition or opportunities.


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The final amount of bonus for each named executive officer wasis approved by the BoardsBoard based upon the EnLink Compensation Committees’Committee’s recommendation and assessment of whether such officer met his or her personal performance objectives established at the beginning of the performance period. These performance objectives includedinclude the quality of leadership within the named executive officer’s assigned area of responsibility, the achievement of technical and professional proficiencies by the named executive officer, the execution of identified priority objectives by the named executive officer, and the named executive officer’s contribution to, and enhancement of, the desired company culture. These performance objectives wereare reviewed and evaluated by the EnLink Compensation CommitteesCommittee as a whole. All named executive officers met or exceeded their minimum personal performance objectives for 2017.2021. Accordingly, the EnLink Compensation CommitteesCommittee and the BoardsBoard awarded bonuses to the named executive officers as follows:
Target Bonus Percentage 
(as a % of Base Salary)		2021 Bonus (as a % of Base Salary)2021 Bonus Amount ($)
Barry E. Davis125 %206.3 %$1,546,994 
Benjamin D. Lamb100 %168.2 %$852,735 
Pablo G. Mercado90 %151.4 %$703,890 
Alaina K. Brooks90 %151.4 %$703,948 
  Target Bonus Percentage (as a % of Base Salary) 2017 Bonus (as a % of Base Salary) 2017 Bonus Amount
Michael J. Garberding 90% 100% $500,000
Mac Hummel 90% 99% $415,000
Benjamin D. Lamb 90% 100% $345,000
Barry E. Davis 125% 138% $960,000
Steve J. Hoppe (1) 90% —% $—

(1)
In January 2018, Mr. Hoppe resigned from his position as Executive Vice President and President of Gas Gathering, Processing and Transmission.

Target adjusted EBITDA was based upon a standard of reasonable market expectations and our performance and varies from year to year. For 2017, our adjusted EBITDA levels for bonuses were $818.0 million for minimum threshold bonuses, $875.0 million for target bonuses and $945.0 million for maximum bonuses. For 2017, the STI Program provided for named executive officers to receive bonus payouts of 45% to 62.5% of base salary at the minimum threshold, 90% to 125% of base salary at the target level and 180% to 250% of base salary at the maximum level.

Long-Term Incentive Plans. Plan. Our named executive officers and outside directors are also eligible to participate in the EnLink Midstream GP, LLC Long-Term Incentive Plan (the “GP Plan”) and the EnLink Midstream, LLC 2014 Long-Term Incentive Plan (the “2014 Plan”). Finally, certain directors, officers and employees participate, to the extent consistent with terms and agreed in connection with the Business Combination, in the EnLink Midstream, LLC 2009 Long-Term Incentive Plan (the “2009 Plan”).

The Board, upon the recommendation of the Governance and Compensation Committee, approves the grants of equity awards to our named executive officers. The Governance and Compensation Committee believes that equity awards should comprise a significant portion of a named executive officer’s total compensation and considers acompensation. A number of factors are considered when determining the grants to each individual named executive officer. The factors considered include: the general goal of allowing the named executive officer the opportunity to earn aggregate equityincluding but not limited to: compensation (comprised of ENLK and ENLC units) targeted at the 75th percentile of oursurveys, Peer Group; the amount of unvested equity held by the individual named executive officer;Group data, the named executive officer’s performance;performance on a group and individual basis, company performance, market conditions, succession planning, retention, and other factors as determined by the Governance and Compensation Committee.Committee and/or the Board.
A discussion of each plan follows:

2014 Plan. Employees, non-employee directors, and other individuals who provide services to us or our affiliates may be eligible to receive awards under the 2014 Plan; however, the Governance and CompensationPlan. The Committee determines which eligible individuals receive awards under the 2014 Plan, subject to the Board’s approval of awards to our named executive officers. The 2014 Plan is administered by the Governance and Compensation Committee and permits the grant of cash and equity-based awards, which may be awarded in the form of options, restricted unit awards, restricted incentive units, unit appreciation rights (“UARs”), distribution equivalent rights (“DERs”), unit awards, cash awards, and performance awards. At the time of adoption of the 2014 Plan, 11,000,000 common units representing limited liability company interests in ENLC were initially reserved for issuance pursuant to awards under the 2014 Plan. In subsequent years, the 2014 Plan has been amended and restated, resulting in an increase to the number of common units reserved for issuance thereunder. As of December 31, 2021, 25,608,795common units remain eligible for future grants. Common units subject to an award under the 2014 Plan that are canceled, forfeited, exchanged, settled in cash, or otherwise terminated, including withheld to satisfy exercise prices or tax withholding obligations, will again become available for delivery pursuant to other awards under the 2014 Plan. Of

In general, the 11,000,000 common units that may be awarded2014 Plan is administered by the Committee. With respect to application of the 2014 Plan to non-employee directors, the 2014 Plan is administered by the Board. The Committee generally has the sole discretion to determine which eligible individuals receive awards under the 2014 Plan, 7,864,403 common units remain eligible for future grants

as of December 31, 2017. The long-term compensation structuresubject to the review of the Board of awards to our executive officers, and the Board has such discretion with respect to which eligible non-employee directors receive awards under 2014 Plan is intended to align the performance of participants with long-term performance for our unitholders.

Plan. The 2014 Plan, as currently amended and restated, will automatically expire on February 5, 2024.September 17, 2030. The Board may amend or terminate the 2014 Plan at any time, subject to any requirement of unitholder approval required by applicable law, rule, or regulation. The Governance and Compensation Committee may generally amend the terms of any outstanding award under the 2014 Plan at any time. However, no action may be taken by the Board or the Governance and Compensation Committee under the 2014 Plan that would materially and adversely affect the rights of a participant under a previously granted award without the participant’s consent.


The following formsPerformance Unit Awards. Our performance-based award agreements (the “Performance-Based Award Agreements”) provide for future awards of awards may be awardedequity-based compensation under the 2014 Plan:

Options. The 2014 Plan permitsPlan. Since 2019, the grant of options covering common units. These options are rights to purchase a specified number of common units of ENLC at a specified price. The exercise price of an option cannot be less than the fair market value per common unit on the date on which the option is granted and the term of the option cannot exceed ten years from the date of grant. Options granted will become exercisable on such terms as the Governance and Compensation Committee determines. The Governance and Compensation Committee will also determine the time or times at which, and the circumstances under which, an option may be exercised in whole or in part (including based on achievement of performance goals and/or future service requirements), the method of exercise, form of consideration payable in settlement, method by or forms in which common units will be delivered to participants, and whether or not an option will be in tandem with a UAR award. Under no circumstances will distributions or DERs be granted or made with respect to option awards. An option granted to an employee may consist of an option that complies with the requirements of Section 422 of the Internal Revenue Code (the “IRC), referred to in the 2014 Plan as an “incentive unit option.” In the case of an incentive unit option granted to an employee who owns (or is deemed to own) more than 10% of the total combined voting power of all classes of units, the exercise price of the option must be at least 110% of the fair market value per common unit on the date of grant and the term of the option cannot exceed five years from the date of grant.

Unit Appreciation Rights or UARs. The 2014 Plan permits the grant of UARs. A UAR is a right to receive an amount equal to the excess of the fair market value of one common unit of ENLC on the date of exercise over the grant price of the UAR. UARs will be exercisable on such terms as the Governance and Compensation Committee determines. The Governance and Compensation Committee will also determine the time or times at which and the circumstances under which a UAR may be exercised in whole or in part (including based on achievement of performance goals and/or future service requirements), the method of exercise, method of settlement, form of consideration payable in settlement, method by or forms in which common units will be delivered or deemed to be delivered to participants, whether or not a UAR shall be in tandem with an option award, and any other terms and conditions of any UAR. UARs may be either freestanding or in tandem with other awards. Under no circumstances will distributions or DERs be granted or made with respect to UAR awards.

Restricted Units. The 2014 Plan permits the grant of restricted units. A restricted unit is a grant of a common unit of ENLC subject to a substantial risk of forfeiture, restrictions on transferability and any other restrictions determined by the Governance and Compensation Committee. The Governance and Compensation Committee may provide, in its discretion,Performance-Based Award Agreements have provided that the distributions made by ENLC with respect to the restricted units will be subject to the same forfeiture and other restrictions as the restricted unit and, if so restricted, such distributions will be held, without interest, until the restricted unit vests or is forfeited with the unit distribution right being paid or forfeited at the same time, as the case may be. In addition, the Governance and Compensation Committee may provide that such distributions be used to acquire additional restricted units for the participant. Under no circumstances will DERs be granted or made with respect to restricted unit awards.

Restricted Incentive Units. The 2014 Plan permits the grant of restricted incentive units. These awards of restricted incentive units are rights that entitle the grantee to receive cash, common units of ENLC or a combination of cash and common units of ENLC upon the vesting of such restricted incentive units. Restricted incentive units may be subject to restrictions, including a risk of forfeiture, as determined by the Governance and Compensation Committee. The Governance and Compensation Committee may, in its sole discretion, grant DERs with respect to restricted incentive units. We intend for the issuance of the common units upon vesting of the restricted incentive units under the 2014 Plan to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of the common units. Therefore, under the current policy, 2014 Plan participants will not pay any consideration for the common units they receive, and ENLC will receive no remuneration for the units.


Distribution Equivalent Rights or DERs. The 2014 Plan permits the grant of DERs. DERs entitle a participant to receive cash or additional awards equal to the amount of any cash distributions made with respect to an ENLC common unit during the period the right is outstanding. DERs may be granted as a stand-alone award or with respect to awards other than restricted units, options or UARs. Subject to Section 409A of the IRC, payment of a DER issued in connection with another award may be subject to the same vesting terms as the award to which it relates or different vesting terms, in the discretion of the Governance and Compensation Committee.

Unit Awards. The 2014 Plan permits the grant of unit awards, which are common units of ENLC that are not subject to vesting restrictions.

Cash Awards. The 2014 Plan permits the grant of cash awards, which are awards denominated and payable in cash.

Performance Awards. The 2014 Plan permits the grant of performance awards. Performance awards represent a participant’s right to receive an amount of cash, common units of ENLC, or a combination of both, contingent upon the annual attainment of specified performance measures within a specified period. The Governance and Compensation Committee or other committee that is intended to satisfy certain requirements of Section 162(m) of the IRC (the “Section 162(m) Committee”), as applicable, will determine the applicable performance period, the performance goals and such other conditions that apply to each performance award. In addition, the 2014 Plan permits, but does not require, the Governance and Compensation Committee or the Section 162(m) Committee, as applicable, to structure any performance award made to a covered employee as qualified performance-based compensation under Section 162(m) of the IRC. As a result of tax reform that became effective on January 1, 2018, future grants of performance awards will no longer be eligible to qualify as qualified performance-based compensation under Section 162(m) of the IRC. However, it may be possible for performance awards that were outstanding as of November 2, 2017 to continue to qualify as qualified performance-based compensation for such purposes; so long as the awards are not modified in any material respect after such date (and assuming that the awards otherwise satisfy any additional transition relief guidance issued by the Internal Revenue Service). Section 162(m) of the IRC generally limits the deductibility for federal income tax purposes of annual compensation paid to certain top executives of a company to $1 million per covered employee in a taxable year (except to the extent such compensation qualifies as (among other things) qualified performance-based compensation as of November 2, 2017 (and are not materially modified), for purposes of Section 162(m) of the IRC). Prior to the payment of any compensation based on the achievement of performance goals applicable to performance awards that were outstanding as of November 2, 2017 and intended to provide qualified performance-based compensation under Section 162(m) of the IRC, the Governance and Compensation Committee or the Section 162(m) Committee, as applicable, must certify in writing that applicable performance goals and any of the material terms thereof were, in fact, satisfied.

Upon a change of control of us, ENLK or the General Partner and except as provided in the applicable award agreement, the Governance and Compensation Committee may cause options and UAR grants to be vested, may cause change of control consideration to be paid in respect of some or all of such awards, or may make other adjustments (if any) that it deems appropriate with respect to such awards. With respect to other awards, upon a change of control of ENLC and except as provided in the award agreement, the Governance and Compensation Committee may cause such awards to be adjusted, which adjustments may relate to the vesting, settlement or the other terms of such awards.

EnLink Midstream 2009 Long-Term Incentive Plan. The EnLink Midstream, LLC 2009 Long-Term Incentive Plan (the “2009 Plan”) Plan provides for the award of options, restricted units, restricted incentive units and other awards (collectively, “Awards”). As a result of the consummation of the Business Combination, however, it is anticipated that no future Awards will be granted under the 2009 Plan. The Governance and Compensation Committee administers the 2009 Plan and has the authority to grant waivers of the applicable plan terms, conditions, restrictions and limitations. As of December 31, 2017, no common units are reserved for issuance under the 2009 Plan. Only unexercised options are outstanding under the 2009 Plan.

The Governance and Compensation Committee may amend, modify, suspend or terminate the 2009 Plan, except that no amendment that would impair the rights of any participant to any Award may be made without the consent of such participant, and no amendment requiring unitholder approval under any applicable legal requirements will be effective until such approval has been obtained.

EnLink Midstream GP, LLC Long-Term Incentive Plan. EnLink Midstream GP, LLC has adopted the GP Plan for employees, consultants and independent contractors of EnLink Midstream GP, LLC and its affiliates and outside directors of the ENLK Board who perform services for ENLK and us. The GP Plan is administered by the ENLK Compensation Committee and permits the grant of awards, which may be awarded in the form of restricted incentive units or options. On May 9, 2013,

ENLK’s unitholders approved the amendment and restatement of the GP Plan, which increased the number of common units representing limited partner interests in ENLK authorized for issuance under the GP Plan by 3,470,000 common units to an aggregate of 9,070,000 common units and made certain other technical amendments. Effective April 6, 2016, ENLK’s unitholders approved the amendment and restatement of the GP Plan, which increased the number of common units representing limited partner interests in ENLK authorized for issuance under the GP Plan by 5,000,000 common units to an aggregate of 14,070,000 common units and other technical changes. Common units subject to an award under the GP Plan that are forfeited or are otherwise terminated or canceled will again become available for delivery pursuant to other awards under the GP Plan. Of the 14,070,000 common units that may be awarded under the GP Plan, 5,011,723 common units remain eligible for future grants as of December 31, 2017. The long-term compensation structure of the GP Plan is intended to align the performance of participants with long-term performance for our unitholders.

The GP Plan will automatically expire on March 3, 2026. The ENLK Board, in its discretion, may terminate or amend the GP Plan at any time with respect to any units for which a grant has not yet been made. The ENLK Board or ENLK Compensation Committee also has the right to alter or amend the GP Plan or any part of the GP Plan from time to time, including increasing the number of units that may be granted subject to the approval requirements of the exchange upon which the common units are listed at that time. The ENLK Compensation Committee may generally amend the terms of any outstanding award under the GP Plan at any time. However, no action may be taken by the ENLK Board or the ENLK Compensation Committee under the GP Plan that would materially reduce the benefits of a participant under a previously granted award without the participant’s consent.

The following forms of awards may be awarded under the GP Plan:

Options. The GP Plan permits the grant of options covering ENLK common units. These options are rights to purchase a specified number of ENLK common units at a specified price. The exercise price of an option cannot be less than the fair market value per common unit on the date on which the option is granted and the term of the option cannot exceed ten years from the date of grant. Options granted will become exercisable on such terms as the ENLK Compensation Committee determines. Under no circumstances will distributions or DERs (as defined below) be granted or made with respect to option awards. In addition, the options may, pursuant to their terms, become exercisable upon a change of control of us, ENLK or the General Partner, as discussed below under “-Potential Payments Upon a Change of Control.” Common units to be delivered upon the exercise of an option may be common units acquired by the General Partner in the open market, common units already owned by the General Partner, common units acquired by the General Partner directly from ENLK or any other person, or any combination of the foregoing. The General Partner will be entitled to reimbursement by ENLK for the difference between the cost incurred by it in acquiring these common units and the proceeds received by it from an optionee at the time of exercise. Thus, the cost of the options will be borne by ENLK. If ENLK issues new common units upon exercise of the options the General Partner will pay ENLK the proceeds it received from the optionee upon exercise of the option.

Restricted Incentive Units. The GP Plan permits the grant of restricted incentive units. These awards of restricted incentive units are rights that entitle the grantee to receive cash, common units or a combination of cash and common units of ENLK upon the vesting of such restricted incentive units. The ENLK Compensation Committee will determine the terms, conditions and limitations applicable to any awards of restricted incentive units. Awards of restricted incentive units will have a vesting period established in the sole discretion of the ENLK Compensation Committee, which may include, without limitation, vesting upon the achievement of specified performance goals. In addition, the restricted incentive units may, pursuant to their terms, vest upon a change of control of ENLK, or the General Partner, as discussed below under “-Potential Payments Upon a Change of Control.” Common units to be delivered upon the vesting of restricted incentive units may be common units acquired by the General Partner in the open market, common units already owned by the General Partner, common units acquired by the General Partner directly from ENLK or any other person or any combination of the foregoing. The General Partner will be entitled to reimbursement by us for the cost incurred in acquiring common units. The ENLK Compensation Committee, in its discretion, may grant tandem distribution equivalent rights (“DERs”) with respect to restricted incentive units, which entitles a participant to receive cash or additional awards equal to the amount of any cash distributions made by ENLK with respect to a common unit during the period the DER is outstanding. The ENLK Compensation Committee may provide, in its discretion, that the DERs will be subject to the same forfeiture and other restrictions as a restricted incentive unit and, if so restricted, such distributions will be held, without interest, until the restricted incentive unit vests or is forfeited with the distribution being paid or forfeited at the same time, as the case may be. We intend for the issuance of the common units upon vesting of the restricted incentive units under the GP Plan to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of

the common units. Therefore, under the current policy, GP Plan participants will not pay any consideration for the common units they receive, and we will receive no remuneration for the units.

Performance Unit Awards. Beginning in 2015, the Managing Member and the General Partner granted performance awards under the 2014 Plan and the GP Plan, respectively. The performance award agreements provide that the vesting of restricted incentive units granted under the GP Plan and 2014 Plan is dependent on the achievement of certain total shareholder return (“TSR”)(i) our TSR performance goals relative to the TSR achievementperformance of a peer group of companies (the “Peer Companies”) overand (ii) our cash flow performance. At the applicabletime of grant, the Board will determine the relative weighting of the two performance period. The performance award agreements contemplategoals by including in the relevant Performance-Based Award Agreement the number of restricted incentive units that the Peer Companieswill be eligible for an individual performance award (the “Subject Award”) are the companies comprising the Alerian MLP Index for Master Limited Partnerships (“AMZ”), excluding ENLK and ENLC,vesting depending on the grantachievement of the TSR performance goals (the “Total TSR Units”) and the achievement of the Cash Flow performance goals (the “Total CF Units”). Since, 2019, our Performance-Based Award Agreements have been weighted so that Total TSR Units represent 80% of the number of available restricted incentive units and Total CF Units represent 20% of the available restricted incentive units.
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The Performance-Based Award Agreement provides for four separate performance periods: (i) three performance periods are each of the first, second, and third calendar years that occur following the vesting commencement date forof the Subject Award.Performance-Based Award Agreement and (ii) the fourth performance period is the cumulative three-year period from the vesting commencement date through the third anniversary thereof (the “Cumulative Performance Period”).

Approximately one-fourth of the Total TSR Units (the “Tranche TSR Units”) relates to the Cumulative Performance Period and each of the first three performance periods described below. The performance units willfollowing table sets out the levels at which the Tranche TSR Units may vest (using linear interpolation) based on the TSR percentile ranking of the average of our and ENLK’s TSR achievement (“EnLink TSR”) for the applicable performance period relative to the TSR achievement of the Designated Peer Companies. Companies:

Performance LevelAchieved TSR
Position Relative to Designated Peer Companies		Vesting percentage
of the Tranche TSR Units
Below ThresholdLess than 25%0%
ThresholdEqual to 25%50%
TargetEqual to 50%100%
MaximumGreater than or Equal to 75%200%

Approximately one-third of the Total CF Units (the “Tranche CF Units”) relates to each of the first three performance periods described above (i.e., the Cash Flow performance goal does not relate to the Cumulative Performance Period). The Board will establish the Cash Flow performance targets for purposes of the column in the table below titled “ENLC’s Achieved Cash Flow” for each performance period no later than March 31 of the year in which the relevant performance period begins. Following the end date of a given performance period, the Committee will measure and determine the Cash Flow performance of ENLC to determine the Tranche CF Units that are eligible to vest, subject to the grantee’s continued employment or service with ENLC or its affiliates through the end of the Cumulative Performance Period. In short, the Performance-Based Award Agreement defines Cash Flow for a given performance period as (A)(i) ENLC’s adjusted EBITDA minus (ii) interest expense, current taxes and other, maintenance capital expenditures, and preferred unit accrued distributions divided by (B) the time-weighted average number of ENLC’s common units outstanding during the relevant performance period. 

In 2021, the Board adopted the metric FCFAD as the cash flow performance goal in the Performance-Based Award Agreement rather than the previously used distributable cash flow per unit. The following table sets out the levels at which the Tranche CF Units were eligible to vest (using linear interpolation) based on the FCFAD performance of ENLC for the performance period ending December 31, 2021:
Performance LevelENLC’s Achieved FCFADVesting percentage
of the Tranche CF Units
Below ThresholdLess than $205 million0%
ThresholdEqual to $205 million50%
TargetEqual to $256 million100%
MaximumGreater than or Equal to $300 million200%

The following table sets out the levels at which the Tranche CF Units were eligible to vest (using linear interpolation) based on the cash flow performance of ENLC for the performance period ending December 31, 2020:
Performance LevelENLC’s Achieved 
Distributable Cash Flow per Unit		Vesting percentage
of the Tranche CF Units
Below ThresholdLess than $1.3450%
ThresholdEqual to $1.34550%
TargetEqual to $1.494100%
MaximumGreater than or Equal to $1.643200%

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The following table sets out the levels at which the Tranche CF Units were eligible to vest (using linear interpolation) based on the cash flow performance of ENLC for the performance period ending December 31, 2019:
Performance LevelENLC’s Achieved 
Distributable Cash Flow per Unit		Vesting percentage
of the Tranche CF Units
Below ThresholdLess than $1.430%
ThresholdEqual to $1.4350%
TargetEqual to $1.55100%
MaximumGreater than or Equal to $1.72200%

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 0% to 200% of the units granted depending on the EnLink TSR as compared to the Peer CompaniesEnLink’s achievement of performance goals on the vesting date. The fair value of each performance unit is estimated as of the date of grant using a Monte Carlo simulation with the following assumptions used for all performance unit grants made under the plan: (i) a risk-free interest rate based on United States Treasury rates as of the grant date; (ii) a volatility assumption based on the historical realized price volatility of our common units and the designatedDesignated Peer Companies securities; (iii) an estimated ranking of us among the designatedDesignated Peer CompaniesCompanies; and (iv) the distribution yield. The fair value of the unit on the date of grant is expensed over a vesting period of approximately three years.


The total value of the equity compensation granted to our executive officers generally has been awarded 50% in ENLK restricted incentive units and 50% in restricted incentiveperformance units of ENLC for fiscal year 2017.on an annual basis. In addition, our executive officers may receive additional grants of equity compensation in certain circumstances, such as promotions. For fiscal year 2017, the General Partner granted 48,544, 35,060, 32,362, 102,482promotions and 35,060 performance and restricted incentive units to Messrs. Garberding, Hummel, Lamb, Davis and Hoppe, respectively. In addition, for fiscal year 2017, the Managing Member granted 45,226, 32,664, 30,150, 95,478 and 32,664 performance and restricted incentive units to Messrs. Garberding, Hummel, Lamb, Davis and Hoppe, respectively.change of ownership. All performance and restricted incentive units that we grant are charged against earnings according to ASC 718.


Anti-Hedging and Anti-Pledging Policy. Pursuant to ENLC’s insider trading policy, ENLC prohibits hedging of its securities by directors, officers, or employees and pledging of its securities as collateral by directors and executive officers.

Retirement and Health Benefits. All eligible employees are offered a variety of health and welfare and retirement programs. The named executive officers are generally eligible for the same programs on the same basis as other employees. ENLKThe Operating Partnership maintains a tax-qualified 401(k) retirement plan that provides eligible employees with an opportunity to save for retirement on a tax deferred basis. In 2017, ENLK2021, the Operating Partnership matched 100% of every dollar contributed for contributions of up to 6% of salaryeligible compensation made by eligible participants plus a 2% non-discretionarydiscretionary profit-sharing contribution (not to exceed the maximum amount permitted by law). The retirement benefits provided to the named executive officers were allocated to us as general and administration expenses.
Perquisites. We generally do not pay for perquisites for any of the named executive officers, other than payment of dues, sales tax, and related expenses for membership in an industry-related private lunch club (totaling less than $2,500 per year per named executive officer).


Change in Control and Severance Agreements


All of our named executive officers and certain members of senior management have entered into amended change in control agreements (the “Change in Control Agreements”) with the Operating Partnership and amended severance agreements (the “Severance Agreements” and collectively with the Change in Control Agreements, the “Agreements”) with the Operating Partnership. Additionally, as certain individuals become members of senior management, the individual may become a party to a change in control agreement and/or a severance agreement in substantially the same form as the applicable Agreement. Under the Change in Control Agreements, the Company’s Chairman and Chief Executive Officer would be entitled to three times the change in control benefit, and the other named executive officers would be entitled to two and a half times the change in control benefit.


The Agreements restrict the officers from competing with us, the Managing Member, the Operating Partnership, ENLK, the General Partner, and their respective affiliates and subsidiaries (the “Company Group”) during the term of employment. The Agreements also restrict the officers from disclosing confidential information of the Company Group and disparaging any member of the Company Group, in each case, during or after the term of their employment. In addition, the Agreements restrict the officers, both during their employment and for varying periods following the termination of employment, from (i) soliciting other employees to terminate their employment with any member of the Company Group or accept employment with a third party and (ii) diverting the business of a client or customer of any member of the Company Group or attempting to convert a client or customer of any member of the Company Group. The Agreements provide the Operating Partnership with equitable

remedies and with the right to clawbackclaw back benefits if the restrictions described in this paragraph are breached by the officer. In
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the event of a termination, the terminated employee is required to execute a general release of the Company Group in order to receive any benefits under the Agreements.


Under the Severance Agreements, if an officer’s employment is terminated without cause (as defined in the Severance Agreement) or is terminated by the officer for good reason (as defined in the Severance Agreement), such officer will be entitled to receive (i) his or her accrued base salary up to the date of termination, (ii) any unpaid annual bonus with respect to the calendar year ending prior to the officer’s termination date that has been earned as of such date, (iii) a prorated amount of the bonus (to the extent such bonus would have otherwise been earned by such officer) for the calendar year in which the termination occurs, (iv) such other fringe benefits (other than any bonus, severance pay benefit or medical insurance benefit) normally provided to employees that are already earned or accrued as of the date of termination (the foregoing items in clauses (i) - (iv) are referred to as the “General Benefits”), (v) certain outplacement services (the “Outplacement Benefits”), (vi) a lump sum severance equal to the sum of (A) the officer’s then-current base salary and (B) any target bonus (as defined in the applicable Agreement) for the year that includes the date of termination (the “Severance Benefit”) times two for the officer (other members of senior management are each entitled to one times the Severance Benefit), plus (vii) an amount equal to the cost to the officer to extend his or her then-current medical insurance benefits for 18 months following the effective date of the termination (the “Medical Severance Benefit”).


Potential Payments Upon a Change of Control


Under the Change in Control Agreements, if, within a period that begins 120 days prior to and ends 24 months following a change in control (as defined in the Change in Control Agreement), an officer’s employment is terminated without cause (as defined in the Change in Control Agreement) or is terminated by the officer for good reason (as defined in the Change in Control Agreement), such officer will be entitled to the General Benefits, the Outplacement Benefits, the Medical Severance Benefit and the Severance Benefit; provided, however, that the Chairman and Chief Executive Officer (“CEO”) would be entitled to three times the Severance Benefit, and the other named executive officers would be entitled to two and a half times the Severance Benefit, and other members of senior management would be entitled to one and a half times the Severance Benefit. Other members of senior management do not receive an increase in the Severance Benefit if they are terminated in connection with a change in control.


In addition, the Agreements provide for the General Benefits upon the officer’s termination of employment due to his or her death or disability (as defined in the Agreements).


The Agreements provide that an officer may only become entitled to payments under the Severance Agreement or the Change in Control Agreement, but not under both Agreements. Upon execution of a Severance Agreement, the Severance Agreement will continue in effect until (i) the first anniversaryInitial Expiration Date (as defined in the Severance Agreement), which is generally a term of one year from the execution date; provided that the term will be automatically renewed for additional one-year periods beginning on the day following the first anniversary of the execution dateInitial Expiration Date (each, a “Renewal Date”), unless the ENLK Board or the ENLK Compensation Committee, as applicable, provides the officer with written notice (a “Non-Renewal Notice”) of the Operating Partnership’s election not to renew the term at least 30 days prior to any Renewal Date or (ii) the termination of the officer’s employment; provided that an officer’s employment may not be terminated by the Operating Partnership for any reason other than cause (as defined in the Severance Agreement) for the 90-day period that follows the termination of the Severance Agreement pursuant to a Non-Renewal Notice. Upon execution of a Change in Control Agreement, the Change in Control Agreement will continue in effect with automatic renewal on each anniversary of the execution date until (i) termination by the applicable Renewal Date and be automatically renewed for additional one-year periods unless the ENLK Board or the ENLK Compensation Committee, as applicable, providesproviding the officer with a Non-Renewal Notice at least 90 days prior to any Renewal Date or (ii) the termination of the officer’s employment, except that a Change in Control Agreement may not be terminated for a period that begins 120 days prior to, and ends 24 months following, a change in control.


If the payments and benefits provided to an officer under the Agreements (i) constitute a “parachute payment” as defined in Section 280G of the IRC and exceed three times the officer’s “base amount” as defined under Section 280G(b)(3) of the IRC, and (ii) would be subject to the excise tax imposed by Section 4999 of the IRC, then the officer’s payments and benefits will be either (A) paid in full, or (B) reduced and payable only as to the maximum amount that would result in no portion of the payments and benefits being subject to such excise tax, whichever results in the receipt by the officer on an after-tax basis of the greatest amount (taking into account the applicable federal, state and local income taxes, the excise tax imposed by Section 4999 of the IRC and all other taxes, including any interest and penalties, payable by the officer).


With respect to the long-term incentive plans,2014 Plan, the amounts to be received by our named executive officers in the event of a change of control (as defined in the long-term incentivesuch plans) will be automatically determined based on the number of units underlying any unvested equity incentive awards held by a named executive officer at the time of a change of control. The

terms of the long-term incentivesuch plans were determined based on past practice and the applicable compensation committee’s understanding of similar plans utilized by public companies generally at the time we adopted such plans. The determination of the reasonable consequences of a change of control is periodically reviewed by the applicable compensation committee.Committee.

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Upon a change of control, and except as provided in the award agreement, the applicable compensation committeeCommittee may cause options and UAR grants to be vested, may cause change of control consideration to be paid in respect of some or all of such awards, or may make other adjustments (if any) that it deems appropriate with respect to such awards. With respect to other awards, upon a change of control and except as provided in the award agreement, the applicable compensation committeeCommittee may cause such awards to be adjusted, which adjustments may relate to the vesting, settlement, or the other terms of such awards.


The potential payments that may be made to the named executive officers upon a termination of their employment or in connection with a change of control as of December 31, 20172021 are set forth in the table in the section below entitled “Payments Upon Termination or Change inof Control.”


Role of Executive Officers in Executive Compensation


The Board, upon recommendation of the Governance and Compensation Committee, determines the compensation payable to each of the named executive officers. None of the named executive officers serves as a member of the Governance and Compensation Committee. The CEOOur Chief Executive Officer makes recommendations regarding the compensation of his leadership team with the Governance and Compensation Committee, including specific recommendations for each element of compensation for each of the named executive officers. The CEOOur Chief Executive Officer does not make any recommendations regarding his personal compensation.


Tax Considerations


We have structured the compensation program in a manner intended to be exempt from, or to comply with, Section 409A of the IRC. If an executive is entitled to nonqualified deferred compensation benefits that are subject to Section 409A, and such benefits do not comply with Section 409A of the IRC, then the benefits are taxable in the first year they are not subject to a substantial risk of forfeiture. In such case, the service provider is subject to regular federal income tax, interest, and an additional federal excise tax of 20% of the benefit includible in income.



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Summary Compensation Table


The following table sets forth certain compensation information for our named executive officers:officers.
Name and Principal PositionYearSalary ($)(1)Bonus ($)(2)Restricted Incentive Unit and Performance Unit Awards ($)(3)All Other Compensation ($)Total ($)
Barry E. Davis2021750,0581,546,9943,968,869643,524(5)6,909,445
Chairman and Chief Executive Officer2020763,269983,6585,412,084660,5827,819,593
2019556,000636,5684,553,287744,4566,490,311
Benjamin D. Lamb2021516,809852,7351,984,434205,645(6)3,559,623
Executive Vice President and Chief Operating Officer2020519,988536,0562,706,036209,6413,971,721
2019491,200521,2071,264,284362,4242,639,115
Pablo G. Mercado (4)2021474,000703,8901,257,142150,520(7)2,585,552
Executive Vice President and Chief Financial Officer2020225,000408,757986,400223,1261,843,283
Alaina K. Brooks2021474,039703,9481,133,962185,407(8)2,497,356
Executive Vice President, Chief Legal and Administrative Officer, and Secretary2020465,252431,6661,391,674181,3112,469,903
2019439,500444,709902,261302,2532,088,723
Name and Principal Position Year Salary
($)		 Bonus
($)(1)		 Restricted Incentive Unit, and Performance Unit Awards
($)(2)		 All Other Compensation
($)		 Total
($)
Michael J. Garberding 2017 500,000 500,000
 2,147,374 396,190(4)3,543,564
President and Chief Executive Officer (3) 2016 462,885 416,000
 3,409,650 376,304 4,664,839
  2015 449,423 400,000
 1,963,183 281,294 3,093,900
             
Mac Hummel 2017 415,192 415,000
 1,550,909 322,421(5)2,703,522
Executive Vice President and President of NGL and Crude 2016 390,000 225,000
 1,092,502 317,871 2,025,373
  2015 389,538 300,000
 1,570,488 203,570 2,463,596
             
Benjamin D. Lamb 2017 345,000 345,000
 1,431,552 274,563(6)2,396,115
Executive Vice President, North Texas and Oklahoma (7) 2016 318,558 250,000
 2,181,257 212,310 2,962,125
  2015 283,904 225,000
 1,702,321 92,414 2,303,639
             
Barry E. Davis 2017 695,000 960,000
 4,533,371 565,075(8)6,753,446
Executive Chairman of the Board (3) 2016 660,000 650,000
 2,498,230 570,612 4,378,842
  2015 659,308 690,000
 3,435,500 440,742 5,225,550
             
Steve J. Hoppe (9) 2017 420,000 —
 1,550,909 250,097(10)2,221,006

 2016 390,000 280,000
 1,092,502 261,800 2,024,302
  2015 389,827 300,000
 1,570,488 147,699 2,408,014
____________________________
(1)Salary for the years 2021 and 2020 included regular earnings and a paid time off payout for Messrs. Lamb and Mercado and Ms. Brooks. Salary for the year 2020 also included an additional 27th pay period.
(1)
Bonuses include all annual bonus payments. For 2015, all annual bonus payments were paid in cash. For 2016 and 2017, the named executive officers received bonuses in the form of equity awards that immediately vest. The amounts shown for 2016 and 2017 represent the grant date fair value of awards computed in accordance with ASC 718. Such awards were allocated 50% in restricted incentive units of ENLK and 50% in restricted incentive units of ENLC.
(2)The amounts shown represent the grant date fair value of awards computed in accordance with ASC 718. See “Item 8. Financial Statements and Supplementary Data—Note 12” for the assumptions made in our valuation of such awards.
(3)
In January 2018, the Board appointed Mr. Davis to Executive Chairman of the Board, Mr. Garberding to President and Chief Executive Officer and Mr. Batchelder to Executive Vice President and Chief Financial Officer. Prior to January 2018, Mr. Davis served as Chief Executive Officer and Chairman of the Board, and Mr. Garberding served as President and Chief Financial Officer.
(4)
Amount of all other compensation for Mr. Garberding includes a matching 401(k) contribution of $13,769, a 401(k) non-discretionary contribution of $5,400, DERs with respect to restricted incentive units of ENLK in the amount of $236,339 and DERs with respect to restricted incentive units of ENLC in the amount of $140,682.
(5)
Amount of all other compensation for Mr. Hummel includes a matching 401(k) contribution of $16,200, a 401(k) non-discretionary contribution of $5,400, $75,526 toward temporary housing expenses, DERs with respect to restricted incentive units of ENLK in the amount of $143,648, and DERs with respect to restricted incentive units of ENLC in the amount of $81,647.
(6)
Amount of all other compensation for Mr. Lamb includes a matching 401(k) contribution of $16,200, a 401(k) non-discretionary contribution of $5,400, DERs with respect to restricted incentive units of ENLK in the amount of $159,514, DERs with respect to restricted incentive units of ENLC in the amount of $93,449.
(7)In February 2018, the Board appointed Mr. Lamb to Executive Vice President, North Texas and Oklahoma. Prior to February 2018, Mr. Lamb served as Executive Vice President, Corporate Development.
(8)
Amount of all other compensation for Mr. Davis includes a matching 401(k) contribution of $16,200, a 401(k) non-discretionary contribution of $5,400, DERs with respect to restricted incentive units of ENLK in the amount of $344,886 and DERs with respect to restricted incentive units of ENLC in the amount of $198,589.
(9)In January 2018, Mr. Hoppe resigned from his position as Executive Vice President and President of Gas Gathering, Processing and Transmission.
(10)
Amount of all other compensation for Mr. Hoppe includes a matching 401(k) contribution of $16,200, a 401(k) non-discretionary contribution of $5,400, DERs with respect to restricted incentive units of ENLK in the amount of $145,107 and DERs with respect to restricted incentive units of ENLC in the amount of $83,389.

(2)Bonuses include all annual bonus payments. For the years 2021 and 2020, the named executive officers received bonuses in the form of 100% cash except for Mr. Mercado, who received $100,000 of his 2020 bonus in restricted incentive units that vested on December 31, 2021. This award was based on the closing price of the ENLC common units as of December 31, 2020, which was $3.71. For 2019, the named executive officers received bonuses in the form of 35% cash and 65% equity awards that immediately vested. Such equity awards were entirely allocated in restricted incentive units of ENLC. Equity awards for 2019 represent the grant date fair value of awards computed in accordance with ASC 718.
(3)The amounts shown represent the grant date fair value of awards computed in accordance with ASC 718. See “Item 8. Financial Statements and Supplementary Data—Note 11” for the assumptions made in our valuation of such awards.
(4)Mr. Mercado was appointed as Executive Vice President and Chief Financial Officer on July 13, 2020.
(5)Amount of all other compensation for Mr. Davis includes a matching 401(k) contribution of $17,400 and DERs with respect to restricted incentive units of ENLC in the amount of $626,124.
(6)Amount of all other compensation for Mr. Lamb includes a matching 401(k) contribution of $17,400 and DERs with respect to restricted incentive units of ENLC in the amount of $188,245.
(7)Amount of all other compensation for Mr. Mercado includes a matching 401(k) contribution of $17,400 and DERs with respect to restricted incentive units of ENLC in the amount of $133,120.
(8)Amount of all other compensation for Ms. Brooks includes a matching 401(k) contribution of $17,400 and DERs with respect to restricted incentive units of ENLC in the amount of $168,007.

CEO Pay Ratio


For fiscal year 2017,2021, the annual total compensation for the then Chairman of our Board and CEO, Barry E.Mr. Davis was $6.8$6.9 million and for the median employee was $111,319.$105,168. The resulting ratio of annual total compensation of the CEOMr. Davis to the annual

total compensation of our median employee was 61:66:1. This pay ratio is a reasonable estimate calculated in accordance with the requirements of Item 402(u) of Regulation S-K. As a result of our methodology for determining the pay ratio, which is described below, our pay ratio may not be comparable to the pay ratios of other companies in our industry or in other industries because other companies may rely on different methodologies or assumptions or may make adjustments that we do not make.For 2021, the same median employee as 2020 was used to determine the pay ratio given that there has not been a material change to (i) the employee population, (ii) compensation arrangements believed to result in a significant change to the pay ratio, and (iii) the original median employee’s circumstances (e.g., a promotion or demotion). If one of the aforementioned material changes did occur, the same approach used to identify the median employee in 2020 would have been applied for 2021.


To determine the pay ratio, we first identified athe median employee by examining 20172020 W-2 Box 1 Federal Taxable Wages (the “Taxable Wages Measure”) for all of our employees, excluding the CEO,our Chairman and Chief Executive Officer, who were employed on December 29, 2017,31, 2021, the last business day of the 20172021 fiscal year. We included all employees, whether employed as full-time, part-time, or on a seasonal basis, and compensation was annualized for any full-time employee that was not employed for all of fiscal year 2017.2021. We use the Taxable Wages Measure because it is consistently applied for all employees and because we believe it reasonably reflects the annual compensation of our employees. After identifying the median employee, we calculated annual total compensation for the median employee using the same methodology used for calculating the annual total compensation of our named executive officers as set forth in the 20172021 Summary Compensation Table above.

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Narrative Disclosure to Summary Compensation Table

A narrative description of all material factors necessary to an understanding of the information included in the above Summary Compensation Table is included in the section titled “Compensation Discussion and Analysis” and in the footnotes to such tables.

Grants of Plan-Based Awards for Fiscal Year 20172021 Table


The following tables providetable provides information concerning each grant of an award made to a named executive officer for fiscal year 2017, including, but not limited to, awards made under the GP Plan and the 2014 Plan.

2021.
ENLINK MIDSTREAM, LLC—GRANTS OF PLAN-BASED AWARDS

Estimated Future Payouts Under Equity Incentive Plan Awards
NameGrant DateThreshold (#)Target (#)Maximum (#)All Other Unit Awards: Number of UnitsGrant Date Fair Value of Unit Awards ($)(1)
Barry E. Davis1/1/2021— — — 471,698 (2)1,750,000 
1/1/2021235,849 471,698 943,396 — (3)2,218,869 
Benjamin D. Lamb1/1/2021— — — 235,849 (2)875,000 
1/1/2021117,925 235,849 471,698 — (3)1,109,435 
Pablo G. Mercado1/1/2021— — — 134,771 (2)500,000 
1/1/202167,386 134,771 269,542 — (3)633,962 
2/16/2021— — — 26,954 (4)123,180 
Alaina K. Brooks1/1/2021— — — 134,771 (2)500,000 
1/1/202167,386 134,771 269,542 — (3)633,962 
____________________________
(1)The amounts shown represent the grant date fair value of awards computed in accordance with ASC 718. See “Item 8. Financial Statements and Supplementary Data—Note 11” for the assumptions made in our valuation of such awards.
(2)These grants include DERs that provide for distribution on restricted incentive units if made on unrestricted common units during the restriction period unless otherwise forfeited and vest 100% on January 1, 2024.
(3)These grants include accrued DERs that provide for distributions on performance awards, unless otherwise forfeited, if distributions are made on common units during the restriction period. When the performance awards vest on January 1, 2024, recipients receive DERs, if any, with respect to the number of performance awards vested.
(4)Mr. Mercado received $100,000 of his 2020 bonus in restricted incentive units that vested on December 31, 2021. This award was based on the closing price of the ENLC common units as of December 31, 2020, which was $3.71. These awards included DERs that provided for distributions on restricted incentive units if made on unrestricted common units during the restriction period unless otherwise forfeited.


161
    Estimated Future Payouts Under Equity Incentive Plan Awards    
Name Grant Date Threshold (#) Target (#)(1) Maximum (#)(1) All Other Unit Awards: Number of Units (2) Grant Date Fair Value of Unit Awards ($)(3)
Michael J. Garberding 3/14/2017       22,613 434,170
  3/14/2017 —
 22,613 45,226   650,576
             
Mac Hummel 3/14/2017       16,332 313,574
  3/14/2017 —
 16,332 32,664   469,872
             
Benjamin D. Lamb 3/14/2017       15,075 289,440
  3/14/2017 —
 15,075 30,150   433,708
             
Barry E. Davis 3/14/2017       47,739 916,589
  3/14/2017 —
 47,739 95,478   1,373,451
             
Steve J. Hoppe (4) 3/14/2017       16,332 313,574
  3/14/2017 —
 16,332 32,664   469,872
(1)These grants include accrued DERs that provide for distributions on performance awards, unless otherwise forfeited, if distributions are made on common units during the restriction period. When the performance awards vest on January 1, 2020, recipients receive DERs, if any, with respect to the number of performance awards vested.
(2)These grants include DERs that provide for distribution on restricted incentive units if made on unrestricted common units during the restriction period unless otherwise forfeited and vest 100% on January 1, 2020.
(3)The amounts shown represent the grant date fair value of awards computed in accordance with ASC 718. See “Item 8. Financial Statements and Supplementary Data—Note 12” for the assumptions made in our valuation of such awards.
(4)
In January 2018, Mr. Hoppe resigned from his position as Executive Vice President and President of Gas Gathering, Processing and Transmission. Pursuant to his resignation, the restricted incentive units and performance awards granted during 2017 were forfeited.




ENLINK MIDSTREAM GP, LLC—GRANTS OF PLAN-BASED AWARDS

Table of Contents
    Estimated Future Payouts Under Equity Incentive Plan Awards    
Name Grant Date Threshold (#) Target (#)(1) Maximum (#)(1) All Other Unit Awards: Number of Units (2) Grant Date Fair Value of Unit Awards ($)(3)
Michael J. Garberding 3/14/2017       24,272 438,110
  3/14/2017 —
 24,272
 48,544
   624,519
             
Mac Hummel 3/14/2017       17,530 316,417
  3/14/2017 —
 17,530
 35,060
   451,047
             
Benjamin D. Lamb 3/14/2017       16,181 292,067
  3/14/2017 —
 16,181
 32,362
   416,337
             
Barry E. Davis 3/14/2017       51,241 924,900
  3/14/2017 —
 51,241
 102,482
   1,318,431
             
Steve J. Hoppe (3) 3/14/2017       17,530 316,417
  3/14/2017 —
 17,530
 35,060
   451,047
(1)These grants include accrued DERs that provide for distributions on performance awards, unless otherwise forfeited, if distributions are made on common units during the restriction period. When the performance awards vest on January 1, 2020, recipients receive DERs, if any, with respect to the number of performance awards vested.
(2)
These grants include DERs that provide for distribution on restricted incentive units if made on unrestricted common units during the restriction period unless otherwise forfeited and vest 100% on January 1, 2020.
(3)The amounts shown represent the grant date fair value of awards computed in accordance with ASC 718. See “Item 8. Financial Statements and Supplementary Data—Note 12” for the assumptions made in our valuation of such awards.
(4)In January 2018, Mr. Hoppe resigned from his position as Executive Vice President and President of Gas Gathering, Processing and Transmission. Pursuant to his resignation, the restricted incentive units and performance awards granted during 2017 were forfeited.



Outstanding Equity Awards at Fiscal Year-End Table for Fiscal Year 20172021


The following tables providetable provides information concerning all outstanding equity awards made to a named executive officer as of December 31, 2017, including, but not limited to, awards made under the 2014 Plan, the 2009 Plan and the GP Plan:2021.


ENLINK MIDSTREAM, LLC—OUTSTANDING EQUITY AWARDS AT FISCAL YEAR-END


Unit Awards
NameVesting Year (1)Number of Units That Have Not Vested (#)Market Value of Shares or Units That Have Not Vested ($)(2)Equity Incentive Plan Awards: Number of Unearned Units or Other Rights that Have Not Vested (#)(3)(4)(5)Equity Incentive Plan Awards: Market or Payout Value of Unearned Units or Other Rights That Have Not Vested ($)(2)
Barry E. Davis2024471,698 3,249,999 471,698 3,249,999 
2023391,499 2,697,428 391,499 2,697,428 
2022135,318 932,341 391,292 (6)2,696,002 
Benjamin D. Lamb2024235,849 1,625,000 235,849 1,625,000 
2023195,749 1,348,711 195,749 1,348,711 
2022— — 96,525 665,057 
Pablo G. Mercado2024134,771 928,572 134,771 928,572 
2023200,000 1,378,000 200,000 1,378,000 
2022— — — — 
Alaina K. Brooks2024134,771 928,572 134,771 928,572 
2023100,671 693,623 100,671 693,623 
2022— — 72,394 498,795 
____________________________
(1)Restricted incentive units vesting in 2022 vest on January 1st provided that, for Mr. Davis, restricted incentive units vesting in 2022 vest on January 1st and August 1st, as applicable. Restricted incentive units vesting in 2023 vest on January 1st and July 13th, as applicable. Restricted incentive units vesting in 2024 vest on January 1st.
(2)The closing price for the ENLC common units was $6.89 as of December 31, 2021.
(3)Reflects the target number of performance units granted to the named executive officers multiplied by a performance percentage of 100%.
(4)Vesting of awards in 2022 and 2023 are contingent upon (i) the EnLink TSR performance measured against a peer group of companies, (ii) EnLink’s achieved distributable cash flow per unit outstanding or EnLink’s achieved free cash flow after distributions depending on the award and vesting tranche as described above.
(5)Vesting of awards in 2024 are contingent upon (i) the EnLink TSR performance measured against a peer group of companies and (ii) EnLink’s achieved free cash flow after distributions.
(6)Vesting of awards in August 2022 for Mr. Davis are contingent upon the EnLink TSR performance measured against a peer group of companies.








162
    Stock Awards
Name Vesting Year (1) Number of Units That Have Not Vested
(#)		 Market Value of Shares or Units That Have Not Vested
($)(2)		 Equity Incentive Plan Awards: Number of Unearned Units or Other Rights that Have Not Vested (#)(3) Equity Incentive Plan Awards: Market or Payout Value of Unearned Units or Other Rights That Have Not Vested ($)(2)
Michael J. Garberding 2020 46,051 810,498 46,051 810,498
  2019 71,457 1,257,643 29,187 513,691
  2018 15,823 278,485 15,823 278,485
Mac Hummel 2020 16,332 287,443 16,332 287,443
  2019 48,309 850,238 22,142 389,699
  2018 12,658 222,781 12,658 222,781
Benjamin D. Lamb 2020 30,700 540,320 30,700 540,320
  2019 46,296 814,810 14,090 247,984
  2018 13,630 239,888 10,074 177,302
Barry E. Davis 2020 47,739 840,206 47,739 840,206
  2019 110,709 1,948,478 50,322 885,667
  2018 27,690 487,344 27,690 487,344
Steve J. Hoppe (4) 2020 16,332 287,443 16,332 287,443
  2019 48,309 850,238 22,142 389,699
  2018 12,658 222,781 12,658 222,781
(1)
Restricted incentive units vest on January 1st of the applicable year, with the exception of 3,556 restricted incentive units for Mr. Lamb that vest on April 1, 2018.
(2)
The closing price for the ENLC common units was $17.60 as of December 29, 2017.
(3)
Reflects the target number of performance units granted to the named executive officers multiplied by a performance percentage of 100%. Vesting of these awards on January 1st of the applicable year is contingent upon EnLink TSR performance over the applicable performance period measured against a peer group of companies.
(4)In January 2018, Mr. Hoppe resigned from his position as Executive Vice President and President of Gas Gathering, Processing and Transmission.



ENLINK MIDSTREAM GP, LLC—OUTSTANDING EQUITY AWARDS AT FISCAL YEAR-END

Table of Contents
    Stock Awards      
Name Vesting Year (1) Number of Units That Have Not Vested
(#)		 Market Value of Shares or Units That Have Not Vested
($)(2)		 Equity Incentive Plan Awards: Number of Unearned Units or Other Rights that Have Not Vested (#)(3) Equity Incentive Plan Awards: Market or Payout Value of Unearned Units or Other Rights That Have Not Vested ($)
Michael J. Garberding 2020 45,411 697,967 45,411 697,967
  2019 82,712 1,271,283 33,784 519,260
  2018 17,532 269,467 17,532 269,467
Mac Hummel 2020 17,530 269,436 17,530 269,436
  2019 55,918 859,460 25,629 393,918
  2018 14,025 215,564 14,025 215,564
Benjamin D. Lamb 2020 30,273 465,296 30,273 465,296
  2019 53,588 823,648 16,309 250,669
  2018 16,553 254,420 11,695 179,752
Barry E. Davis 2020 51,241 787,574 51,241 787,574
  2019 128,145 1,969,589 58,248 895,272
  2018 30,680 471,552 30,680 471,552
Steve J. Hoppe (4) 2020 17,530 269,436 17,530 269,436
  2019 55,918 859,460 25,629 393,918
  2018 14,025 215,564 14,025 215,564
(1)
Restricted incentive units vest on January 1st of the applicable year, with the exception of 4,858 restricted incentive units awarded to Mr. Lamb that vest on April 1, 2018.
(2)
The closing price for the ENLK common units was $15.37 as of December 29, 2017.
(3)
Reflects the target number of performance units granted to the named executive officers multiplied by a performance percentage of 100%. Vesting of these awards on January 1st of the applicable year is contingent upon EnLink TSR performance over the applicable performance period measured against a peer group of companies.
(4)In January 2018, Mr. Hoppe resigned from his position as Executive Vice President and President of Gas Gathering, Processing and Transmission.


Units Vested Table for Fiscal Year 20172021


The following table provides information related to the vesting of restricted units and restricted incentive units during fiscal year ended 2017:2021.


ENLINK MIDSTREAM, LLC—UNITS VESTED


NameDate VestedNumber of Units Acquired on VestingValue Per Unit Realized on Vesting ($)Total ($)
Barry E. Davis1/1/202142,6143.71 158,098
1/21/202142,6143.95 168,325
1/1/202156,1163.71 208,190
1/21/202156,1163.95 221,658
Benjamin D. Lamb1/1/202119,8863.71 73,777
1/1/202126,1883.71 97,157
8/1/202115,6745.57 87,304
8/1/202127,4305.57 152,785
8/1/202118,4535.57 102,783
8/1/202132,2945.57 179,878
Pablo G. Mercado12/31/202126,9546.80 183,287
Alaina K. Brooks1/1/202111,2223.71 41,634
1/21/202111,2223.95 44,327
1/1/202114,7783.71 54,826
1/21/202114,7783.95 58,373
8/1/202110,9725.57 61,114
8/1/202110,9725.57 61,114
8/1/202112,9185.57 71,953
8/1/202112,9185.57 71,953


163
  EnLink Midstream Partners, LP Unit Awards 
EnLink Midstream, LLC
Unit Awards
Name Number of Units Acquired on Vesting Value Realized on Vesting (1) Number of Units Acquired on Vesting Value Realized on Vesting (2)
Michael J. Garberding 59,040 $1,142,942
(1) 52,107 $1,034,529
(6)
Mac Hummel 42,128 $815,763
(2) 33,338 $662,386
(7)
Benjamin D. Lamb 22,187 $409,565
(3) 19,277 $367,067
(8)
Barry E. Davis 113,097 $2,189,862
(4) 99,347 $1,974,152
(9)
Steve J. Hoppe 47,375 $917,284
(5) 41,640 $827,349
(10)
Table of Contents
(1)
Consisted of 11,391 units at $19.27 per unit and 47,649 units at $19.38 per unit.
(2)
Consisted of 6,161 units at $19.27 per unit, 4,201 units at $19.38 per unit and 31,766 units at $19.38 per unit.
(3)
Consisted of 6,846 units at $19.27 per unit, 7,147 units at $19.38 per unit and 8,194 units at $16.98 per unit.
(4)
Consisted of 17,798 units at $19.27 per unit and 95,299 units at $19.38 per unit.
(5)
Consisted of 7,667 units at $19.27 per unit and 39,708 units at $19.38 per unit.
(6)
Consisted of 11,123 units at $19.50 per unit and 40,984 units at $19.95 per unit.
(7)
Consisted of 6,016 units at $19.50 per unit and 27,322 units at $19.95 per unit.
(8)
Consisted of 6,684 units at $19.50 per unit, 6,148 units at $19.95 per unit and 6,445 units at $17.70 per unit.
(9)
Consisted of 17,380 units at $19.50 per unit and 81,967 units at $19.95 per unit.
(10)
Consisted of 7,487 units at $19.50 per unit and 34,153 units at $19.95 per unit.


Payments Upon Termination or Change of Control


The following tables showtable shows potential payments that would have been made to the named executive officers as of December 31, 2017:2021.

Named Executive OfficerPayment Under Severance Agreements Upon Termination Other Than For Cause or With Good Reason ($)(1)Health Care Benefits Under Change in Control and Severance Agreements Upon Termination Other Than For Cause or With Good Reason ($)(2)Payment and Health Care Benefits Under Change in Control and Severance Agreements Upon Termination For Cause or Without Good Reason ($)(3)Payment Under Change in Control Agreements Upon Termination and Change of Control ($)(4)Acceleration of Vesting Under Long-Term Incentive Plans Upon Change of Control ($)(5)
Barry E. Davis4,971,99423,890— 6,659,49415,523,198
Benjamin D. Lamb2,930,73530,752— 3,437,7356,612,478
Pablo G. Mercado2,520,89029,214— 2,962,6404,613,144
Alaina K. Brooks2,520,94831,290— 2,962,6983,743,185
____________________________
(1)Each named executive officer is entitled to a lump sum amount equal to two times the Severance Benefit, the Outplacement Benefit, and when applicable, the bonus amounts comprising the General Benefits will be paid if he or she is terminated without cause (as defined in the Severance Agreement) or if he or she terminates employment for good reason (as defined in the Severance Agreement), subject to compliance with certain non-competition and non-solicitation covenants described elsewhere in this Annual Report on Form 10-K. The figures shown do not include amounts of base salary previously paid or fringe benefits previously received.
(2)Each named executive officer is entitled to health care benefits equal to a lump sum payment of the estimated monthly cost of the benefits under COBRA for 18 months if he or she is terminated without cause (as defined in the applicable Severance Agreement or Change of Control Agreement (the “Applicable Agreement”) or if he or she terminates employment for good reason (as defined in the Applicable Agreement)).
(3)Each named executive officer is entitled to his or her then current base salary up to the date of termination plus such other fringe benefits (other than any bonus, severance pay benefit, participation in the company’s 401(k) employee benefit plan, or medical insurance benefit) normally provided to employees of the company as earned up to the date of termination if he or she is terminated for cause (as defined in the Applicable Agreement) or he or she terminates employment without good reason (as defined in the Applicable Agreement). The figures shown do not include amounts of base salary previously paid or fringe benefits previously received.
(4)Each named executive officer is entitled to a lump sum payment equal to two and a half times the Severance Benefit (three times in the case of the Chairman and Chief Executive Officer), the Outplacement Benefit, and when applicable, the bonus amounts comprising the General Benefits will be paid if he or she is terminated without cause (as defined in the Change of Control Agreement) or if he or she terminates employment for good reason (as defined in the Change of Control Agreement) within 120 days prior to or two years following a change in control (as defined in the Severance Agreement), subject to compliance with certain non-competition, non-solicitation, and other covenants described elsewhere in this Annual Report on Form 10-K. The figures shown do not include amounts of base salary previously paid or fringe benefits previously received.
(5)Each named executive officer is entitled to accelerated vesting of certain outstanding equity awards in the event of a change of control (as defined under the long-term incentive plans). These amounts correspond to the values set forth in the table in the section above entitled Outstanding Equity Awards at Fiscal Year-End Table for Fiscal Year 2021.

164
Named Executive Officer 
Payment Under Severance Agreements Upon Termination Other Than For Cause or With Good Reason
($)(1)
 
Health Care Benefits Under Change in Control and Severance Agreements Upon Termination Other Than For Cause or With Good Reason
($)(2)
 
Payment and Health Care Benefits Under Change in Control and Severance Agreements Upon Termination For Cause or Without Good Reason
($)(3)
 
Payment Under Change in Control Agreements Upon Termination and Change of Control
($)(4)
 
Acceleration of Vesting Under Long-Term Incentive Plans Upon Change of Control
($)(5)
Michael J. Garberding 2,450,000 31,220 —
 2,450,000 3,725,411
Mac Hummel 2,061,000 31,220 —
 2,061,000 2,223,378
Benjamin D. Lamb 1,706,000 33,556 —
 1,706,000 2,439,081
Barry E. Davis 4,137,500 34,095 —
 5,701,250 10,872,358
Steve J. Hoppe (6) 2,063,312 33,556 —
 2,063,312 2,223,378
Table of Contents
(1)
Each named executive officer is entitled to a lump sum amount equal to two times the Severance Benefit, the Outplacement Benefit, and when applicable, the bonus amounts comprising the General Benefits will be paid if he is terminated without cause (as defined in the Severance Agreement) or if he terminates employment for good reason (as defined in the Severance Agreement), subject to compliance with certain non-competition and non-solicitation covenants described elsewhere in this Annual Report on Form 10-K. The figures shown do not include amounts of base salary previously paid or fringe benefits previously received.
(2)
Each named executive officer is entitled to health care benefits equal to a lump sum payment of the estimated monthly cost of the benefits under COBRA for 18 months if he is terminated without cause (as defined in the applicable Severance Agreement or Change of Control Agreement (the “Applicable Agreement”) or if he terminates employment for good reason (as defined in the Applicable Agreement).
(3)
Each named executive officer is entitled to his then current base salary up to the date of termination plus such other fringe benefits (other than any bonus, severance pay benefit, participation in the company’s 401(k) employee benefit plan, or medical insurance benefit) normally provided to employees of the company as earned up to the date of termination if he is terminated for cause (as defined in the Applicable Agreement) or he terminates employment without good reason (as defined in the Applicable Agreement). The figures shown do not include amounts of base salary previously paid or fringe benefits previously received.
(4)
Each named executive officer is entitled to a lump sum payment equal to two times the Severance Benefit (three times in the case of the Chief Executive Officer), the Outplacement Benefit, and when applicable, the bonus amounts comprising the General Benefits will be paid if he is terminated without cause (as defined in the Change of Control Agreement) or if he terminates employment for good reason (as defined in the Change of Control Agreement) within one-hundred and twenty (120) days prior to or two (2) years following a change in control (as defined in the Severance Agreement), subject to compliance with certain non-competition, non-solicitation and other covenants described elsewhere in this Annual Report on Form 10-K. The figures shown do not include amounts of base salary previously paid or fringe benefits previously received.
(5)
Each named executive officer is entitled to accelerated vesting of certain outstanding equity awards in the event of a change of control (as defined under the long-term incentive plans). These amounts correspond to the values set forth in the table in the section above entitled Outstanding Equity Awards at Fiscal Year-End Table for Fiscal Year 2017.
(6)In January 2018, Mr. Hoppe resigned from his position as Executive Vice President and President of Gas Gathering, Processing and Transmission.



Compensation of Directors for Fiscal Year 20172021


DIRECTOR COMPENSATION


NameFees Earned or Paid in Cash ($)Unit Awards ($)(1)All Other Compensation ($)(2)Total ($)
Deborah G. Adams95,625 198,071 11,624 305,320 
Tiffany Thom Cepak (3)— — — — 
James C. Crain (4)82,500 198,071 5,812 286,383 
Leldon E. Echols107,375 198,071 11,624 317,070 
Kyle D. Vann105,000 198,071 11,624 314,695 
Name 
Fees Earned or Paid in Cash
($)
 Unit Awards (1) ($) All Other Compensation (2) ($) 
Total
($)
James C. Crain 115,000 100,009 6,360 221,369
Leldon E. Echols 96,500 99,995 7,995 204,490
Rolf A. Gafvert 97,500 100,009 6,360 203,869
Mary P. Ricciardello 90,000 99,995 7,995 197,990
____________________________
(1)At December 31, 2021, Ms. Adams and Messrs. Echols and Vann each held an aggregate of 30,997 outstanding restricted incentive unit awards. On July 1, 2021, Ms. Adams and Messrs. Crain, Echols, and Vann were each granted awards of restricted incentive units with a fair market value of $6.39 per unit and that vested on January 1, 2022. The amounts shown represent the grant date fair value of awards computed in accordance with ASC 718. See “Item 8. Financial Statements and Supplementary Data—Note 11” for the assumptions made in our valuation of such awards. The number of units granted to each director was based on a unit value of $3.71, the closing trading price on December 31, 2021, and is consistent with the unit value used for grants to Named Executive Officers in the same year. Value on this date represents the Board approved award of equity compensation valued at $115,000. This approach for determining the number of units granted to directors is consistent with prior years. In 2020, this approach resulted in director grants valued at $29,586 compared to approved award value of $115,000.
(1)Mr. Crain, Mr. Echols, Mr. Gafvert and Ms. Ricciardello were granted awards of restricted incentive units of ENLC on March 7, 2017 with a fair market value of $19.95 per unit and that will vest on March 7, 2018 in the following amounts, respectively: 5,013, 2,506, 5,013 and 2,506. Mr. Echols and Ms. Ricciardello were granted awards of restricted incentive units of ENLK on March 7, 2017 with a fair market value of $19.38 per unit and that will vest on March 7, 2018 in the following amounts, respectively: 2,580 and 2,580. The amounts shown represent the grant date fair value of awards computed in accordance with ASC 718. See “Item 8. Financial Statements and Supplementary Data—Note 12” for the assumptions made in our valuation of such awards. At December 31, 2017, Mr. Crain, Mr. Echols, Mr. Gafvert and Ms. Ricciardello held aggregate outstanding restricted incentive unit awards, in the following amounts, respectively: 5,013, 2,506, 5,013 and 2,506. At December 31, 2017, Mr. Echols and Ms. Ricciardello held aggregate outstanding restricted units of ENLK in the following amounts, respectively: 2,580 and 2,580.
(2)
Other Compensation is comprised of DERs with respect to restricted incentive units.

(2)Other Compensation is comprised of DERs with respect to restricted incentive units.
(3)Ms. Cepak was appointed to the Board in December 2021.
(4)Mr. Crain was a member of the Board until his death in July 2021.

Each director of the Managing Member who is not an employee of the Managing Member or DevonGIP is paid an annual retainer fee of $72,500$97,500 and equity compensation valued at $100,000.$115,000. Directors do not receive an attendance fee for each regularly scheduled quarterly board meeting or each additional meeting that they attend. The respective chairs of each committee receivereceived the following annual fees:fees for fiscal year ended 2021: Audit—$24,000, EnLink20,000, Governance and Compensation Committees—Committee—$10,00015,000, Conflicts—$15,000, and Conflicts—$20,000. The respective members of each committee receive the following annual fees: Audit—$17,500, EnLink Compensation Committees—$7,500 and Conflicts—Sustainability—$15,000. Directors arewere also reimbursed for related out-of-pocket expenses. Michael J. Garberding,

Barry E. Davis, Thomas Mitchell, David Hager, Lyndon Taylor, R. Alan Marcum and Jeff L. Ritenour, as officersan officer of the Managing Member, or Devon,William J. Brilliant, Thomas W. Horton, James K. Lee, and Scott E. Telesz, as representatives of GIP, receive no separate compensation for their respective service as directors. For directors that serve on both the boards of EnLink Midstream GP, LLC and EnLink Midstream Manager, LLC, the above listed fees are generally allocated 25% to us and 75% to ENLK and equity grants are comprised of 50% of our units and 50% of ENLK’s units.


Governance and Compensation Committee Interlocks and Insider Participation


Our Governance and Compensation Committee is comprised of Rolf A. GafvertKyle D. Vann (chair), William J. Brilliant, and David A. Hager.Leldon E. Echols. As described elsewhere in this report, Mr. HagerBrilliant is an executive officera representative of DevonGIP and may have an interest in the transactions among Devon, theGIP, ENLK, and us. Please see “Item 13. Certain Relationships and Related Party Transactions.Transactions, and Director Independence.”


No other member of the Compensation Committee during fiscal 2021 was a current or former officer or employee of the General Partner or had any relationship requiring disclosure by us under Item 404 of Regulation S-K as adopted by the Commission. None of the General Partner’s executive officers served on the board of directors or the compensation committee of any other entity for which any officers of such other entity served either on the Board or the Committee.

Board Leadership Structure and Risk Oversight


The Board has no policy that requires that the positions of the Chairman of the Board (the “Chairman”) and the Chief Executive Officer be separate or that they be held by the same individual. The Board believes that this determination should be based on circumstances existing from time to time, including the composition, skills, and experience of the Board and its members, specific challenges faced by us or the industry in which we operate, and governance efficiency. Based on these factors, the Board has determined that having Barry E. Davis serve as theChairman and Chief Executive Officer and Chairman up to January 2018 wasis in our best interest at this time, and that such arrangement mademakes the best use of Mr. Davis’ unique skills and experience in the industry. In January 2018, the Board appointed Mr. Davis to Executive Chairman

165
Table of the Board and Mr. Garberding to President and Chief Executive Officer, thereby separating the positions of Chairman and Chief Executive Officer. Contents

The Board is responsible for risk oversight. Management has implemented internal processes to identify and evaluate the risks inherent in our business and to assess the mitigation of those risks. The Audit Committee will review the risk assessments with management and provide reports to the Board regarding the internal risk assessment processes, the risks identified, and the mitigation strategies planned or in place to address the risks in the business. The Board and the Audit Committee each provide

insight into the issues, based on the experience of their members, and provide constructive challenges to management’s assumptions and assertions.



166
Table of Contents
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters


EnLink Midstream, LLC Ownership and Devon Energy Corporation Ownership


The following table shows the beneficial ownership of EnLink Midstream, LLC, as well as the beneficial ownership of shares of common stock of Devon Energy Corporation,ENLC, as of February 14, 2018,9, 2022, held by:


•each person who is known to ENLC to beneficially ownsown more than 5% or more of any class of voting units then outstanding;
•all the directors of EnLink Midstream Manager, LLC;the Managing Member;
•each named executive officer of EnLink Midstream Manager, LLC;the Managing Member; and
•all the directors and executive officers of EnLink Midstream Manager, LLCthe Managing Member as a group.



The percentage of total ENLC common units of EnLink Midstream, LLC beneficially owned is based on a total of 180,901,963546,319,579 units (including 18,594 restricted incentive62,293,613 common units, that are deemed beneficially owned)which reflects the as-exchanged amount of the outstanding 54,168,359 ENLC Class C Common Units) as of February 14, 2018. 9, 2022.
Name of Beneficial Owner (1)Common Units Beneficially Owned (2)Percentage of Common Units Beneficially Owned (3)Total Units Beneficially Owned (2)Percentage of Total Units Beneficially Owned (4)
Global Infrastructure Investors III, LLC (5)224,355,359 46.4 %224,355,359 41.1 %
ALPS Advisors, Inc. (6)43,392,248 9.0 %43,392,248 7.9 %
Invesco Ltd. (7)39,070,300 8.1 %39,070,300 7.2 %
Barry E. Davis (8)2,062,952 *2,062,952 *
Benjamin D. Lamb538,603 *538,603 *
Pablo G. Mercado16,347 *16,347 *
Alaina K. Brooks236,412 *236,412 *
Deborah G. Adams87,721 *87,721 *
William J. Brilliant— *— *
Tiffany Thom Cepak— *— *
Leldon E. Echols177,746 *177,746 *
Thomas W. Horton— *— *
James K. Lee— *— *
Scott E. Telesz— *— *
Kyle D. Vann (9)252,628 *252,628 *
All directors and executive officers as a group (12 persons)3,372,409 *3,372,409 *
____________________________
* Less than 1%

(1)Unless otherwise indicated, the beneficial owner has sole voting and dispositive power over all units listed. Unless otherwise indicated, the address of each beneficial owner is 1722 Routh Street, Suite 1300, Dallas, Texas 75201.
(2)Pursuant to Rule 13d-3 under the Exchange Act, a person has beneficial ownership of a security as to which that person, directly or indirectly, through any contract, arrangement, understanding, relationship, or otherwise has or shares voting power and/or investment power of such security and as to which that person has the right to acquire beneficial ownership of such security within 60 days.
(3)The percentage of total shares of Devon Energy Corporation beneficially owned ispercentages reflected in the column below are based on a total of 528,239,732 shares of484,025,966 common stock outstanding as of February 14, 2018.units.
  EnLink Midstream, LLC Devon Energy Corporation
Name of Beneficial Owner (1) 
Common
Units
Beneficially
Owned
 Percent 
Shares of
Common
Stock
Beneficially
Owned
 Percent
Devon Energy Corporation (2) 115,495,669
 63.84% —
 *
Chickasaw Capital Management, LLC 15,898,889
 8.79% —
 *
Michael J. Garberding 174,632
 *
 500
 *
Eric D. Batchelder —
 *
 —
 *
Mac Hummel 45,997
 *
 3,617
 *
Benjamin D. Lamb (3) 31,866
 *
 —
 *
Barry E. Davis (4) 1,796,663
 *
 —
 *
James C. Crain (5) 77,306
 *
 —
 *
Leldon E. Echols (6) 34,903
 *
 —
 *
David A. Hager —
 *
 428,382
 *
Kevin D. Lafferty —
 *
 16,323
 *
Mary P. Ricciardello (7) 10,454
 *
 45,653
 *
Rolf A. Gafvert (8) 20,910
 *
 —
 *
Jeff L. Ritenour —
 *
 136,681
 *
Lyndon Taylor —
 *
 114,991
 *
R. Alan Marcum —
 *
 178,474
 *
All directors and executive officers as group (15 persons) 2,237,125
 1.24% 924,621
 *
*      Less than 1%.
(1)The address of each person listed above is 1722 Routh Street, Suite 1300, Dallas, Texas 75201, except for (i) Devon Energy Corporation, whose address is 333 W. Sheridan Avenue, Oklahoma City, Oklahoma 73102, and (ii) Chickasaw Capital Management, LLC, whose address is 6075 Poplar Avenue, Suite 720, Memphis, Tennessee, 38119.
(2)Devon Gas Services, L.P. (“Devon Gas Services”) is the record holder of 115,495,669 common units. As the indirect owner of 100% of the outstanding limited and general partner interests in Devon Gas Services, Devon Energy Corporation may be deemed to beneficially own all of the common units held by Devon Gas Services.
(3)
Includes 28,310 common units owned of record by Mr. Lamb and 3,556 restricted incentive units that are deemed beneficially owned.
(4)
Includes 1,796,663 common units owned of record by Mr. Davis. Of these common units, 1,025,000 are held by MK Holdings, LP, a family limited partnership, which Mr. Davis controls, and Mr. Davis disclaims beneficial ownership of these securities except to the extent of his pecuniary interest therein.
(5)Includes 72,293 common units owned of record by Mr. Crain and 5,013 restricted incentive units that are deemed beneficially owned. 1,000 of these common units are held by the James C. Crain Trust, and Mr. Crain disclaims beneficial ownership of these securities except to the extent of his pecuniary interest therein.
(6)
Includes 32,397 common units owned of record by Mr. Echols and 2,506 restricted incentive units that are deemed beneficially owned.
(7)
Includes 7,948 common units owned of record by Ms. Ricciardello and 2,506 restricted incentive units that are deemed beneficially owned.
(8)Includes 15,897 common units owned of record by Mr. Gafvert and 5,013 restricted incentive units that are deemed beneficially owned.

EnLink Midstream Partners, LP Ownership

(4)The following table showspercentages reflected in the beneficial ownership of units of EnLink Midstream Partners, LP as of February 14, 2018, held by:
each person who beneficially owns 5% or more of any class of units then outstanding;
all the directors of EnLink Midstream Manager, LLC;
each named executive officer of EnLink Midstream Manager, LLC; and
all the directors and executive officers of EnLink Midstream Manager, LLC as a group.


The percentage of total units beneficially owned iscolumn below are based uponon a total of 350,043,269546,319,579 common units, (including 20,338 restricted incentivewhich includes the units that are deemed beneficially owned)described in (3) above, and 57,469,93962,293,613 common units, which reflects the as-exchanged amount of the 54,168,359 ENLC Class C Common Units held by the Series B Preferred Unitholders. The Series B Preferred Units asare exchangeable into ENLC common units on a 1-for-1.15 basis, subject to certain adjustments. For this reason, the percentages in this column reflect the exchange of February 14, 2018.the Series CB Preferred Units into ENLC common units. Upon any exchange of Series B Preferred Units into ENLC common units, an equal number of ENLC Class C Common Units will be canceled.
(5)Based solely on the Amendment No. 2 to the Schedule 13D filed with the Commission on February 5, 2019 by Global Infrastructure Investors III, LLC (“Global Investors”). Such filing indicates that Global Investors, Global Infrastructure GP III, L.P. (“Global GP”), GIP III Stetson Aggregator II, L.P. (“Aggregator II”), GIP III Stetson Aggregator I, L.P. (“Aggregator I”), and GIP III Stetson GP, LLC (“Stetson GP”) have shared voting and dispositive power with respect to 224,355,359 ENLC common units, and that GIP III Stetson II, L.P. (“Stetson II”) and GIP III Stetson I, L.P. (“Stetson I”) are perpetual preferredthe record holders of 115,495,669 and 108,859,690 ENLC common units, respectively. Global Investors is the sole general partner of Global GP, which is the general partner of each of Aggregator I and Aggregator II, which are the managing members of Stetson GP, which is the general partner of each of Stetson I and Stetson II. As a result, Global Investors, Global GP, Aggregator I, Aggregator II and Stetson GP may be deemed to share beneficial ownership of the ENLC common units beneficially owned by Stetson I and Stetson II. Adebayo Ogunlesi, Jonathan Bram, William Brilliant, Matthew Harris, Michael McGhee, Rajaram Rao, William Woodburn, Salim Samaha and Robert O’Brien, as the voting members of the Investment Committee of Global Investors, may be deemed to share beneficial ownership of the ENLC common units beneficially owned by Global Investors. Such individuals expressly disclaim any such beneficial ownership. The address of each of Global Investors, Global GP, Aggregator II, Aggregator I, Stetson GP, Stetson I,
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Stetson II, and Messrs. Ogunlesi, Bram, Brilliant, Harris, McGhee, Rao, Woodburn, Samaha, and O’Brien is c/o Global Infrastructure Management, LLC, 1345 Avenue of the Americas, 30th Floor, New York, New York 10105.
(6)As reported on Schedule 13G/A filed with the Commission on February 3, 2022 by ALPS Advisors, Inc. and Alerian MLP ETF each with an address of 1290 Broadway, Suite 1000, Denver, Colorado 80203. The Schedule 13G/A reports that ALPS Advisors, Inc. (“AAI”), an investment adviser registered under the Investment Advisers Act of 1940, as amended, furnishes investment advice to investment companies registered under the Investment Company Act of 1940, as amended (collectively referred to as the “Funds”). In its role as investment advisor, AAI has voting and/or investment power over the registrant's common units that are not convertible intoowned by the Funds, and may be deemed to be the beneficial owner of such common units held by the Funds. Alerian MLP ETF is an investment company registered under the Investment Company Act of 1940 and thereforeis one of the Funds to which AAI provides investment advice. Alerian MLP ETF has shared voting and investment power over 43,392,248 common units. The common units reported herein are owned by the Funds and AAI disclaims beneficial ownership of such common units.
(7)Based solely on the Schedule 13G/A filed with the Commission on February 9, 2022 by Invesco Ltd. (“Invesco”). Such filing indicates that Invesco has sole voting and dispositive power with respect to 39,070,300 ENLC common units. The address of Invesco is 1555 Peachtree Street NE, Suite 1800, Atlanta, GA 30309.
(8)Of these ENLC common units, 1,101,424 are held by MK Holdings, LP, a family limited partnership, which Mr. Davis controls, and Mr. Davis disclaims beneficial ownership of these securities except to the extent of his pecuniary interest therein.
(9)Of these ENLC Common Units, 181,631 are held indirectly through The Kyle and Barbara Vann Revocable Trust.

GIP’s Pledge of Equity Interests in ENLC and the Managing Member

GIP has pledged all of the equity interests that it owns in ENLC and the Managing Member to its lenders as security under a secured credit facility entered into by a GIP entity in connection with the GIP Transaction (the “GIP Credit Facility”). Although we are not factored intoa party to this credit facility, if GIP were to default under the percentage ownership calculations. NoneGIP Credit Facility, GIP’s lenders could foreclose on the pledged equity interests. Any such foreclosure on GIP’s interest would result in a change of control of the named beneficial owners set forth inManaging Member and would allow the table below owns anynew owner to replace the board of directors and officers of the 400,000 outstanding Series C Preferred Units asManaging Member with its own designees and to control the decisions taken by the board of February 14, 2018.
Name of Beneficial Owner (1) Common Units Beneficially Owned Percentage of Common Units Beneficially Owned (2) Series B Convertible Preferred Units Beneficially Owned Percentage of Series B Preferred Units Beneficially Owned Total Units Beneficially Owned Percentage of Total Units Beneficially Owned (3)
Michael J. Garberding 157,645
 * —
 —
 157,645
 *
Eric D. Batchelder —
 * —
 —
 —
 *
Mac Hummel 51,639
 * —
 —
 51,639
 *
Benjamin D. Lamb (4) 42,857
 * —
 —
 42,857
 *
Barry E. Davis (5) 497,478
 * —
 —
 497,478
 *
James C. Crain —
 * —
 —
 —
 *
Leldon E. Echols (6) 31,697
 * —
 —
 31,697
 *
David A. Hager —
 * —
 —
 —
 *
Kevin D. Lafferty —
 * —
 —
 —
 *
Mary P. Ricciardello (7) 10,573
 * —
 —
 10,573
 *
Rolf A. Gafvert —
 * —
 —
 —
 *
Jeff L. Ritenour —
 * —
 —
 —
 *
Lyndon Taylor —
 * —
 —
 —
 *
R. Alan Marcum —
 * —
 —
 —
 *
All directors and executive officers as group (15 persons) 843,323
 * —
 —
 843,323
 *
*      Less than 1%
(1)The address of each person listed above is 1722 Routh Street, Suite 1300, Dallas, Texas 75201.
(2)
The percentages reflected in the column below are based on a total of 350,043,269 common units, including 20,338 restricted incentive units that are deemed beneficially owned.
(3)
The percentages reflected in the column below are based on a total of 407,513,208 common units, which includes the units described in (2) above, and 57,469,939 Series B Preferred Units, which are convertible into common units on a one-for-one basis, subject to certain adjustments. Series C Preferred Units are perpetual preferred units that are not convertible into common units and therefore are not factored into the percent ownership calculations.
(4)Includes 37,999 common units owned of record by Mr. Lamb and 4,858 restricted incentive units that are deemed beneficially owned.
(5)
Includes 497,478 common units owned of record by Mr. Davis. Of these common units, 50,042 are held by MK Holdings, LP, a family limited partnership, which Mr. Davis controls, and Mr. Davis disclaims beneficial ownership of these securities except to the extent of his pecuniary interest therein.
(6)
Includes 29,117 common units owned of record by Mr. Echols and 2,580 restricted incentive units that are deemed beneficially owned.
(7)
Includes 7,993 common units owned of record by Ms. Ricciardello and 2,580 restricted incentive units that are deemed beneficially owned.

Beneficial Ownership of General Partner Interest

EnLink Midstream GP, LLC ownsdirectors and officers. See “Item 1A. Risk Factors—GIP has pledged all of ENLK’s general partner interestthe equity interests that it owns in ENLC and allthe Managing Member to GIP’s lenders under its credit facility. A default under GIP’s credit facility could result in a change of ENLK’s incentive distribution rights. EnLink Midstream GP, LLC is 100% indirectly owned by EnLink Midstream, LLC.control of the Managing Member.”



Equity Compensation Plan Information

Plan CategoryNumber of Securities to be Issued Upon Exercise of Outstanding Options, Warrants, and RightsWeighted-Average Price of Outstanding Options, Warrants and RightsNumber of Securities Remaining Available for Future Issuance Under Equity Compensation Plan (Excluding Securities Reflected in Column(a))
(a)(b)(c)
Equity Compensation Plans Approved by Security Holders (1)11,082,298(2)N/A25,608,795 (3)
Equity Compensation Plans Not Approved by Security HoldersN/AN/AN/A
____________________________
(1)These plans include both the 2014 Plan, which was approved by our unitholders in March 2014 for the benefit of our officers, employees, and directors, and the GP Plan, which was approved by ENLK’s unitholders effective April 6, 2016 for the benefit of ENLK’s officers, employees, and directors. As of the closing of the Merger, ENLC assumed all obligations in respect of the GP Plan.
(2)The number of securities includes 7,500,028 restricted units that have been granted under the 2014 Plan that have not vested and 7,443 restricted units that have been granted under the GP Plan that have not vested. In addition, the number of securities includes 3,574,827 performance unit awards that have been granted under the 2014 Plan, assuming the target distribution at the time of vesting,. Actual issuance of these performance unit awards may range from 0% to 200% of the target distribution depending on performance actually attained. See “Item 11—Executive Compensation—Compensation Discussion and Analysis” for additional information regarding the 2014 Plan.
(3)Effective as of the closing of the Merger, the 2014 Plan, as amended, provided for the issuance of a total of 21,116,046 common units under the 2014 Plan, inclusive of the ENLK units that remained eligible for future grants under the GP Plan immediately prior to the effective time of the Merger (which ENLK units were converted to ENLC common units and included among the available units under the 2014 Plan). No additional grants of equity awards will be made under the GP Plan for periods after the Merger. Additionally, effective as of September 17, 2020, the 2014 Plan, as amended, provided for the issuance of an additional 20,000,000 common units, which altogether provided for the issuance of a total 41,116,046 under the 2014 Plan. Of the 41,116,046 common units that may be awarded under the 2014 Plan, 25,608,795 common units remained eligible for future grants as of December 31, 2021.

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Plan Category Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants, and Rights Weighted-Average Price of Outstanding Options, Warrants and Rights Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plan (Excluding Securities Reflected in Column(a))
  (a) (b) (c)
Equity Compensation Plans Approved by Security Holders(1) 2,438,149(2)N/A 7,864,403
Equity Compensation Plans Not Approved by Security Holders N/A N/A N/A
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(1)Our 2014 Long-Term Incentive Plan was approved by our unitholders in March 2014 for the benefit of our officers, employees and directors. See “Item 11—Executive Compensation—Compensation Discussion and Analysis.” The plan, as amended, provides for the issuance of a total of 11,000,000 common units under the plan.
(2)The number of securities includes 1,889,310 restricted units that have been granted under our long-term incentive plan that have not vested. In addition, the number of securities includes 548,839 performance unit awards granted under the plan, assuming the target distribution at the time of vesting. Actual issuance of these performance unit awards may range from 0% to 200% of the target distribution depending on performance actually attained.


Item 13. Certain Relationships and Related Transactions, and Director Independence


Relationship with EnLink Midstream Partners, LP


As of December 31, 2017,In connection with the Merger, we indirectly owned 88,528,451issued 304,822,035 common units representing an approximate 21.7% limited partnership interest,to acquire all of the outstanding ENLK common units not previously owned by us. Subsequent to the general partner interest in ENLKMerger, ENLC owns all of ENLK’s common units and also owns all of the incentive distribution rights in ENLK. Through our ownershipmembership interests of the General Partner, we have the powerwhich allows us to appoint all of the officers and directors of the General Partner and to manage and operate ENLK and effectively to veto some of the ENLK’s actions. We pay ENLK a fee for administrative and compensation costs incurred by ENLK on our behalf.ENLK.


Relationship with Devon Energy CorporationGIP


We are managed by our managing member,Managing Member, which is wholly-owned by Devon.GIP. Therefore, DevonGIP controls us and our ability to manage and operate our business. Additionally, fivefour of our directors, including David A. Hager, Kevin D. Lafferty, Jeff L. Ritenour, Lyndon TaylorWilliam J. Brilliant, Thomas W. Horton, James K. Lee, and Tony VaughnScott E. Telesz are officersrepresentatives of Devon.GIP, and they control a majority of the voting power on the Board. Those individuals do not receive separate compensation for their service on the Board, but they are entitled to indemnification related to their service as directors pursuant to the indemnification agreements as described below. For the years endedDecember 31, 2021 and 2020, we recorded general and administrative expenses of $0.5 million and $0.2 million, respectively, related to personnel secondment services provided by GIP. We did not record any expenses related to transactions with GIP for the year ended December 31, 2019.


On February 15, 2022, we and GIP entered into an agreement pursuant to which we will repurchase, on a quarterly basis, a pro rata portion of the ENLC common units held by GIP, based upon the number of common units purchased by us during the applicable quarter from public unitholders under our common unit repurchase program. The number of ENLC common units held by GIP that we repurchase in any quarter will be calculated such that GIP’s then-existing economic ownership percentage of our outstanding common units is maintained after our repurchases of common units from public unitholders are taken into account, and the per unit price we pay to GIP will be the average per unit price paid by us for the common units repurchased from public unitholders. The terms of the agreement with GIP were unanimously approved by the Board and, based upon the related party nature of the agreement with the GIP Entities, the Conflicts Committee of the Board. For more information about our repurchase agreement with GIP, see Item 9B of this Report.

Related Party Transactions


Refer to “Item 8. Financial Statements and Supplementary information—Information—Note 5”4” for information about our related party transactions, including commercial agreements with Devon.transactions.


Office Leases

In connection with the consummation of the Business Combination, we entered into three office lease agreements with a wholly-owned subsidiary of Devon pursuant to which we will lease office space at Devon’s Bridgeport, Oklahoma City and Cresson office buildings. Rent payable to Devon under these lease agreements is $174,000, $31,000 and $66,000, respectively, on an annual basis.

Certain Relationships


From time to time, we may do business with other companies affiliated with TPG, which holds an interest in Enfield Holdings, L.P., the beneficial ownerour board of ENLK’s Series B Preferred Units,directors, or with Natural Resources XI, L.P.NGP, Marathon Petroleum Corporation,or Kinder Morgan, Inc., our joint venture partners in the Delaware Basin JV, Ascension JV, and Cedar Cove JV, respectively. We believe that any such arrangements have been or will be conducted on an arms-length basis.




Indemnification of Directors and Officers


We have entered into indemnification agreements (the “Indemnification Agreements”) with each of the Managing Member’s directors and executive officers (collectively, the “Indemnitees”). Under the terms of the Indemnification Agreements, we agree to indemnify and hold each Indemnitee harmless, subject to certain conditions, from and against any and all losses, claims, damages, liabilities, expenses (including legal fees and expenses), judgments, fines, taxes (including ERISA excise taxes,taxes), penalties (whether civil, criminal, or other), interest, assessments, amounts paid or payable in settlements, or other amounts (collectively, “losses”) and expenses (as defined in the Indemnification Agreements) arising from any and all threatened, pending, or completed claims, demands, actions, suits, proceedings, or proceedings,alternative dispute mechanisms, whether civil, criminal, administrative, arbitrative, investigative, or investigative, andother, whether made pursuant to federal, state, or local law, whether formal or informal, and including appeals (a “proceeding”), in which the Indemnitee ismay be involved, or is threatened to be involved, as a party, a witness, or otherwise, becauseincluding any inquiries, hearings, or investigations that the Indemnitee determines might lead to the institution of any proceeding, related to the fact that Indemnitee is or was a director, manager, or officer of us, the General Partner, or the Managing Member or us, or is or was serving at the request of us, the General Partner, or the Managing Member or us as a manager, managing member, general partner, director, officer, fiduciary, trustee, or trusteeagent of anotherany other entity, organization, or person of any nature.nature, including service with respect to employee benefit plans, or by reason of an action or inaction by Indemnitee in any such capacity on behalf of, for the benefit of, or at the request of us, the General Partner, or the Managing Member. We have also agreed to advance the expenses of an Indemnitee relating to the foregoing. To the extent that a change in the laws of the State of Delaware permits greater indemnification under any statute, agreement, organizational document, or governing
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document than would be afforded under the Indemnification Agreements as of the date of the Indemnification Agreements, the Indemnitee shall enjoy the greater benefits so afforded by such change.


Approval and Review of Related Party Transactions


If we contemplate entering into aOur policies and procedures for the review, approval, or ratification of transactions with “related persons” are contained in our Code of Business Conduct and Ethics (the “Code of Ethics”) as well as our operating agreement. Pursuant to our Code of Ethics, the Audit Committee of the Board must approve any transaction, other than a routinearrangement, or in the ordinary courserelationship, or any series of business transaction,similar transactions, arrangements, or relationships, in which we or any of our subsidiaries is or will be a related personparticipant, the aggregate amount involved will or may be expected to exceed $120,000 in any fiscal year, and any director, executive officer, equity holder owning more than 5% of any class of ENLC’s securities, or any immediate family member of any of the foregoing has or will have a direct or indirect materialinterest.

Whenever a conflict arises between the Managing Member or its affiliates, on the one hand, and ENLC and certain of its affiliates, on the other hand, the Managing Member will resolve that conflict in accordance with the provisions of our operating agreement. The Managing Member is authorized but not required in connection with its resolution of such conflict of interest to seek approval of a majority of the proposed transaction is submitted for consideration to the Board or our senior management, as appropriate. If the Board is involved in the approval process, it determines whether it is advisable to refer the matter tomembers of the Conflicts Committee of the Board comprised entirelyor the approval of independent directors, as constituted under our operating agreement. The Conflicts Committee operates pursuant toa majority of the unitholders (excluding units owned by the Managing Member and its written charter and our operating agreement. Ifaffiliates). Any resolution, course of action, or transaction receiving approval of a matter is referred to the Conflicts Committee, the Conflicts Committee obtains information regarding the proposed transaction from management and determines whether it is advisable to engage independent legal counsel or an independent financial advisor to advisemajority of the members of the committee regardingConflicts Committee of the transaction. If the committee retains such counselBoard or financial advisor, it considers the advice and, in the caseapproval of a financial advisor, such advisor’s opinion asmajority of the unitholders (excluding units owned by the Managing Member and its affiliates) will be conclusively deemed to whether the transaction is fairbe approved by ENLC and reasonable to us and to our unitholders.all of its members.


Director Independence


See “Item 10. Directors, Executive Officers, and Corporate Governance” for information regarding director independence.



Item 14. Principal AccountingAccountant Fees and Services


Audit Fees


The fees for professional services rendered for the audit of our annual financial statements for the fiscal years ended December 31, 2017, 20162021, 2020, and 2015,2019, review of our internal control procedures for the fiscal years ended December 31, 2017, 20162021, 2020, and 2015,2019, and the reviews of the financial statements included in our quarterly reports on Form 10-Q or services that are normally provided by KPMG in connection with statutory or regulatory filings or engagements for each of those fiscal years were $0.3 million.$2.5 million, $2.5 million, and $2.6 million, respectively. These amounts also included fees associated with comfort letters and consents related to debt and equity offerings.


Audit-Related Fees


KPMG did not perform any assurance and related services in connection with the audit or review of our financial statements for the fiscal years ended December 31, 2017, 20162021, 2020, and 20152019 that were not included in the audit fees listed above.


Tax Fees


KPMG did not perform any tax related services for the years ended December 31, 2017, 20162021, 2020, and 2015.2019, except for certain tax related services in the amounts of $43.5 thousand and $16.7 thousand for the years ended December 31, 2021 and 2019, respectively, in connection with the preparation of calculations under Internal Revenue Code Section 280G.


All Other Fees


KPMG did not render services to us, other than those services covered in the section captioned “Audit Fees” and “Tax Fees” for the fiscal years ended December 31, 2017, 20162021, 2020, and 2015.2019.



Audit Committee Approval of Audit and Non-Audit Services


All audit and non-audit services and any services that exceed the annual limits set forth in our annual engagement letter for audit services must be pre-approved by the Audit Committee. In 2017, the Audit Committee did not pre-approve the use of KPMG for any non-audit related services. The Chairmanchair of the Audit Committee is authorized by the Audit Committee to pre-approve additional KPMG audit and non-audit services between meetings of the Audit Committee, meetings, provided
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that the additional services do not affect KPMG’s independence under applicable Securities and Exchange Commission rules and any such pre-approval is reported to the Audit Committee at its next meeting. For the years ended December 31, 2021 and 2019, the Audit Committee of the Board pre-approved KPMG providing certain tax related services in the amounts of $43.5 thousand and $16.7 thousand, respectively, for the preparation of calculations under Internal Revenue Code Section 280G.

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PART IV


Item 15. Exhibits and Financial Statement Schedules


(a)Financial Statements and Schedules

(a)Financial Statements and Schedules
1.See “Item 8. Financial Statements and Supplementary Data.”


2.Exhibits

1.See “Item 8. Financial Statements and Supplementary Data.”

2.Exhibits

The exhibits filed as part of this report are as follows (exhibits incorporated by reference are set forth with the name of the registrant, the type of report and registration number or last date of the period for which it was filed, and the exhibit number in such filing):
NumberDescription
2.1**—
TOM-STACK Securities Purchase Agreement and Plan of Merger, dated as of December 6, 2015,October 21, 2018, by and among Tall OakEnLink Midstream, LLC, FE-STACK,EnLink Midstream Manager, LLC, TOM-STACK Holdings, LLC, TOM-STACK,NOLA Merger Sub, LLC, EnLink TOM Holdings,Midstream Partners, LP, and EnLink Midstream GP, LLC and, solely for purposes of Section 6.19 thereof, EnLink Midstream Partners, LP (incorporated by reference to Exhibit 2.1 to EnLink Midstream Partners, LP’sour Current Report on Form 8-K dated December 7, 2015,October 21, 2018, filed with the Commission on December 7, 2015,October 22, 2018, file No. 001-36340)001-36336).
2.23.1**—
TOMPC Securities Purchase Agreement, dated as of December 6, 2015, among TOMPC LLC, Tall Oak Midstream, LLC, EnLink TOM Holdings, LP, and EnLink Midstream, LLC and, solely for purposes of Section 6.19 thereof, EnLink Midstream Partners, LP (incorporated by reference to Exhibit 2.2 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated December 7, 2015, filed with the Commission on December 7, 2015, file No. 001-36340).
3.1—
Certificate of Formation of EnLink Midstream, LLC (incorporated by reference to Exhibit 3.1 to our Registration Statement on Form S-4, filed with the Commission on November 20, 2013, file No. 333-192419).
3.2—
Certificate of Amendment to Certificate of Formation of EnLink Midstream, LLC (incorporated by reference to Exhibit 3.2 to Amendment No. 2 to our Registration Statement on Form S-4, filed with the Commission on January 21, 2014, file No. 333-192419).
3.3—
FirstSecond Amended and Restated Operating Agreement of EnLink Midstream, LLC, dated as of March 7, 2014January 25, 2019 (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K dated March 7, 2014,January 25, 2019, filed with the Commission on March 11, 2014,January 29, 2019, file No. 001-36336).
3.4—
Certificate of Formation of EnLink Midstream Manager, LLC (incorporated by reference to Exhibit 3.12 to our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2014)2014, filed with the Commission on August 6, 2014, file No. 001-36336).
3.5—
Certificate of Amendment to the Certificate of Formation of EnLink Midstream Manager, LLC (incorporated by reference to Exhibit 3.13 to our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2014)2014, filed with the Commission on August 6, 2014, file No. 001-36336).
3.6—
FirstSecond Amended and Restated Limited Liability Company Agreement of EnLink Midstream Manager, LLC, dated as of July 18, 2018 (incorporated by reference to Exhibit 3.143.1 to our QuarterlyCurrent Report on Form 10-Q for8-K dated July 17, 2018, filed with the quarterly period ended June 30, 2014)Commission on July 23, 2018, file No. 001-36336).
3.7—
Certificate of Formation of EnLink Midstream GP, LLC (incorporated by reference to Exhibit 3.7 to EnLink Midstream Partners, LP’s Registration Statement on Form S-1, file No. 333-97779).
3.8—
Certificate of Amendment to the Certificate of Formation of EnLink Midstream GP, LLC (incorporated by reference to Exhibit 3.12 to EnLink Midstream Partners, LP’s Registration Statement on Form S-3, filed with the Commission on March 10, 2014, file No. 333-194465).
3.9—
ThirdFourth Amended and Restated Limited Liability Company Agreement of EnLink Midstream GP, LLC, dated as of July 7, 201418, 2018 (incorporated by reference to Exhibit 3.2 to EnLink Midstream Partners, LP’sour Current Report on Form 8-K dated July 7, 2014,17, 2018, filed with the Commission on July 7, 2014,23, 2018, file No. 001-36340)001-36336).
3.10—
Amendment No. 1 to Third Amended and Restated Limited Liability Company Agreement of EnLink Midstream GP, LLC, dated as of January 7, 2016 (incorporated by reference to Exhibit 3.2 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated January 12, 2016, filed with the Commission on January 12, 2016, file No. 001-36340).
3.11—
Certificate of Limited Partnership of EnLink Midstream Partners, LP (incorporated by reference to Exhibit 3.1 to EnLink Midstream Partners, LP’s Registration Statement on Form S-1, filed with the Commission on August 7, 2002, file No. 333-97779).
3.123.11—
Certificate of Amendment to the Certificate of Limited Partnership of EnLink Midstream Partners, LP (incorporated by reference to Exhibit 3.2 to EnLink Midstream Partners, LP’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2012, filed with the Commission on August 7, 2012, file No. 000-50067).
3.133.12—
Second Amendment to the Certificate of Limited Partnership of EnLink Midstream Partners, LP (incorporated by reference to Exhibit 3.3 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated March 6, 2014, filed with the Commission on March 11, 2014, file No. 001-36340).

3.13
3.14—
Third Amendment to the Certificate of Limited Partnership of EnLink Midstream Partners, LP (incorporated by reference to Exhibit 3.1 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated June 16, 2017, filed with the Commission on June 19, 2017, file No. 001-36340).
3.153.14—
NinthTenth Amended and Restated Agreement of Limited Partnership of EnLink Midstream Partners, LP, dated as of September 21, 2017January 25, 2019 (incorporated by reference to Exhibit 3.1 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated September 21, 2017, filed with the Commission on September 21, 2017, file No. 001-36340).
3.16—
Amendment No. 1 to Ninth Amended and Restated Agreement of Limited Partnership of EnLink Midstream Partners, LP, dated as of December 12, 2017 (incorporated by reference to Exhibit 3.13.2 to our Current Report on Form 8-K dated December 12, 2017,January 25, 2019, filed with the Commission on December 14, 2017,January 29, 2019, file No. 001-36336).
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4.1—
Registration Rights Agreement, dated as of March 7, 2014, by and among Devon Gas Services, L.P. and, EnLink Midstream, LLC and, pursuant to a joinder thereto, dated as of July 18, 2018, GIP III Stetson II, L.P. (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K dated March 7, 2014, filed with the Commission on March 11, 2014, file No. 001-36336).
4.2—
Amended and Restated Registration Rights Agreement, dated as of January 7, 2016,25, 2019, by and between EnLink Midstream, Partners, LPLLC and Enfield Holdings, L.P. and, pursuant to joinders thereto, dated as of August 4, 2021, Patton BIP HoldCo I LLC, Patton BIP HoldCo II LLC, and OCM ENLK Holdings, LLC (incorporated by reference to Exhibit 4.110.1 to EnLink Midstream Partners, LP’sour Current Report on Form 8-K dated January 12, 2016,25, 2019, filed with the Commission on January 12, 2016)29, 2019, file No. 001-36336).
4.3—
Registration Rights Agreement, dated as of January 7, 2016, by and among EnLink Midstream, LLC, Tall Oak Midstream, LLC and FE-STACK, LLC (incorporated by reference to Exhibit 4.2 to our Current Report on Form 8-K dated January 12,7, 2016, filed with the Commission on January 12, 2016, file No. 001-36336).
4.4—
Unitholder Agreement, dated as of March 7, 2014, by and among Devon Energy Corporation, Devon Gas Corporation, Devon Gas Services, L.P., Southwestern Gas Pipeline, Inc. and EnLink Midstream Partners, LP (incorporated by reference to Exhibit 4.1 to EnLink Midstream Partner’s Current Report on Form 8-K dated March 6, 2014, filed with the Commission on March 11, 2014), file No. 001-36340).
4.5—
Specimen Certificate representing common units (incorporated by reference to Exhibit 5 to our Registration Statement on Form 8-A, filed with the Commission on March 6, 2014, file No. 001-36336).
4.64.5—
Indenture, dated as of March 19, 2014, by and between EnLink Midstream Partners, LP and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.2 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated March 19, 2014, filed with the Commission on March 21, 2014, file No. 001-36340).
4.74.6—
First Supplemental Indenture, dated as of March 19, 2014, by and between EnLink Midstream Partners, LP and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.3 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated March 19, 2014, filed with the Commission on March 21, 2014, file No. 001-36340).
4.84.7—
Second Supplemental Indenture, dated as of November 12, 2014, by and between EnLink Midstream Partners, LP and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.3 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated November 6, 2014, filed with the Commission on November 12, 2014, file No. 001-36340).
4.94.8—
Third Supplemental Indenture, dated as of May 12, 2015, by and between EnLink Midstream Partners, LP and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.3 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated May 7, 2015, filed with the Commission on May 12, 2015)2015, file No. 001-36340).
4.104.9—
Fourth Supplemental Indenture, dated as of July 14, 2016, by and between EnLink Midstream Partners, LP and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.2 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated July 11, 2016, filed with the Commission on July 14, 2016, file No. 001-36340).
4.114.10—
Fifth Supplemental Indenture, dated as of May 11, 2017, by and between EnLink Midstream Partners, LP and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.2 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated May 11, 2017, filed with the Commission on May 11, 2017, file No. 001-36340).
10.14.11—
First Offer Agreement,Indenture, dated as of March 7, 2014,April 9, 2019, by and between EnLink Midstream, LLC and Devon Energy CorporationWells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K dated April 4, 2019, filed with the Commission on April 9, 2019, file No. 001-36336).
4.12—
First Supplemental Indenture, dated as of April 9, 2019, by and among EnLink Midstream, LLC, EnLink Midstream Partners, LP, and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.2 to our Current Report on Form 8-K dated April 4, 2019, filed with the Commission on April 9, 2019, file No. 001-36336).
4.13—
Indenture, dated as of December 17, 2020, by and among EnLink Midstream, LLC, as issuer, EnLink Midstream Partners, LP, as guarantor, and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K dated December 14, 2020, filed with the Commission on December 18, 2020, file No. 001-36336).
4.14*—
Description of Securities.
10.1—
Form of Indemnification Agreement (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K dated March 7, 2014,July 17, 2018, filed with the Commission on March 11, 2014,July 23, 2018, file No. 001-36336).
10.2—
Preferential Rights Agreement, dated as of March 7, 2014, by and among Crosstex Energy, Inc., EnLink Midstream Partners, LP and EnLink Midstream, LLC (incorporated by reference to Exhibit 10.1 to EnLink Midstream Partner LP’s Current Report on Form 8-K dated March 6, 2014, filed with the Commission on March 11, 2014, file No. 001-36340).

10.3—
Gas Gathering and Processing Contract-Bridgeport Plant, dated as of March 7, 2014, by and between Devon Gas Services, L.P. and EnLink Midstream Services, LLC (incorporated by reference to Exhibit 10.2 to EnLink Midstream Partner LP’s Current Report on Form 8-K dated March 6, 2014, filed with the Commission on March 11, 2014, file No. 001-36340).
10.4—
Gas Gathering and Processing Contract-Northridge Plant, dated as of March 7, 2014, by and between Devon Gas Services, L.P. and EnLink Midstream Services, LLC (incorporated by reference to Exhibit 10.4 to EnLink Midstream Partner LP’s Current Report on Form 8-K dated March 6, 2014, filed with the Commission on March 11, 2014, file No. 001-36340).
10.5—
Gas Gathering and Processing Contract-East Johnson County System, dated as of March 7, 2014, by and between Devon Gas Services, L.P. and EnLink Midstream Services, LLC (incorporated by reference to Exhibit 10.5 to EnLink Midstream Partner LP’s Current Report on Form 8-K dated March 6, 2014, filed with the Commission on March 11, 2014, file No. 001-36340).
10.6—
Form of Indemnification Agreement (incorporated by reference to Exhibit 10.6 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated March 6, 2014, filed with the Commission on March 11, 2014, file No. 001-36340).
10.7—
Form of Indemnification Agreement (incorporated by reference to Exhibit 10.8 to our Current Report on Form 8-K dated March 7, 2014, filed with the Commission on March 11, 2014, file No. 001-36336).
10.8†—
EnLink Midstream GP, LLC Long-Term Incentive Plan, (the “GP Plan”), as amended and restated in 2016 (incorporated by reference to Exhibit 10.1 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated March 9, 2016, filed with the Commission on March 9, 2016, file No. 001-36340).
10.9†—
EnLink Midstream, LLC 2014 Long-Term Incentive PlanJanuary 25, 2019 (the “2014“GP Plan”) (incorporated by reference to Exhibit 4.44.2 to our Registration Statement on Form S-8 dated March 7, 2014,January 28, 2019, filed with the Commission on March 7, 2014January 28, 2019, file No. 333-194395)333-229393).
10.1010.3*†—
EnLink Midstream, LLC 2014 Long-Term Incentive Plan, as amended and restated December 16, 2021 (the “2014 Plan”).
10.4†—
Form of Severance AgreementAmended Performance Conditions for Certain Performance Unit Agreements made under the GP Plan and 2014 Plan, effective as of January 25, 2019 (incorporated by reference to Exhibit 10.1 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated September 17, 2014, filed with the Commission on September 23, 2014, file No. 001-36340).
10.11†—
Form of Amended and Restated Severance Agreement (incorporated by reference to Exhibit 10.1 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated October 31, 2014, filed with the Commission on November 3, 2014, file No. 001-36340).
10.12—
Form of Amended and Restated Change in Control Agreement (incorporated by reference to Exhibit 10.1 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated June 12, 2015, filed with the Commission June 15, 2015, file No. 001-36340).
10.13†—
Form of Restricted Incentive Unit Agreement made under the 2014 Plan (Executive Form) (incorporated by reference to Exhibit 4.6 to our Registration Statement on Form S-8, file No. 333-194395).
10.14†—
Form of Restricted Incentive Unit Agreement made under the 2014 Plan (Employee Form) (incorporated by reference to Exhibit 4.7 to our Registration Statement on Form S-8, file No. 333-194395).
10.15†—
Form of Restricted Unit Agreement made under the GP Plan (incorporated by reference to Exhibit 10.910.6 to our Annual Report on Form 10-K for the year endeddated December 31, 2009, file No. 000-50067).
10.16—
Form of Restricted Incentive Unit Agreement made under the GP Plan (incorporated by reference to Exhibit 10.2 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated May 9, 2013,2018, filed with the Commission on May 13, 2013,February 20, 2019, file No. 000-50067)001-36336).
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10.1710.5—
Revolving Credit Agreement, dated as of March 7, 2014,December 11, 2018, by and among EnLink Midstream, LLC, Bank of America, N.A., as Administrative Agent, Swing Line Lender and L/C Issuer, thereunder,Bank of Montreal and Royal Bank of Canada, as Co-Syndication Agents, Citibank, N.A. and Wells Fargo Bank, National Association, as Co-Syndication Agents, Royal Bank of Canada and Bank of Montreal, as Co-Documentation Agents, and the other lenders party thereto (incorporated by reference to Exhibit 10.710.1 to our Current Report on Form 8-K dated March 7, 2014,December 11, 2018, filed with the Commission on March 11, 2014,December 12, 2018, file No. 001-36336).
10.1810.6—
First Amendment to CreditGuaranty Agreement, and Waiver, dated as of December 23, 2015,January 25, 2019, by and among EnLink Midstream LLC,Partners, LP in favor of Bank of America, N.A., as Administrative Agent, andfor the ratable benefit of the lenders from time to time party theretoto the Revolving Credit Agreement, dated as of December 11, 2018 (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K dated December 29, 2015,January 25, 2019, filed with the Commission on DecemberJanuary 29, 2015,2019, file No. 001-36336).
10.19—
Credit Agreement, dated as of February 20, 2014, by and among Crosstex Energy, L.P., Bank of America, N.A., as Administrative Agent, Swing Line Lender and L/C Issuer thereunder, Citibank, N.A. and Wells Fargo Bank, National Association, as Co-Syndication Agents, Royal Bank of Canada and Bank of Montreal, as Co-Documentation Agents, and the other lenders party thereto (incorporated by reference to Exhibit 10.1 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated February 20, 2014, filed with the Commission on February 21, 2014, file No. 000-50067).
10.20—
First Amendment to Credit Agreement, dated as of December 23, 2015, by and among EnLink Midstream Partners, LP, Bank of America, N.A., as Administrative Agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated December 29, 2015, filed with the Commission on December 29, 2015, file No. 001-36340).

10.2110.7†—
Form of Performance Unit Agreement made under the GP Plan (incorporated by reference to Exhibit 10.1 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated January 30, 2015, filed with the Commission February 5, 2015, file No. 001-36340).
10.22†—
Form of Performance Unit Agreement made under the 2014 Plan (incorporated by reference to Exhibit 10.2 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated January 30, 2015, filed with the Commission February 5, 2015, file No. 001-36340).
10.23†—
Form of Restricted Incentive Unit Agreement made under the GP Plan (incorporated by reference to Exhibit 10.3 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated January 30, 2015, filed with the Commission February 5, 2015, file No. 001-36340).
10.24†—
Form of Restricted Incentive Unit Agreement made under the 2014 Plan (incorporated by reference to Exhibit 10.4 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated January 30, 2015, filed with the Commission February 5, 2015, file No. 001-36340).
10.25—
Commitment Increase and Extension Agreement, dated as of February 5, 2015, by and among EnLink Midstream Partners, LP, the Lenders party thereto, and Bank of America, N.A., as an L/C Issuer, as Swing Line Lender, and as Administrative Agent for the Lenders (incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K dated February 5, 2015, filed with the Commission on February 11, 2015, file No. 001-36340).
10.26—
Convertible Preferred Unit Purchase Agreement, dated as of December 6, 2015, by and between EnLink Midstream Partners, LP and Enfield Holdings, L.P. (incorporated by reference to Exhibit 10.1 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated December 7, 2015, filed with the Commission on December 7, 2015, file No. 001-36340).
10.27—
Board Representation Agreement, dated as of January 7, 2016, by and among EnLink Midstream GP, LLC, EnLink Midstream Partners, LP, EnLink Midstream, Inc. and TPG VII Management, LLC (incorporated by reference to Exhibit 10.1 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated January 12, 2016, filed with the Commission on January 12, 2016, file No. 001-36340).
10.28†—
Form of Performance Unit Agreement made under the GP Plan (incorporated by reference to Exhibit 10.1 to EnLink Midstream Partners, LP’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2017, file No. 001-36340).
10.2910.8†—
Form of Performance Unit Agreement made under the 2014 Plan (incorporated by reference to Exhibit 10.2 to EnLink Midstream Partners, LP’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2017, file No. 001-36340).
10.3010.9†—
Form of Restricted Incentive Unit Agreement made under the GP Plan (incorporated by reference to Exhibit 10.3 to EnLink Midstream Partners, LP’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2017, file No. 001-36340).
10.3110.10†—
Form of Restricted Incentive Unit Agreement made under the 2014 Plan (incorporated by reference to Exhibit 10.4 to EnLink Midstream Partners, LP’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2017, file No. 001-36340).
10.11†—
Form of Performance Unit Agreement made under the 2014 Plan (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K dated March 8, 2019, filed with the Commission March 14, 2019, file No. 001-36336).
10.12†—
Form of Restricted Incentive Unit Agreement made under the 2014 Plan (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K dated March 8, 2019, filed with the Commission March 14, 2019, file No. 001-36336).
10.13*†—
Form of Performance Unit Agreement made under the 2014 Plan.
10.14†—
Form of EnLink Midstream Operating, LP Amended and Restated Severance Agreement (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K dated September 18, 2019, filed with the Commission on September 23, 2019, file No. 001-36336).
10.15*†—
Form of EnLink Midstream Operating, LP Amended and Restated Change in Control Agreement.
10.16—
Sale and Contribution Agreement, dated as of October 21, 2020, by and among EnLink Midstream Funding, LLC, EnLink Midstream Operating, LP, and the originators from time to time party thereto (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K dated October 21, 2020, filed with the Commission on October 22, 2020, file No. 001-36336).
10.17—
Receivables Financing Agreement, dated as of October 21, 2020, by and among EnLink Midstream Funding, LLC, as borrower, EnLink Midstream Operating, LP, as initial servicer, PNC Bank, National Association, as administrative agent and lender, the lenders party thereto, and PNC Capital Markets, LLC, as structuring agent (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K dated October 21, 2020, filed with the Commission on October 22, 2020, file No. 001-36336).
10.18—
First Amendment to the Receivables Financing Agreement, dated as of February 26, 2021, by and among EnLink Midstream Funding, LLC, as borrower, EnLink Midstream Operating, LP, as initial servicer, and PNC Bank, National Association, as administrative agent and as lender (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K dated February 26, 2021, filed with the Commission on March 1, 2021, file No. 001-36336).
10.19—
Second Amendment to the Receivables Financing Agreement, dated as of September 24, 2021, by and among EnLink Midstream Funding, LLC, as borrower, EnLink Midstream Operating, LP, as initial servicer, and PNC Bank, National Association, as administrative agent and as lender and PNC Capital Markets LLC, as structuring agent and sustainability agent (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K dated September 24, 2021, filed with the Commission on September 27, 2021, file No. 001-36336).
10.20*—
Unit Repurchase Agreement, dated as of February 15, 2022 between EnLink Midstream, LLC, GIP III Stetson I, L.P. and GIP III Stetson II, L.P.
21.1*—
List of Subsidiaries.
23.122.1*—
Subsidiary Guarantors.
23.1*—
Consent of KPMG LLP.
31.1*—
Certification of the Principal Executive Officer.
31.2*—
Certification of the Principal Financial Officer.
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32.1*—
Certification of the Principal Executive Officer and the Principal Financial Officer of the Partnership pursuant to 18 U.S.C. Section 1350.
101*—The following financial information from EnLink Midstream, LLC’sLLC's Annual Report on Form 10-K for the year ended December 31, 2017,2021, formatted in XBRL (eXtensibleiXBRL (Inline eXtensible Business Reporting Language): (i) Consolidated Balance Sheets as of December 31, 2021 and December 31, 2020, (ii) Consolidated Statements of Operations for the years ended December 31, 2017, 20162021, 2020, and 2015, (ii) Consolidated Balance Sheets as of December 31, 2017 and 2016,2019, (iii) Consolidated Statements of Cash Flows for the years ended December 31, 2017, 2016 and 2015, (iv) Consolidated Statements of Changes in Members’ Equity for the years ended December 31, 2017, 20162021, 2020, and 20152019, (iv) Consolidated Statements of Cash Flows for the years ended December 31, 2021, 2020, and 2019, and (v) the Notesnotes to Consolidated Financial Statements.
104*—Cover Page Interactive Data File (formatted as Inline iXBRL and included in Exhibit 101).
____________________________

*    Filed herewith.


**    In accordance with the instruction on Item 601(b)(2)601(a)(5) of Regulation S-K, the exhibits and schedules to ExhibitsExhibit 2.1 and 2.2 are not filed herewith. The agreements identifyagreement identifies such exhibits and schedules, including the general naturesubject matter of their content. We undertake to provide copies of such exhibits and schedules to the Commission upon request.


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


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SIGNATURES


Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


ENLINK MIDSTREAM, LLC
By:EnLink Midstream Manager, LLC, its managing member
February 21, 201816, 2022By:/s/ MICHAEL J. GARBERDINGBARRY E. DAVIS
Michael J. Garberding,Barry E. Davis
PresidentChairman and Chief Executive Officer


Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below on the dates indicated by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.


SignatureTitleDate
SignatureTitleDate
/s/ MICHAEL J. GARBERDINGPresident and Chief Executive Officer (Principal Executive Officer)February 21, 2018
Michael J. Garberding
/s/ BARRY E. DAVISChairman, Chief Executive Chairman of the BoardOfficer, and Director
(Principal Executive Officer)		February 21, 201816, 2022
Barry E. Davis
/s/ JAMES C. CRAINDEBORAH G. ADAMSDirectorFebruary 21, 201816, 2022
James C. CrainDeborah G. Adams
/s/ WILLIAM J. BRILLIANTDirectorFebruary 16, 2022
William J. Brilliant
/s/ TIFFANY THOM CEPAKDirectorFebruary 16, 2022
Tiffany Thom Cepak
/s/ LELDON E. ECHOLSDirectorFebruary 21, 201816, 2022
Leldon E. Echols
/s/ ROLF A. GAFVERTTHOMAS W. HORTONDirectorFebruary 21, 201816, 2022
Rolf A. GafvertThomas W. Horton
/s/ DAVID A. HAGERJAMES K. LEEDirectorFebruary 21, 201816, 2022
David A. HagerJames K. Lee
/s/ KEVIN D. LAFFERTYSCOTT E. TELESZDirectorFebruary 21, 201816, 2022
Kevin D. LaffertyScott E. Telesz
/s/ R. ALAN MARCUMKYLE D. VANNDirectorFebruary 21, 201816, 2022
R. Alan MarcumKyle D. Vann
/s/ MARY P. RICCIARDELLOPABLO G. MERCADODirectorFebruary 21, 2018
Mary P. Ricciardello
/s/ JEFF L. RITENOURDirectorFebruary 21, 2018
Jeff L. Ritenour
/s/ LYNDON C. TAYLORDirectorFebruary 21, 2018
Lyndon C. Taylor
/s/ ERIC D. BATCHELDERExecutive Vice President and Chief Financial Officer (Principal Financial Officer)February 16, 2022
Pablo G. Mercado
/s/ J. PHILIPP ROSSBACHVice President and Chief Accounting Officer
(Principal Accounting Officer)		February 21, 201816, 2022
Eric D. BatchelderJ. Philipp Rossbach

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