10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

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

For the fiscal year ended December 31, 2021

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)

Delaware		46-4108528
(State of organization)		(I.R.S. Employer Identification No.)
1722 Routh St.,	Suite 1300
Dallas,	Texas	75201
(Address of principal executive offices)		(Zip Code)

(214) 953-9500

(Registrant’s telephone number, including area code)

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

Title of Each Class	Trading Symbol	Name of Exchange on which Registered
Common Units Representing Limited Liability Company Interests	ENLC	The New York Stock Exchange

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 ☒ 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 ☒

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

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

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

Large accelerated filer	☒	Accelerated filer	☐
Non-accelerated filer	☐	Smaller reporting company	☐
Emerging growth company	☐		☐

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

Indicate by check mark whether the registrant 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 ☒

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

At February 9, 2022, there were 484,003,750 common units outstanding.

DOCUMENTS INCORPORATED BY REFERENCE:

None.

TABLE OF CONTENTS

Item	Description	Page
	PART I
1.	BUSINESS	5
1A.	RISK FACTORS	32
1B.	UNRESOLVED STAFF COMMENTS	61
2.	PROPERTIES	62
3.	LEGAL PROCEEDINGS	62
4.	MINE SAFETY DISCLOSURES	62
	PART II
5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED UNITHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES	63
6.	[RESERVED]	63
7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	64
7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	88
8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	92
9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	145
9A.	CONTROLS AND PROCEDURES	145
9B.	OTHER INFORMATION	145
	PART III
10.	DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE	147
11.	EXECUTIVE COMPENSATION	151
12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS	166
13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE	169
14.	PRINCIPAL ACCOUNTANT FEES AND SERVICES	170
	PART IV
15.	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES	172

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DEFINITIONS

The following terms as defined are used in this document:

Defined Term	Definition
/d	Per day.
2014 Plan	ENLC’s 2014 Long-Term Incentive Plan.
Adjusted gross margin	Revenue less cost of sales, exclusive of operating expenses and depreciation and amortization. Adjusted gross margin is a non-GAAP financial measure. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures” for additional information.
AR Facility	An 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.
ASC	The 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 JV	Ascension Pipeline Company, LLC, a joint venture between a subsidiary of ENLK and a subsidiary of Marathon Petroleum Corporation in which ENLK owns a 50% interest and Marathon Petroleum Corporation owns a 50% interest. The Ascension JV, which began operations in April 2017, owns an NGL pipeline that connects ENLK’s Riverside fractionator to Marathon Petroleum Corporation’s Garyville refinery.
Avenger	Avenger crude oil gathering system, a crude oil gathering system in the northern Delaware Basin.
Bbls	Barrels.
Bcf	Billion cubic feet.
Beginning TSR Price	The beginning total shareholder return (“TSR”) price, which is the closing unit price of ENLC on the grant date of the performance award agreement or the previous trading day if the grant date was not a trading day, is one of the assumptions used to calculate the grant-date fair value of performance award agreements.
BLM	Bureau of Land Management.
BKV	Banpu Kalnin Ventures Corporation, an affiliate of BKV Oil and Gas Capital Partners.
CCS	Carbon capture, transportation, and sequestration.
Cedar Cove JV	Cedar Cove Midstream LLC, a joint venture between a subsidiary of ENLK and a subsidiary of Kinder Morgan, Inc. in which ENLK owns a 30% interest and Kinder Morgan, Inc. owns a 70% interest. The Cedar Cove JV, which was formed in November 2016, owns gathering and compression assets in Blaine County, Oklahoma, located in the STACK play.
CFTC	U.S. Commodity Futures Trading Commission.
CNOW	Central Northern Oklahoma Woodford Shale.
CO2	Carbon dioxide.
Commission	U.S. Securities and Exchange Commission.
Consolidated Credit Facility	A $1.75 billion unsecured revolving credit facility entered into by ENLC that matures on January 25, 2024, which includes a $500.0 million letter of credit subfacility. The Consolidated Credit Facility was available upon closing of the Merger and is guaranteed by ENLK.
Delaware Basin	A large sedimentary basin in West Texas and New Mexico.
Delaware Basin JV	Delaware G&P LLC, a joint venture between a subsidiary of ENLK and an affiliate of NGP in which ENLK owns a 50.1% interest and NGP owns a 49.9% interest. The Delaware Basin JV, which was formed in August 2016, owns the Lobo processing facilities and the Tiger processing plant located in the Delaware Basin in Texas.
Devon	Devon Energy Corporation.
ENLC	EnLink Midstream, LLC.
ENLC Class C Common Units	A class of non-economic ENLC common units issued immediately prior to the Merger equal to the number of Series B Preferred Units held immediately prior to the effective time of the Merger, in order to provide certain voting rights to holders of the Series B Preferred Units with respect to ENLC.
ENLC EDA	Equity 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.

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ENLK	EnLink Midstream Partners, LP or, when applicable, EnLink Midstream Partners, LP together with its consolidated subsidiaries. Also referred to as the “Partnership.”
Exchange Act	The Securities Exchange Act of 1934, as amended.
FERC	Federal Energy Regulatory Commission.
GAAP	Generally accepted accounting principles in the United States of America.
Gals	Gallons.
GCF	Gulf 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 Partner	EnLink 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.
GHG	Greenhouse gas.
GIP	Global Infrastructure Management, LLC, an independent infrastructure fund manager, itself, its affiliates, or managed fund vehicles, including GIP III Stetson I, L.P., GIP III Stetson II, L.P., and their affiliates.
GIP Transaction	On 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 Plan	The 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.
ISDAs	International Swaps and Derivatives Association Agreements.
Managing Member	EnLink Midstream Manager, LLC, the managing member of ENLC.
MEGA system	Midland Energy Gathering Area system in Midland, Martin, and Glasscock counties, Texas.
Merger	On January 25, 2019, NOLA Merger Sub, LLC (previously a wholly-owned subsidiary of ENLC) merged with and into ENLK with ENLK continuing as the surviving entity and a subsidiary of ENLC.
Midland Basin	A large sedimentary basin in West Texas.
MMbbls	Million barrels.
MMbtu	Million British thermal units.
MMcf	Million cubic feet.
MVC	Minimum volume commitment.
NGL	Natural gas liquid.
NGP	NGP Natural Resources XI, LP.
NOLA Merger Sub	NOLA Merger Sub, LLC, previously a wholly-owned subsidiary of ENLC prior to the Merger.
NYSE	New York Stock Exchange.
OPEC+	Organization of the Petroleum Exporting Countries and its broader partners.
Operating Partnership	EnLink Midstream Operating, LP, a Delaware limited partnership and wholly-owned subsidiary of ENLK.
ORV	ENLK’s Ohio River Valley crude oil, condensate stabilization, natural gas compression, and brine disposal assets in the Utica and Marcellus shales.
OTC	Over-the-counter.
Permian Basin	A large sedimentary basin that includes the Midland and Delaware Basins primarily in West Texas and New Mexico.
POL contracts	Percentage-of-liquids contracts.
POP contracts	Percentage-of-proceeds contracts.
Series B Preferred Unit	ENLK’s Series B Cumulative Convertible Preferred Unit.
Series C Preferred Unit	ENLK’s Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Unit.
STACK	Sooner Trend Anadarko Basin Canadian and Kingfisher Counties in Oklahoma.
Term Loan	A term loan originally in the amount of $850.0 million entered into by ENLK on December 11, 2018 with Bank of America, N.A., as Administrative Agent, Bank of Montreal and Royal Bank of Canada, as Co-Syndication Agents, Citibank, N.A. and Wells Fargo Bank, National Association, as Co-Documentation Agents, and the lenders party thereto, which ENLC assumed in connection with the Merger and the obligations of which ENLK guaranteed. The Term Loan was paid at maturity on December 10, 2021.
VEX	The 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 Star	White Star Petroleum, LLC.

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ENLINK MIDSTREAM, LLC

PART I

Item 1. Business

General and Recent Developments

Formation

ENLC is a Delaware limited liability company formed in October 2013. EnLink Midstream, LLC common units are traded on the 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 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” 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,” 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.

On July 18, 2018, GIP acquired control of us and our 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 fiscal year ended December 31, 2019, filed with the Commission on February 26, 2020, and available here.

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The following diagram depicts our organization and ownership as of December 31, 2021:

____________________________

(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 conditions fully 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, and selling NGLs; and

•gathering, transporting, stabilizing, storing, trans-loading, and selling crude oil and condensate, in addition to brine disposal services.

Our midstream energy asset network includes approximately 12,100 miles of pipelines, 22 natural gas processing plants with approximately 5.5 Bcf/d of processing capacity, seven fractionators with approximately 320,000 Bbls/d of fractionation capacity, barge and rail terminals, product storage facilities, purchasing and marketing capabilities, brine disposal wells, a crude oil trucking fleet, and equity investments in certain joint ventures. Our operations are based in the United States, and our sales are derived primarily from domestic customers.

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

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

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

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.

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

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

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

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

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

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

For more information about our segment reporting, see “Item 8. Financial Statements and Supplementary Data—Note 15.”

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 while growing prudently and profitably. We intend to accomplish this objective by executing the following strategies:

•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 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 are 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 participating in the energy transition. As part of this effort, we are developing an

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integrated 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 advantage 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 will continue to be 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 reduce or offset emissions in our operations using process improvements and technology, or utilizing renewable energy. With respect to safety, we are committed to operating safely and in an environmentally responsible manner. During 2021, EnLink had its best safety year on record with the lowest number of employee reportable incidents in our history.

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Our Assets

Our assets consist of gathering systems, transmission pipelines, processing facilities, fractionation facilities, stabilization facilities, storage facilities, and ancillary assets. The following tables provide information about our assets as of and for the year ended December 31, 2021:

				Year Ended
				December 31, 2021
Gathering and Transmission Pipelines	Approximate Length (Miles)	Compression (HP)	Estimated Capacity (1)	Average Throughput (2)
Gas Pipelines
Permian assets:
MEGA System gathering facilities	980	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 system	3,035	97,400	3,975	2,160,800
Oklahoma assets:
Central Oklahoma gathering system	1,850	211,490	1,180	965,900
Northridge gathering system	140	14,000	65	26,500
Oklahoma gas assets	1,990	225,490	1,245	992,400
North Texas assets:
Bridgeport rich and lean gathering systems	2,780	188,000	822	668,200
Johnson County gathering system	385	49,000	400	92,300
Silver Creek gathering system	890	45,000	205	200,600
Acacia transmission system	130	16,000	920	416,300
North Texas gas assets	4,185	298,000	2,347	1,377,400
Total Gas Pipelines	10,430	880,006	8,392	5,597,600
NGL, Crude Oil, and Condensate Pipelines
Permian assets:
Permian Crude Oil and Condensate assets	490	—	188,500	134,600
Louisiana assets:
Cajun-Sibon NGL pipeline system	760	—	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 assets	1,005	—	252,370	212,800
Oklahoma assets:
Central Oklahoma crude oil gathering systems	200	—	160,000	20,200
Total NGL, Crude Oil, and Condensate Pipelines	1,695	—	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, 2021
Processing Facilities	Processing Capacity (MMcf/d)	Average Throughput (MMbtu/d)
Permian assets:
MEGA system processing facilities	663	648,000
Delaware processing facilities	635	362,000
Permian assets	1,298	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 facility	200	94,300
Oklahoma assets	1,360	1,010,300
North Texas assets:
Bridgeport processing facility	800	505,200
Silver Creek processing system (3)	280	126,300
North Texas assets	1,080	631,500
Total Processing Facilities	5,516	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 Facilities	Estimated 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 plant	8,500	1,100
Eunice fractionation facility	75,000	62,600
Louisiana assets	220,300	177,500
North Texas assets:
Bridgeport processing facility	25,000	11,000
Corporate assets:
GCF (3)	56,000	11,800
Total Fractionation Facilities	316,300	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.

		Year Ended
		December 31, 2021
Storage Assets	Storage Type	Estimated Storage Capacity (1)
Permian assets:
Avenger storage	Crude	0.1
Louisiana assets:
Belle Rose gas storage facility	Gas	9.0
Sorrento gas storage facility	Gas	5.6
Jefferson Island storage facility	Gas	3.0
Napoleonville NGL storage facility	NGL	6.8
ORV storage	Crude	0.7
Oklahoma assets:
Central Oklahoma storage	Crude	0.2

____________________________

(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 Permian segment assets include 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 Permian segment consist of the following:

•MEGA system gathering facilities. This gathering system in the Midland 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.

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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 crude oil gathering system in the northern Delaware Basin that is 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 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.

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

•MEGA system processing facilities. Our MEGA system natural gas processing facilities 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 195 MMcf/d, the Riptide processing facility with a capacity of 240 MMcf/d, and the War Horse processing plant with a capacity of 95 MMcf/d.

•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 Lobo I, Lobo II, and Lobo III processing plants which account for 35 MMcf/d, 140 MMcf/d, and 220 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.

•Fractionation Facility. The Mesquite fractionator has an approximate capacity of 15,000 Bbls/d and is located at our Midland gas processing plant complex. The Mesquite fractionator is not currently operational.

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

•Transmission and Gathering Systems. The 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, 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. Our gas processing facilities and storage facilities in the Louisiana segment consist of the following:

•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. We have shut down the Blue Water gas processing plant, and we do not expect to operate it in the near future unless 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 Central Louisiana and has a capacity of 350 MMcf/d of natural gas. We have shut down the Eunice processing plant, and we do not expect the plant to operate in the near 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 in Johnson's Bayou, Louisiana and has a processing capacity of 300 MMcf/d of natural gas. We have shut down the Sabine Pass processing plant, and we do not expect the plant to operate in the near future unless volumes are sufficient to run the plant.

•NGL and Crude Oil Pipeline Systems. Our NGL and crude oil pipeline systems in the Louisiana segment consist of NGL pipelines, crude oil and condensate pipelines, underground NGL 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 Plaquemine or Eunice fractionators or to third-party fractionators when necessary.

•Ascension Pipeline. The Ascension JV is an NGL pipeline that connects our Riverside fractionator to Marathon Petroleum Corporation’s Garyville refinery and is owned 50% by Marathon 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 136,800 Bbls/d of raw-make NGL products.

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

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

•Riverside Fractionation Facility. The Riverside fractionator and loading facility are located on the Mississippi River upriver from Geismar, Louisiana. Liquids are delivered to the Riverside fractionator by pipeline from the 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 approximately seven 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.

•Northridge processing facility. Our Northridge processing plant 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 Energy, Inc., Enable Midstream Partners, LP, and MPLX LP.

•Crude Oil Gathering Systems. Our crude and condensate assets in the Oklahoma segment have crude oil and condensate pipelines and above ground storage in Central Oklahoma. These assets consist of the following:

•Central Oklahoma Crude Oil Gathering Systems. Our Central Oklahoma crude oil gathering systems include Black Coyote and Redbud. Black Coyote operates in the core of the STACK play in Central Oklahoma and was built primarily to service acreage dedicated from Devon, which is the anchor customer on the system. Redbud 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 delivered to the 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 North Texas segment consist of 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.

•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,

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which account for 50 MMcf/d, 200 MMcf/d, and 30 MMcf/d of processing capacity, respectively. The Azle and Goforth plants are idled due to decreased volumes, and these plants remain non-operational. Currently, the processing capacity at the Silver Creek plant is sufficient to process all gas on the Silver 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 are not significant to our adjusted gross margin.

Corporate Segment Assets. Our Corporate segment assets primarily consist of our 38.75% ownership interest in GCF and 30% ownership interest in the Cedar Cove JV.

•GCF. We own a 38.75% interest in GCF, with the remaining interests owned 22.5% by Phillips 66, and 38.75% by Targa Resources Partners, LP. GCF owns an NGL fractionator located on the Gulf Coast at Mont Belvieu, Texas. Targa 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 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. We own a 30% interest in the Cedar Cove JV, which operates gathering and compression assets in Blaine County, Oklahoma that 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 expect to complete the relocation in the second half of 2022.

Amarillo Rattler Acquisition. On April 30, 2021, we completed the acquisition of Amarillo Rattler, LLC, the owner of a gathering and processing system located in the Midland Basin. 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.

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 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 processing 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 compete with similar enterprises in providing additional gathering and processing services in its respective areas of operation. Many of our competitors may offer more services or have greater 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.

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,
	2021		2020		2019
Devon	6.7	%	14.4	%	10.5	%
Dow Hydrocarbons and Resources LLC	14.5	%	13.2	%	10.0	%
Marathon Petroleum Corporation	13.4	%	12.2	%	13.8	%

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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 pipeline that is subject to regulation as a natural gas company by FERC under the Natural Gas Act of 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 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 tariff 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.

In addition to policies 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 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 gives 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 approximately $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 Natural Gas Policy Act of 1978 (“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 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. On December 17, 2020, for the five-year period beginning on July 1, 2021, FERC established an annual index adjustment equal to the change in the producer price index for finished goods plus 0.78%. On January 20, 2022, however, FERC issued an Order 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 result of the change in the index adjustment, certain ceiling levels for our interstate liquids pipelines were reduced and any rates that exceeded the 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 (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 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. The U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (“PHMSA”) regulates safety issues related to downhole facilities located at both intrastate and interstate underground natural gas storage facilities. PHMSA mandates certain reporting requirements for operators of underground

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natural gas storage facilities and sets minimum federal safety standards. In addition, all intrastate transportation related underground natural gas storage facilities are subject to minimum federal safety standards and are 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. We are in compliance with 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, 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. 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. In December 2020, the President of the United States signed the Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2020 (the “PIPES Act”), which reauthorizes PHMSA’s oil and gas pipeline programs through 2023 and imposes additional mandates on the agency. For example, the law requires, among other things, rulemaking to amend the integrity management program, emergency response plan, operation and maintenance manual, and pressure control recordkeeping requirements for gas distribution operators; to create new leak detection and repair program obligations; and to set new minimum federal safety standards for onshore gas gathering lines. Additionally, PHMSA’s maximum civil penalties were increased in January 2021.

On January 23, 2017, PHMSA issued 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 added 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 January 20, 2021, the Biden Administration came into office and immediately issued a number of executive orders related to environmental matters that could affect our operations and those of our customers, including 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. Among the areas that could be affected by the review are regulations addressing methane emissions and the part of the extraction 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 rejoining the Paris Agreement, the Biden Administration announced that the United States 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. 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.

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. 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”). Effective September 23, 2019, the DFW area was reclassified to a serious nonattainment area under this standard, 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 50 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 25 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 1.2 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 promulgated a new NAAQS for ozone of 70 parts per billion (“ppb”) for both the 8-hour primary and secondary standards, 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 by its marginal attainment date of August 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.

In partial response to the issues raised regarding the 2012 rulemaking, the EPA 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 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 to 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 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. EPA draft guidance issued in September 2018 clarified that this rule pertains to the oil and gas industry.

Other federal agencies have 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, 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 the effective date of others was delayed until 2019 pending reconsideration. In September 2018, BLM published a final rule that rescinded several requirements of the 2016 methane rules. 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. 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 Biden 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. In addition, 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” seeking to adopt new regulations and policies to address

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climate change and suspend, revise, or rescind, prior agency actions that are identified as conflicting with the 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 November 2019, the State Department formally informed the United Nations of the United States’ withdrawal from the Paris 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 will formally re-join the Paris Agreement on February 19, 2021. As part of rejoining the Paris Agreement, President Biden announced that the United States 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. If upheld, the rule is expected to expand federal jurisdiction under the Clean Water Act. On 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. District Court for the District of Arizona 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 “Revised Definition of ‘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 April 2020 final rule, 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 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.

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 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 ODNR 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 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 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. 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. A federal district court invalidated these BLM rules in June 2016, but they were reinstated on appeal by the U.S. Court of Appeals for the Tenth Circuit in September 2017. In 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 in the U.S. Court of Appeals for the Ninth Circuit. Reinstatement of the 2015 BLM rules, or 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 lease approximately 157,600 square feet of space at our executive offices in Dallas, Texas under a lease expiring in February 2030. We also lease office space of approximately 56,000 square feet in Midland, Texas, and 47,500 square feet in Houston, Texas under long-term leases, and various other locations to support our operations.

Human Capital

As of December 31, 2021, we (through our subsidiaries) employed 1,073 full-time employees. Of these employees, 249 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

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

•GIP owns approximately 46.4% of our outstanding common units as of February 9, 2022 and 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 9, 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 GIP, have conflicts of interest with us and limited duties to us and may favor their own interests to your detriment.

GIP owns and controls the Managing Member and appoints all of the directors of the Managing Member. Some of the directors of the Managing Member, including directors with a majority of the voting power of the board of directors of the Managing Member, are also directors or officers of 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 GIP, in its capacity as the sole member of the Managing Member. Conflicts of interest may arise between GIP 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 GIP to pursue a business strategy that favors us or to enter into any commercial or business arrangement with us. GIP’s directors and officers have a fiduciary duty to make decisions in the best interests of the owners of GIP, which may be contrary to our interests;

•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;

•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 affiliates of GIP, on the other, may not be the result of arm’s-length negotiations;

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

•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.

GIP 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 midstream companies, which may compete directly or indirectly with us. In addition, GIP and its affiliates may acquire, construct, or dispose of additional

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midstream or other assets and may be presented with new business opportunities, without any obligation to offer us the opportunity to purchase or construct such assets or to engage in such business opportunities.

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

We 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, 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 Commission;

•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 composed entirely of independent directors. 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 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 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 have limited voting rights and are not 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 trade.

Unlike the holders of common stock in a corporation, ENLC unitholders 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. 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 9, 2022, the Managing Member and its affiliates owned approximately 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.

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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 GIP 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 the approval of the holders of common units, which would dilute 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, 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.

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 9, 2022, GIP held 224,355,359 ENLC common units. Additionally, we have agreed to provide GIP 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 9, 2022, GIP owned an aggregate of approximately 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 following the date of the distribution.

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

As of February 9, 2022, approximately 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 a significant customer;

•events affecting GIP;

•announcements by us or our competitors of significant contracts or acquisitions;

•changes in accounting standards, policies, guidance, interpretations, or principles;

•general economic 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.

Financial and Indebtedness Risks

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

Currently, our only cash-generating asset is our partnership interest in ENLK. Our cash flow is therefore completely dependent upon the ability of ENLK to generate cash or our ability to borrow under the Consolidated Credit Facility and the AR Facility.

The amount of cash that ENLK can provide to 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 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 be available to 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 and distribution requirements with respect to Series B Preferred Units and Series C Preferred Units;

•fluctuations in its working capital needs;

•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 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 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.

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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, 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 applicable 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 ENLC. 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.”

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Increases in interest rates 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 affect 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 state 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 deferred tax assets and liabilities are also dependent upon the tax rates expected to be in effect at the time they are realized. A change in enacted corporate tax rates in our major jurisdictions, especially the U.S. federal corporate tax rate, would change the value of our deferred taxes, which could be material.

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.

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 NOLs for tax purposes during 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 July 27, 2017, the 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 reluctance to travel, as well as whether governmental and other measures implemented to try to slow the spread of the virus and its 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 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 financial 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 the 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 numerous 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 the 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 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. 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.

Any decrease in the volumes that we gather, process, fractionate, or transport would adversely affect our financial condition, results of operations, or cash flows.

Our financial performance depends to a large extent 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 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 affected by, among other things, the availability and cost of capital, levels of 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 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 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, 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 margins or even result in losses.

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.

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. As recently as 2020, during the COVID-19 pandemic, commodity prices fell,

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which led to lower drilling activity, and resulted in lower 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, exploration and production industry may negatively impact current and future drilling activity. In addition, real or perceived differences in economic returns from 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.

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, 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.

Commodity	Closing Price		Date
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

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(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 and 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 reductions 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 condition, 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 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, 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. These volumes are influenced by the production from the regions that supply our systems. Adverse weather conditions and persistent electrical blackouts 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. 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 subsidence and coastal erosion. Such processes could cause serious damage to our pipelines, which could affect our ability to provide transportation services.

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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, we may incur significant costs to repair and preserve our pipeline infrastructure. Such costs could adversely affect our financial condition, results of operations, or cash flows.

We are dependent on certain large customers for a substantial portion of the natural gas that we gather, process, and transport. The loss of any of these customers would adversely affect our financial condition, results of operations, or cash flows.

We are dependent on certain large customers for a substantial portion of our natural gas supply. For the year ended December 31, 2021, Dow Hydrocarbons and Resources LLC, Marathon Petroleum Corporation, and Devon represented 14.5%, 13.4%, and 6.7%, respectively, of our 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 businesses, may present different challenges and risks. We may be unable to execute 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 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.

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 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 and may result in curtailment 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.

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. 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 joint 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.

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 adjusted gross 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, 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 may 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 sale 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 financial computer systems and those 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 loss, 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 make 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 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.

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 price 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 regulate 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 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.

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.

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 approximately $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, 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. All of these FERC policies and potential changes could have a material impact on our 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 includes requirements to reconfirm 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. 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 $3.2 million, $2.6 million, and $3.1 million for the years ended December 31, 2021, 2020, and 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 VOCs 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 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

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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.

The BLM also adopted new rules, 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.

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 is subject to complex and evolving U.S. laws and regulations regarding privacy and data protection (“data protection laws”). Many of these 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 subject 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 us 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 compliance, and adversely affect our business. As noted above, we are also subject to the possibility of cyberattacks, which themselves may result in a violation of these laws. Additionally, if we acquire a company that has violated or is not in compliance with applicable data protection laws, we may incur significant liabilities and penalties as a result.

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 Managing 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.

See “Item 8. Financial Statements and Supplementary Data—Note 14” for more information on litigation proceedings and 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.

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 January 31, 2022, there were approximately 30,873 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.”

Unless restricted by the terms of the Consolidated Credit Facility, we intend to pay distributions to our unitholders on a quarterly basis from our available cash 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

•maintaining cash reserves the board of directors of the Managing Member believes are prudent to maintain.

Purchases of Equity Securities

During the three months ended December 31, 2021, we re-acquired ENLC common units from certain employees in order to satisfy the employees’ tax liability in connection with the vesting of restricted incentive units, and we repurchased common units in open market transactions 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, 2021	1,919	$	6.82	—	$	84.3
November 1, 2021 to November 30, 2021	1,679,243	$	7.24	1,679,243	$	72.2
December 1, 2021 to December 31, 2021	2,028,069	$	6.69	2,017,462	$	58.7
Total	3,709,231	$	6.94	3,696,705

____________________________

(1)The total number of units purchased shown in the table includes 12,526 units received by us from employees for the payment 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 reset 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 open market or private transactions and may be made pursuant to a trading plan meeting the requirements of Rule 10b5-1 under the Securities Exchange Act of 1934, as amended. The repurchases will depend on market conditions and may be discontinued at any time. On February 15, 2022, we and GIP entered into an agreement pursuant to which we 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.

Item 6. [Reserved]

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

Overview

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

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

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

•gathering, transporting, stabilizing, storing, trans-loading, and selling crude oil and condensate, in addition to brine disposal services.

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

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 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:

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

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

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

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

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

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We manage our consolidated operations by focusing on adjusted gross margin because our business is generally to gather, process, transport, or market natural gas, NGLs, crude oil, and condensate using our assets for a fee. We earn our fees through various fee-based contractual arrangements, which include stated fee-only contract arrangements or arrangements with fee-based components where we purchase and resell commodities in connection with providing the related service and earn a net margin as our fee. We earn our net margin under our purchase and resell contract arrangements primarily as a result of stated service-related fees that are deducted from the price of the commodity purchase. While our transactions vary in form, the essential element of most of our transactions is the use of our assets to transport a product or provide a processed product to an end-user or marketer at the tailgate of the plant, pipeline, or barge, truck, or rail terminal. Adjusted gross margin is a non-GAAP financial measure and is explained in greater detail under “Non-GAAP Financial Measures” below. Approximately 89% of our adjusted gross margin was derived from fee-based contractual arrangements with minimal direct commodity price exposure for the year ended December 31, 2021.

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

•gathering and transporting natural gas, NGLs, and crude oil on the pipeline systems we own;

•processing natural gas at our processing plants;

•fractionating and marketing recovered NGLs;

•providing compression services;

•providing crude oil and condensate transportation and terminal services;

•providing condensate stabilization services;

•providing brine disposal services; and

•providing natural gas, crude oil, and NGL storage.

The following customers individually represented greater than 10% of our consolidated revenues 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,
	2021		2020		2019
Devon	6.7	%	14.4	%	10.5	%
Dow Hydrocarbons and Resources LLC	14.5	%	13.2	%	10.0	%
Marathon Petroleum Corporation	13.4	%	12.2	%	13.8	%

We gather, transport, or store gas owned by others under fee-only contract arrangements based either on the volume of gas gathered, transported, or stored or, for firm transportation arrangements, a stated monthly fee for a specified monthly quantity with an additional fee based on actual volumes. We also buy natural gas from producers or shippers at a market index less a fee-based deduction subtracted from the purchase price of the natural gas. We then gather or transport the natural gas and sell the natural gas at a market index, thereby earning a margin through the fee-based deduction. We attempt to execute substantially all purchases and sales concurrently, or we enter into a future delivery obligation, thereby establishing the basis for the fee we will receive for each natural gas transaction. We are also party to certain long-term gas sales commitments that we satisfy through supplies purchased under long-term gas purchase agreements. When we enter into those arrangements, our sales obligations generally match our purchase obligations. However, over time, the supplies that we have under contract may decline due to reduced drilling or other causes, and we may be required to satisfy the sales obligations by buying additional gas at prices that may exceed the prices received under the sales commitments. In our purchase/sale transactions, the resale price is generally based on the same index at which the gas was purchased.

We typically buy mixed NGLs from our suppliers to our gas processing plants at a fixed discount to market indices for the component NGLs with a deduction for our fractionation fee. We subsequently sell the fractionated NGL products based on the same index-based prices. To a lesser extent, we transport and fractionate or store NGLs owned by others for a fee based on the volume of NGLs transported and fractionated or stored. The operating results of our NGL fractionation business are largely dependent upon the volume of mixed NGLs fractionated and the level of fractionation fees charged. With our fractionation business, we also have the opportunity for product upgrades for each of the discrete NGL products. We realize higher adjusted gross margins from product upgrades during periods with higher NGL prices.

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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 transportation deduction. We then transport and resell the crude oil and condensate through a process of basis and fixed price trades. We execute substantially all purchases and sales concurrently, thereby establishing the net margin we will receive for each crude oil and condensate transaction.

We realize adjusted gross margins from our gathering and processing services primarily through different contractual arrangements: processing margin (“margin”) contracts, POL contracts, POP contracts, fixed-fee based contracts, or a combination of these contractual arrangements. See “Item 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 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 margins are higher during periods of high NGL prices relative to natural gas prices. Adjusted gross margin results under POL contracts are impacted only by the value of the liquids produced with margins higher during periods of higher liquids prices. Adjusted gross margin results under POP contracts are impacted only by the value of the natural gas and liquids produced with margins higher during periods of higher natural gas and liquids prices. Under fixed-fee based contracts, our adjusted gross margins are driven by throughput volume.

Operating expenses are costs directly associated with the operations of a particular asset. Among the most significant of these costs are those associated with direct labor and supervision, property insurance, property taxes, repair and maintenance expenses, contract services, and utilities. These costs are normally fairly stable across broad volume ranges and therefore do not normally increase or decrease significantly in the short term with increases or decreases in the volume of gas, liquids, crude oil, and condensate moved through or by our assets.

CCS Business

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

Recent Developments Affecting Industry Conditions and Our Business

Current Market Environment

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

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

There has been, and we believe there will continue to be, volatility in commodity prices and in the relationships among NGL, crude oil, and natural gas prices. 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 regional industrial activity and export markets. Our activities and, in turn, our financial performance in the Louisiana segment are highly dependent on the availability of natural gas and NGLs produced by our upstream gathering and processing business and by other market participants. To date, the supply of natural gas and NGLs has remained at levels sufficient for us to supply our customers, and maintaining such supply is a key business focus.

For additional discussion regarding these factors, see “Item 1A—Risk Factors—Business and Industry Risks.”

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 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 conditions fully 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 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 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 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.

Amarillo Rattler Acquisition. On April 30, 2021, we completed the acquisition of Amarillo Rattler, LLC, the owner of a gathering and processing system located in the Midland Basin. 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.

Organic Growth

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

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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 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%.

Senior Unsecured Notes. On December 14, 2020, ENLC issued $500.0 million in aggregate principal amount of ENLC’s 5.625% senior unsecured notes due January 15, 2028 (the “2028 Notes”) at a price to the public of 100% of their face value. Interest payments on the 2028 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 $494.7 million were used to repay a portion of the borrowings under the Term Loan, which matured in December 2021.

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 debt	0.6
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 senior unsecured notes.

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.

For the year ended December 31, 2021, ENLC repurchased 6,091,001 outstanding ENLC common units for an aggregate cost, including commissions, of $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.

Redemption of Series B Preferred Units

In December 2021, we redeemed 3,300,330 Series B Preferred Units for total consideration of $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, upon such redemption, a corresponding number of ENLC Class C Common Units were automatically cancelled. The redemption price for both the December 2021 and January 2022 redemptions was 101% of the preferred units’ par value. In connection with these Series B Preferred Unit redemptions, we have agreed with the holders of the Series B Preferred Units that we will pay cash in lieu of making a quarterly PIK distribution through the distribution declared for the fourth quarter of 2022. See “Item 8. Financial Statements and Supplementary Data—Note 8” for more information regarding distributions with respect to the Series B Preferred Units.

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Non-GAAP Financial Measures

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

Adjusted Gross Margin

We define adjusted gross margin as revenues less cost of sales, exclusive of operating expenses and depreciation and amortization. We present adjusted gross margin by segment in “Results of Operations.” We disclose adjusted gross margin in addition to gross margin as defined by GAAP because it is the primary performance measure used by our management to evaluate consolidated operations. We believe adjusted gross margin is an important measure because, in general, our business is to gather, process, transport, or market natural gas, NGLs, condensate, and crude oil for a fee or to purchase and resell natural gas, NGLs, condensate, and crude oil for a margin. Operating expense is a separate measure used by our management to evaluate the operating performance of field operations. Direct labor and supervision, property insurance, property taxes, repair and maintenance, utilities, and contract services comprise the most significant portion of our operating expenses. We exclude all operating expenses and depreciation and amortization from adjusted gross margin because these expenses are largely independent of the volumes we transport or process and fluctuate depending on the activities performed during a specific period. The GAAP measure most directly comparable to adjusted gross margin is gross margin. Adjusted gross margin should not be considered an alternative to, or more meaningful than, gross margin as determined in accordance with GAAP. Adjusted gross margin has important limitations because it excludes all operating expenses and depreciation and amortization that affect gross margin. Our adjusted gross margin may not be comparable to similarly titled measures of other companies because other entities may not calculate these amounts in the same manner.

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

	Year Ended December 31,
	2021		2020
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 margin	525.6		492.9
Operating expenses	362.9		373.8
Depreciation and amortization	607.5		638.6
Adjusted gross margin	$	1,496.0	$	1,505.3

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Adjusted EBITDA

We define adjusted EBITDA as net income (loss) plus (less) interest expense, net of interest income; depreciation and amortization; impairments; (income) loss from unconsolidated affiliate investments; distributions from unconsolidated affiliate investments; (gain) loss on disposition of assets; (gain) loss on extinguishment of debt; unit-based compensation; income tax expense (benefit); unrealized (gain) loss on commodity swaps; costs associated with the relocation of processing facilities; accretion expense associated with asset retirement obligations; transaction costs; (non-cash rent); and (non-controlling interest share of adjusted EBITDA from joint ventures). Adjusted EBITDA is one of the primary metrics used in our short-term incentive program for compensating employees. In addition, adjusted EBITDA is used as a supplemental liquidity and performance measure by our management and by external users of our financial statements, such as investors, commercial banks, research analysts, and others, to assess:

•the financial performance of our assets without regard to financing methods, capital structure, or historical cost basis;

•the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness, and make cash distributions to our unitholders;

•our operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing methods or capital structure; and

•the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

The GAAP measures most directly comparable to adjusted EBITDA are net income (loss) and net cash provided by operating activities. Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income (loss), operating income (loss), net cash provided by operating activities, or any other measure of financial performance presented in accordance with GAAP. Adjusted EBITDA may not be comparable to similarly titled measures of other companies because other companies may not calculate adjusted EBITDA in the same manner.

Adjusted EBITDA does not include interest expense, net of interest income; income tax expense (benefit); and depreciation and amortization. Because we have borrowed money to finance our operations, interest expense is a necessary element of our costs and our ability to generate cash available for distribution. Because we have capital assets, depreciation and amortization are also necessary elements of our costs. Therefore, any measures that exclude these elements have material limitations. To compensate for these limitations, we believe that it is important to consider net income (loss) and net cash provided by operating activities as determined under GAAP, as well as adjusted EBITDA, to evaluate our overall performance.

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

	Year Ended December 31,
	2021		2020
Net income (loss)	$	142.9	$	(315.6)
Interest expense, net of interest income	238.7		223.3
Depreciation and amortization	607.5		638.6
Impairments	0.8		362.8
(Income) loss from unconsolidated affiliate investments	11.5		(0.6)
Distributions from unconsolidated affiliate investments	3.9		2.1
(Gain) loss on disposition of assets	(1.5)		8.8
Gain on extinguishment of debt	—		(32.0)
Unit-based compensation	25.3		28.4
Income tax expense	25.4		143.2
Unrealized loss on commodity swaps	12.4		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 interest	1,094.6		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

____________________________

(1)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 to complete the relocation of equipment and facilities from the Thunderbird processing plant in 2022.

(2)Includes accretion expense associated with asset retirement obligations; transaction costs; and non-cash rent, which relates to lease incentives pro-rated over the lease term.

(3)Non-controlling interest share of adjusted EBITDA from joint ventures includes NGP’s 49.9% share of adjusted EBITDA from the Delaware Basin JV, 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, net of interest income); (distributions declared on common units); (accrued cash distributions on Series B Preferred Units and Series C Preferred Units paid or expected to be paid); (costs associated with the relocation of processing facilities); non-cash interest (income)/expense; (payments to terminate interest rate swaps); (current income taxes); and proceeds from the sale of equipment and land.

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

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

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

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

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

	Year Ended December 31,
	2021		2020
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 transactions	2.1		(4.3)
Distributions from unconsolidated affiliate investment in excess of earnings	3.9		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 other	273.5		6.4
Accounts payable, accrued product purchases, and other accrued liabilities	(328.3)		104.8
Adjusted EBITDA before non-controlling interest	1,094.6		1,069.2
Non-controlling interest share of adjusted EBITDA from joint ventures (6)	(44.9)		(30.7)
Adjusted EBITDA, net to ENLC	1,049.7		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 expense	9.5		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

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(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 to 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):

	Permian		Louisiana		Oklahoma		North Texas		Corporate		Totals
Year Ended December 31, 2021
Gross margin	$	89.8	$	183.9	$	123.3	$	136.6	$	(8.0)	$	525.6
Depreciation and amortization	139.9		141.0		204.3		114.3		8.0		607.5
Segment profit	229.7		324.9		327.6		250.9		—		1,133.1
Operating expenses	81.5		123.7		80.0		77.7		—		362.9
Adjusted gross margin	$	311.2	$	448.6	$	407.6	$	328.6	$	—	$	1,496.0

	Permian		Louisiana		Oklahoma		North Texas		Corporate		Totals
Year Ended December 31, 2020
Gross margin	$	44.9	$	139.8	$	188.5	$	127.0	$	(7.3)	$	492.9
Depreciation and amortization	125.2		145.8		216.9		143.4		7.3		638.6
Segment profit	170.1		285.6		405.4		270.4		—		1,131.5
Operating expenses	94.2		120.0		82.2		77.4		—		373.8
Adjusted gross margin	$	264.3	$	405.6	$	487.6	$	347.8	$	—	$	1,505.3

	Permian		Louisiana		Oklahoma		North Texas		Corporate		Totals
Year Ended December 31, 2019
Gross margin	$	36.6	$	143.1	$	255.2	$	149.8	$	(8.4)	$	576.3
Depreciation and amortization	119.8		154.1		194.9		139.8		8.4		617.0
Segment profit	156.4		297.2		450.1		289.6		—		1,193.3
Operating expenses	112.9		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,
	2021	2020	2019
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 the 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,
	2021		2020
Goodwill impairment	$	—	$	184.6
Property and equipment impairment	0.6		168.0
Lease right-of-use asset impairment	0.2		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,
	2021		2020
ENLK and ENLC Senior Notes	$	201.1	$	175.0
Term Loan	4.2		17.5
Consolidated Credit Facility	5.8		13.9
AR Facility	4.1		0.9
Capitalized interest	(0.3)		(3.4)
Amortization of debt issuance costs and net discount of senior unsecured notes	5.2		4.6
Interest rate swaps - realized	18.3		14.5
Other	0.3		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,
	2021		2020
Operating cash flows before working capital	$	802.5	$	842.3
Changes in working capital	54.8		(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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These changes to operating cash flows were offset by the following:

•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,
	2021		2020
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,
	2021		2020
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 2022 include the relocation of the Phantom processing plant, continued development of our existing systems through well connects, and other low-cost development projects. We expect to fund our remaining 2022 capital expenditures from operating cash flows and capital contributions by joint venture partners that relate to the non-controlling interest share of our consolidated entities.

It is possible that not all of our planned projects will be commenced or completed. Our ability to pay distributions to our unitholders, to fund planned capital expenditures, and to make acquisitions will depend upon our future operating performance, which will be affected by prevailing economic conditions in the industry, financial, business, and other factors, some of which are beyond our control.

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, 2021 and 2020.

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Total Contractual Cash Obligations. A summary of our total contractual cash obligations as of December 31, 2021 is as follows (in millions):

	Payments Due by Period
	Total		2022		2023		2024		2025		2026		Thereafter
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 obligations	2,334.9		201.2		201.2		189.7		163.3		148.3		1,431.2
Operating lease obligations	115.6		21.1		15.3		10.1		9.8		8.9		50.4
Purchase obligations	4.9		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

____________________________

(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 that is not already disclosed in the table above.

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

Our contractual cash obligations for 2022 are expected to be funded from cash flows generated from our operations and the available capacity under the Consolidated 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 lender commitments to $350.0 million and extend the scheduled termination date to September 24, 2024. As of December 31, 2021, the AR Facility had a borrowing base of $350.0 million and there was $350.0 million in outstanding borrowings under the AR Facility.

In addition, as 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, 2021.

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Guarantees. The amounts outstanding on our senior unsecured notes and the Consolidated Credit Facility are guaranteed in full 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 absolute, and cover all payment obligations arising under the senior unsecured notes and the Consolidated Credit Facility. Liabilities under the guarantees rank equally in right of payment with all existing and future senior unsecured indebtedness of ENLK.

ENLC’s assets consist of all of the outstanding common units of ENLK and all of the membership interests of the General Partner. Other than these equity interests, all of our assets and operations are held by our non-guarantor operating subsidiaries. ENLK, directly and indirectly, owns all of these non-guarantor operating subsidiaries, which in some cases are joint ventures that are partially owned by a third party. As a result, the assets, liabilities, and results of operations of ENLK are not materially different than the corresponding amounts presented in our consolidated financial statements.

As of 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 and Supplementary Data—Note 6” for more information on our outstanding 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 years. 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 increased inflation may increase the cost to acquire or replace property and equipment and 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 14.”

Recent Accounting Pronouncements

See “Item 8. Financial Statements and Supplementary Data—Note 2” in our Annual Report on Form 10-K for the 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 within the meaning of the federal securities laws. Although these statements reflect the current views, assumptions and expectations of our management, the matters addressed herein involve certain assumptions, risks and uncertainties that could cause actual activities, performance, outcomes and results to differ materially from those indicated herein. Therefore, you should not rely on any of these forward-looking statements. All statements, other than statements of historical fact, included in this Annual Report constitute forward-looking statements, including, but not limited to, statements identified by the words “forecast,” “may,” “believe,” “will,” “should,” “plan,”

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“predict,” “anticipate,” “intend,” “estimate,” “expect,” “continue,” and similar expressions. Such forward-looking statements include, 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 future 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 laws and governmental regulations, including environmental and climate change requirements and other uncertainties. In addition to the specific uncertainties, factors, and risks discussed above and elsewhere in this 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 CFTC to regulate certain markets for derivative products, including OTC derivatives. The CFTC has issued several relevant regulations, and other rulemakings are pending at the CFTC, the product of which would be rules that implement the mandates in the legislation to cause significant portions of derivatives markets to clear through clearinghouses. While some of these rules have been finalized, some have not, and, as a result, the final form and timing of the implementation of the regulatory regime affecting commodity derivatives remains uncertain.

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

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

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.

Commodity	Closing Price		Date
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.

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 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. While approximately 89% of our adjusted gross margin for the year ended December 31, 2021 was generated from arrangements with fee-based structures with minimal direct commodity price exposure, the remainder is subject to more direct commodity price exposure. Our exposure to these commodity price fluctuations is primarily in the gas processing component of our business. We currently earn adjusted gross margin under four main types of contractual arrangements (or a combination of these types of contractual arrangements) as summarized below.

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

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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 processing if the natural gas must be processed to meet pipeline quality specifications. For the year ended December 31, 2021, less than 1% of our adjusted gross margin was generated from processing margin contracts.

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

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

For the year ended December 31, 2021, approximately 6% of our adjusted gross margin was generated from POL or POP contracts.

Our primary commodity risk management objective is to reduce volatility in our cash flows. We maintain a risk management committee, including members of senior management, which oversees all hedging activity. We enter into hedges for natural gas, crude and condensate, and NGLs using OTC derivative financial instruments with only certain well-capitalized counterparties, which have been approved in accordance with our commodity risk management policy.

We have hedged our exposure to fluctuations in prices for natural gas, NGLs, and crude oil volumes produced for our account. We have tailored our hedges to generally match the product composition and the delivery points to those of our physical equity volumes. The hedges cover specific products based upon our expected equity composition.

The following table sets forth certain information related to derivative instruments outstanding at December 31, 2021. 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 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.

Period	Underlying	Notional Volume	We Pay	We Receive (1)	Net Fair Value Asset/(Liability) (In millions)
January 2022 - September 2022	Propane	1,235 (MBbls)	Index	$1.063/Gal	$	(8.1)
January 2022 - September 2022	Normal butane	265 (MBbls)	Index	$1.248/Gal	(2.5)
January 2022 - October 2022	Natural gas	56,625 (MMbtu/d)	Index	$3.8406/MMbtu	(5.1)
January 2022 - January 2023	Crude and condensate	7,715 (MBbls)	Index	$75.82/Bbl	1.2
					$	(14.5)

____________________________

(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, 2021, outstanding natural gas swap agreements, NGL swap agreements, swing swap agreements, storage swap agreements, and other derivative instruments had a net fair value liability of $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 a change of approximately $4.5 million in the net fair value of these contracts as of December 31, 2021.

Interest Rate Risk

We are exposed to interest rate risk on the Consolidated Credit Facility and the AR Facility. At December 31, 2021, we had $15.0 million and $350.0 million in outstanding borrowings under the Consolidated Credit Facility and the AR Facility, respectively. A 1.0% increase or decrease in interest rates would change our annualized interest expense by approximately $0.2 million and $3.5 million for the 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 2024, 2025, 2026, 2044, 2045, or 2047 or our senior unsecured notes due in 2028 and 2029 as these are fixed-rate obligations. As of December 31, 2021, the estimated fair value of the senior unsecured notes was approximately $4,155.0 million, based on the market prices of ENLK’s and our publicly traded debt at December 31, 2021. Market risk is estimated as the potential decrease in fair value of our long-term debt resulting from a hypothetical increase of 1.0% in interest rates. Such an increase in interest rates would result in an approximate $255.4 million decrease in fair value of the senior unsecured notes at December 31, 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:
Management’s Report on Internal Control Over Financial Reporting	93
Report of Independent Registered Public Accounting Firm (KPMG LLP, Dallas, TX, Auditor Firm ID: 185)	94
Consolidated Balance Sheets as of December 31, 2021 and 2020	96
Consolidated Statements of Operations for the years ended December 31, 2021, 2020, and 2019	97
Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2021, 2020, and 2019	98
Consolidated Statements of Changes in Members’ Equity for the years ended December 31, 2021, 2020, and 2019	99
Consolidated Statements of Cash Flows for the years ended December 31, 2021, 2020, and 2019	101
Notes to Consolidated Financial Statements	102

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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 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 GAAP, and that receipts and expenditures of the Company are being made only in accordance with authorization of 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, 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, 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 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 Report on Form 10-K.

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Report of Independent Registered Public Accounting Firm

To 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 and subsidiaries (the Company) as of December 31, 2021 and 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, 2021, and the related notes (collectively, the consolidated financial statements). We also have audited the Company’s internal control over financial reporting as of December 31, 2021, based on criteria established in Internal 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 the Company as of December 31, 2021 and 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, 2021, in conformity with U.S. generally accepted accounting principles. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2021 based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

Basis for Opinions

The 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 Over Financial Reporting. Our responsibility is to express an opinion on the Company’s consolidated financial statements and an opinion on the 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) and are required to be independent with respect to the 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 the Company’s auditor since 2013.

Dallas, Texas

February 16, 2022

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Consolidated Balance Sheets

(In millions, except unit data)

	December 31, 2021		December 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, respectively	94.9		80.6
Accrued revenue and other	693.3		447.5
Fair value of derivative assets	22.4		25.0
Other current assets	83.6		58.7
Total current assets	920.4		651.4
Property and equipment, net of accumulated depreciation of $4,332.0 and $3,863.0, respectively	6,388.3		6,652.1
Intangible assets, net of accumulated amortization of $795.1 and $668.8, respectively	1,049.7		1,125.4
Investment in unconsolidated affiliates	28.0		41.6
Fair value of derivative assets	0.2		4.9
Other assets, net	96.6		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 liabilities	34.9		37.1
Current maturities of long-term debt	—		349.8
Other current liabilities	202.9		149.1
Total current liabilities	898.9		888.0
Long-term debt	4,363.7		4,244.0
Other long-term liabilities	93.9		94.8
Deferred tax liability, net	137.5		108.6
Fair value of derivative liabilities	2.2		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 interest	1,662.6		1,719.5
Total members’ equity	2,987.0		3,213.0
Commitments and contingencies (Note 14)
Total liabilities and members’ equity	$	8,483.2	$	8,550.9

____________________________

(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,
	2021		2020		2019
Revenues:
Product sales	$	5,994.0	$	2,977.5	$	5,030.1
Midstream services	851.0		938.3		1,008.4
Gain (loss) on derivative activity	(159.1)		(22.0)		14.4
Total revenues	6,685.9		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 expenses	362.9		373.8		467.1
Depreciation and amortization	607.5		638.6		617.0
Impairments	0.8		362.8		1,133.5
(Gain) loss on disposition of assets	(1.5)		8.8		(1.9)
General and administrative	107.8		103.3		152.6
Loss on secured term loan receivable	—		—		52.9
Total operating costs and expenses	6,267.4		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 taxes	168.3		(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 interest	120.5		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)

____________________________

(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.

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,
	2021		2020		2019
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 interest	120.5		105.9		119.7
Comprehensive income (loss) attributable to ENLC	$	36.3	$	(425.8)	$	(1,128.3)

____________________________

(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.

See accompanying notes to consolidated financial statements.

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Consolidated Statements of Changes in Members’ Equity

(In millions)

	Common Units			Accumulated Other Comprehensive Loss		Non-Controlling Interest		Total		Redeemable 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 842	0.3		—	—		—		0.3		—
Balance, January 1, 2019	1,731.2		181.3	(2.0)		3,245.3		4,974.5		9.3
Issuance of common units for ENLK public common units related to the Merger	1,958.1		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 compensation	37.5		—	—		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 interest	3.0		—	—		—		3.0		(4.0)
Net income (loss)	(1,119.3)		—	—		119.5		(999.8)		0.2
Balance, December 31, 2019	2,135.5		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 compensation	33.0		—	—		—		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 interest	0.4		—	—		—		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	$	—

____________________________

(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)

(In millions)

	Common Units			Accumulated Other Comprehensive Loss		Non-Controlling Interest		Total		Redeemable 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 compensation	23.6		—	—		—		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 income	22.4		—	—		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,
	2021		2020		2019
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 amortization	607.5		638.6		617.0
Impairments	0.8		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 compensation	25.3		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 notes	5.2		4.6		4.9
Amortization of designated cash flow hedge	12.5		0.5		0.1
Payments to terminate interest rate swaps	(1.8)		(10.9)		—
Deferred income tax expense	24.6		142.1		6.9
Distribution of earnings from unconsolidated affiliates	—		1.6		16.5
(Income) loss from unconsolidated affiliates	11.5		(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 liabilities	328.3		(104.8)		(245.5)
Net cash provided by operating activities	857.3		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 property	4.8		17.6		14.3
Distribution from unconsolidated affiliates in excess of earnings	3.9		0.5		3.7
Other investing activities	0.6		(1.3)		(4.6)
Net cash used in investing activities	(231.4)		(317.7)		(741.5)
Cash flows from financing activities:
Proceeds from borrowings	1,234.5		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 interests	3.2		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 activities	2.5		(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 period	39.6		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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Notes to Consolidated Financial Statements

(1) Organization and Nature of Business

(a) Organization of Business

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

Devon Transaction

In 2014, we completed a series of transactions with Devon pursuant to which Devon contributed certain subsidiaries and assets to us in exchange for a 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, ENLC, and the Managing Member to GIP. As a result of the transaction:

•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 23.1% of the outstanding limited partner interests in ENLK;

•GIP, through GIP III Stetson II, L.P., acquired all of the equity interests held by subsidiaries of Devon in ENLC, which, as of the closing date, amounted to approximately 63.8% of the outstanding limited liability company interests in ENLC; and

•Through this transaction, GIP acquired control of (i) the Managing Member, (ii) ENLC, and (iii) ENLK, as a result of ENLC’s ownership of the General Partner.

Simplification of the Corporate Structure

On January 25, 2019, we completed the Merger, an internal reorganization pursuant to which ENLC owns all of the outstanding common units of ENLK. As a result 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 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 8—Certain Provisions of the Partnership Agreement” for additional information regarding the modified terms of the Series B Preferred Units.

•ENLC issued to the holder of the 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 ENLC. In connection with the Merger, we entered into the Consolidated Credit Facility, with respect to which ENLK is a guarantor. See “Note 6—Long-Term Debt” for additional information regarding the Consolidated Credit Facility.

•We were required to allocate the goodwill in our Corporate reporting unit previously associated with the incentive distribution rights in 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.

•We reduced our deferred tax liability by $399.0 million related to ENLC’s step-up in 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, and selling NGLs; and

•gathering, transporting, stabilizing, storing, trans-loading, and selling crude oil and condensate, in addition to brine disposal services.

Our midstream energy asset network includes approximately 12,100 miles of pipelines, 22 natural gas processing plants with approximately 5.5 Bcf/d of processing capacity, seven fractionators with approximately 320,000 Bbls/d of fractionation capacity, barge and rail terminals, product storage facilities, purchasing and marketing capabilities, brine disposal wells, a crude oil trucking fleet, and equity investments in certain joint ventures. Our operations are based in the United States, and our sales are derived primarily from domestic customers.

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

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

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

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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.

(2) Significant Accounting Policies

(a)Basis of Presentation

The accompanying consolidated financial statements have been prepared in accordance with GAAP. All significant intercompany balances and transactions have been eliminated in consolidation. Certain reclassifications were made to the financial statements for the prior period to conform to current period presentation. The effect of these reclassifications had no impact on previously reported members’ equity or net income (loss).

(b)Management’s Use of Estimates

The preparation of financial statements in accordance with 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.

(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 most of our transactions is the use of our assets to transport a product or provide a processed product to an end-user or marketer at the tailgate of the plant, pipeline, or barge, truck, or rail terminal. Revenues from both “Product sales” and “Midstream services” represent revenues from contracts with customers and are reflected on the consolidated statements of operations as follows:

•Product sales—Product 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 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 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 commodity 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 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. We typically receive payment for invoiced 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 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).

Minimum Volume Commitments and Firm Transportation Contracts

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

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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 Fees	Commitments
2022	$	138.8
2023	126.5
2024	108.9
2025	63.8
2026	57.8
Thereafter	289.6
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 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.

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 payable	10.0
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 equipment	16.3
Intangible assets	50.6
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 $16.3 million and $6.1 million at December 31, 2021 and 2020, respectively, which approximate the fair value of these imbalances. We had imbalance receivables of $14.5 million and $7.5 million at December 31, 2021 and 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.

(g)Cash and Cash Equivalents

We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents.

(h)Income Taxes

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.”

(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.

(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. Routine repairs and maintenance are charged against income when incurred. Renewals and improvements 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,
	2021		2020
Transmission assets	$	1,442.2	$	1,410.5
Gathering systems	4,903.8		4,782.9
Gas processing plants	4,119.1		4,082.1
Other property and equipment	161.0		161.0
Construction in process	94.2		78.6
Property and equipment	10,720.3		10,515.1
Accumulated depreciation	(4,332.0)		(3,863.0)
Property and equipment, net of accumulated depreciation	$	6,388.3	$	6,652.1

Depreciation Expense. Depreciation is calculated using the straight-line method based on the estimated useful life of each asset, as follows:

	Useful Lives
Transmission assets	20 - 25 years
Gathering systems	20 - 25 years
Gas processing plants	20 - 25 years
Other property and equipment	3 - 25 years

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 consolidated statements of operations. For the years ended December 31, 2021, 2020, and 2019, dispositions primarily related to the sale of certain non-core assets. The (gain) loss on disposition of assets are as follows (in millions):

	Year Ended December 31,
	2021		2020		2019
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 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.

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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, 2021, we recognized a $0.6 million impairment on property and equipment.

For the year ended December 31, 2020, we recognized a $168.0 million impairment on property and equipment related to a portion of our Louisiana reporting segment because the carrying amounts were not recoverable based on our expected future cash flows, and $3.4 million of impairments related to certain cancelled projects.

For the year ended December 31, 2019, we recognized a $7.9 million impairment on property and equipment related to certain decommissioned and removed non-core assets.

(k)Comprehensive Income (Loss)

Comprehensive income (loss) is comprised of net income (loss) and the effective portion of gains or losses on derivative financial instruments that qualify as cash flow hedges pursuant to ASC 815. For additional information about the effect of financial instruments on comprehensive income (loss), see “Note 12—Derivatives.”

(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 10—Investment in Unconsolidated Affiliates.”

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Notes to Consolidated Financial Statements (continued)

(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 evaluated goodwill for impairment annually as of October 31 and whenever events or changes in circumstances indicated it was more likely than not that the fair value of a reporting unit is less than its carrying amount. For additional information regarding our previous assessments of goodwill for impairment, see “Note 3—Goodwill and Intangible Assets.”

(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 3—Goodwill and Intangible Assets.”

(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 more information, see “Note 5—Leases.”

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Notes to Consolidated Financial Statements (continued)

(r)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. 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 to hedge variability in interest rates and effectively lock in the benchmark interest rate at the inception of the swap.

In 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 repayments of the Term Loan, which was one of our floating-rate, LIBOR-based borrowings. The following table presents the interest rate swaps terminations and the associated cash payments during 2021 and 2020 (in millions):

	Interest Rate Swaps Terminations		Cash Payments Associated with Interest Rate Swaps Terminations
December 2021	$	150.0	$	—
September 2021	100.0		0.5
May 2021	100.0		1.3
December 2020	500.0		10.9
Total termination of interest rate swaps	$	850.0	$	12.7

For additional information, see “Note 12—Derivatives.”

(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 significant customers discussed below, since our customers represent a broad and diverse group of energy marketers and end users.

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,
	2021		2020		2019
Devon	6.7	%	14.4	%	10.5	%
Dow Hydrocarbons and Resources LLC	14.5	%	13.2	%	10.0	%
Marathon Petroleum Corporation	13.4	%	12.2	%	13.8	%

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Notes to Consolidated Financial Statements (continued)

We continually monitor and review the credit exposure of our counter-parties based on various credit quality indicators and metrics. We obtain letters of credit or other appropriate security 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 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 $0.5 million, respectively.

(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 not material for the years ended December 31, 2021, 2020, and 2019.

(u)Unit-Based Awards

We recognize compensation cost related to all unit-based awards in our consolidated financial statements in accordance with ASC 718. Unit-based compensation associated with ENLC’s unit-based compensation plan awarded to directors, officers, and employees of the General Partner is recorded by ENLK since ENLC has no substantial or managed operating activities other than its interests in ENLK. For additional information, see “Note 11—Employee Incentive Plans.”

(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 14—Commitments and Contingencies.”

(w)Debt Issuance Costs

Costs incurred in connection with the issuance of long-term debt are deferred and amortized 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 $27.8 million and $32.6 million as of December 31, 2021 and 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 the debt.

(x)Redeemable Non-Controlling Interest

Non-controlling interests that contain an option for the non-controlling interest holder to require us to purchase 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 interests are not considered to be a component of members’ equity and are 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.

During the first quarter of 2020, the non-controlling interest holder in one of our non-wholly owned subsidiaries exercised its option to require us to purchase its remaining interest. We have recorded an estimated $4.0 million related to the redemption of the non-controlling interest included in “Other current liabilities” on the consolidated balance sheets as of December 31, 2021 and 2020, but we have not yet agreed to a redemption value with the non-controlling interest holder.

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Notes to Consolidated Financial Statements (continued)

(3) Goodwill and Intangible Assets

Goodwill Impairments

Goodwill Impairment Analysis for the Year Ended December 31, 2020

During the first quarter of 2020, we determined that a sustained decline in our unit price and weakness in the overall energy sector, driven by low commodity prices and lower consumer demand due to the 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 Permian reporting unit. Based on this analysis, a goodwill impairment loss for our Permian reporting unit in the amount of $184.6 million was recognized as 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 no goodwill remaining as of December 31, 2020.

Goodwill Impairment Analysis for the Year Ended December 31, 2019

During the first quarter of 2019, 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 the 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, 2019. The goodwill for our North Texas and Oklahoma reporting units primarily related to the goodwill reallocated from our Corporate reporting unit as a result of the Merger in January 2019.

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Notes to Consolidated Financial Statements (continued)

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.

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

	Gross Carrying Amount		Accumulated Amortization		Net 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 business	50.6		—		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

____________________________

(1)Intangible assets retired as a result of the disposition of certain non-core assets.

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

2022	$	127.6
2023	127.6
2024	127.6
2025	110.3
2026	106.4
Thereafter	450.2
Total	$	1,049.7

(4) Related Party Transactions

(a)Transactions with Cedar Cove JV

For the years ended December 31, 2021, 2020, and 2019, we recorded cost of sales of $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. Additionally, we had accounts payable balances related to transactions with the Cedar Cove JV of $1.6 million and $1.0 million at December 31, 2021 and 2020, respectively.

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Notes to Consolidated Financial Statements (continued)

(b)Transactions with GIP

For the years ended December 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.

(c)Transactions with ENLK

On January 25, 2019, we completed the Merger, an internal reorganization pursuant to which ENLC owns all of the 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 have the right to control the use of the compressors and 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, 2021			December 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 leases	10.3 years			11.1 years
Weighted-average discount rate—Operating leases	4.9		%	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,
	2021		2020		2019
Finance lease expense:
Amortization of right-of-use asset	$	—	$	—	$	5.2
Interest on lease liability	—		—		0.1
Operating lease expense:
Long-term operating lease expense	21.7		23.1		28.7
Short-term lease expense	17.5		22.1		32.0
Variable lease expense	15.6		11.8		7.7
Impairments	0.2		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 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.

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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 Midland offices. We are attempting to sublease the vacated space; however, as we believe 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 for the year ended December 31, 2020.

Lease Maturities

The following table summarizes the maturity of our lease liability as of December 31, 2021 (in millions):

	Total		2022		2023		2024		2025		2026		Thereafter
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, 2021 and 2020, long-term debt consisted of the following (in millions):

	December 31, 2021						December 31, 2020
	Outstanding Principal		Premium (Discount)		Long-Term Debt		Outstanding Principal		Premium (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 2024	521.8		0.7		522.5		521.8		1.1		522.9
ENLK’s 4.15% Senior unsecured notes due 2025	720.8		(0.4)		720.4		720.8		(0.6)		720.2
ENLK’s 4.85% Senior unsecured notes due 2026	491.0		(0.3)		490.7		491.0		(0.4)		490.6
ENLC’s 5.625% Senior unsecured notes due 2028	500.0		—		500.0		500.0		—		500.0
ENLC’s 5.375% Senior unsecured notes due 2029	498.7		—		498.7		498.7		—		498.7
ENLK’s 5.60% Senior unsecured notes due 2044	350.0		(0.2)		349.8		350.0		(0.2)		349.8
ENLK’s 5.05% Senior unsecured notes due 2045	450.0		(5.5)		444.5		450.0		(5.7)		444.3
ENLK’s 5.45% Senior unsecured notes due 2047	500.0		(0.1)		499.9		500.0		(0.1)		499.9
Debt classified as long-term	$	4,397.3	$	(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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Notes to Consolidated Financial Statements (continued)

Maturities

Maturities for the long-term debt as of December 31, 2021 are as follows (in millions):

2022	$	—
2023	—
2024	886.8
2025	720.8
2026	491.0
Thereafter	2,298.7
Subtotal	4,397.3
Less: net discount	(5.8)
Less: debt issuance cost	(27.8)
Long-term debt, net of unamortized issuance cost	$	4,363.7

Term Loan

On December 11, 2018, ENLK entered into the Term Loan 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. 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.

Consolidated Credit Facility

The Consolidated Credit Facility permits ENLC to borrow up to $1.75 billion on a revolving credit basis and includes a $500.0 million letter of credit subfacility. The Consolidated Credit Facility 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 Consolidated Credit Facility are accelerated due to a default, ENLK will be liable for the entire outstanding balance and 105% of the outstanding letters of credit under the Consolidated Credit Facility. 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, 2021.

The Consolidated Credit Facility will mature on January 25, 2024, unless ENLC requests, and the requisite lenders agree, to extend it pursuant to its terms. The Consolidated 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. The financial covenants include (i) maintaining a ratio of consolidated EBITDA (as defined in the Consolidated Credit Facility, which term includes projected EBITDA from certain capital expansion projects) to consolidated interest charges of no less than 2.5 to 1.0 at all times prior to the occurrence of an investment grade event (as defined in the Consolidated Credit Facility) 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 Consolidated Credit Facility bear interest at ENLC’s option at the Eurodollar Rate (LIBOR) plus an applicable margin (ranging from 1.125% to 2.00%) or the Base Rate (the highest of the Federal Funds Rate plus 0.50%, the 30-day Eurodollar Rate plus 1.0% or the administrative agent’s prime rate) plus an applicable margin (ranging from 0.125%

to 1.00%). The applicable margins vary depending on ENLC’s debt rating. Upon breach by ENLC of certain covenants governing the Consolidated Credit Facility, amounts outstanding under the Consolidated Credit Facility, if any, may become due and payable immediately.

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Notes to Consolidated Financial Statements (continued)

At December 31, 2021, we were in compliance with and expect to be in compliance with the financial covenants of the Consolidated Credit Facility for at least the next twelve months.

AR Facility

On October 21, 2020, EnLink Midstream Funding, LLC, a bankruptcy-remote special purpose entity that is an indirect subsidiary of ENLC (the “SPV”) entered into the AR Facility 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 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 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, 2021, the AR Facility had a borrowing base of $350.0 million. Borrowings under the AR Facility bear interest (based on LIBOR or LMIR (as defined in the AR 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 the obligations under the AR Facility must be repaid in full by no later than (i) the date that is ninety (90) days following such date or (ii) such earlier date on which the loans under the AR Facility become due and 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, 2021, we were in compliance with and expect to be in compliance with the financial covenants of the AR Facility for at least the next twelve months.

Issuances and Redemptions of Senior Unsecured Notes

On December 14, 2020, ENLC issued $500.0 million in aggregate principal amount of ENLC’s 5.625% senior unsecured notes due January 15, 2028 (the “2028 Notes”) at a price to the public of 100% of their face value. Interest payments on the 2028 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 $494.7 million were used to repay a portion of the borrowings under the Term Loan, which matured in December 2021.

All interest payments for senior unsecured notes are due semi-annually, in arrears.

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Notes to Consolidated Financial Statements (continued)

Senior Unsecured Notes Redemption Provisions

Each issuance of the senior unsecured notes may be fully or partially redeemed prior to an early redemption date (see “Early Redemption 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 Point 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 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:

Issuance	Maturity Date of Notes	Early Redemption Date	Basis Point Premium
2024 Notes	April 1, 2024	Prior to January 1, 2024	25 Basis Points
2025 Notes	June 1, 2025	Prior to March 1, 2025	30 Basis Points
2026 Notes	July 15, 2026	Prior to April 15, 2026	50 Basis Points
2028 Notes	January 15, 2028	Prior to July 15, 2027	50 Basis Points
2029 Notes	June 1, 2029	Prior to March 1, 2029	50 Basis Points
2044 Notes	April 1, 2044	Prior to October 1, 2043	30 Basis Points
2045 Notes	April 1, 2045	Prior to October 1, 2044	30 Basis Points
2047 Notes	June 1, 2047	Prior to December 1, 2046	40 Basis Points

Senior Unsecured Notes 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, 2021, ENLC and ENLK were in compliance and expect 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 debt	0.6
Gain on extinguishment of debt	$	32.0

(7) Income Taxes

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

	Year Ended December 31,
	2021		2020		2019
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)

The following schedule reconciles total income tax expense and the amount calculated by applying the statutory U.S. federal tax rate to income before income taxes (in millions):

	Year Ended December 31,
	2021		2020		2019
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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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, 2021 and 2020 are as follows (in millions):

	December 31, 2021		December 31, 2020
Deferred income tax assets:
Federal net operating loss carryforward	$	573.6	$	488.3
State net operating loss carryforward	59.6		61.0
Total deferred tax assets, gross	633.2		549.3
Valuation allowance	(151.6)		(153.3)
Total deferred tax assets, net of valuation allowance	481.6		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)

____________________________

(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, 2021, we had federal net operating loss (“NOL”) carryforwards of $2.7 billion that represent a net deferred tax asset of $573.6 million. As of December 31, 2021, we had state NOL carryforwards of $1.3 billion that represent a net deferred tax asset of $59.6 million. These carryforwards will begin expiring in 2028 through 2040. 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 it is more likely than not that the Company will realize the benefits of the deferred tax assets, net of valuation allowance.

For the years ended December 31, 2021 and 2020, there was no recorded unrecognized tax benefit. Per our accounting policy election, penalties and interest related to unrecognized tax benefits are recorded to income tax expense. As of December 31, 2021, tax years 2017 through 2021 remain subject to examination by various taxing authorities.

(8) Certain Provisions of the Partnership Agreement

(a) 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 in a private placement for a cash purchase price of $15.00 per Series B Preferred Unit (the “Issue Price”). 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 ENLC 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 $50.0 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.

Conversion and Distributions

Series B Preferred Units are exchangeable for ENLC common units 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 (the “Series B Exchange Ratio”). The exchange is subject to ENLK’s option to pay cash instead of issuing additional ENLC common units, and can occur in whole or in part at the option of the holder of the Series B Preferred Units at any time, or in whole at our option, provided the daily volume-weighted average closing price of the ENLC common units for the 30 trading days ending two trading days prior to the exchange is greater than 150% of the Issue Price divided by the conversion ratio of 1.15.

The holder of the Series B Preferred Units is entitled to quarterly cash distributions and distributions in-kind of additional Series B Preferred Units. The quarterly in-kind distribution (the “Series B PIK Distribution”) equals the greater of (A) 0.0025 Series B Preferred Units per Series B Preferred Unit and (B) the number of Series B Preferred Units equal to the quotient of (x) the excess (if any) of (1) the distribution that would have been payable by ENLC had the Series B Preferred Units been 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 plus 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 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, 2021, 2020, and 2019 is provided below:

Declaration period	Distribution paid as additional Series B Preferred Units	Cash distribution (in millions)		Date paid/payable
2021
First Quarter of 2021	150,871	$	17.0	May 14, 2021
Second Quarter of 2021	151,248	$	17.0	August 13, 2021
Third Quarter of 2021	151,626	$	17.1	November 12, 2021
Fourth Quarter of 2021	—	$	19.2	February 11, 2022 (1)
2020
First Quarter of 2020	149,371	$	16.8	May 13, 2020
Second Quarter of 2020	149,745	$	16.8	August 13, 2020
Third Quarter of 2020	150,119	$	16.9	November 13, 2020
Fourth Quarter of 2020	150,494	$	16.9	February 12, 2021
2019
First Quarter of 2019	147,887	$	16.7	May 14, 2019
Second Quarter of 2019	148,257	$	17.1	August 13, 2019
Third Quarter of 2019	148,627	$	17.1	November 13, 2019
Fourth Quarter of 2019	148,999	$	16.8	February 13, 2020

____________________________

(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.

(b) Series C Preferred Units

In September 2017, ENLK issued 400,000 Series C Preferred Units representing ENLK limited partner interests at a price to the public of $1,000 per unit. 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’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 the 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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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, 2021, ENLC repurchased 6,091,001 outstanding ENLC common units for an aggregate cost, including commissions, of $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 the Merger

In connection with the consummation of the Merger, we issued 304,822,035 ENLC common units in exchange for all of the outstanding ENLK common units not previously owned by us.

(c) ENLC Equity Distribution Agreement

On February 22, 2019, ENLC entered into the ENLC EDA with 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. Under the ENLC EDA, ENLC may also sell common units to any ENLC Sales Agent as principal for the ENLC Sales Agent’s own account at a price agreed upon at the time of sale. ENLC has no obligation to sell any ENLC common units under the ENLC EDA and may at any time suspend solicitation and offers under the ENLC EDA. As of February 9, 2022, ENLC has not sold any common units under the ENLC EDA.

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Notes to Consolidated Financial Statements (continued)

(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,
	2021		2020		2019
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 units	0.5		(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)

____________________________

(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,
	2021	2020	2019
Basic weighted average units outstanding:
Weighted average common units outstanding	488.8	489.3	463.9
Diluted weighted average units outstanding:
Weighted average basic common units outstanding	488.8	489.3	463.9
Dilutive effect of non-vested restricted units (1)	5.5	—	—
Total weighted average diluted common units outstanding	494.3	489.3	463.9

____________________________

(1)For the years ended December 31, 2020 and 2019, all common unit equivalents were antidilutive because a net loss existed for those periods.

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

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Notes to Consolidated Financial Statements (continued)

(e) Distributions

A summary of our distribution activity related to the ENLC common units for the years ended December 31, 2021, 2020, and 2019, respectively, is provided below:

Declaration period	Distribution/unit		Date 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

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Notes to Consolidated Financial Statements (continued)

(10) Investment in Unconsolidated Affiliates

As of December 31, 2021, our unconsolidated investments consisted of a 38.75% ownership in GCF and a 30% ownership in 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,
	2021		2020		2019
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)

___________________________

(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.

The following table shows the balances related to our investment in unconsolidated affiliates as of December 31, 2021 and 2020 (in millions):

	December 31, 2021		December 31, 2020
GCF	$	28.0	$	40.6
Cedar Cove JV (1)	(1.8)		1.0
Total investment in unconsolidated affiliates	$	26.2	$	41.6

___________________________

(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.

(11) Employee Incentive Plans

(a) Long-Term Incentive Plans

We account for unit-based compensation in accordance with ASC 718, which requires that compensation related to all unit-based awards be recognized in the consolidated financial statements. Unit-based compensation cost is valued at fair value at the date of grant, and that grant date fair value is recognized as expense over each award’s requisite service period with a corresponding increase to equity or liability based on the terms of each award and the appropriate accounting treatment under ASC 718. Unit-based compensation associated with ENLC’s unit-based compensation plan awarded to directors, officers, and employees of the General Partner is recorded by ENLK since ENLC has no substantial or managed operating activities other than its interests in 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,
	2021		2020		2019
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 expense	6.6		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

____________________________

(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.

(b) ENLC Restricted Incentive Units

ENLC restricted incentive units were valued at their fair value at the date of grant, which is equal to the market value of ENLC common units on such date. A summary of the restricted incentive unit activity for the year ended December 31, 2021 is provided below:

	Year Ended December 31, 2021
ENLC Restricted Incentive Units:	Number of Units		Weighted Average Grant-Date Fair Value
Non-vested, beginning of period	5,350,086		$	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 period	7,507,471		$	5.46
Aggregate intrinsic value, end of period (in millions)	$	51.7

____________________________

(1)Restricted incentive units typically vest at the end of three years.

(2)Vested units included 382,343 units withheld for payroll taxes paid on behalf of employees.

A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for the years ended December 31, 2021, 2020, and 2019 is provided below (in millions):

	Year Ended December 31,
ENLC Restricted Incentive Units:	2021		2020		2019
Aggregate intrinsic value of units vested	$	5.6	$	12.1	$	17.3
Fair value of units vested	$	16.3	$	31.5	$	22.8

As of December 31, 2021, there were $13.0 million of unrecognized compensation costs that related to non-vested ENLC restricted incentive units. These costs are expected to be recognized over a weighted average period of 1.6 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) ENLC Performance Units

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

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 performance 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 Cumulative Performance Period. In short, the TSR for a given performance period is defined as (i)(A) the average closing price of a common equity security at the end of the relevant performance period minus (B) the average closing price of a common equity security at the beginning of the relevant performance period plus (C) reinvested dividends divided by (ii) the average closing price of a common equity security at the beginning of the relevant performance period.

The following table sets 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 Designated Peer Companies:

Performance Level	Achieved ENLC TSR Position Relative to Designated Peer Companies	Vesting percentage of the Tranche TSR Units
Below Threshold	Less than 25%	0%
Threshold	Equal to 25%	50%
Target	Equal to 50%	100%
Maximum	Greater 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. 

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Notes to Consolidated Financial Statements (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 Level	ENLC’s Achieved FCFAD	Vesting percentage of the Tranche CF Units
Below Threshold	Less than $205 million	0%
Threshold	Equal to $205 million	50%
Target	Equal to $256 million	100%
Maximum	Greater than or Equal to $300 million	200%

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 Level	ENLC’s Achieved  Distributable Cash Flow per Unit	Vesting percentage of the Tranche CF Units
Below Threshold	Less than $1.345	0%
Threshold	Equal to $1.345	50%
Target	Equal to $1.494	100%
Maximum	Greater than or Equal to $1.643	200%

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 Level	ENLC’s Achieved  Distributable Cash Flow per Unit	Vesting percentage of the Tranche CF Units
Below Threshold	Less than $1.43	0%
Threshold	Equal to $1.43	50%
Target	Equal to $1.55	100%
Maximum	Greater than or Equal to $1.72	200%

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 Designated Peer 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 value assumptions by performance unit grant date:

ENLC Performance Units:	January 2021			July 2020			March 2020			January 2020			October 2019			June 2019			March 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 rate	0.17		%	0.17		%	0.42		%	1.62		%	1.44		%	1.72		%	2.42		%
Volatility factor	71.00		%	67.00		%	51.00		%	37.00		%	35.00		%	33.50		%	33.86		%

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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 Units		Weighted Average Grant-Date Fair Value
Non-vested, beginning of period	2,351,241		$	8.82
Granted	1,388,139		4.70
Vested (1)	(164,553)		26.73
Non-vested, end of period	3,574,827		$	6.40
Aggregate intrinsic value, end of period (in millions)	$	24.6

____________________________

(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:	2021		2020		2019
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, 2021, there were $10.4 million of unrecognized compensation costs that related to non-vested ENLC performance units. These costs are expected to be recognized over a weighted-average period of 1.6 years.

(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 eligible compensation. Contributions of $7.0 million, $7.2 million, and $9.4 million were made to the plan for the years ended December 31, 2021, 2020, and 2019, respectively.

(12) Derivatives

Interest Rate Swaps

In 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 repayments of the Term Loan, which was one of our floating-rate, LIBOR-based borrowings. The following table presents the interest rate swaps terminations and the associated cash payments during 2021 and 2020 (in millions):

	Interest Rate Swaps Terminations		Cash Payments Associated with Interest Rate Swaps Terminations
December 2021	$	150.0	$	—
September 2021	100.0		0.5
May 2021	100.0		1.3
December 2020	500.0		10.9
Total termination of interest rate swaps	$	850.0	$	12.7

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Notes to Consolidated Financial Statements (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 follows (in millions):

	Year Ended December 31,
	2021		2020		2019
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, recognized from accumulated other comprehensive loss from the monthly settlement of our interest rate swaps and amortization of the termination payments, included in our consolidated statements of operations were as follows (in millions):

	Year Ended December 31,
	2021		2020		2019
Interest expense	$	18.3	$	14.5	$	0.4

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

The fair value of our interest rate swaps included in our consolidated balance sheets were as follows (in millions):

	December 31, 2021		December 31, 2020
Fair value of derivative liabilities—current	$	—	$	(7.6)

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 and to manage margins on offsetting fixed-price purchase or sale commitments for physical quantities of crude, condensate, natural gas, and NGLs. We do not designate commodity swaps 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. For condensate, crude oil, and natural gas, index swaps are also used to hedge the basis location price risk resulting from supply and markets being priced on different indices. 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.

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,
	2021		2020		2019
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, 2021		December 31, 2020
Fair value of derivative assets—current	$	22.4	$	25.0
Fair value of derivative assets—long-term	0.2		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, 2021 (in millions). The remaining term of the contracts extend no later than January 2023.

		December 31, 2021
Commodity	Instruments	Unit	Volume	Net Fair Value
NGL (short contracts)	Swaps	Gals	(63.0)	$	(10.6)
NGL (long contracts)	Swaps	Gals	—	—
Natural gas (short contracts)	Swaps	MMbtu	(7.5)	2.7
Natural gas (long contracts)	Swaps	MMbtu	13.2	(7.8)
Crude and condensate (short contracts)	Swaps	MMbbls	(3.9)	(4.4)
Crude and condensate (long contracts)	Swaps	MMbbls	3.9	5.6
Total fair value of commodity swaps				$	(14.5)

On all transactions where we are exposed to counterparty risk, we analyze the counterparty’s financial condition prior to entering into an agreement, establish limits, and monitor the appropriateness of these limits on an ongoing basis. We primarily deal with financial institutions when entering into financial derivatives on commodities. We have entered into Master ISDAs that allow for netting of swap contract receivables and payables in the event of default by either party. If our counterparties failed to perform under existing commodity swap contracts, the maximum loss on our gross receivable position of $22.6 million as of December 31, 2021 would be reduced to $0.8 million due to the offsetting of gross fair value payables against gross fair value receivables as allowed by the ISDAs.

(13) Fair Value Measurements

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)

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.

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

	Level 2
	December 31, 2021		December 31, 2020
Interest rate swaps (1)	$	—	$	(7.6)
Commodity swaps (2)	$	(14.5)	$	(2.1)

____________________________

(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.

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, 2021				December 31, 2020
	Carrying Value		Fair Value		Carrying Value		Fair 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	$	—	$	—

____________________________

(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.”

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

The fair values of all senior unsecured notes as of December 31, 2021 and 2020 were based on Level 2 inputs from third-party market quotations.

(14) Commitments and Contingencies

(a) 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.

(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.

(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. We may also be involved from time to time in the future in various proceedings in the normal course of business, including litigation on disputes related to contracts, property rights, property use or damage (including nuisance claims), personal injury, or the value of pipeline easements or other rights obtained through the exercise of eminent domain or common carrier rights.

137

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Notes to Consolidated Financial Statements (continued)

(15) Segment Information

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 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:

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

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

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

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

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

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Notes to Consolidated Financial Statements (continued)

We evaluate the performance of our operating segments based on segment profit and adjusted gross margin. Adjusted gross margin is a non-GAAP financial measure. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures” for additional information. Summarized financial information for our reportable segments is shown in the following tables (in millions):

	Permian		Louisiana		Oklahoma		North Texas		Corporate		Totals
Year Ended December 31, 2021
Natural gas sales	$	609.4	$	693.5	$	213.4	$	150.0	$	—	$	1,666.3
NGL sales	0.9		3,353.1		2.0		1.1		—		3,357.1
Crude oil and condensate sales	677.4		212.0		81.2		—		—		970.6
Product sales	1,287.7		4,258.6		296.6		151.1		—		5,994.0
NGL sales—related parties	1,008.4		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 parties	1,008.4		129.7		630.9		454.1		(2,223.1)		—
Gathering and transportation	46.8		64.7		186.9		157.0		—		455.4
Processing	29.1		2.4		98.7		108.3		—		238.5
NGL services	—		82.6		—		0.3		—		82.9
Crude services	18.4		39.3		12.8		0.7		—		71.2
Other services	0.2		1.7		0.6		0.5		—		3.0
Midstream services	94.5		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 customers	2,390.6		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 margin	311.2		448.6		407.6		328.6		—		1,496.0
Operating expenses	(81.5)		(123.7)		(80.0)		(77.7)		—		(362.9)
Segment profit	229.7		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

____________________________

(1)Includes related party cost of sales of $17.9 million for the year ended December 31, 2021.

139

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (continued)

	Permian		Louisiana		Oklahoma		North Texas		Corporate		Totals
Year Ended December 31, 2020
Natural gas sales	$	150.1	$	330.5	$	153.1	$	70.3	$	—	$	704.0
NGL sales	0.2		1,545.4		2.8		—		—		1,548.4
Crude oil and condensate sales	558.1		126.7		40.3		—		—		725.1
Product sales	708.4		2,002.6		196.2		70.3		—		2,977.5
NGL sales—related parties	312.6		31.4		296.4		115.2		(755.6)		—
Crude oil and condensate sales—related parties	0.6		—		(0.1)		3.6		(4.1)		—
Product sales—related parties	313.2		31.4		296.3		118.8		(759.7)		—
Gathering and transportation	42.8		46.5		228.7		179.2		—		497.2
Processing	24.1		2.0		123.6		132.6		—		282.3
NGL services	—		75.8		—		0.2		—		76.0
Crude services	16.8		45.2		16.5		0.2		—		78.7
Other services	1.2		1.6		0.4		0.9		—		4.1
Midstream services	84.9		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 customers	1,106.5		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 derivatives	1.1		(6.5)		(4.5)		(0.6)		—		(10.5)
Adjusted gross margin	264.3		405.6		487.6		347.8		—		1,505.3
Operating expenses	(94.2)		(120.0)		(82.2)		(77.4)		—		(373.8)
Segment profit	170.1		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

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Notes to Consolidated Financial Statements (continued)

	Permian		Louisiana		Oklahoma		North Texas		Corporate		Totals
Year Ended December 31, 2019
Natural gas sales	$	94.3	$	416.6	$	236.4	$	129.3	$	—	$	876.6
NGL sales	0.9		1,725.6		19.6		30.9		—		1,777.0
Crude oil and condensate sales	1,975.0		291.9		109.6		—		—		2,376.5
Product sales	2,070.2		2,434.1		365.6		160.2		—		5,030.1
Natural gas sales—related parties	0.4		—		—		—		(0.4)		—
NGL sales—related parties	347.7		25.7		421.1		94.8		(889.3)		—
Crude oil and condensate sales—related parties	13.5		1.7		—		5.5		(20.7)		—
Product sales—related parties	361.6		27.4		421.1		100.3		(910.4)		—
Gathering and transportation	48.8		58.3		234.5		196.4		—		538.0
Processing	30.5		3.2		138.2		143.0		—		314.9
NGL services	—		50.6		—		0.1		—		50.7
Crude services	19.2		51.9		19.8		—		—		90.9
Other services	12.0		0.7		0.1		1.1		—		13.9
Midstream services	110.5		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 customers	2,542.3		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 derivatives	9.4		5.1		—		—		—		14.5
Change in fair value of derivatives	1.5		(1.8)		—		0.2		—		(0.1)
Adjusted gross margin	269.3		444.5		554.1		392.5		—		1,660.4
Operating expenses	(112.9)		(147.3)		(104.0)		(102.9)		—		(467.1)
Segment profit	156.4		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

____________________________

(1)Includes related party cost of sales of $21.7 million for the year ended December 31, 2019.

141

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (continued)

The table below represents information about segment assets as of December 31, 2021 and 2020 (in millions):

Segment Identifiable Assets:	December 31, 2021		December 31, 2020
Permian	$	2,358.6	$	2,236.3
Louisiana	2,428.6		2,312.4
Oklahoma	2,619.5		2,847.6
North Texas	896.8		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:	2021		2020		2019
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)	$	—

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (continued)

(17) Other Information

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

Other current assets:	December 31, 2021		December 31, 2020
Natural gas and NGLs inventory	$	49.4	$	44.9
Prepaid expenses and other	34.2		13.8
Other current assets	$	83.6	$	58.7

Other current liabilities:	December 31, 2021		December 31, 2020
Accrued interest	$	47.2	$	35.7
Accrued wages and benefits, including taxes	33.1		22.5
Accrued ad valorem taxes	28.3		26.5
Capital expenditure accruals	23.2		10.6
Short-term lease liability	18.1		16.3
Installment payable (1)	10.0		—
Inactive easement commitment (2)	9.8		—
Operating expense accruals	9.6		8.4
Other	23.6		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.

143

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

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 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, 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, 2021 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

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.

145

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.

146

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 the Operating Partnership. References to our officers, directors, and employees are references to the officers, directors, and employees of the Managing Member or the Operating Partnership.

The following table shows information for the members of the Board of Directors of the Managing Member (the “Board”) and the executive officers of the Managing Member. Executive officers and directors serve until their successors are duly appointed or elected.

Name	Age	Position with EnLink Midstream Manager, LLC
Barry E. Davis	60	Chairman and Chief Executive Officer
Benjamin D. Lamb	42	Executive Vice President and Chief Operating Officer
Pablo G. Mercado	45	Executive Vice President and Chief Financial Officer
Alaina K. Brooks	47	Executive Vice President, Chief Legal and Administrative Officer, and Secretary
Deborah G. Adams (1)	61	Director and Member of the Audit and Sustainability (2) Committees
William J. Brilliant	46	Director and Member of the Governance and Compensation Committee
Tiffany Thom Cepak (1)	48	Director and Member of the Audit and Conflicts Committees
Leldon E. Echols (1)	66	Director and Member of the Governance and Compensation and Audit (2) Committees
Thomas W. Horton	60	Director
James K. Lee	40	Director
Scott E. Telesz	54	Director and Member of the Sustainability Committee
Kyle D. Vann (1)	74	Director and Member of the Conflicts (2) and Governance and Compensation (2) Committees

____________________________

(1)Independent director.

(2)Chairperson of committee.

Barry E. Davis, Chairman and Chief Executive Officer, has served in this position since August 2019, after serving as Executive Chairman 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 Crosstex Energy, Inc. in 2004. Crosstex Energy was formed in 1996 when Mr. Davis led the 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. 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. In addition to serving on our Board of Directors, Mr. Davis is a Trustee of Texas Christian University (TCU) and a board member of the Kirby Corp. and several other civic and nonprofit organizations. Mr. Davis is a member and former president of the Natural Gas and Electric 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 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 Operating Officer, has served in this position since June 2018. Mr. Lamb previously served in a number of leadership roles, most recently as Executive Vice President—North Texas and Oklahoma from February 2018 to June 2018 and previously as Executive Vice President—Corporate Development, Senior Vice President—Finance and Corporate Development, and Vice President—Finance from December 2012 to February 2018. Prior to 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 from September 2014 until June 2018 and as Deputy General Counsel until September 2014. In Ms. Brooks’ current role, she serves on our Executive Leadership Team and leads the legal, regulatory, public and industry affairs, contract administration, and human resources functions. Prior to 2008, Ms. Brooks practiced law at Weil, Gotshal & Manges LLP and Baker Botts 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.

Deborah G. Adams has served as a director of the Managing Member since February 2020. Ms. Adams served on the Executive Leadership Team at Phillips 66 as Senior Vice President of Health, Safety, and Environment, Projects and Procurement from 2014 until her retirement in October 2016. Ms. Adams previously served as Division President, Transportation for 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. and 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 inducted 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 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. Brilliant 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 from Tulane University. Ms. Cepak was selected to serve as a director due to, among other factors, her extensive experience in the energy sector and her engineering, operational, and finance experience.

Leldon E. Echols has served as a director of the Managing Member since March 2014. Mr. Echols joined Crosstex Energy, Inc, the predecessor to ENLC, as a director in January 2008. Mr. Echols served as a director of the General Partner from March 2014 until January 2019. Mr. Echols is a private investor. Mr. Echols also currently serves as an independent director of Trinity Industries, Inc. and HollyFrontier 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.

Thomas W. Horton has served as a director of the Managing Member since August 2019. Mr. Horton is a Partner at GIP. Prior to joining GIP, Mr. Horton was a 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 General Electric Co. and Walmart Inc. He also serves on the executive board of the Cox School of Business at Southern Methodist University. Mr. Horton was selected to 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 joining GIP, Mr. Lee was an investment banker at Goldman Sachs & Co. Mr. Lee previously served on the Board of Directors of Competitive Power Ventures, a privately held electric power generation development and asset management company. Mr. Lee holds a Bachelor 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 in electrical engineering from Duke University in 1989 and a Master of Business Administration from Harvard Business School in 1994. Mr. Telesz 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 extensive experience in the energy industry and his business expertise, among other factors.

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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. Vann and Echols and Mses. 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 Commission 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 Commission rules, including that the person meets the relevant definition of an “independent” director. Mr. Echols is an independent director who has been determined to be an audit committee financial expert. Unitholders should understand that this designation is a disclosure requirement of the Commission related to the experience and understanding of the individual with respect to certain accounting and auditing matters. The designation does not impose on such director any duties, obligations, or liabilities that are greater than are generally imposed on the director as a member of the Audit Committee and the Board, and the designation of a director as an audit committee financial expert pursuant to this Commission requirement does not affect the duties, obligations, or liabilities of any other member of the Audit Committee or the Board.

Board Committees

The Board has four standing committees: the Audit Committee, the Conflicts Committee, the 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) and Mses. 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 Mr. Vann (chair) and Ms. 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 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, comprised of Messrs. Vann (chair), Brilliant, and Echols, reviews matters involving governance, including assessing the effectiveness of current policies, monitoring industry developments, and overseeing 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 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.

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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 expectations of our employees that enable us to provide accurate and timely disclosure in our filings with the Commission 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 Commission.

Item 11. Executive Compensation

Governance and Compensation Committee Report

Kyle D. Vann and Leldon E. Echols, who serve on the Governance and Compensation Committee of our Managing Member (the “Committee”), are independent directors in accordance with NYSE standards. The Committee has reviewed and discussed with management the following section titled “Compensation Discussion and Analysis.” Based upon its review and discussions, the 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 Committee:

Kyle D. Vann (chair)

William 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 with 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 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 the 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.

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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 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 generally comprised of 60% equity-based awards issued under our long-term incentive plan, 20% annual bonus awarded under the Short-Term Incentive Program (the “STI Program”), and 20% base salary.

The 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 plan 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 the interests of executives with those of our unitholders;

•The compensation program should be sufficiently flexible to address special circumstances, including retention initiatives 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

The 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 Committee recommended to the Board adjustments to the compensation program and to each individual element as determined necessary to achieve our goals. The Committee retains a compensation consultant to assist in its review and to provide input regarding the compensation program and each individual element.

Role of Compensation Consultant

The Committee retained Mercer (US) Inc., (“Mercer”) as its independent compensation consultant to advise the Committee on certain matters relating to compensation programs applicable to the named executive officers and other employees of the General Partner during 2021. In particular, Mercer assisted in the Committee’s overall 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 Committee about emerging best practices and changes in the regulatory and governance environment. Mercer’s work for the Committee did not raise any conflicts of interest in 2021.

Role of Peer Group and Benchmarking

The Committee and Mercer collaborated to identify the following companies as our peer companies in 2021: Crestwood Equity Partners, L.P., DCP Midstream, L.P., Enable Midstream Partners, LP, Equitrans Midstream Corporation, Genesis Energy, L.P., Magellan Midstream Partners, L.P., MPLX, L.P., NuStar Energy L.P., ONEOK Inc., and Targa Resources Corp. (the “Peer Group”). The 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 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 Committee, with the assistance of 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 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, the compensation consultant provides guidance on current industry trends and best practices to the Committee relating to all aspects of executive compensation.

While compensation surveys and Peer Group data are considered, the 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 Committee of our performance relative to expectations and actual market/business conditions.

Elements of Compensation

For fiscal year 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 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 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 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 2021 (and payable for fiscal 2022 beginning in March) are as follows:

	2021 Base Salary		Base 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	%

Bonus Awards. The Board and the Committee oversee the STI Program. All employees, including named executive officers, 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 success and are subject to the discretion of the Board and the 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 Component and associated information are as follows:

Component	Weighting	Threshold Level	Target Level	Maximum Level
Financial - Adjusted EBITDA	55%	$867 million	$958 million	$1,042 million
Financial - FCFAD	10%	$205 million	$256 million	$300 million
Operational	15%	Operational Scorecard
Safety and Sustainability	15%	Safety and Sustainability Scorecard
Capital Projects	5%	Timely and cost-effective capital projects
Total Weighting	100%

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 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 Board and the Committee to determine the bonus amounts that are ultimately payable under the STI Program, including to the named executive officers, as further described below.

The Committee and the Board, with input from management, set the annual weightings for each Primary Bonus Component, any additional weightings that apply with respect to the features comprising a particular Primary Bonus Component, and the “threshold/target/maximum” standard that applies to the Primary Bonus Components. This 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 Board, based on recommendations of the Committee, initially establishes the target bonus awards that may be earned and ultimately determines the final bonus amounts, if any, that are payable under the STI Program for the named executive officers. Initial bonus award amounts for consideration by the Committee and the Board for the named executive officers will be established by multiplying (i) the relevant named executive officer’s target bonus percentage by (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 (iii) the achievement percentage for the relevant year.

The Committee believes that a portion of executive compensation for named executive officers must remain discretionary. Therefore, the STI Program contemplates that the Committee and the Board retain discretion with respect to target bonus awards and the final bonus amounts for named executive officers. In this regard, the Committee may exercise such discretion to recommend to the Board 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 is approved by the Board based upon the 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 include 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 are reviewed and evaluated by the Committee as a whole. All named executive officers met or exceeded their minimum personal performance objectives for 2021. Accordingly, the Committee and the Board 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. Davis	125	%	206.3	%	$	1,546,994
Benjamin D. Lamb	100	%	168.2	%	$	852,735
Pablo G. Mercado	90	%	151.4	%	$	703,890
Alaina K. Brooks	90	%	151.4	%	$	703,948

Long-Term Incentive Plan. Our named executive officers and outside directors are also eligible to participate in the EnLink Midstream, LLC 2014 Long-Term Incentive Plan (the “2014 Plan”). The Board, upon the recommendation of the Committee, approves the grants of equity awards to our named executive officers. The Committee believes that equity awards should comprise a significant portion of a named executive officer’s total compensation. A number of factors are considered when determining grants to each individual named executive officer including but not limited to: compensation surveys, Peer Group data, the named executive officer’s performance on a group and individual basis, company performance, market conditions, succession planning, retention, and other factors as determined by the Committee and/or the Board.

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. 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 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, 25,608,795 common 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.

In general, the 2014 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, subject 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. The 2014 Plan, as currently amended and restated, will automatically expire on 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 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 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.

Performance Unit Awards. Our performance-based award agreements (the “Performance-Based Award Agreements”) provide for future awards of equity-based compensation under the 2014 Plan. Since 2019, the Performance-Based Award Agreements have provided that the vesting of restricted incentive units under the 2014 Plan is dependent on (i) our TSR performance relative to the TSR performance of a peer group of companies and (ii) our cash flow performance. At the time of grant, the Board will determine the relative weighting of the two performance goals by including in the relevant Performance-Based Award Agreement the number of restricted incentive units that will be eligible for vesting depending on the achievement 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 of the 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 following table sets out the levels at which the Tranche TSR Units may vest (using linear interpolation) based on the TSR percentile ranking for the applicable performance period relative to the TSR achievement of the Designated Peer Companies:

Performance Level	Achieved TSR Position Relative to Designated Peer Companies	Vesting percentage of the Tranche TSR Units
Below Threshold	Less than 25%	0%
Threshold	Equal to 25%	50%
Target	Equal to 50%	100%
Maximum	Greater 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 Level	ENLC’s Achieved FCFAD	Vesting percentage of the Tranche CF Units
Below Threshold	Less than $205 million	0%
Threshold	Equal to $205 million	50%
Target	Equal to $256 million	100%
Maximum	Greater than or Equal to $300 million	200%

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 Level	ENLC’s Achieved  Distributable Cash Flow per Unit	Vesting percentage of the Tranche CF Units
Below Threshold	Less than $1.345	0%
Threshold	Equal to $1.345	50%
Target	Equal to $1.494	100%
Maximum	Greater than or Equal to $1.643	200%

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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 Level	ENLC’s Achieved  Distributable Cash Flow per Unit	Vesting percentage of the Tranche CF Units
Below Threshold	Less than $1.43	0%
Threshold	Equal to $1.43	50%
Target	Equal to $1.55	100%
Maximum	Greater than or Equal to $1.72	200%

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 EnLink’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 Designated Peer Companies securities; (iii) an estimated ranking of us among the Designated Peer Companies; and (iv) the distribution yield.

The total value of the equity compensation granted to our executive officers generally has been awarded 50% restricted incentive units and 50% performance units on an annual basis. In addition, our executive officers may receive additional grants of equity compensation in certain circumstances, such as promotions and 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. The 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 2021, the Operating Partnership matched 100% of every dollar contributed for contributions of up to 6% of eligible compensation made by eligible participants plus a discretionary 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 change in control agreements (the “Change in Control Agreements”) with the Operating Partnership and 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 claw 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 would be entitled to three times the Severance Benefit, 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.

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 Initial 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 Initial Expiration Date (each, a “Renewal Date”), unless the Board 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 Board providing 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 2014 Plan, the amounts to be received by our named executive officers in the event of a change of control (as defined in such 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 such 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 Committee.

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Upon a change of control, and except as provided in the award agreement, the 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 and except as provided in the award agreement, the Committee 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, 2021 are set forth in the table in the section below entitled “Payments Upon Termination or Change of Control.”

Role of Executive Officers in Executive Compensation

The Board, upon recommendation of the Committee, determines the compensation payable to each of the named executive officers. None of the named executive officers serves as a member of the Committee. Our Chief Executive Officer makes recommendations regarding the compensation of his leadership team with the Committee, including specific recommendations for each element of compensation for each of the named executive officers. Our 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.

Name and Principal Position	Year	Salary ($)(1)	Bonus ($)(2)	Restricted Incentive Unit and Performance Unit Awards ($)(3)	All Other Compensation ($)		Total ($)
Barry E. Davis	2021	750,058	1,546,994	3,968,869	643,524	(5)	6,909,445
Chairman and Chief Executive Officer	2020	763,269	983,658	5,412,084	660,582		7,819,593
	2019	556,000	636,568	4,553,287	744,456		6,490,311
Benjamin D. Lamb	2021	516,809	852,735	1,984,434	205,645	(6)	3,559,623
Executive Vice President and Chief Operating Officer	2020	519,988	536,056	2,706,036	209,641		3,971,721
	2019	491,200	521,207	1,264,284	362,424		2,639,115
Pablo G. Mercado (4)	2021	474,000	703,890	1,257,142	150,520	(7)	2,585,552
Executive Vice President and Chief Financial Officer	2020	225,000	408,757	986,400	223,126		1,843,283
Alaina K. Brooks	2021	474,039	703,948	1,133,962	185,407	(8)	2,497,356
Executive Vice President, Chief Legal and Administrative Officer, and Secretary	2020	465,252	431,666	1,391,674	181,311		2,469,903
	2019	439,500	444,709	902,261	302,253		2,088,723

____________________________

(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.

(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 2021, the annual total compensation for Mr. Davis was $6.9 million and for the median employee was $105,168. The resulting ratio of annual total compensation of Mr. Davis to the annual total compensation of our median employee was 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 the median employee by examining 2020 W-2 Box 1 Federal Taxable Wages (the “Taxable Wages Measure”) for all of our employees, excluding our Chairman and Chief Executive Officer, who were employed on December 31, 2021, the last business day of the 2021 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 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 2021 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 2021 Table

The following table provides information concerning each grant of an award made to a named executive officer for fiscal year 2021.

ENLINK MIDSTREAM, LLC—GRANTS OF PLAN-BASED AWARDS

		Estimated Future Payouts Under Equity Incentive Plan Awards
Name	Grant Date	Threshold (#)	Target (#)	Maximum (#)	All Other Unit Awards: Number of Units		Grant Date Fair Value of Unit Awards ($)(1)
Barry E. Davis	1/1/2021	—	—	—	471,698	(2)	1,750,000
	1/1/2021	235,849	471,698	943,396	—	(3)	2,218,869
Benjamin D. Lamb	1/1/2021	—	—	—	235,849	(2)	875,000
	1/1/2021	117,925	235,849	471,698	—	(3)	1,109,435
Pablo G. Mercado	1/1/2021	—	—	—	134,771	(2)	500,000
	1/1/2021	67,386	134,771	269,542	—	(3)	633,962
	2/16/2021	—	—	—	26,954	(4)	123,180
Alaina K. Brooks	1/1/2021	—	—	—	134,771	(2)	500,000
	1/1/2021	67,386	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.

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Outstanding Equity Awards at Fiscal Year-End Table for Fiscal Year 2021

The following table provides information concerning all outstanding equity awards made to a named executive officer as of December 31, 2021.

ENLINK MIDSTREAM, LLC—OUTSTANDING EQUITY AWARDS AT FISCAL YEAR-END

		Unit Awards
Name	Vesting Year (1)	Number of Units That Have Not Vested (#)	Market Value of Shares or Units That Have Not Vested ($)(2)	Equity Incentive Plan Awards: Number of Unearned Units or Other Rights that Have Not Vested (#)(3)(4)(5)		Equity Incentive Plan Awards: Market or Payout Value of Unearned Units or Other Rights That Have Not Vested ($)(2)
Barry E. Davis	2024	471,698	3,249,999	471,698		3,249,999
	2023	391,499	2,697,428	391,499		2,697,428
	2022	135,318	932,341	391,292	(6)	2,696,002
Benjamin D. Lamb	2024	235,849	1,625,000	235,849		1,625,000
	2023	195,749	1,348,711	195,749		1,348,711
	2022	—	—	96,525		665,057
Pablo G. Mercado	2024	134,771	928,572	134,771		928,572
	2023	200,000	1,378,000	200,000		1,378,000
	2022	—	—	—		—
Alaina K. Brooks	2024	134,771	928,572	134,771		928,572
	2023	100,671	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.

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Units Vested Table for Fiscal Year 2021

The following table provides information related to the vesting of restricted units and restricted incentive units during fiscal year ended 2021.

ENLINK MIDSTREAM, LLC—UNITS VESTED

Name	Date Vested	Number of Units Acquired on Vesting	Value Per Unit Realized on Vesting ($)	Total ($)
Barry E. Davis	1/1/2021	42,614	3.71	158,098
	1/21/2021	42,614	3.95	168,325
	1/1/2021	56,116	3.71	208,190
	1/21/2021	56,116	3.95	221,658
Benjamin D. Lamb	1/1/2021	19,886	3.71	73,777
	1/1/2021	26,188	3.71	97,157
	8/1/2021	15,674	5.57	87,304
	8/1/2021	27,430	5.57	152,785
	8/1/2021	18,453	5.57	102,783
	8/1/2021	32,294	5.57	179,878
Pablo G. Mercado	12/31/2021	26,954	6.80	183,287
Alaina K. Brooks	1/1/2021	11,222	3.71	41,634
	1/21/2021	11,222	3.95	44,327
	1/1/2021	14,778	3.71	54,826
	1/21/2021	14,778	3.95	58,373
	8/1/2021	10,972	5.57	61,114
	8/1/2021	10,972	5.57	61,114
	8/1/2021	12,918	5.57	71,953
	8/1/2021	12,918	5.57	71,953

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Payments Upon Termination or Change of Control

The following table shows potential payments that would have been made to the named executive officers as of December 31, 2021.

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)
Barry E. Davis	4,971,994	23,890	—	6,659,494	15,523,198
Benjamin D. Lamb	2,930,735	30,752	—	3,437,735	6,612,478
Pablo G. Mercado	2,520,890	29,214	—	2,962,640	4,613,144
Alaina K. Brooks	2,520,948	31,290	—	2,962,698	3,743,185

____________________________

(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.

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Compensation of Directors for Fiscal Year 2021

DIRECTOR COMPENSATION

Name	Fees Earned or Paid in Cash ($)	Unit Awards ($)(1)	All Other Compensation ($)(2)	Total ($)
Deborah G. Adams	95,625	198,071	11,624	305,320
Tiffany Thom Cepak (3)	—	—	—	—
James C. Crain (4)	82,500	198,071	5,812	286,383
Leldon E. Echols	107,375	198,071	11,624	317,070
Kyle D. Vann	105,000	198,071	11,624	314,695

____________________________

(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.

(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 GIP is paid an annual retainer fee of $97,500 and equity compensation valued at $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 received the following annual fees for fiscal year ended 2021: Audit—$20,000, Governance and Compensation Committee—$15,000, Conflicts—$15,000, and Sustainability—$15,000. Directors were also reimbursed for related out-of-pocket expenses.

Barry E. Davis, as an officer of the Managing Member, 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.

Governance and Compensation Committee Interlocks and Insider Participation

Our Governance and Compensation Committee is comprised of Kyle D. Vann (chair), William J. Brilliant, and Leldon E. Echols. As described elsewhere in this report, Mr. Brilliant is a representative of GIP and may have an interest in the transactions among GIP, ENLK, and us. Please see “Item 13. Certain Relationships and Related 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 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 Chairman and Chief Executive Officer is in our best interest at this time, and that such arrangement makes the best use of Mr. Davis’ unique skills and experience in the industry.

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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.

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Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters

EnLink Midstream, LLC Ownership

The following table shows the beneficial ownership of ENLC, as of February 9, 2022, held by:

•each person who is known to ENLC to beneficially own more than 5% of any class of voting units then outstanding;

•all the directors of the Managing Member;

•each named executive officer of the Managing Member; and

•all the directors and executive officers of the Managing Member as a group.

The percentage of total ENLC common units beneficially owned is based on a total of 546,319,579 units (including 62,293,613 common units, which reflects the as-exchanged amount of the outstanding 54,168,359 ENLC Class C Common Units) as of February 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. Lamb	538,603	*		538,603	*
Pablo G. Mercado	16,347	*		16,347	*
Alaina K. Brooks	236,412	*		236,412	*
Deborah G. Adams	87,721	*		87,721	*
William J. Brilliant	—	*		—	*
Tiffany Thom Cepak	—	*		—	*
Leldon E. Echols	177,746	*		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 percentages reflected in the column below are based on a total of 484,025,966 common units.

(4)The percentages reflected in the column below are based on a total of 546,319,579 common units, which includes the units described in (3) above, and 62,293,613 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 are 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 the Series B 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 the 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 owned 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 is 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 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. See “Item 1A. Risk Factors—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.”

Equity Compensation Plan Information

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)	11,082,298	(2)	N/A	25,608,795	(3)
Equity Compensation Plans Not Approved by Security Holders	N/A		N/A	N/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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Item 13. Certain Relationships and Related Transactions, and Director Independence

Relationship with EnLink Midstream Partners, LP

In connection with the Merger, we issued 304,822,035 common units to acquire all of the outstanding ENLK common units not previously owned by us. Subsequent to the Merger, ENLC owns all of ENLK’s common units and also owns all of the membership interests of the General Partner, which allows us to appoint all of the officers and directors of the General Partner and to manage and operate ENLK.

Relationship with GIP

We are managed by our Managing Member, which is wholly-owned by GIP. Therefore, GIP controls us and our ability to manage and operate our business. Additionally, four of our directors, William J. Brilliant, Thomas W. Horton, James K. Lee, and Scott E. Telesz are representatives of 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 ended December 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—Note 4” for information about our related party transactions.

Certain Relationships

From time to time, we may do business with other companies affiliated with our board of directors, or with 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, judgments, fines, taxes (including ERISA excise 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 alternative dispute mechanisms, whether civil, criminal, administrative, arbitrative, investigative, or other, whether made pursuant to federal, state, or local law, whether formal or informal, and including appeals (a “proceeding”), in which the Indemnitee may be involved, or is threatened to be involved, as a party, a witness, or otherwise, including 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 is or was serving at the request of us, the General Partner, or the Managing Member as a manager, managing member, general partner, director, officer, fiduciary, trustee, or agent of any other entity, organization, or person of any 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

Our 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, arrangement, or relationship, or any series of similar transactions, arrangements, or relationships, in which we or any of our subsidiaries is or will be a participant, 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 interest.

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 members of the Conflicts Committee of the Board or the approval of a majority of the unitholders (excluding units owned by the Managing Member and its affiliates). Any resolution, course of action, or transaction receiving approval of a majority of the members of the Conflicts Committee of the Board or approval of a majority of the unitholders (excluding units owned by the Managing Member and its affiliates) will be conclusively deemed to be approved by ENLC and all of its members.

Director Independence

See “Item 10. Directors, Executive Officers, and Corporate Governance” for information regarding director independence.

Item 14. Principal Accountant 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, 2021, 2020, and 2019, review of our internal control procedures for the fiscal years ended December 31, 2021, 2020, and 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 $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, 2021, 2020, and 2019 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, 2021, 2020, and 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, 2021, 2020, and 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. The chair 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, provided

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that the additional services do not affect KPMG’s independence under applicable 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

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):

Number			Description
2.1	**	—	Agreement and Plan of Merger, dated as of October 21, 2018, by and among EnLink Midstream, LLC, EnLink Midstream Manager, LLC, NOLA Merger Sub, LLC, EnLink Midstream Partners, LP, and EnLink Midstream GP, LLC (incorporated by reference to Exhibit 2.1 to our Current Report on Form 8-K dated October 21, 2018, filed with the Commission on October 22, 2018, file No. 001-36336).
3.1		—	Certificate of Formation of EnLink Midstream, LLC (incorporated by reference to Exhibit 3.1 to our Registration Statement on Form S-4, filed with the Commission on November 20, 2013, file No. 333-192419).
3.2		—	Certificate of Amendment to Certificate of Formation of EnLink Midstream, LLC (incorporated by reference to Exhibit 3.2 to Amendment No. 2 to our Registration Statement on Form S-4, filed with the Commission on January 21, 2014, file No. 333-192419).
3.3		—	Second Amended and Restated Operating Agreement of EnLink Midstream, LLC, dated as of January 25, 2019 (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K dated January 25, 2019, filed with the Commission on January 29, 2019, file No. 001-36336).
3.4		—	Certificate of Formation of EnLink Midstream Manager, LLC (incorporated by reference to Exhibit 3.12 to our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2014, filed with the Commission on August 6, 2014, file No. 001-36336).
3.5		—	Certificate of Amendment to the Certificate of Formation of EnLink Midstream Manager, LLC (incorporated by reference to Exhibit 3.13 to our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2014, filed with the Commission on August 6, 2014, file No. 001-36336).
3.6		—	Second Amended and Restated Limited Liability Company Agreement of EnLink Midstream Manager, LLC, dated as of July 18, 2018 (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K dated July 17, 2018, filed with the Commission on July 23, 2018, file No. 001-36336).
3.7		—	Certificate of Formation of EnLink Midstream GP, LLC (incorporated by reference to Exhibit 3.7 to EnLink Midstream Partners, LP’s Registration Statement on Form S-1, file No. 333-97779).
3.8		—	Certificate of Amendment to the Certificate of Formation of EnLink Midstream GP, LLC (incorporated by reference to Exhibit 3.12 to EnLink Midstream Partners, LP’s Registration Statement on Form S-3, filed with the Commission on March 10, 2014, file No. 333-194465).
3.9		—	Fourth Amended and Restated Limited Liability Company Agreement of EnLink Midstream GP, LLC, dated as of July 18, 2018 (incorporated by reference to Exhibit 3.2 to our Current Report on Form 8-K dated July 17, 2018, filed with the Commission on July 23, 2018, file No. 001-36336).
3.10		—	Certificate of Limited Partnership of EnLink Midstream Partners, LP (incorporated by reference to Exhibit 3.1 to EnLink Midstream Partners, LP’s Registration Statement on Form S-1, filed with the Commission on August 7, 2002, file No. 333-97779).
3.11		—	Certificate of Amendment to the Certificate of Limited Partnership of EnLink Midstream Partners, LP (incorporated by reference to Exhibit 3.2 to EnLink Midstream Partners, LP’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2012, filed with the Commission on August 7, 2012, file No. 000-50067).
3.12		—	Second Amendment to the Certificate of Limited Partnership of EnLink Midstream Partners, LP (incorporated by reference to Exhibit 3.3 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated March 6, 2014, filed with the Commission on March 11, 2014, file No. 001-36340).
3.13		—	Third Amendment to the Certificate of Limited Partnership of EnLink Midstream Partners, LP (incorporated by reference to Exhibit 3.1 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated June 16, 2017, filed with the Commission on June 19, 2017, file No. 001-36340).
3.14		—	Tenth Amended and Restated Agreement of Limited Partnership of EnLink Midstream Partners, LP, dated as of January 25, 2019 (incorporated by reference to Exhibit 3.2 to our Current Report on Form 8-K dated January 25, 2019, filed with the Commission on January 29, 2019, file No. 001-36336).

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4.1		—	Registration Rights Agreement, dated as of March 7, 2014, by and among Devon Gas Services, L.P., 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 25, 2019, by and between EnLink Midstream, LLC 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 10.1 to our Current Report on Form 8-K dated January 25, 2019, filed with the Commission on January 29, 2019, file No. 001-36336).
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 7, 2016, filed with the Commission on January 12, 2016, file No. 001-36336).
4.4		—	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).
4.5		—	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).
4.6		—	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).
4.7		—	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).
4.8		—	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, file No. 001-36340).
4.9		—	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).
4.10		—	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).
4.11		—	Indenture, dated as of April 9, 2019, by and between EnLink Midstream, LLC and Wells 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 July 17, 2018, filed with the Commission on July 23, 2018, file No. 001-36336).
10.2	†	—	EnLink Midstream GP, LLC Long-Term Incentive Plan, as amended and restated January 25, 2019 (the “GP Plan”) (incorporated by reference to Exhibit 4.2 to our Registration Statement on Form S-8 dated January 28, 2019, filed with the Commission on January 28, 2019, file No. 333-229393).
10.3	*†	—	EnLink Midstream, LLC 2014 Long-Term Incentive Plan, as amended and restated December 16, 2021 (the “2014 Plan”).
10.4	†	—	Form of Amended 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 10.6 to our Annual Report on Form 10-K dated December 31, 2018, filed with the Commission on February 20, 2019, file No. 001-36336).

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10.5		—	Revolving Credit Agreement, dated as of December 11, 2018, by and among EnLink Midstream, LLC, Bank of America, N.A., as Administrative Agent, Swing Line Lender and L/C Issuer, 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 (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K dated December 11, 2018, filed with the Commission on December 12, 2018, file No. 001-36336).
10.6		—	Guaranty Agreement, dated as of January 25, 2019, by EnLink Midstream Partners, LP in favor of Bank of America, N.A., as Administrative Agent, for the ratable benefit of the lenders from time to time party to 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 January 25, 2019, filed with the Commission on January 29, 2019, file No. 001-36336).
10.7	†	—	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).
10.8	†	—	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).
10.9	†	—	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).
10.10	†	—	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.
22.1	*	—	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's Annual Report on Form 10-K for the year ended December 31, 2021, formatted in iXBRL (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, 2021, 2020, and 2019, (iii) Consolidated Statements of Changes in Members’ Equity for the years ended December 31, 2021, 2020, and 2019, (iv) Consolidated Statements of Cash Flows for the years ended December 31, 2021, 2020, and 2019, and (v) the notes to Consolidated Financial Statements.
104	*	—	Cover Page Interactive Data File (formatted as Inline iXBRL and included in Exhibit 101).

____________________________

*    Filed herewith.

**    In accordance with Item 601(a)(5) of Regulation S-K, the exhibits and schedules to Exhibit 2.1 are not filed herewith. The agreement identifies such exhibits and schedules, including the subject 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 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 16, 2022	By:	/s/ BARRY E. DAVIS
		Barry E. Davis
		Chairman 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.

Signature	Title	Date
/s/ BARRY E. DAVIS	Chairman, Chief Executive Officer, and Director (Principal Executive Officer)	February 16, 2022
Barry E. Davis
/s/ DEBORAH G. ADAMS	Director	February 16, 2022
Deborah G. Adams
/s/ WILLIAM J. BRILLIANT	Director	February 16, 2022
William J. Brilliant
/s/ TIFFANY THOM CEPAK	Director	February 16, 2022
Tiffany Thom Cepak
/s/ LELDON E. ECHOLS	Director	February 16, 2022
Leldon E. Echols
/s/ THOMAS W. HORTON	Director	February 16, 2022
Thomas W. Horton
/s/ JAMES K. LEE	Director	February 16, 2022
James K. Lee
/s/ SCOTT E. TELESZ	Director	February 16, 2022
Scott E. Telesz
/s/ KYLE D. VANN	Director	February 16, 2022
Kyle D. Vann
/s/ PABLO G. MERCADO	Executive Vice President and Chief Financial Officer (Principal Financial Officer)	February 16, 2022
Pablo G. Mercado
/s/ J. PHILIPP ROSSBACH	Vice President and Chief Accounting Officer (Principal Accounting Officer)	February 16, 2022
J. Philipp Rossbach

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EX-4.14

Exhibit 4.14

ENLINK MIDSTREAM, LLC

DESCRIPTION OF SECURITIES

As of December 31, 2021, EnLink Midstream LLC (“we” or “ENLC”) had two classes of securities registered under Section 12 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”): (i) common units representing non-managing membership interests in ENLC (the “common units”) and (ii) 5.375% senior unsecured notes due 2029 (the “notes”).

DESCRIPTION OF COMMON UNITS

General

Our common units represent non-managing membership interests in ENLC. Our unitholders are entitled to participate in cash distributions and exercise the rights and privileges available to non-managing members under our Second Amended and Restated Operating Agreement, dated as of January 25, 2019 (the “operating agreement”). The following summary of our common units, our certificate of formation, and our operating agreement does not purport to be complete and is qualified in its entirety by reference to the provisions of applicable law and to the full text of our certificate of formation and our operating agreement, which are filed as Exhibits 3.1 and 3.3, respectively, to ENLC’s Annual Report on Form 10-K for the fiscal year ended December 31, 2021. Our common units are traded on the NYSE under the symbol “ENLC.”

Transfer Agent and Registrar

Duties

American Stock Transfer & Trust Company, LLC serves as registrar and transfer agent for our common units. We pay all fees charged by the transfer agent for transfers of our common units except the following, which must be paid by our unitholders:

•surety bond premiums to replace lost or stolen certificates, taxes, and other governmental charges;

•special charges for services requested by a unitholder; and

•other similar fees or charges.

There will be no charge to our unitholders for disbursements of cash distributions by us. We will indemnify the transfer agent, its agents, and each of their stockholders, directors, officers, and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.

Resignation or Removal

The transfer agent may resign by providing us notice. We may also remove the transfer agent. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If no successor is appointed, our managing member may act as the transfer agent and registrar until a successor is appointed.

Transfer of Our Common Units

By transfer of our common units in accordance with our operating agreement, each transferee of our common units will be admitted as a non-managing member with respect to our common units transferred when such transfer is reflected in our books and records and such transferee becomes the record holder of our common units transferred. Each transferee:

•represents that the transferee has the capacity, power, and authority to become bound by our operating agreement;

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•automatically becomes bound by the terms of our operating agreement; and

•gives the consents, acknowledgements, and waivers contained in our operating agreement, such as the approval of all transactions and agreements entered into in connection with our formation.

Our board of directors will cause any transfers to be recorded on our books and records from time to time as necessary to ensure their accuracy.

We may, at our discretion, treat the nominee holder of any of our common units as the absolute owner. In that case, the beneficial holder’s rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

Our common units are securities and any transfers are subject to the laws governing transfer of securities. In addition to other rights acquired upon transfer, the transferor gives the transferee the right to become a non-managing member for the transferred common units.

Until any common unit has been transferred on our books, we and the transfer agent may treat the record holder of the common unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

DESCRIPTION OF OUR OPERATING AGREEMENT

The following is a summary of the material provisions of our operating agreement.

Organization and Duration

We were organized on October 16, 2013 and will have a perpetual existence unless terminated pursuant to the terms of our operating agreement.

Purpose

Our purpose, as set forth in our operating agreement is limited to any business activity that is approved by our managing member, in its sole discretion, and that lawfully may be conducted by a limited liability company organized under Delaware law. Although our managing member has the ability to cause us and our subsidiaries to engage in activities other than the business of owning, operating, developing, and acquiring crude oil and natural gas gathering and processing assets and the owning of equity securities in EnLink Midstream Partners, LP (“ENLK”), our managing member may decline to do so in its sole discretion. Our managing member is generally authorized to perform all acts it determines to be necessary or appropriate to carry out the purposes of, and to conduct, our business.

Capital Contributions

Unitholders are not obligated to make additional capital contributions, except as described below under “—Limited Liability.”

Voting Rights

The following is a summary of the unitholder vote required for approval of the matters specified below. Matters that require the approval of a “unit majority” require the approval of a majority of the common units and our Class C common units representing limited liability company interests in us (the “Class C Common Units” and, together with our common units, the “ENLC Units”), voting together as a single class. 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 Cumulative Convertible Preferred Unit representing a limited partner interest in ENLK (an “ENLK Series B Unit”) is then exchangeable (which is the product of the number of ENLK Series B Units being exchanged multiplied by 1.15 (subject to certain adjustments)). In addition, the holders of Class C Common Units are entitled to vote as a separate class on any

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matter that (i) adversely affects the rights, preferences, and privileges of the Class C Common Units or the ENLK Series B Units, including certain minority protections with respect to substantially the same matters for which the holders of ENLK Series B Units have approval rights under the limited partnership agreement of ENLK, or (ii) amends or modifies any of the terms of the Class C Common Units or ENLK Series B Units. The approval of a majority of the Class C Common Units is required to approve any matter for which the holders of Class C Common Units are entitled to vote as a separate class.

In voting their common units, affiliates of our managing member will have no duty or obligation whatsoever to us or our members, including any duty to act in our best interest or the best interests of our members.

Matter	Vote Requirement
Issuance of additional units	No approval right.
Amendment of the operating agreement	Certain amendments may be made by our managing member without the approval of the unitholders. Other amendments generally require the approval of a unit majority. See “—Amendment of the Operating Agreement.”
Merger of or the sale of all or substantially all of our assets	Unit majority in certain circumstances. See “—Merger, Consolidation, Conversion, Sale, or Other Disposition of Assets.”
Dissolution of EnLink Midstream	Unit majority. See “—Dissolution.”
Continuation of our business upon dissolution	Unit majority. See “—Dissolution.”
Withdrawal of our managing member	No approval right. See “—Withdrawal or Removal of Our Managing Member.”
Removal of our managing member	Not less than 662/3% of the outstanding ENLC Units, voting as a single class, including units held by our managing member and its affiliates. See “—Withdrawal or Removal of Our Managing Member.”
Transfer of ownership interests in our managing member	No approval right. See “—Transfer of Ownership Interests in Our Managing Member.”
Transfer of the interest of our managing member	No approval right. See “—Transfer of Managing Member Interest.”

If any person or group other than our managing member and its affiliates acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units from our managing member or its affiliates (other than us) and any transferees of that person or group approved by our managing member or to any person or group who acquires the units with the written approval of our managing member, including the holders of the Class C Common Units and the ENLK Series B Units.

Applicable Law; Forum, Venue, and Jurisdiction

Our operating agreement is governed by Delaware law. Our operating agreement requires that 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 our members, or the rights or powers of, or restrictions on, us or our members);

•brought in a derivative manner on our behalf;

•asserting a claim of breach of a fiduciary duty or other duty owed by any of our or our managing member’s directors, officers, or other employees, or owed by our managing member, to us or our members;

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

•asserting a claim governed by the internal affairs doctrine;

shall 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),

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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 acquiring our common units, holders of our common units irrevocably consent 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 with subject matter jurisdiction) in connection with any such claims, suits, actions, or proceedings.

Limited Liability

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 shall be liable to the limited liability company for the amount of the distribution for three years. Under the DLLCA, an assignee who becomes a substituted unitholder of a company is liable for the obligations of his assignor to make contributions to the company, except the assignee is not obligated for liabilities unknown to him at the time he became a unitholder and that could not be ascertained from the limited liability company agreement.

Issuance of Additional Interests

Our operating agreement authorizes us to issue an unlimited number of additional membership interests for the consideration and on the terms and conditions determined by our managing member without the approval of our unitholders, except that our operating agreement restricts our ability to issue any membership interests senior to or on parity with the ENLK Series B 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 Class C Common Units, voting separately as a class.

It is possible that we will fund acquisitions through the issuance of additional common units or other membership interests. Holders of any additional common units issued by us will be entitled to share equally with the then-existing holders of our common units in distributions. In addition, the issuance of additional common units or other membership interests may dilute the value of the interests of the then-existing holders of our common units in our net assets.

In accordance with Delaware law and the provisions of our operating agreement, we may also issue additional membership interests that, as determined by our managing member, may have rights to distributions or special voting rights to which our common units are not entitled. In addition, except as described above with respect to the ENLK Series B Units, our operating agreement does not prohibit our subsidiaries from issuing equity interests, which may effectively rank senior to our common units.

Class C Common Units

The holders of Class C Common Units are not entitled to distributions thereon of any kind. For each additional ENLK Series B Unit issued by ENLK pursuant to limited partnership agreement of ENLK, we will issue an additional Class C Common Unit to the applicable holder of ENLK Series B Units pursuant to our operating agreement, so that the number of Class C Common Units issued and outstanding will always equal the number of ENLK Series B Units issued and outstanding. In addition, upon any exchange of ENLK Series B Units for our common units, a number of Class C Common Units equal to the number of ENLK Series B Units subject to such exchange will be cancelled.

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The voting rights of the Class C Common Units are described under “—Voting Rights” above.

Amendment of the Operating Agreement

Amendments to our operating agreement may be proposed only by our managing member. However, to the fullest extent permitted by law, our managing member will have no duty or obligation to propose or approve any amendment and may decline to do so free of any duty or obligation whatsoever to us or our members, including any duty to act in our best interest or in the best interest of our members. In order to adopt a proposed amendment, other than the amendments discussed below, our managing member is required to seek written approval of the holders of the number of common units required to approve the amendment or to call a meeting of the members to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a unitholder majority.

Prohibited Amendments. No amendment may be made that would:

•enlarge the obligations of any non-managing member without its consent, unless approved by at least a majority of the type or class of non-managing membership interests so affected; or

•enlarge the obligations of, restrict, change, or modify in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable, or otherwise payable to our managing member or any of its affiliates without the consent of our managing member, which consent may be given or withheld at its option.

The provision of our operating agreement preventing the amendments having the effects described in the clauses above can be amended upon the approval of the holders of at least 90% of the outstanding ENLC Units, voting together as a single class (including ENLC Units owned by our managing member and its affiliates).

Without Unitholder Approval. Our managing member may generally make amendments to our operating agreement without the approval of any member to reflect:

•a change in our name, the location of our principal place of business, our registered agent, or our registered office;

•the admission, substitution, withdrawal, or removal of members in accordance with our operating agreement;

•a change that our managing member determines to be necessary or appropriate to qualify or continue our qualification as a limited liability company or other entity in which the members have limited liability under the laws of any state;

•an amendment that is necessary, in the opinion of our legal counsel, to prevent us or our managing member, or its directors, officers, agents, or trustees from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisers Act of 1940, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974 (“ERISA”), whether or not substantially similar to plan asset regulations currently applied or proposed;

•an amendment that our managing member determines to be necessary or appropriate in connection with the creation, authorization, or issuance of additional membership interests or derivative instruments related to, convertible into, or exchangeable for additional membership interests;

•any amendment expressly permitted in our operating agreement to be made by our managing member acting alone;

•an amendment effected, necessitated, or contemplated by a merger agreement that has been approved under the terms of our operating agreement;

•any amendment that our managing member determines to be necessary or appropriate to reflect and account for the formation by us of, or our investment in, any corporation, partnership, or other entity, in connection with conduct otherwise permitted by our operating agreement;

•a change in our fiscal year or taxable period and related changes;

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•conversions into, mergers with, or conveyances to another limited liability entity that is newly formed and has no assets, liabilities, or operations at the time of the conversion, merger, or conveyance other than those it receives by way of the conversion, merger, or conveyance; or

•any other amendments substantially similar to any of the matters described in the clauses above or in the clauses that immediately follow.

In addition, our managing member may make amendments to our operating agreement, without the approval of any member, if our managing member determines that those amendments:

•do not adversely affect the non-managing members, including any particular class of non-managing members, in any material respect;

•are necessary or appropriate to satisfy any requirements, conditions, or guidelines contained in any opinion, directive, order, ruling, or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;

•are necessary or appropriate to facilitate the trading of membership interests or to comply with any rule, regulation, guideline, or requirement of any securities exchange on which the membership interests are or will be listed or admitted to trading;

•are necessary or appropriate in connection with any action taken by our managing member relating to splits or combinations of units under the provisions of our operating agreement; or

•are required to effect the intent expressed in this prospectus or the intent of the provisions of our operating agreement or are otherwise contemplated by our operating agreement.

With Unitholder Approval. In addition to the above restrictions:

•any amendment that our managing member determines adversely affects, in any material respect, one or more particular classes of members will require the approval of at least a majority of the class or classes so affected, but no vote will be required by any class or classes of members that our managing member determines are not adversely affected in any material respect;

•any amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding ENLC Units in relation to other classes of common units will require the approval of at least a majority of the type or class of ENLC Units so affected;

•any amendment that would reduce the voting percentage required to take any action other than to remove our managing member or call a meeting of our unitholders is required to be approved by the affirmative vote of members whose aggregate outstanding ENLC Units constitute not less than the voting requirement sought to be reduced; and

•any amendment that would increase the percentage of ENLC Units required to remove our managing member or call a meeting of our unitholders must be approved by the affirmative vote of members whose aggregate outstanding units constitute not less than the percentage sought to be increased.

Opinion of Counsel. For amendments of the type not requiring approval of a unitholder majority, our managing member will not be required to obtain an opinion of counsel that an amendment will not result in a loss of limited liability to the members in connection with any of the amendments. No other amendments to our operating agreement will become effective without the approval of holders of at least 90% of the outstanding ENLC Units, voting as a single class, unless we first obtain an opinion of counsel to the effect that the amendment will not affect the limited liability of any of its members under applicable law.

Merger, Consolidation, Conversion, Sale, or Other Disposition of Assets

A merger, consolidation, or conversion of ENLC requires the prior consent of our managing member. However, our managing member will have no duty or obligation to consent to any merger, consolidation, or conversion and may decline to do so in its sole discretion.

In addition, our operating agreement generally prohibits our managing member from causing us to sell, exchange, or otherwise dispose of all or substantially all of (i) our assets and the assets of our subsidiaries, taken as a whole, or

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(ii) for so long as our Class C Common Units remain outstanding, the assets of ENLK and its subsidiaries, taken as a whole, in a single transaction or a series of related transactions, without the prior approval of the holders of a majority of the ENLC Units. Our managing member may, however, mortgage, pledge, hypothecate, or grant a security interest in all or substantially all of our assets and the assets of our subsidiaries or the assets of ENLK and its subsidiaries, taken as a whole, without such approval. Our managing member may also sell all or substantially all of our assets and our subsidiaries’ assets or the assets of ENLK and its subsidiaries, taken as a whole, under a foreclosure or other realization upon those encumbrances without such approval. Finally, our managing member may consummate any merger without the prior approval of our members if (i) we are the surviving entity in the transaction, (ii) our managing member has received an opinion of counsel regarding limited liability matters, (iii) the transaction would not result in an amendment to our operating agreement (other than an amendment that our managing member could adopt without the consent of our unitholders), (iv) each of our common units would be an identical unit of ours following the transaction, and (v) the membership securities to be issued in the transaction do not exceed 20% of the outstanding membership interests immediately prior to the transaction.

If the conditions specified in our operating agreement are satisfied, our managing member may convert our company or any of our subsidiaries into a new limited liability entity or merge us or any of our subsidiaries into, or convey all of our assets to, a newly formed entity that has no assets, liabilities, or operations, if (i) the sole purpose of that conversion, merger, or conveyance is to effect a mere change in our legal form into another limited liability entity, (ii) we have received an opinion of counsel regarding limited liability matters, and (iii) our managing member determines that the governing instruments of the new entity provide the non-managing members and our managing member with substantially the same rights and obligations as contained in our operating agreement. Holders of ENLC Units will not be entitled to dissenters’ rights of appraisal under our operating agreement or applicable Delaware law in the event of a conversion, merger, or consolidation, a sale of substantially all of our assets, or any other similar transaction or event.

Dissolution

We will continue as a limited liability company until dissolved under the terms of our operating agreement. We will dissolve upon:

•the election by our managing member to dissolve our business, if approved by a unit majority;

•there being no members other than our managing member, unless we are continued without dissolution in accordance with the DLLCA;

•the entry of a decree of judicial dissolution pursuant to the provisions of the DLLCA; or

•the withdrawal or removal of our managing member or any other event that results in its ceasing to be our managing member other than by reason of a transfer of its managing member interest in accordance with our operating agreement or its withdrawal or removal following the approval and admission of a successor.

Upon a dissolution under the last clause above, the holders of a unit majority may also elect, within specific time limitations, to continue our business on the same terms and conditions described in our operating agreement by appointing as a successor managing member an entity approved by a unit majority, subject to the receipt by us of an opinion of counsel to the effect that the action would not result in the loss of limited liability under Delaware law of any member.

Liquidation and Distribution of Proceeds

If we dissolve in accordance with our operating agreement, unless our business is continued, the liquidator authorized to wind up our affairs will, acting with all of the powers of our managing member that are necessary or appropriate, liquidate our assets. The liquidator will first apply the proceeds of liquidation to the payment of our creditors and, thereafter, holders of our common units would be entitled to share ratably in the distribution of any remaining proceeds.

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Withdrawal or Removal of Our Managing Member

Our managing member may withdraw as managing member without first obtaining approval of our unitholders by giving 90 days’ written notice, and that withdrawal will not constitute a violation of our operating agreement. In addition, our operating agreement permits our managing member, in some instances, to sell or otherwise transfer all of its managing member interest in us without the approval of the unitholders.

Upon withdrawal of our managing member under any circumstances, other than as a result of a transfer by our managing member of all or a part of its managing member interest in us, the holders of a unit majority may select a successor to that withdrawing managing member. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability matters cannot be obtained, we will be dissolved, wound up, and liquidated, unless within a specified period after that withdrawal, the holders of a unit majority agree in writing to continue our business and to appoint a successor managing member. See “—Dissolution.”

Our managing member may not be removed unless (i) that removal is approved by the vote of the holders of not less than 662/3% of the outstanding ENLC Units, including ENLC Units held by our managing member and its affiliates, and (ii) we have received an opinion of counsel regarding limited liability matters. Any removal of our managing member is also subject to the approval of a successor managing member by the vote of a unit majority, including ENLC Units held by our managing member and its affiliates. The ownership of more than 331/3% of the voting power of the ENLC Units by our managing member and its affiliates gives them the ability to prevent their removal as our managing member.

In the event of the removal of our managing member under circumstances where cause exists or withdrawal of our managing member where that withdrawal violates our operating agreement, a successor managing member will have the option to purchase the managing member interest of the departing managing member and its affiliates for a cash payment equal to the fair market value of those interests. Under all other circumstances where the managing member withdraws or is removed by the members, the departing managing member will have the option to require the successor managing member to purchase the managing member interest of the departing managing member and its affiliates for fair market value. In each case, this fair market value will be determined by agreement between the departing managing member and the successor managing member. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing managing member and the successor managing member will determine the fair market value. Or, if the departing managing member and the successor managing member cannot agree upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.

If the option described above is not exercised by either the departing managing member or the successor managing member, the departing managing member’s managing member interest will automatically convert into common units equal to the fair market value of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.

In addition, we will be required to reimburse the departing managing member for all amounts due the departing managing member, including, without limitation, all employee-related liabilities, including severance liabilities, incurred as a result of the termination of any employees employed for our benefit by the departing managing member or its affiliates.

Transfer of Managing Member Interest

At any time, our managing member may transfer all or any part of its managing member interest in us to another person without the approval of any other member. As a condition of this transfer, the transferee must, among other things, assume the rights and duties of our managing member, agree to be bound by the provisions of our operating agreement, and furnish an opinion of counsel regarding limited liability matters.

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Transfer of Ownership Interests in Our Managing Member

At any time, the owner of our managing member may sell or transfer all or part of its ownership interests in our managing member to an affiliate or third party without the approval of our unitholders.

Change of Management Provisions

Our operating agreement contains specific provisions that are intended to discourage a person or group from attempting to remove our managing member or from otherwise changing our management. If any person or group, other than our managing member and its affiliates, acquires beneficial ownership of 20% or more of any class of ENLC Units, that person or group loses voting rights on all of its ENLC Units. This loss of voting rights does not apply to any person or group that acquires the ENLC Units from our managing member or its affiliates and any transferees of that person or group approved by our managing member or to any person or group who acquires the common units with the prior approval of our board of directors.

Call Right

If at any time our managing member and its affiliates own more than 90% of the then-issued and outstanding membership interests of any class, our managing member will have the right, which it may assign in whole or in part to any of its affiliates or to our managing member, to acquire all, but not less than all, of the membership interests of the class held by unaffiliated persons, as of a record date to be selected by our managing member, on at least 10, but not more than 60, days’ notice. The purchase price in the event of this purchase is the greater of:

•the highest price paid by our managing member or any of its affiliates for any membership interests of the class purchased within the 90 days preceding the date on which our managing member first mails notice of its election to purchase those membership interests; and

•the average of the daily closing prices of the membership interests of such class over the 20 trading days preceding the date that is three days before the date the notice is mailed.

As a result of our managing member’s right to purchase outstanding membership interests, a holder of membership interests may have his membership interests purchased at an undesirable time or at a price that may be lower than market prices at various times prior to such purchase or lower than a unitholder may anticipate the market price to be in the future. The tax consequences to a holder of ENLC Units of the exercise of this call right are the same as a sale by that unitholder of its ENLC Units in the market.

Meetings; Voting

Except as described below regarding a person or group owning 20% or more of any class of ENLC Units, record holders of ENLC Units on the record date will be entitled to notice of, and to vote at, meetings of our members and to act upon matters for which approvals may be solicited.

Any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or, if authorized by the managing member, without a meeting if consents in writing describing the action so taken are signed by holders of the number of ENLC Units necessary to authorize or take that action at a meeting. Meetings of the unitholders may be called by our managing member or by unitholders owning at least 20% of the outstanding units of the class for which a meeting is proposed. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting has been called, represented in person or by proxy, will constitute a quorum, unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage.

Each record holder of an ENLC Unit will have a vote according to such holder’s percentage interest in us, although additional membership interests having special voting rights could be issued. See “—Issuance of Additional Interests.” However, if at any time any person or group, other than our managing member and its affiliates, or a direct or subsequently approved transferee of our managing member or its affiliates and purchasers specifically

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approved by our managing member, acquires, in the aggregate, beneficial ownership of 20% or more of any class of units, that person or group will lose voting rights on all of its ENLC Units, and the ENLC Units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum or for other similar purposes. Our common units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and his nominee provides otherwise.

Any notice, demand, request, report, or proxy material required or permitted to be given or made to record holders of ENLC Units under our operating agreement will be delivered to the record holder by us or by our transfer agent.

Status as Member

By transfer of our common units in accordance with our operating agreement, each transferee of our common units shall be admitted as a member with respect to our common units transferred when such transfer and admission are reflected in our books and records. Except as described under “—Limited Liability,” our common units will be fully paid, and unitholders will not be required to make additional contributions.

Indemnification

Section 18-108 of the DLLCA, as amended, empowers a Delaware limited liability company to indemnify and hold harmless any member or manager or other person from and against all claims and demands whatsoever. Our operating agreement provides that we will indemnify the following persons, to the fullest extent permitted by the law, from and against all losses, claims, damages, or similar events:

•our managing member;

•any departing managing member;

•any person who is or was an affiliate of our managing member or any departing managing member;

•any person who is or was one of our managers, managing members, general partners, directors, officers, employees, agents, fiduciaries or trustees, our subsidiaries, our managing member, any departing managing member, or any of their respective affiliates;

•any person who is or was serving as a manager, managing member, general partners, director, officer, employee, agent, fiduciary, or trustee of another person owing a fiduciary duty to us or our subsidiaries; and

•any person designated by our managing member;

unless there has been a final and non-appealable judgment by a court of competent jurisdiction that, in respect of the matter for which such persons are seeking indemnification, those persons acted in bad faith, or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that their conduct was unlawful.

Any indemnification under these provisions will only be out of our assets. Unless our managing member otherwise agrees, it will not be personally liable for, or have any obligation to contribute or lend funds or assets to us to enable us to effectuate, indemnification. We may purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under our operating agreement.

We have entered into indemnification agreements with each of the directors and executive officers of our managing member. Under the terms of these indemnification agreements, we agree to indemnify and hold each indemnitee harmless from and against any and all losses, claims, damages, liabilities, judgments, fines, taxes (including ERISA excise taxes), penalties (whether civil, criminal, or other), interest, assessments, amounts paid or payable in settlements, or other amounts and any and all “expenses” (as defined in the indemnification agreements) arising from any and all threatened, pending, or completed claims, demands, actions, suits, proceedings, or alternative dispute mechanisms, whether civil, criminal, administrative, arbitrative, investigative, or otherwise, whether made pursuant to federal, state, or local law, whether formal or informal, and including appeals, in each case, which the

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indemnitee may be involved, or is threatened to be involved, as a party, a witness, or otherwise, including 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 or our managing member, or is or was serving at the request of us or our managing member, each as applicable, as a manager, managing member, general partner, director, officer, fiduciary, trustee, or agent of any other entity, organization, or person of any nature. 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 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.

Reimbursement of Expenses

Our operating agreement requires us to reimburse our managing member on a monthly basis for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our managing member in connection with operating our business. Our operating agreement does not set a limit on the amount of expenses for which our managing member and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation, and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our managing member by its affiliates. Our managing member is entitled to determine the expenses that are allocable to us.

Books and Reports

Our managing member is required to keep appropriate books of our business at its principal offices. These books will be maintained for both tax and financial reporting purposes on an accrual basis in accordance with generally acceptable accounting principles (GAAP). For tax and fiscal reporting purposes, our fiscal year is the calendar year.

We will furnish or make available to record holders of our common units, within 105 days after the close of each fiscal year, an annual report containing audited consolidated financial statements and a report on those consolidated financial statements by its independent public accountants. Except for its fourth quarter, we will also furnish or make available summary financial information within 50 days after the close of each quarter. We will be deemed to have made any such report available if we file such report with the U.S. Securities and Exchange Commission (the “SEC”) via its Electronic Data Gathering, Analysis and Retrieval system or make the report available on a publicly available website which we maintain.

Right to Inspect Books and Records

Our operating agreement provides that a member can, for a purpose reasonably related to such member’s interest as a member, upon reasonable written demand stating the purpose of such demand and at such member’s own expense, have furnished to such member:

•true and full information regarding the status of our business and financial condition (provided that this obligation shall be satisfied to the extent the member is furnished the most recent annual report and any subsequent quarterly or periodic reports required to be filed (or which would be required to be filed) with the SEC by us pursuant to Section 13 of the Exchange Act); and

•a current list of the name and last known address of each record holder; and copies of our operating agreement, our certificate of formation, related amendments, and powers of attorney under which they have been executed.

Under our operating agreement, however, each of our members and other persons who acquire our membership interests, do not have rights to receive information from us or any of the persons we indemnify as described above under “—Indemnification” for the purpose of determining whether to pursue litigation or assist in pending litigation against us or those indemnified persons relating to its affairs, except pursuant to the applicable rules of discovery relating to the litigation commenced by the person seeking information.

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Our managing member may, and intends to, keep confidential from our members trade secrets or other information the disclosure of which our managing member determines is not in our best interests, could damage us or that we are required by law or by agreements with third parties to keep confidential. Our operating agreement limits the right to information that a member would otherwise have under Delaware law.

Conflicts of Interest

Conflicts of interest exist and may arise in the future as a result of the relationships between our managing member or its affiliates, on the one hand, and us, our members, or our subsidiaries, on the other hand. Our operating agreement specifically defines the remedies available to our unitholders for actions taken that, without these defined liability standards, might constitute breaches of fiduciary duty under applicable Delaware law. The DLLCA provides that Delaware limited liability companies may, in their operating agreements, expand, restrict, or eliminate the fiduciary duties otherwise owed by the manager to the members and the company, but such agreements may not eliminate the implied contractual covenant of good faith and fair dealing.

Whenever a conflict arises between our managing member or its affiliates, on the one hand, and us, our members, or our subsidiaries, on the other hand, the resolution or course of action in respect of such conflict of interest shall be permitted and conclusively deemed approved by us and all of our members and shall not constitute a breach of our operating agreement, of any agreement contemplated thereby, or of any duty, if the resolution or course of action in respect of such conflict of interest is:

•approved by the conflicts committee of our board of directors; or

•approved by a unit majority, excluding any such common units owned by our managing member and its affiliates.

Our managing member may, but is not required to, seek the approval of such resolutions or courses of action from the conflicts committee of our board of directors or from the holders of a majority of the outstanding common units as described above. Unless the resolution of a conflict is specifically provided for in our operating agreement, our board of directors or the conflicts committee of our board of directors may consider any factors they determine in good faith to consider when resolving a conflict. An independent third party is not required to evaluate the resolution. Under our operating agreement, a determination, other action, or failure to act by our managing member, our board of directors, or any committee thereof (including the conflicts committee) will be deemed to be in “good faith” if our managing member, our board of directors, or any committee thereof (including the conflicts committee) subjectively believed such determination, other action or failure to act was in, or not opposed to, our best interests. In any proceeding brought by or on behalf of us or any of our unitholders, the person bringing or prosecuting such proceeding will have the burden of proving that such determination, other action, or failure to act was not in good faith.

Elimination and Replacement of Fiduciary Duties

Duties owed to unitholders by our managing member are prescribed by law and in our operating agreement. The DLLCA provides that Delaware limited liability companies may, in their operating agreements, expand, restrict, or eliminate the fiduciary duties otherwise owed by our managing member to members and us.

Our operating agreement contains various provisions that eliminate and replace the fiduciary duties that might otherwise be owed by our managing member. These provisions have been negotiated to allow our managing member or its affiliates to engage in transactions with us that otherwise might be prohibited by state law fiduciary standards and to take into account the interests of other parties in addition to our interests when resolving conflicts of interest. Without these modifications, our managing member’s ability to make decisions involving conflicts of interest would be restricted. Replacing the fiduciary duty standards in this manner benefits our managing member by enabling it to take into consideration all parties involved in the proposed action. Replacing the fiduciary duty standards also strengthens the ability of our managing member to attract and retain experienced and capable directors. Replacing the fiduciary duty standards represents a detriment to our public unitholders because it restricts

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the remedies available to the public unitholders for actions that, without those limitations, might constitute breaches of fiduciary duty, as described below, and permits our managing member to take into account the interests of third parties in addition to our interests when resolving conflicts of interests.

The following is a summary of the fiduciary duties imposed on managers of a limited liability company by the DLLCA in the absence of operating agreement provisions to the contrary, the contractual duties of our managing member contained in our operating agreement that replace the fiduciary duties that would otherwise be imposed by Delaware laws on our managing member and the rights and remedies of its unitholders with respect to these contractual duties:

State law fiduciary standards	Fiduciary duties are generally considered to include an obligation to act in good faith and with due care and loyalty. The duty of care, in the absence of a provision in an operating agreement providing otherwise, would generally require a managing member to act for the company in the same manner as a prudent person would act on his own behalf. The duty of loyalty, in the absence of a provision in an operating agreement providing otherwise, would generally require that any action taken or transaction engaged in be entirely fair to the company.
Operating agreement modified standards	Our operating agreement contains provisions that waive or consent to conduct by our managing member and its affiliates that might otherwise raise issues as to compliance with fiduciary duties or applicable law. For example, our operating agreement provides that when our managing member is acting in its capacity as our managing member, as opposed to in its individual capacity, it must act in “good faith” and will not be subject to any other standard under applicable law (other than the implied contractual covenant of good faith and fair dealing). In addition, when our managing member is acting in its individual capacity, as opposed to in its capacity as our managing member, it may act without any fiduciary obligation to us or the unitholders whatsoever. These standards replace the obligations that our managing member would otherwise be held to. If our managing member does not obtain approval from the conflicts committee of the board of directors of our managing member or the holders of our common units, excluding any units owned by our managing member or its affiliates, and our board of directors approves the resolution or course of action taken with respect to the conflict of interest, then it will be presumed that, in making its decision, our board of directors, which may include board members affected by the conflict of interest, 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. These standards replace the obligations that our managing member would otherwise be held to.
Rights and remedies of unitholders	The DLLCA generally provides that a member may institute legal action on behalf of the company to recover damages from a third party where a manager has refused to institute the action or where an effort to cause a manager to do so is not likely to succeed. These actions include actions against a manager for breach of its duties or of our operating agreement. In addition, the statutory or case law of some jurisdictions may permit a member to institute legal action on behalf of himself and all other similarly situated members to recover damages from a manager for violations of its fiduciary duties to the members.
Operating agreement modified standards	The DLLCA provides that, unless otherwise provided in an operating agreement, a member or other person shall not be liable to a limited liability company or to another member or to another person that is a party to or is otherwise bound by an operating agreement for breach of fiduciary duty for the member’s or other person’s good faith reliance on the provisions of the operating agreement. Under our operating agreement, to the extent that, at law or in equity an indemnitee has duties (including fiduciary duties) and liabilities relating thereto to us or to our members, our managing member, and any other indemnitee acting in connection with its business or affairs shall not be liable to us or to any member for its good faith reliance on the provisions of our operating agreement.

By acquiring our common units, each new holder of our common units automatically agrees to be bound by the provisions in our operating agreement, including the provisions discussed above. This is in accordance with the

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policy of the DLLCA favoring the principle of freedom of contract and the enforceability of operating agreements. The failure of a member to sign an operating agreement does not render the operating agreement unenforceable against that person.

Under our operating agreement, we must indemnify our managing member and its officers, directors, managers, and certain other specified persons, to the fullest extent permitted by law, against liabilities, costs, and expenses incurred by our managing member or these other persons. We must provide this indemnification unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that these persons acted in bad faith, or engaged in fraud or willful misconduct. We must also provide this indemnification for criminal proceedings unless our managing member or these other persons acted with knowledge that their conduct was unlawful. Thus, our managing member could be indemnified for its negligent acts if it meets the requirements set forth above. To the extent these provisions purport to include indemnification for liabilities arising under the Securities Act in the opinion of the SEC, such indemnification is contrary to public policy and, therefore, unenforceable. See “—Indemnification.”

CASH DISTRIBUTION POLICY

Our Cash Distribution Policy

We make cash distributions, if any, to holders of our common units on a pro rata basis; provided, however, that, if ENLK fails to pay in full certain cash amounts with respect to quarterly distributions to the holder of the ENLK Series B Units when due, then from and after the first date of such failure and continuing until such failure is cured by payment in full in cash of all such cash arrearages, we are not permitted to, and will not, declare or make any distributions in respect of our common units and any other class of membership interests that, with respect to distributions, ranks junior to the ENLK Series B Units.

Unless restricted by the terms of the agreements governing our outstanding indebtedness, we intend to pay distributions to holders of our common units on a quarterly basis from our available cash 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

•maintaining cash reserves the board of directors of our managing member believes are prudent to maintain.

Our ability to pay distributions is limited by the DLLCA, 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 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.

DESCRIPTION OF NOTES

We are party to a base indenture, dated as of April 9, 2019, between us and Wells Fargo Bank, National Association, as trustee, pursuant to which we issued the notes, as supplemented by a supplemental indenture among us, ENLK, as guarantor, and Wells Fargo Bank, National Association, as trustee, setting forth the specific terms of the notes. In this description, when we refer to the “indenture,” we mean the base indenture as so amended and supplemented by the supplemental indenture. This description is a summary of the material provisions of the notes and the indenture. This description does not restate those agreements and instruments in their entirety. The following summary of the indenture and the notes does not purport to be complete and is qualified in its entirety by reference to the full text of the base indenture and the supplemental indenture, copies of which are filed as Exhibits 4.11 and 4.12 to ENLC’s Annual Report on Form 10-K for the fiscal year ended December 31, 2019.

You can find the definitions of various terms used in this description under “—Certain Definitions” below. In this description, the terms “ENLC,” “we,” “us,” and “our” refer only to EnLink Midstream, LLC and not to any of its Subsidiaries, and the term “ENLK” refers only to EnLink Midstream Partners, LP and not to any of its Subsidiaries.

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General

The notes:

•are general unsecured, senior obligations of ENLC, ranking equally with all other existing and future unsecured and unsubordinated indebtedness of ENLC;

•were issued in an aggregate principal amount of $500 million;

•will mature on June 1, 2029;

•were issued in denominations of $2,000 and integral multiples of $1,000 in excess thereof;

•bear interest at an annual rate of 5.375%; and

•are redeemable at any time at our option at the applicable redemption price described below under “—Optional Redemption.”

The notes constitute a series of debt securities under the indenture. The indenture does not limit the amount of debt securities we may issue under the indenture from time to time in one or more series. We may in the future issue additional debt securities under the indenture in addition to the notes as described below under “—Further Issuances.”

Interest

We pay interest on the notes in cash semi-annually in arrears on June 1 and December 1 of each year. We make interest payments on the notes to the persons in whose names the notes are registered at the close of business on May 15 and November 15, as applicable, before the next interest payment date.

Interest will be computed on the basis of a 360-day year consisting of twelve 30-day months. If any interest payment date falls on a day that is not a business day, the payment will be made on the next business day, and no interest will accrue on the amount of interest due on that interest payment date for the period from and after the interest payment date to the date of payment.

Paying Agent and Registrar

The trustee acts as paying agent and registrar for the notes. We may change the paying agent or registrar without prior notice to the holders of the notes, and we or any of our Subsidiaries may act as paying agent or registrar; provided, however, that we are required to maintain at all times an office or agency in The City of New York (which may be an office of the trustee or an affiliate of the trustee or the registrar or a co-registrar for the notes) where the notes may be presented for payment and where notes may be surrendered for registration of transfer or for exchange and where notices and demands to or upon us in respect of the notes and the indenture may be served. We may also from time to time designate one or more additional offices or agencies where the notes may be presented or surrendered for any or all such purposes and may from time to time rescind such designations.

Further Issuances

We may from time to time, without notice to or the consent of the holders of the notes, create and issue additional notes having the same terms as any of the series of notes, except for the issue date, public offering price, and in some cases, the first interest payment date. Additional notes issued in this manner will form a single series with the previously issued and outstanding notes of such series.

Optional Redemption

Prior to March 1, 2029 (three months prior to the maturity date of the notes) (the “Par Call Date”), the notes are redeemable, at our option, at any time in whole, or from time to time in part, at a price equal to the greater of:

•100% of the principal amount of the notes to be redeemed; or

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•the sum of the present values of the remaining scheduled payments of principal and interest on the notes to be redeemed that would be due if the notes matured on the Par Call Date (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 50 basis points;

plus, in either case, accrued and unpaid interest to, but excluding, the redemption date.

At any time on or after the Par Call Date, the notes will be redeemable in whole or in part, at our option, at a redemption price equal to 100% of the principal amount of the notes to be redeemed plus accrued and unpaid interest thereon to, but excluding, the redemption date.

For purposes of determining the redemption price, the following definitions are applicable:

“Comparable Treasury Issue”means the United States Treasury security selected by the Quotation Agent as having a maturity comparable to the remaining term of the notes to be redeemed (calculated as if the maturity date of the notes was the Par Call Date) that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of such notes (calculated as if the maturity date of the notes was the Par Call Date).

“Comparable Treasury Price”means, with respect to any redemption date for notes, (1) the average of four Reference Treasury Dealer Quotations for such redemption date after excluding the highest and lowest of all of the Reference Treasury Dealer Quotations or (2) if the Quotation Agent obtains fewer than four such Reference Treasury Dealer Quotations, the average of all such quotations.

“Quotation Agent”means the Reference Treasury Dealer appointed by us.

“Primary Treasury Dealer”means a U.S. government securities dealer in the United States.

“Reference Treasury Dealer”means each of (i) RBC Capital Markets, LLC, BMO Capital Markets Corp., and Wells Fargo Securities, LLC and their respective successors that are Primary Treasury Dealers and (ii) a Primary Treasury Dealer selected by SunTrust Robinson Humphrey, Inc. or it successor, provided that, if at any time any of the foregoing is not a Primary Treasury Dealer, ENLC will substitute therefor another Primary Treasury Dealer.

“Reference Treasury Dealer Quotation” means, with respect to each Reference Treasury Dealer and any redemption date, the average, as determined by the Quotation Agent, of the bid and asked prices for the Comparable Treasury Issue (expressed in each case as a percentage of its principal amount) quoted in writing to the Quotation Agent by such Reference Treasury Dealer at 5:00 p.m., New York City time, on the third business day preceding the redemption date.

“Treasury Rate” means, with respect to any redemption date, the rate per year equal to the semi-annual equivalent yield to maturity of the Comparable Treasury Issue, calculated using a price for the Comparable Treasury Issue (expressed as a percentage of its principal amount) equal to the Comparable Treasury Price for such redemption date. The Treasury Rate will be calculated on the third business day preceding any redemption date.

Redemption Procedures

If fewer than all of the notes are to be redeemed at any time, such notes will be selected for redemption not more than 60 days prior to the redemption date and such selection will be made by the trustee on a pro rata basis, by lot or by such other method as the trustee deems appropriate (or, in the case of notes represented by a note in global form, by such method as The Depository Trust Company (“DTC”) may require); provided, that no partial redemption of any note will occur if such redemption would reduce the principal amount of such note to less than $2,000. Notices of redemption with respect to the notes will be sent at least 15 but not more than 60 days before the redemption date to each holder of notes to be redeemed.

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If any note is to be redeemed in part only, the notice of redemption that relates to such note will state the portion of the principal amount thereof to be redeemed. A new note in principal amount equal to the unredeemed portion thereof will be issued in the name of the holder thereof upon cancellation of the original note. Notes called for redemption will become due on the date fixed for redemption. Unless we default in payment of the redemption price, on and after the redemption date, interest will cease to accrue on the notes or portions of the notes called for redemption.

Subsidiary Guarantees

The notes are guaranteed by our subsidiary, ENLK. None of our other Subsidiaries guaranteed the notes upon their issuance. However, if at any time following the issuance of the notes, any other Subsidiary of ENLC becomes a guarantor or co-obligor of the Credit Agreement, then ENLC will cause such Subsidiary to promptly execute and deliver to the trustee a supplemental indenture in a form satisfactory to the trustee pursuant to which such Subsidiary guarantees ENLC’s obligations with respect to the notes on the terms provided for in the indenture.

The guarantee of ENLK and any other Subsidiary Guarantor may be released under certain circumstances. If we exercise our legal or covenant defeasance option with respect to the notes as described below under “—Defeasance and Discharge,” then ENLK and any other Subsidiary Guarantor will be released. Further, if no default has occurred and is continuing under the indenture, and to the extent not otherwise prohibited by the indenture, any Subsidiary Guarantor will be unconditionally released and discharged from its guarantee:

•automatically upon any sale, exchange, or transfer, whether by way of merger or otherwise, to any Person that is not our affiliate, of all of the direct or indirect limited partnership interests or other equity interests in the Subsidiary Guarantor;

•automatically upon the merger of the Subsidiary Guarantor into us or any other Subsidiary Guarantor or the liquidation and dissolution of the Subsidiary Guarantor; or

•following delivery of a written notice by us to the trustee, upon the release of all guarantees or other obligations of the Subsidiary Guarantor with respect to the obligations of ENLC or any of its Subsidiaries under the Credit Agreement.

If at any time following any release of ENLK or any other Subsidiary Guarantor from its guarantee of the notes pursuant to the third bullet point in the preceding paragraph, the Subsidiary Guarantor again becomes a guarantor or co-obligor of the Credit Agreement, then ENLC will cause the Subsidiary Guarantor to again guarantee the notes in accordance with the indenture.

Ranking

The notes are unsecured, unless we are required to secure them pursuant to the limitations on liens covenant described below under “—Certain Covenants —Limitations on Liens.” The notes are also the unsubordinated obligations of ENLC and rank equally with all other existing and future unsubordinated indebtedness of ENLC. The guarantee of the notes by ENLK and any guarantee of the notes by any other Subsidiary Guarantor is an unsecured and unsubordinated obligation of ENLK or the applicable Subsidiary Guarantor and rank equally with all other existing and future unsubordinated indebtedness of ENLK (including its outstanding senior notes and its guarantee of the Credit Agreement) and the applicable Subsidiary Guarantor. The notes and each guarantee will effectively rank junior to any future indebtedness of ENLC or any Subsidiary Guarantor that is both secured and unsubordinated to the extent of the value of the assets securing such indebtedness, and the notes structurally rank junior to all indebtedness and other liabilities of ENLC’s existing and future Subsidiaries that are not Subsidiary Guarantors.

Open Market Purchases; No Mandatory Redemption or Sinking Fund

We may at any time and from time to time repurchase notes in the open market or otherwise, in each case without any restriction under the indenture. We are not required to make any mandatory redemption or sinking fund payments with respect to the notes.

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Certain Covenants

Except as set forth below, neither ENLC nor any of its Subsidiaries is restricted by the indenture from incurring any type of indebtedness or other obligation, from paying dividends or making distributions on its limited liability company or other equity interests or from purchasing or redeeming its limited liability company or other equity interests. The indenture does not require the maintenance of any financial ratios or specified levels of net worth or liquidity. In addition, the indenture does not contain any provisions that would require ENLC to repurchase or redeem or otherwise modify the terms of the notes upon a change in control or other events involving ENLC that could adversely affect the creditworthiness of ENLC.

Limitations on Liens. ENLC will not, nor will it permit any of its Principal Subsidiaries to, create, assume, incur or suffer to exist any mortgage, lien, security interest, pledge, charge or other encumbrance (“liens”) upon any Principal Property or upon any capital stock of any Principal Subsidiary, whether owned on the date of the supplemental indenture creating the notes or thereafter acquired, to secure any Indebtedness of ENLC or any other Person (other than the notes), without in any such case making effective provisions whereby all of the outstanding notes are secured equally and ratably with, or prior to, such Indebtedness so long as such Indebtedness is so secured.

Notwithstanding the foregoing, under the indenture, ENLC may, and may permit any of its Principal Subsidiaries to, create, assume, incur, or suffer to exist without securing the notes (a) any Permitted Lien, (b) any lien upon any Principal Property or capital stock of a Principal Subsidiary to secure Indebtedness of ENLC or any other Person, provided that the aggregate principal amount of all Indebtedness then outstanding secured by such lien and all similar liens under this clause (b), together with all Attributable Indebtedness from Sale-Leaseback Transactions (excluding Sale-Leaseback Transactions permitted by clauses (1) through (4), inclusive, of the first paragraph of the restriction on sale-leasebacks covenant described below), does not exceed 15% of Consolidated Net Tangible Assets or (c) any lien upon (i) any Principal Property that was not owned by ENLC or any of its Subsidiaries on the date of the supplemental indenture creating the notes or (ii) the capital stock of any Principal Subsidiary that owns no Principal Property that was owned by ENLC or any of its Subsidiaries on the date of the supplemental indenture creating the notes, in each case owned by a Subsidiary of ENLC (an “Excluded Subsidiary”) that (A) is not, and is not required to be, a Subsidiary Guarantor and (B) has not granted any liens on any of its property securing Indebtedness with recourse to ENLC or any Subsidiary of ENLC other than such Excluded Subsidiary or any other Excluded Subsidiary.

Restriction on Sale-Leasebacks. ENLC will not, and will not permit any Principal Subsidiary to, engage in the sale or transfer by ENLC or any of its Principal Subsidiaries of any Principal Property to a Person (other than ENLC or a Principal Subsidiary) and the taking back by ENLC or any Principal Subsidiary, as the case may be, of a lease of such Principal Property (a “Sale-Leaseback Transaction”), unless:

1.such Sale-Leaseback Transaction occurs within one year from the date of completion of the acquisition of the Principal Property subject thereto or the date of the completion of construction, development or substantial repair or improvement, or commencement of full operations on such Principal Property, whichever is later;

2.the Sale-Leaseback Transaction involves a lease for a period, including renewals, of not more than three years;

3.ENLC or such Principal Subsidiary would be entitled to incur Indebtedness secured by a lien on the Principal Property subject thereto in a principal amount equal to or exceeding the Attributable Indebtedness from such Sale-Leaseback Transaction without equally and ratably securing the notes; or

4.ENLC or such Principal Subsidiary, within a one-year period after such Sale-Leaseback Transaction, applies or causes to be applied an amount not less than the Attributable Indebtedness from such Sale-Leaseback Transaction to (a) the prepayment, repayment, redemption, reduction or retirement of any Indebtedness of ENLC or any of its Subsidiaries that is not subordinated to the notes or any guarantee, or (b) the expenditure or expenditures for Principal Property used or to be used in the ordinary course of business of ENLC or its Subsidiaries.

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Notwithstanding the foregoing, ENLC may, and may permit any Principal Subsidiary to, effect any Sale-Leaseback Transaction that is not excepted by clauses (1) through (4), inclusive, of the preceding paragraph provided that the Attributable Indebtedness from such Sale-Leaseback Transaction, together with the aggregate principal amount of outstanding Indebtedness (other than the notes) secured by liens permitted by clause (b) of the second paragraph of the restriction on liens covenant described above, does not exceed 15% of Consolidated Net Tangible Assets.

Merger, Consolidation or Sale of Assets. ENLC shall not consolidate with or merge into any Person or sell, lease, convey, transfer, or otherwise dispose of all or substantially all of its assets to any Person unless:

1.the Person formed by or resulting from any such consolidation or merger or to which such assets have been transferred (the “successor”) is ENLC or expressly assumes by supplemental indenture all of ENLC’s obligations and liabilities under the indenture and the notes;

2.the successor is organized under the laws of the United States, any state, or the District of Columbia;

3.immediately after giving effect to the transaction no Default or Event of Default has occurred and is continuing;

4.if ENLC is not the successor, then each Subsidiary Guarantor confirms to the Trustee that the guarantee of such Subsidiary Guarantor continues to apply; and

5.ENLC has delivered to the trustee an officers’ certificate and an opinion of counsel, each stating that such consolidation, merger, or transfer complies with the indenture.

The successor will be substituted for ENLC in the indenture with the same effect as if it had been an original party to the indenture. Thereafter, the successor may exercise the rights and powers of ENLC under the indenture. If ENLC conveys or transfers all or substantially all of its assets, it will be released from all liabilities and obligations under the indenture and under the notes except that no such release will occur in the case of a lease of all or substantially all of its assets.

Satisfaction and Discharge

The indenture will be discharged and will cease to be of further effect as to the notes issued thereunder, when:

(a)    either:

(1)    all outstanding notes that have been authenticated (except lost, stolen, or destroyed notes that have been replaced or paid and notes for whose payment money has theretofore been deposited in trust and thereafter repaid to us) have been delivered to the Trustee for cancellation; or

(2)    all outstanding notes that have not been delivered to the Trustee for cancellation have become due and payable or will become due and payable at their stated maturity within one year or are to be called for redemption within one year under arrangements satisfactory to the Trustee and in any case we have irrevocably deposited with the Trustee as trust funds cash, certain U.S. government obligations or a combination thereof, in such amounts as will be sufficient, to pay the entire indebtedness of the notes not delivered to the Trustee for cancellation, for principal, premium, if any, and accrued interest to the stated maturity or redemption date;

(b)    we have paid or caused to be paid all other sums payable by us under the indenture with respect to the notes; and

(c)    we have delivered to the trustee an officers’ certificate as to the sufficiency of the trust funds, without reinvestment, to pay the entire indebtedness of the notes at maturity.

Notwithstanding such satisfaction and discharge, our obligations to compensate and indemnify the trustee, to pay additional amounts, if any, in respect of the notes in certain circumstances, and to transfer or exchange the notes pursuant to the terms thereof and our obligations and the obligations of the Trustee to hold funds in trust and to apply such funds pursuant to the terms of the indenture, with respect to issuing temporary notes, with respect to the registration, transfer and exchange of notes, with respect to the replacement of mutilated, destroyed, lost, or stolen

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notes and with respect to the maintenance of an office or agency for payment, shall in each case survive such satisfaction and discharge.

Defeasance

At any time, we may terminate, with respect to the notes, all our obligations under the notes and the indenture, which we call a “legal defeasance.” If we decide to make a legal defeasance, however, we may not terminate our obligations specified in the indenture, including those:

•relating to the defeasance trust;

•to register the transfer or exchange of the notes;

•to replace mutilated, destroyed, lost, or stolen notes; or

•to maintain a registrar and paying agent in respect of the notes.

At any time we may also effect a “covenant defeasance,” which means we have elected to terminate our obligations under the additional covenants established pursuant to the terms of the notes, which covenants are described in the prospectus supplement applicable to the notes, and any Event of Default resulting from a failure to observe such covenants.

The legal defeasance option may be exercised notwithstanding a prior exercise of the covenant defeasance option. If the legal defeasance option is exercised, payment of the affected series of debt securities may not be accelerated because of an Event of Default with respect to that series. If the covenant defeasance option is exercised, payment of the affected series of debt securities may not be accelerated because of:

•failure by us or by a guarantor to comply for 60 days after notice with the other agreements contained in the indenture, any supplement to the indenture with respect to the notes or any board resolution authorizing the issuance of the notes;

•certain events of bankruptcy, insolvency, or reorganization of us or, if the series of debt securities is guaranteed by the guarantors, of the guarantors; or

•(i) any of the guarantees by the guarantors ceases to be in full force and effect, except as otherwise provided in the indenture; (ii) any of the guarantees by the guarantors is declared null and void in a judicial proceeding; or (iii) any guarantor denies or disaffirms its obligations under the indenture or its guarantee.

•or an Event of Default that is added specifically for such series and described in a prospectus supplement.

In order to exercise either defeasance option, we must:

•irrevocably deposit in trust with the trustee money or certain U.S. government obligations for the payment of principal, premium, if any, and interest on the series of debt securities to redemption or stated maturity, as the case may be;

•comply with certain other conditions, including that no bankruptcy or default with respect to us has occurred and is continuing 91 days after the deposit in trust; and

•deliver to the trustee an opinion of counsel to the effect that holders of the defeased series of debt securities will not recognize income, gain, or loss for Federal income tax purposes as a result of such defeasance and will be subject to Federal income tax on the same amounts and in the same manner and at the same times as would have been the case if such defeasance had not occurred. In the case of legal defeasance only, such opinion of counsel must be based on a ruling of the Internal Revenue Service or a change in applicable Federal income tax law.

Concerning the Trustee

The indenture contains certain limitations on the right of the trustee, should it become our creditor, to obtain payment of claims in certain cases, or to realize for its own account on certain property received in respect of any such claim as security or otherwise. The trustee is permitted to engage in certain other transactions. However, if it acquires any conflicting interest within the meaning of the Trust Indenture Act after a default has occurred and is

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continuing, it must eliminate the conflict within 90 days, apply to the SEC for permission to continue as trustee or resign.

If an Event of Default occurs and is not cured or waived, the trustee is required to exercise such of the rights and powers vested in it by the indenture and use the same degree of care and skill in their exercise as a prudent person would exercise or use under the circumstances in the conduct of his own affairs. Subject to such provisions, the trustee will not be under any obligation to exercise any of its rights or powers under the indenture at the request of any of the holders of notes unless they have offered to the trustee security or indemnity satisfactory to it against the costs, expenses, and liabilities it may incur.

Wells Fargo Bank, National Association is the trustee under the indenture and the registrar and paying agent with regard to the notes. The trustee and its affiliates maintain commercial banking and other relationships with ENLC and its Subsidiaries.

Governing Law

The indenture and the notes are governed by, and construed in accordance with, the laws of the State of New York.

Book-Entry System

We have obtained the information in this section concerning The Depository Trust Company (“DTC”) and its book-entry systems and procedures from DTC, and we take no responsibility for the accuracy of this information. In addition, the description in this section reflects our understanding of the rules and procedures of DTC as they are currently in effect. DTC could change its rules and procedures at any time.

The notes are represented by one or more fully registered global notes. Each such global note is deposited with, or on behalf of, DTC or any successor thereto and registered in the name of Cede & Co. (DTC’s nominee). Interests in the global notes may be held through DTC either as a participant in DTC or indirectly through organizations that are participants in DTC.

So long as DTC or its nominee is the registered owner of the global securities representing the notes, DTC or such nominee is considered the sole owner and holder of the notes for all purposes of the notes and the indenture. Except as provided below, owners of beneficial interests in the notes are not entitled to have the notes registered in their names, do not receive or are not entitled to receive physical delivery of the notes in definitive form and are not considered the owners or holders of the notes under the indenture, including for purposes of receiving any reports delivered by us or the trustee pursuant to the indenture. Accordingly, each person owning a beneficial interest in a note must rely on the procedures of DTC or its nominee and, if such person is not a participant, on the procedures of the participant through which such person owns its interest, in order to exercise any rights of a holder of notes.

The Depository Trust Company. DTC acts as securities depositary for the notes. The notes are issued as fully registered notes registered in the name of Cede & Co. DTC has advised us as follows:

DTC is:

•a limited-purpose trust company organized under the New York Banking Law;

•a “banking organization” within the meaning of the New York Banking Law;

•a member of the Federal Reserve System;

•a “clearing corporation” within the meaning of the New York Uniform Commercial Code; and

•a “clearing agency” registered pursuant to the provisions of Section 17A of the Exchange Act.

DTC holds securities that its direct participants deposit with DTC. DTC facilitates the settlement among direct participants of securities transactions, such as transfers and pledges, in deposited securities through electronic computerized book-entry changes in direct participants’ accounts, thereby eliminating the need for physical movement of securities certificates.

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Direct participants of DTC include securities brokers and dealers (including the underwriters), banks, trust companies, clearing corporations, and certain other organizations. DTC is owned by a number of its direct participants. Access to the DTC system is also available to securities brokers and dealers, banks and trust companies that clear through or maintain a custodial relationship with a direct participant, either directly or indirectly.

Only direct participants or indirect participants may purchase, sell, or otherwise transfer ownership of, or other interests in, notes. DTC agrees with and represents to DTC participants that it will administer its book-entry system in accordance with its rules and by-laws and requirements of law. The SEC has on file a set of the rules applicable to DTC and its direct participants.

Purchases of notes under DTC’s system must be made by or through direct participants, who will receive a credit for the notes on DTC’s records. The ownership interest of each beneficial owner is in turn to be recorded on the records of direct participants and indirect participants. Beneficial owners will not receive written confirmation from DTC of their purchase, but beneficial owners are expected to receive written confirmations providing details of the transaction, as well as periodic statements of their holdings, from the direct participants or indirect participants through which such beneficial owners entered into the transaction. Transfers of ownership interests in the notes are to be accomplished by entries made on the books of participants acting on behalf of beneficial owners. Beneficial owners will not receive certificates representing their ownership interests in the notes, except in the event that use of the book-entry system for the notes is discontinued.

To facilitate subsequent transfers, all notes deposited by direct participants with DTC are registered in the name of DTC’s nominee, Cede & Co., or such other name as may be requested by an authorized representative of DTC. The deposit of notes with DTC and their registration in the name of Cede & Co. do not affect any change in beneficial ownership. DTC has no knowledge of the actual beneficial owners of the notes. DTC’s records reflect only the identity of the direct participants to whose accounts such notes are credited, which may or may not be the beneficial owners. The participants remain responsible for keeping account of their holdings on behalf of their customers.

Conveyance of notices and other communications by DTC to direct participants, by direct participants to indirect participants and by direct participants and indirect participants to beneficial owners will be governed by arrangements among them, subject to any statutory or regulatory requirements as may be in effect from time to time.

Book-Entry Format. Under the book-entry format, the trustee pays interest or principal payments to Cede & Co., as nominee of DTC. DTC forwards the payment to the direct participants, who then forward the payment to the indirect participants or to the beneficial owner. Neither ENLC, the trustee under the indenture nor any paying agent has any direct responsibility or liability for the payment of principal or interest on the notes to owners of beneficial interests in the notes.

DTC is required to make book-entry transfers on behalf of its direct participants and is required to receive and transmit payments of principal, premium, if any, and interest on the notes. Any direct participant or indirect participant is similarly required to make book-entry transfers and to receive and transmit payments with respect to the notes. ENLC, the underwriters, and the trustee under the indenture have no responsibility for any aspect of the actions of DTC or any of its direct or indirect participants. ENLC, the underwriters, and the trustee under the indenture have no responsibility or liability for any aspect of the records kept by DTC or any of its direct or indirect participants relating to, or payments made on account of, beneficial ownership interests in the notes or for maintaining, supervising, or reviewing any records relating to such beneficial ownership interests. ENLC also does not supervise these systems in any way.

DTC has advised us that it will only take action regarding a note if one or more of the direct participants to whom the note is credited directs DTC to take such action and only in respect of the portion of the aggregate principal amount of the notes as to which that participant or participants has or have given that direction. DTC can only act on behalf of its direct participants.

Neither DTC nor Cede & Co. (nor such other DTC nominee) will consent or vote with respect to the notes unless authorized by a direct participant in accordance with DTC’s procedures. Under its usual procedures, DTC will mail

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an omnibus proxy to us as soon as possible after the record date. The omnibus proxy assigns Cede & Co.’s consenting or voting rights to those direct participants to whose accounts the notes are credited on the record date (identified in a listing attached to the omnibus proxy).

DTC has agreed to the foregoing procedures in order to facilitate transfers of the notes among its participants. However, DTC is under no obligation to perform or continue to perform those procedures and may discontinue those procedures at any time.

Certain Definitions

“Attributable Indebtedness” when used with respect to any Sale-Leaseback Transaction, means, as at the time of determination, the present value (discounted at the rate set forth or implicit in the terms of the lease included in such transaction) of the total obligations of the lessee for rental payments (other than amounts required to be paid on account of property taxes, maintenance, repairs, insurance, assessments, utilities, operating and labor costs and other items that do not constitute payments for property rights) during the remaining term of the lease included in such Sale-Leaseback Transaction (including any period for which such lease has been extended). In the case of any lease that is terminable by the lessee upon the payment of a penalty or other termination payment, such amount shall be the lesser of the amount determined assuming termination upon the first date such lease may be terminated (in which case the amount shall also include the amount of the penalty or termination payment, but no rent shall be considered as required to be paid under such lease subsequent to the first date upon which it may be so terminated) or the amount determined assuming no such termination.

“Consolidated Net Tangible Assets”means, at any date of determination, the total amount of assets of ENLC and its consolidated Subsidiaries after deducting therefrom:

1.all current liabilities (excluding (A) any current liabilities that by their terms are extendable or renewable at the option of the obligor thereon to a time more than twelve months after the time as of which the amount thereof is being computed, and (B) current maturities of long-term debt); and

2.the value (net of any applicable reserves) of all goodwill, trade names, trademarks, patents and other like intangible assets,

all as set forth, or on a pro forma basis would be set forth, on the consolidated balance sheet of ENLC and its consolidated Subsidiaries for ENLC’s most recently completed fiscal quarter for which financial statements have been filed with the SEC, prepared in accordance with generally accepted accounting principles.

“Credit Agreement”means the Revolving Credit Agreement, dated as of December 11, 2018, among ENLC, Bank of America, N.A., as Administrative Agent, and the other agents and lenders party thereto, as amended, restated, or otherwise modified from time to time, and any successor or replacement agreement with banks or other financial institutions that provides for revolving loans to ENLC or ENLK.

“Exchange Act” means the Securities Exchange Act of 1934, as amended, and any successor statute.

“Indebtedness”of any Person at any date means any obligation created or assumed by such Person for the repayment of borrowed money or any guaranty thereof.

“Managing Member”means EnLink Midstream Manager, LLC, a Delaware limited liability company, and its successors as managing member of ENLC.

“Permitted Liens” means:

1.liens upon rights-of-way for pipeline purposes;

2.easements, rights-of-way, restrictions, and other similar encumbrances affecting real property and encumbrances consisting of zoning restrictions, easements, licenses, restrictions on the use of real property or minor imperfections in title thereto and which do not in the aggregate materially adversely affect the

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value of the properties encumbered thereby or materially impair their use in the operation of the business of ENLC and its Subsidiaries;

3.rights reserved to or vested by any provision of law in any municipality or public authority to control or regulate any of the properties of ENLC or any Subsidiary or the use thereof or the rights and interests of ENLC or any Subsidiary therein, in any manner under any and all laws;

4.rights reserved to the grantors of any properties of ENLC or any Subsidiary, and the restrictions, conditions, restrictive covenants, and limitations, in respect thereto, pursuant to the terms, conditions and provisions of any rights-of-way agreements, contracts or other agreements therewith;

5.any statutory or governmental lien or lien arising by operation of law, or any mechanics’, repairmen’s, materialmen’s, suppliers’, carriers’, landlords’, warehousemen’s or similar lien (including liens on property in the possession of storage facilities, pipelines or barges) incurred in the ordinary course of business which is not more than sixty (60) days past due or which is being contested in good faith by appropriate proceedings, if necessary, and any undetermined lien which is incidental to construction, development, improvement or repair;

6.any right reserved to, or vested in, any municipality or public authority by the terms of any right, power, franchise, grant, license, permit or by any provision of law, to purchase or recapture or to designate a purchaser of, any property;

7.liens for taxes and assessments which are (a) for the then current year, (b) not at the time delinquent, or (c) delinquent but the validity or amount of which is being contested at the time by ENLC or any of its Subsidiaries in good faith by appropriate proceedings;

8.banker’s liens, rights of set-off or similar rights and remedies as to deposit accounts or other funds maintained with a creditor depository institution and arising in the ordinary course of business;

9.liens on deposits required by any Person with whom ENLC or any Subsidiary enters into forward contracts, futures contracts, swap agreements or other commodities contracts in the ordinary course of business and in accordance with established risk management policies and liens of, or to secure performance of, leases, other than capital leases;

10.any lien in favor of ENLC or any Subsidiary;

11.any lien upon any property or assets of ENLC or any Subsidiary in existence on the date of the initial issuance of the notes;

12.any lien incurred in the ordinary course of business in connection with workmen’s compensation, unemployment insurance, temporary disability, social security, retiree health or similar laws or regulations or to secure obligations imposed by statute or governmental regulations or to secure letters of credit with respect thereto;

13.liens in favor of any person to secure obligations under provisions of any letters of credit, bank guarantees, bonds or surety obligations required or requested by any governmental authority or in connection with any contract or statute, provided that such obligations do not constitute Indebtedness; or any lien upon or deposits of any assets to secure performance of bids, trade contracts, surety, stay, customs, and appeal bonds, performance and return-of money bonds, bankers’ acceptance facilities, leases or statutory obligations, and other obligations of a like nature incurred in the ordinary course of business or to secure letters of credit with respect thereto;

14.any lien upon any property or assets created at the time of acquisition of such property or assets by ENLC or any of its Subsidiaries or within one year after such time to secure all or a portion of the purchase price for such property or assets or debt incurred to finance such purchase price, whether such debt was incurred prior to, at the time of or within one year after the date of such acquisition;

15.any lien upon any property or assets to secure all or part of the cost of construction, development, repair, or improvements thereon or to secure Indebtedness incurred prior to, at the time of, or within one year after completion of such construction, development, repair or improvements or the commencement of full operations thereof (whichever is later), to provide funds for any such purpose;

16.any lien upon any property or assets existing thereon at the time of the acquisition thereof by ENLC or any of its Subsidiaries and any lien upon any property or assets of a Person existing thereon at the time such Person becomes a Subsidiary of ENLC by acquisition, merger or otherwise; provided that, in each case, such lien only encumbers the property or assets so acquired or owned by such Person at the time such Person becomes a Subsidiary and any additions thereto, proceeds thereof and property in replacement or substitution thereof;

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17.liens imposed by law or order as a result of any proceeding before any court or regulatory body that is being contested in good faith, and liens which secure a judgment or other court-ordered award or settlement as to which ENLC or the applicable Subsidiary has not exhausted its appellate rights;

18.any extension, renewal, refinancing, refunding or replacement (or successive extensions, renewals, refinancing, refunding or replacements) of liens, in whole or in part, referred to in clauses (1) through (17) above; provided, however, that any such extension, renewal, refinancing, refunding or replacement lien shall be limited to the property or assets covered by the lien extended, renewed, refinanced, refunded or replaced and that the obligations secured by any such extension, renewal, refinancing, refunding or replacement lien shall be in an amount not greater than the amount of the obligations secured by the lien extended, renewed, refinanced, refunded or replaced and any expenses of ENLC or its Subsidiaries (including any premium) incurred in connection with such extension, renewal, refinancing, refunding or replacement; or

19.any lien resulting from the deposit of moneys or evidence of indebtedness in trust for the purpose of defeasing Indebtedness of ENLC or any of its Subsidiaries.

“Person”means any individual, corporation, partnership, limited liability company, joint venture, incorporated or unincorporated association, joint-stock company, trust, unincorporated organization, government or any agency or political subdivision thereof or any other entity.

“Principal Property”means, whether owned or leased on the date of the initial issuance of the notes or thereafter acquired:

1.any pipeline assets of ENLC or any of its Subsidiaries, including any related facilities employed in the gathering, transportation, distribution, storage or marketing of natural gas, refined petroleum products, natural gas liquids and petrochemicals, that are located in the United States of America or any territory or political subdivision thereof; and

2.any processing, compression, treating, blending, or manufacturing plant or terminal owned or leased by ENLC or any of its Subsidiaries that is located in the United States or any territory or political subdivision thereof, except in the case of either of the preceding clause (1) or this clause (2):

•any such assets consisting of inventories, furniture, office fixtures and equipment (including data processing equipment), vehicles and equipment used on, or useful with, vehicles; and

•any such assets which, in the opinion of the board of directors of the Managing Member are not material in relation to the activities of ENLC and its Subsidiaries taken as a whole.

“Principal Subsidiary”means any Subsidiary owning or leasing, directly or indirectly through ownership in another Subsidiary, any Principal Property.

“Subsidiary”means, as to any Person, (1) any corporation, association or other business entity (other than a partnership or limited liability company) of which more than 50% of the outstanding capital stock having ordinary voting power is at the time owned or controlled, directly or indirectly, by such Person or one or more of the other Subsidiaries of such Person or (2) a partnership (whether general or limited) in which such Person or a Subsidiary of such Person is, at the date of determination, a general partner of such partnership, but only if such Person, directly or by one or more Subsidiaries of such Person, or a combination thereof, controls such partnership on the date of determination, or (3) any other Person in which such Person, one or more Subsidiaries of such Person, or a combination thereof, directly or indirectly, at the date of determination, has (i) a majority ownership interest or (ii) the power to elect or direct the election of directors with a majority of the voting power of the board of directors (or other governing body) of such Person or the sole member or managing member of such Person, as applicable.

“Subsidiary Guarantor”means each Subsidiary of ENLC that guarantees the notes pursuant to the terms of the indenture but only so long as such Subsidiary is a guarantor with respect to the notes on the terms provided for in the indenture.

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EX-10.3

Exhibit 10.3

ENLINK MIDSTREAM, LLC

2014 LONG-TERM INCENTIVE PLAN

(As Amended and Restated Effective December 16, 2021)

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ENLINK MIDSTREAM, LLC

2014 LONG-TERM INCENTIVE PLAN

(As Amended and Restated Effective December 16, 2021)

ARTICLE I.

ESTABLISHMENT AND PURPOSE

1.1    Establishment. The EnLink Midstream, LLC 2014 Long-Term Incentive Plan (the “Plan”) established as of February 5, 2014, and most-recently amended and restated as of December 28, 2020, is hereby amended and restated, effective as of the Effective Date (as defined below). Capitalized terms used herein without definition shall have the respective meanings assigned to them in Article II.

1.2    Purpose. The purposes of the Plan are to attract able persons to enter the employ of the Company, to encourage Employees and Consultants to remain in the employ or service of the Company, and to provide motivation to Employees and Consultants to put forth maximum efforts toward the continued growth, profitability, and success of the Company, by providing incentives to such persons through the ownership and/or performance of the Units of EnLink Midstream. A further purpose of the Plan is to provide a means through which the Company may attract able persons to become directors of the EnLink Manager and to provide such individuals with incentive and reward opportunities. Toward these objectives, Awards may be granted under the Plan to Employees, Consultants, and Outside Directors on the terms and subject to the conditions set forth in the Plan and the Award Agreements thereunder.

ARTICLE II.

DEFINITIONS

2.1    Affiliate. “Affiliate” means, with respect to any Person, any other Person that directly or indirectly through one or more intermediaries controls, is controlled by, or is under common control with, the Person in question. As used herein, the term “control” means the possession, direct or indirect, of the power to direct or cause the direction of the management and policies of a Person, whether through ownership of voting securities, by contract or otherwise. With respect to an Incentive Unit Option, “Affiliate” means a “parent corporation” or a “subsidiary corporation” of EnLink Midstream, as those terms are defined in Sections 424(e) and (f) of the Code.

2.2    Award. “Award” means an award granted to a Participant in the form of an Option, UAR, Restricted Unit Award, Restricted Incentive Unit, Unit Award, Cash Award, or Performance Award and includes, as appropriate, any tandem DERs granted with respect to an Award (other than a Restricted Unit, Option, or UAR). Subject to Section 16.1, all Awards shall be granted under, confirmed by, and subject to the terms of, an Award Agreement.

2.3    AwardAgreement. “Award Agreement” means a written agreement between EnLink Midstream and a Participant that sets forth the terms, conditions, restrictions, and/or limitations applicable to an Award.

2.4    Board. “Board” means the Board of Directors of the EnLink Manager, the managing member of EnLink Midstream.

2.5    Cash Award. “Cash Award” means an Award granted to a Participant under Section 12.1 that is denominated and payable in cash.

2.6    Cause. “Cause” means, except as otherwise provided in an Award Agreement, (i) Participant has failed to perform the duties assigned to him or her and such failure has continued following delivery by the Company of written notice to Participant of such failure, (ii) Participant has been convicted of a felony or misdemeanor involving moral turpitude, (iii) Participant has engaged in acts or omissions against the Company constituting dishonesty, breach of fiduciary obligation, or intentional wrongdoing or misfeasance, (iv) Participant has acted intentionally or in bad faith in a manner that results in a material detriment to the assets, business, or prospects of the Company, or (v) Participant has breached any obligation under the Plan or Award Agreement.

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2.7    Change of Control. “Change of Control” shall have the meaning set forth in Section 14.1.

2.8    Code. “Code” means the Internal Revenue Code of 1986, as amended from time to time, including regulations thereunder and successor provisions and regulations thereto.

2.9    Committee. “Committee” means (i) with respect to the application of this Plan to Employees and Consultants, the Compensation Committee of the Board or such other committee of the Board as may be designated by the Board to administer the Plan, which committee shall consist of two or more non-employee directors, each of whom is a “non-employee director” under Rule 16b-3, and (ii) with respect to the application of this Plan to an Outside Director, the Board. To the extent that no Committee exists that has the authority to administer the Plan, or to the extent the Board so elects, the functions of the Committee shall be exercised by the Board. If for any reason the appointed Committee does not meet the requirements of Rule 16b-3, such noncompliance with such requirements shall not affect the validity of Awards, grants, interpretations, or other actions of the Committee.

2.10    Company. “Company” means EnLink Midstream and its Affiliates.

2.11    Consultant.“Consultant” means an individual performing services for EnLink Midstream or an Affiliate who is treated for tax purposes as an independent contractor at the time of performance of the services.

2.12    Distribution Equivalent Right. “Distribution Equivalent Right” or “DER” means a contingent right, granted alone or in tandem with a specific Award (other than a Restricted Unit, Option, or UAR) under Section 12.2, to receive with respect to each Unit subject to the Award an amount in cash, Units, and/or Restricted Incentive Units, as determined by the Committee in its sole discretion, equal in value to the distributions made by the Company with respect to a Unit during the period such Award is outstanding.

2.13    Effective Date. “Effective Date” means December [•], 2021, which is the date this Plan, as hereby amended and restated, becomes effective.

2.14    Employee. “Employee” means an employee of the Company; provided, however, that the term Employee does not include an Outside Director or a Consultant.

2.15    EnLinkManager. “EnLink Manager” means EnLink Midstream Manager, LLC, a Delaware limited liability company, and any successor thereto.

2.16    EnLinkMidstream. “EnLink Midstream” means EnLink Midstream, LLC, a Delaware limited liability company, and any successor thereto.

2.17    ExchangeAct. “Exchange Act” means the Securities Exchange Act of 1934, as amended from time to time, including regulations thereunder and successor provisions and regulations thereto.

2.18    FairMarketValue. “Fair Market Value” means the closing sales price of a Unit on the applicable date (or if there is no trading in the Units on such date, on the next preceding date on which there was trading) as reported in The Wall Street Journal (or other reporting service approved by the Committee). In the event the Units are not publicly traded at the time a determination of fair market value is required to be made hereunder, the determination of fair market value shall be made in good faith by the Committee and in compliance with Section 409A or 422 of the Code, as applicable.

2.19    GIP. “GIP” means (i) Global Infrastructure Partners III-A/B, L.P., (ii) Global Infrastructure Partners III-C Intermediate, L.P., (iii) Global Infrastructure Partners III-C2 Intermediate, L.P., (iv) Global Infrastructure Partners II-C Stetson AIV, L.P., and (v) each of their Affiliates and any funds, partnerships, or other investment vehicles managed by Global Infrastructure Management, LLC or their Affiliates (including in each case, any portfolio companies of such entities).

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2.20    GrantDate. “Grant Date” means the date an Award is granted by the Committee.

2.21    IncentiveUnitOption. “Incentive Unit Option” means an Option that is intended to meet the requirements of Section 422(b) of the Code.

2.22    NonqualifiedUnitOption. “Nonqualified Unit Option” means an Option that is not an Incentive Unit Option.

2.23    Option. “Option” means an option to purchase Units granted to a Participant pursuant to Article VII. An Option may be either an Incentive Unit Option or a Nonqualified Unit Option, as determined by the Committee.

2.24    OutsideDirector. “Outside Director” means a “non-employee director” of the EnLink Manager, as defined in Rule 16b-3.

2.25    Participant. “Participant” means an Employee, Consultant, or Outside Director to whom an Award has been granted under the Plan.

2.26    Partnership. “Partnership” means EnLink Midstream Partners, LP, a Delaware Limited Partnership.

2.27    PerformanceAward. “Performance Award” means an Award granted to a Participant pursuant to Article XIII, which Award is subject to the attainment of one or more Performance Goals.

2.28    PerformanceGoal. “Performance Goal” means a standard established by the Committee to determine, in whole or in part, whether a Performance Award shall be earned.

2.29    Person. “Person” means an individual or a corporation, limited liability company, partnership, joint venture, trust, unincorporated organization, association, government agency or political subdivision thereof, or other entity; provided, that for purposes of Section 14.1 only, “Person” shall also include any “person“ or any “group” within the meaning of Sections 13(d) and 14(d)(2) of the Exchange Act.

2.30    Plan. “Plan” means this EnLink Midstream, LLC 2014 Long-Term Incentive Plan, as hereby amended and restated effective as of the Effective Date, and as hereafter amended from time to time.

2.31    Prior Plan. “Prior Plan” means the applicable version of the EnLink Midstream, LLC 2014 Long-Term Incentive Plan, as in effect at the applicable time prior to its amendment and restatement on the Effective Date.

2.32    RestrictedIncentiveUnit. “Restricted Incentive Unit” means a notional Unit granted under the Plan pursuant to Article X which, upon vesting, entitles the Participant to receive, at the time of settlement, a Unit or an amount of cash equal to the Fair Market Value of a Unit (or combination thereof), as determined by the Committee in its sole discretion.

2.33    RestrictedUnit. “Restricted Unit” means a Unit granted to a Participant pursuant to Article IX, which is subject to such restrictions as may be determined by the Committee. Restricted Units shall constitute issued and outstanding Units for all corporate purposes.

2.34    RestrictionPeriod.“Restriction Period” means the period established by the Committee at the time of a grant of an Award during which an Award shall be fully or partially forfeitable.

2.35    Rule16b-3. “Rule 16b-3” means Rule 16b-3 promulgated by the Securities and Exchange Commission under the Exchange Act, or any successor rule or regulation thereto as in effect from time to time.

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2.36    UnitAppreciationRight. “Unit Appreciation Right” or “UAR” means a contingent right granted under the Plan pursuant to Article VIII that entitles the holder to receive, in cash or Units (or combination thereof), as determined by the Committee in its sole discretion, an amount equal to the excess of the Fair Market Value of a Unit on the exercise date of the Unit Appreciation Right (or another specified date) over the exercise price of the Unit Appreciation Right, multiplied by the number of Units which respect to which the UAR shall have been exercised.

2.37    Unit Award. “Unit Award” means an Award of one or more vested Units granted under Article XI.

2.38    UnitDistributionRight. “Unit Distribution Right” or “UDR” means a distribution made by the Company with respect to a Restricted Unit.

2.39    Units. “Units” means the units, $.01 par value per Unit, of EnLink Midstream, or any units or other securities of EnLink Midstream hereafter issued or issuable in substitution or exchange for the Units.

2.40    Voting Stock. “Voting Stock” of any specified Person as of any date means the capital stock (or comparable equity securities) of such Person that is at the time entitled (without regard to the occurrence of any contingency) to vote in the election of the board of directors (or comparable governing body) of such Person.

2.41    Working Group. “Working Group” means EnLink Midstream, the Partnership, EnLink Midstream GP, LLC and EnLink Manager.

2.42    Working Subsidiary. “Working Subsidiary” means, with respect to any Working Group member, (i) in the case of a corporation, any corporation of which an applicable Working Group member directly or indirectly owns shares representing more than 50% of the combined voting power of the shares of all classes or series of capital stock of such corporation which have the right to vote generally on matters submitted to a vote of the stockholders of such corporation and (ii) in the case of a partnership, limited liability company, or other business entity not organized as a corporation, any such business entity of which an applicable Working Group member (A) directly or indirectly owns more than 50% of the voting, capital, or profits interests (whether in the form of partnership interests, membership interests, or otherwise) or (B) has the power to elect or direct the election of directors with a majority of the voting power of the board of directors (or comparable governing body) of such partnership, limited liability company, or other business entity or the sole member or managing member of such partnership, limited liability company, or other business entity, as applicable.

ARTICLE III.

PLAN ADMINISTRATION

3.1    PlanAdministrator. The Plan shall be administered by the Committee. The Committee may, subject to applicable law, delegate some or all of its power to the Chief Executive Officer or other executive officers of the Company as the Committee deems appropriate; provided, that in no event shall the Committee delegate its power with regard to the selection for participation in the Plan of an officer or other Person subject to Section 16 of the Exchange Act or decisions concerning the timing, pricing, or amount of an Award to such an officer or other Person.

3.2    AuthorityofAdministrator. The Committee shall have total and exclusive responsibility to control, operate, manage, and administer the Plan in accordance with its terms. The Committee shall have all the authority that may be necessary or advisable to enable it to discharge its responsibilities with respect to the Plan. Without limiting the generality of the preceding sentence, but subject to the limitation that none of the enumerated powers of the Committee shall be deemed to include any action that would intentionally cause a tax to be imposed on a Participant pursuant to Section 409A of the Code, the Committee shall have the exclusive right to: (i) interpret the Plan and the Award Agreements; (ii) determine eligibility for participation in the Plan; (iii) decide all questions concerning eligibility for, and the amount of, Awards granted under the Plan; (iv) construe any ambiguous provision of the Plan or any Award Agreement; (v) prescribe the form of the Award Agreements embodying Awards granted

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under the Plan; (vi) correct any defect, supply any omission, or reconcile any inconsistency in the Plan or any Award Agreement; (vii) issue administrative guidelines as an aid to administering the Plan and make changes in such guidelines as the Committee from time to time deems proper; (viii) make regulations for carrying out the Plan and make changes in such regulations as the Committee from time to time deems proper; (ix) determine whether Awards should be granted singly or in combination; (x) to the extent permitted under the Plan or an Award Agreement, grant waivers of terms, conditions, restrictions, and limitations under the Plan or Award Agreement, as applicable; (xi) accelerate the exercise, vesting, or payment of an Award when such action or actions would be in the best interests of the Company; (xii) grant Awards in replacement of Awards previously granted under the Plan or any other employee benefit plan of the Company; and (xiii) take any and all other actions the Committee deems necessary or advisable for the proper operation or administration of the Plan. Notwithstanding anything herein to the contrary, except in connection with a corporate transaction involving the Company as provided in Section 4.2 (including, without limitation, any distribution, unit split, extraordinary cash distribution, recapitalization, reorganization, merger, consolidation, split-up, spin-off, combination, or exchange of Units), the terms of outstanding Awards may not be amended to reduce the exercise price of outstanding Options or UARs or cancel, exchange, substitute, buyout, or surrender outstanding Options or UARs in exchange for cash, other awards, or Options with an exercise price that is less than the exercise price of the original Options or UARs without unitholder approval.

3.3    DiscretionaryAuthority. The Committee shall have full discretionary authority in all matters related to the discharge of its responsibilities and the exercise of its authority under the Plan, including, without limitation, its construction of the terms of the Plan and the Award Agreements thereunder and its determination of eligibility for participation under the Plan. The decisions of the Committee and its actions with respect to the Plan shall be final, conclusive, and binding on all Persons having or claiming to have any right or interest in or under the Plan, including Participants and their respective estates, beneficiaries, and legal representatives.

3.4    Liability; Indemnification. No member of the Committee nor any Person to whom authority has been delegated, shall be personally liable for any action, interpretation, or determination made in good faith with respect to the Plan or Awards granted hereunder, and each member of the Committee (or delegate of the Committee) shall be fully indemnified and protected by EnLink Midstream with respect to any liability he or she may incur with respect to any such action, interpretation, or determination, to the extent permitted by applicable law.

ARTICLE IV.

UNITS SUBJECT TO THE PLAN

4.1    AvailableUnits. As of the time of the merger contemplated by that certain Agreement and Plan of Merger, dated as of October 21, 2018 (the “Merger Agreement”), by and among EnLink Midstream, the Partnership and certain other parties thereto, became effective (the “EnLink Effective Time”), EnLink Midstream assumed all obligations under the EnLink Midstream GP, LLC Long-Term Incentive Plan, as amended and restated (the “ENLK Plan”). In connection with such assumption of the ENLK Plan, the remaining common units representing limited partner interests in the Partnership available for grant under the ENLK Plan (as rolled-over into Units pursuant to the terms of the Merger Agreement (the “Rollover Units”)) were included among the Units available for grant of Awards under the Plan. Accordingly, the maximum number of Units that shall be available for grant of Awards under the Plan shall not exceed a total of 41,116,046 Units, which equals: (a) the sum of (i) the 17,700,000 Units made available in connection with that certain prior amendment and restatement of the Prior Plan effective as of January 20, 2019, and (ii) the additional 20,000,000 Units made available in connection with this amendment and restatement of the Prior Plan effective as of December 28, 2020 (collectively, the “Standard Units”), plus (b) the 3,416,046 Rollover Units which became available as of the EnLink Effective Time, in each case, subject to adjustment as provided in Sections 4.2 and 4.3. For periods on and after the EnLink Effective Time, the Committee shall keep separate records of the Rollover Units and the Standard Units for purposes of the relevant New York Stock Exchange rules. All Units available for issuance hereunder may be issued as Incentive Unit Options.

4.2    Adjustments for Recapitalizations and Reorganizations.

(a)    The Units with respect to which Awards may be granted under the Plan are Units as presently constituted, but if, and whenever, prior to the expiration or satisfaction of an Award theretofore granted,

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EnLink Midstream shall effect a subdivision or consolidation of Units or the payment of a distribution on Units in the form of Units without receipt of consideration by EnLink Midstream, the number of Units with respect to which such Award may thereafter be exercised or satisfied, as applicable, (i) in the event of an increase in the number of outstanding Units, shall be proportionately increased, and, if applicable, the exercise price per Unit shall be proportionately reduced, and (ii) in the event of a reduction in the number of outstanding Units, shall be proportionately reduced, and, if applicable, the exercise price per Unit shall be proportionately increased.

(b)    If EnLink Midstream recapitalizes or otherwise changes its capital structure, thereafter upon any exercise or satisfaction, as applicable, of an Award theretofore granted the Participant shall be entitled to (or entitled to purchase, if applicable) under such Award, in lieu of the number of Units then covered by such Award, the number and class of units or other securities to which the Participant would have been entitled pursuant to the terms of the recapitalization if, immediately prior to such recapitalization, the Participant had been the holder of record of the number of Units then covered by such Award.

(c)    In the event of changes in the outstanding Units by reason of a reorganization, merger, consolidation, combination, separation (including a spin-off or other distribution of Units or property), exchange, or other relevant change in capitalization occurring after the Grant Date of any Award and not otherwise provided for by this Section 4.2, any outstanding Awards and any Award Agreements evidencing such Awards shall be subject to adjustment by the Committee in its absolute discretion as to the number, price and kind of units or other consideration subject to, and other terms of, such Awards to reflect such changes in the outstanding Units.

(d)    In the event of any changes in the outstanding Units provided for in this Section 4.2, the aggregate number of Units available for grant of Awards under the Plan shall be equitably adjusted by the Committee, whose determination shall be conclusive. Any adjustment provided for in this Section 4.2 shall be subject to any required unitholder action.

4.3    Adjustments for Awards. The Committee shall have full discretion to determine the manner in which Units available for grant of Awards under the Plan are counted. Without limiting the discretion of the Committee under this Section 4.3, unless otherwise determined by the Committee, the following rules shall apply for the purpose of determining the number of Units available for grant of Awards under the Plan:

(a)    Unit-Based Awards. The grant of Awards other than Awards settled in cash shall reduce the number of Units available for grant of Awards under the Plan by the number of Units subject to such Award.

(b)    Termination. If any Award referred to in paragraph (a) above is canceled or forfeited, or terminates, expires, or lapses for any reason, the Units then subject to such Award shall again be available for grant of Awards under the Plan.

(c)    Payment of Exercise Price and Withholding Taxes. If previously acquired Units are used to pay the exercise price of an Award or Units are withheld in payment of such exercise price, the number of Units available for grant of Awards under the Plan shall be increased by the number of Units delivered or withheld as payment of such exercise price. If previously acquired Units are used to pay withholding taxes payable upon exercise, vesting, or payment of an Award, or Units that would be acquired upon exercise, vesting, or payment of an Award are withheld to pay withholding taxes payable upon exercise, vesting, or payment of such Award, the number of Units available for grant of Awards under the Plan shall be increased by the number of Units delivered or withheld as payment of such withholding taxes. For purposes of this Section 4.3(c), if any Units delivered or withheld could not again be available for Awards to a particular Participant under any applicable law or regulation, such Units shall be available exclusively for Awards to Participants who are not subject to such limitation.

(d)     Fractional Units. If any such adjustment would result in a fractional security being (i) available under the Plan, such fractional security shall be disregarded or (ii) subject to an Award, EnLink Midstream shall pay the holder of such Award, in connection with the applicable vesting, exercise, or settlement of such Award in whole or in part occurring after such adjustment, an amount in cash determined by multiplying (x) the fraction of

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such security (rounded to the nearest hundredth) by (y) the excess, if any, of the Fair Market Value on the vesting, exercise, or settlement date over the exercise price, if any, of such Award.

ARTICLE V.

ELIGIBILITY

All Employees, Consultants, and Outside Directors are eligible to participate in the Plan. The Committee shall recommend, from time to time, that Awards be granted to those Employees, Consultants, and Outside Directors who, in the opinion of the Committee, can further the Plan’s purposes. Once an Employee, Consultant, or Outside Director is recommended for an Award by the Committee, the Committee shall determine the type and size of Award to be granted to such Employee, Consultant, or Outside Director, as a Participant, and shall establish in the related Award Agreement the terms, conditions, restrictions, and/or limitations applicable to the Award, in addition to those set forth in the Plan and the administrative guidelines and regulations, if any, established by the Committee.

ARTICLE VI.

FORM OF AWARDS

Awards may, at the Committee’s sole discretion, be granted under the Plan in the form of Options, UARs, Restricted Unit Awards, Restricted Incentive Units, Unit Awards, Cash Awards, Performance Awards, or a combination thereof. All Awards shall be subject to the terms, conditions, restrictions, and limitations of the Plan. The Committee may, in its absolute discretion, subject any Award to such other terms, conditions, restrictions, and/or limitations (including, but not limited to, the time and conditions of exercise, vesting, or payment of an Award, restrictions on transferability of any Units issued or delivered pursuant to an Award, and forfeiture of Awards in the event of termination of employment by the Participant, or termination of the Participant’s service relationship with the Company); provided, they are not inconsistent with the terms of the Plan. Awards under a particular Article of the Plan need not be uniform, and Awards under more than one Article of the Plan may be combined into a single Award Agreement. Any combination of Awards may be granted at one time and on more than one occasion to the same Participant.

ARTICLE VII.

OPTIONS

7.1    General. Awards may be granted to Employees, Consultants, and Outside Directors in the form of Options. Options may be awarded in such numbers and at such times as the Committee shall determine in the form of Incentive Unit Options or Nonqualified Unit Options, or a combination of both; provided, however, that Incentive Unit Options may be granted only to Employees.

7.2    Terms and Conditions of Options. An Option shall be exercisable in whole or in such installments and at such times as may be determined by the Committee. The price at which a Unit may be purchased upon exercise of an Option shall be determined by the Committee, but such exercise price shall not be less than 100% of the Fair Market Value per Unit on the Grant Date. Except as otherwise provided in Section 7.3, the term of each Option shall be as specified by the Committee; provided, however, that no Options shall be exercisable later than ten years from the Grant Date. Options may be granted with respect to Restricted Units or Units that are not Restricted Units, as determined by the Committee in its absolute discretion. In no event shall an Award of Options include any right to receive distributions or DERs in connection with the Units that are subject to such Options or with respect to periods occurring prior to the exercise of such Options.

7.3    Restrictions Relating to Incentive Unit Options. Options granted in the form of Incentive Unit Options (including any UAR in tandem therewith) shall, in addition to being subject to the terms and conditions of Section 7.2, comply with Section 422(b) of the Code. Accordingly, no Incentive Unit Options shall be granted later than ten years from September 17, 2020 (the date of adoption of the most recent form of the Prior Plan by the Board). To the extent that the aggregate Fair Market Value (determined at the time the respective Incentive Unit Option is granted) of Units with respect to which Incentive Unit Options are exercisable for the first time by an individual during any calendar year under all incentive unit option plans of EnLink Midstream and its Affiliates

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exceeds $100,000, such excess Incentive Unit Options shall be treated as Nonqualified Unit Options. The Committee shall determine, in accordance with the applicable provisions of the Code, which of a Participant’s Incentive Unit Options will not constitute Incentive Unit Options because of such limitation and shall notify the Participant of such determination as soon as practicable after such determination. The price at which a Unit may be purchased upon exercise of an Incentive Unit Option shall be determined by the Committee, but such exercise price shall not be less than 100% of the Fair Market Value of a Unit on the Grant Date. No Incentive Unit Option shall be granted to an Employee under the Plan if, at the time such Option is granted, such Employee owns Units possessing more than 10% of the total combined voting power of all classes of units of EnLink Midstream or an Affiliate, within the meaning of Section 422(b)(6) of the Code, unless (i) on the Grant Date of such Option, the exercise price of such Option is at least 110% of the Fair Market Value of the Units subject to the Option and (ii) such Option by its terms is not exercisable after the expiration of five years from the Grant Date of the Option.

7.4    Additional Terms and Conditions. The Committee may subject any Award of Options to such other terms, conditions, restrictions, and/or limitations as it determines are necessary or appropriate; provided, that they are not inconsistent with the Plan.

7.5    Exercise of Options. Subject to the terms and conditions of the Plan, Options shall be exercised by the delivery of a written notice of exercise to EnLink Midstream, setting forth the number of Units with respect to which the Option is to be exercised, accompanied by full payment for such Units.

(a)    Upon exercise of an Option, the exercise price of the Option shall be payable to EnLink Midstream in full either: (i) in cash or an equivalent acceptable to the Committee, or (ii) in the absolute discretion of the Committee and in accordance with any applicable administrative guidelines established by the Committee, by tendering one or more previously acquired nonforfeitable Units that have been owned by the Participant or by reducing the number of Units issuable upon exercise of the Option, in either case having an aggregate Fair Market Value at the time of exercise equal to the total exercise price (including an actual or deemed multiple series of exchanges of such Units), or (iii) in a combination of the forms of payment specified in clauses (i) and (ii) above.

(b)    From and after such time as EnLink Midstream registers the Units under Section 12 of the Exchange Act, payment of the exercise price of an Option may also be made, in the absolute discretion of the Committee, by delivery to EnLink Midstream or its designated agent of an executed irrevocable option exercise form together with irrevocable instructions to a broker-dealer to sell or margin a sufficient portion of the Units with respect to which the Option is exercised and deliver the sale or margin loan proceeds directly to EnLink Midstream to pay the exercise price and any required withholding taxes.

(c)    As soon as reasonably practicable after receipt of written notification of exercise of an Option and full payment of the exercise price and any required withholding taxes, EnLink Midstream shall deliver to the Participant, in the Participant’s name, a unit certificate or certificates in an appropriate amount based upon the number of Units purchased under the Option.

ARTICLE VIII.

UNIT APPRECIATION RIGHTS

8.    1General. Awards may be granted to Employees, Consultants, and Outside Directors in the form of UARs. UARs shall be awarded in such numbers and at such times as the Committee shall determine.

8.2    Right to Payment. A UAR shall confer on the Participant to whom it is granted a right to receive, upon exercise thereof, the excess of(a) the Fair Market Value of one Unit on the date of exercise over(b) the exercise price of the UAR on the Grant Date as determined by the Committee; provided, that, such exercise price shall not be less than 100% of the Fair Market Value of one Unit on the Grant Date.

8.3    Rights Related to Options. A UAR granted in tandem with an Option shall entitle a Participant, upon exercise, to surrender that Option or any portion thereof, to the extent unexercised, and to receive payment of an amount computed pursuant to Section 8.3(b). That Option shall then cease to be exercisable to the extent

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surrendered. UARs granted in connection with an Option shall be subject to the terms of the Award Agreement governing the Option, which shall comply with the following provisions in addition to those applicable to Options:

(a)    A UAR granted in tandem with an Option shall be exercisable only at such time or times and only to the extent that the related Option is exercisable and shall not be transferable except to the extent that the related Option is transferable.

(b)    Upon the exercise of a UAR granted in tandem with an Option, a Participant shall be entitled to receive payment from the Company of an amount determined by multiplying: (i) the difference obtained by subtracting the exercise price with respect to one Unit specified in the related Option from the Fair Market Value of one Unit on the date of exercise of the UAR, by (ii) the number of Units as to which that UAR has been exercised.

8.4    Right Without Option. A UAR granted independent of an Option shall be exercisable as determined by the Committee and set forth in the Award Agreement governing the UAR.

8.5    Terms. Except as otherwise provided herein, the Committee shall determine at the Grant Date or thereafter, (a) 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), (b) the method of exercise, method of settlement, form of consideration payable in settlement, and method by or forms in which Units will be delivered or deemed to be delivered to Participants, (c) whether or not a UAR shall, subject to Section 409A of the Code, be in tandem or in combination with any other Award, and (d) any other terms and conditions of any UAR. In no event shall an Award of UARs include any right to receive distributions or DERs in connection with the Units that are subject to such UARs or with respect to periods occurring prior to the exercise of such UARs.

ARTICLE IX.

RESTRICTED UNITS

9.1    General. Awards may be granted to Employees, Consultants, and Outside Directors in the form of Restricted Units. Restricted Units shall be awarded in such numbers and at such times as the Committee shall determine.

9.2    Restriction Period. At the time an Award of Restricted Units is granted, the Committee shall establish the Restriction Period applicable to such Restricted Units. Each Award of Restricted Units may have a different Restriction Period, in the discretion of the Committee. The Restriction Period applicable to a particular Award of Restricted Units shall not be changed except as permitted by Article IV or Section 9.4 of this Article.

9.3    UDRs. To the extent provided by the Committee, in its discretion, a grant of Restricted Units may provide that the distributions made by the Company with respect to the Restricted Units shall be subject to the same forfeiture and other restrictions as the Restricted Unit and, if restricted, such distributions shall be held, without interest, until the Restricted Unit vests or is forfeited with the UDR being paid or forfeited at the same time, as the case may be. In addition, the Committee may provide that such distributions be used to acquire additional Restricted Units for the Participant. Such additional Restricted Units may be subject to such vesting and other terms as the Committee may prescribe. Absent such a restriction on the UDRs in the Award Agreement, UDRs shall be paid to the holder of the Restricted Unit without restriction at the same time as cash distributions are paid by the Company to its unitholders. Notwithstanding the foregoing, UDRs shall only be paid in a manner that is either exempt from or in compliance with the requirements under Section 409A of the Code.

9.4    Other Terms and Conditions. Restricted Units awarded to a Participant under the Plan shall be represented by a unit certificate registered in the name of the Participant or, at the option of EnLink Midstream, in the name of a nominee of EnLink Midstream. Subject to Section 9.3 and unless otherwise provided in the Award Agreement, a Participant to whom Restricted Units have been awarded shall have the right to vote the Restricted Units and to enjoy all other unitholder rights with respect thereto, except that: (a) the Participant shall not be entitled to possession of the unit certificate representing the Restricted Units until the Restriction Period has expired; (b)

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EnLink Midstream shall retain custody of the Restricted Units during the Restriction Period; (c) the Participant may not sell, transfer, pledge, exchange, hypothecate, or otherwise dispose of the Restricted Units during the Restriction Period; and (d) a breach of the terms and conditions established by the Committee pursuant to the Award of the Restricted Units shall cause a forfeiture of the Restricted Units. At the time of an Award of Restricted Units, the Committee may, in its absolute discretion, prescribe additional terms, conditions, restrictions, and/or limitations applicable to the Restricted Units.

9.5    Payment for Restricted Units. A Participant shall not be required to make any payment for Restricted Units awarded to the Participant, except to the extent otherwise required by the Committee or by applicable law.

9.6    Miscellaneous. Nothing in this Article shall prohibit the exchange of Restricted Units issued under the Plan pursuant to a plan of reorganization for Units or securities of EnLink Midstream or another corporation that is a party to the reorganization, but the units or securities so received for Restricted Units shall, except as provided in Article IV or XIII, become subject to the restrictions applicable to the Award of such Restricted Units. Any Units received as a result of a unit split or distribution with respect to Restricted Units shall also become subject to the restrictions applicable to the Award of such Restricted Units.

ARTICLE X.

RESTRICTED INCENTIVE UNITS

10.1    General. Awards may be granted to Employees, Consultants, and Outside Directors in the form of Restricted Incentive Units. Restricted Incentive Units shall be awarded in such numbers and at such times as the Committee shall determine.

10.2    Restriction Period. At the time an Award of Restricted Incentive Units is granted, the Committee shall establish the Restriction Period applicable to such Restricted Incentive Units. Each Award of Restricted Incentive Units may have a different Restriction Period, in the discretion of the Committee. The Restriction Period applicable to a particular Award of Restricted Incentive Units shall not be changed except as permitted by Article IV or Section 10.4 of this Article.

10.3    DERs. Unless otherwise determined by the Committee at the Grant Date, DERs if granted on the specified number of Units covered by an Award of Restricted Incentive Units, shall, as specified in the Award Agreement, be either (a) paid with respect to such Restricted Incentive Units on the distribution date in cash or in unrestricted Units having a Fair Market Value equal to the amount of such distribution, or (b) deferred with respect to such Restricted Incentive Units and the amount or value thereof may automatically be deemed reinvested in additional Restricted Incentive Units and paid at the time payment is made with respect to such Award of Restricted Incentive Units. Notwithstanding the foregoing, DERs shall only be paid in a manner that is either exempt from or in compliance with the requirements under Section 409A of the Code.

10.4    Other Terms and Conditions. At the time of an Award of Restricted Incentive Units, the Committee may, in its absolute discretion, prescribe additional terms, conditions, restrictions, and/or limitations applicable to the Restricted Incentive Units prior to expiration of the Restriction Period. Unless otherwise provided in the Award Agreement, a Participant receiving an Award of Restricted Incentive Units shall not possess voting rights with respect to such Award. Restricted Incentive Units shall be satisfied by the delivery of cash or Units in the amount equal to the Fair Market Value of the specified number of Units covered by the Restricted Incentive Units, or a combination thereof, as determined by the Committee on the Grant Date or thereafter.

ARTICLE XI.

UNIT AWARDS

11.1    General. An Award may be in the form of a Unit Award. The terms, conditions, and limitations applicable to any Unit Awards granted pursuant to this Plan shall be determined by the Committee. Any Unit Award

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that is not an Award of Restricted Incentive Units shall be subject to the specific provisions for Restricted Units set forth in Article IX.

11.2    Bonus Units and Awards in Lieu of Obligations. For the avoidance of doubt, the Committee is authorized to grant Units as a bonus, or to grant Units or other Awards in lieu of obligations to pay cash or deliver other property under this Plan or under other bonus plans or compensatory arrangements; provided, that in the case of Participants subject to Section 16 of the Exchange Act, the amount of such grants remains within the discretion of the Committee to the extent necessary to ensure that acquisitions of Units or other Awards are exempt from liability under Section 16(b) of the Exchange Act. Units or Awards granted hereunder shall be subject to such other terms as shall be determined by the Committee. In the case of any grant of Units to an officer of the Company in lieu of salary or other cash compensation, the number of Units granted in place of such compensation shall be reasonable, as determined by the Committee.

ARTICLE XII.

CASH AWARDS; DERS

12.1    General. An Award may be in the form of a Cash Award. The terms, conditions, and limitations applicable to any Cash Awards granted pursuant to this Plan shall be determined by the Committee.

12.2    DERs. To the extent provided by the Committee, in its discretion, an Award (other than a Restricted Unit, Option, or UAR) may include a tandem DER grant, which may provide that such DERs shall be paid directly to the Participant, be reinvested into additional Awards, be credited to a bookkeeping account (with or without interest in the discretion of the Committee) subject to the same vesting restrictions as the tandem Award, or be subject to such other provisions or restrictions as determined by the Committee in its discretion. Absent a contrary provision in the Award Agreement, DERs shall be paid to the Participant without restriction at the same time as ordinary cash distributions are paid by the Company to its unitholders. Notwithstanding the foregoing, DERs shall only be paid in a manner that is either exempt from or in compliance with Section 409A of the Code.

ARTICLE XIII.

PERFORMANCE AWARDS

13.1    General. Without limiting the type or number of Awards that may be made under the other provisions of this Plan, an Award may be in the form of a Performance Award. The terms, conditions, and limitations applicable to any Performance Award granted to Participants pursuant to this Plan shall be determined by the Committee, subject to the limitations specified below. In no event shall a Performance Award include any right to receive distributions or DERs during periods occurring prior to the vesting of such Performance Award. The Committee shall set Performance Goals in its sole discretion which, depending on the extent to which they are met, will determine the value and/or amount of Performance Awards that will be paid out to the Participant and/or the portion of an Award that may be exercised.

13.2    Performance Awards. Performance Awards granted to Employees, Consultants, or Outside Directors shall be based on achievement of such Performance Goals and be subject to such terms, conditions, and restrictions as the Committee or its delegate shall determine, and shall generally be consistent with the terms and conditions set forth below. Performance Awards under this Plan shall be paid, vested, or otherwise deliverable on account of the attainment of the Performance Goals established and administered by the Committee prior to the earlier to occur of (x) 90 days after the commencement of the period of service to which the Performance Goal relates and (y) the lapse of 25% of the period of service (as scheduled in good faith at the time the goal is established), and in any event while the outcome is substantially uncertain. Achievement of Performance Goals in respect of such Performance Awards shall be measured over a performance period of up to ten years, as specified by the Committee.

(a)    Such a Performance Goal may be based on one or more business and individual performance criteria that apply to a Participant, one or more business units, divisions, or sectors of the Company, or

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the Company as a whole, and if so desired by the Committee, by comparison with a peer group of companies. A Performance Goal need not be the same for each Participant:

(i)    Business Criteria. The following business criteria for the Company, on a consolidated basis, and/or for specified subsidiaries or business or geographical units of the Company (except with respect to the total unitholder return and earnings per unit criteria), may be used by the Committee in establishing performance goals for such Performance Awards: (1) earnings per unit; (2) increase in revenues; (3) increase in cash flow; (4) increase in cash flow from operations; (5) increase in cash flow return; (6) return on net assets; (7) return on assets; (8) return on investment; (9) return on capital; (10) return on equity; (11) economic value added; (12) operating margin; (13) contribution margin; (14) net income; (15) net income per unit; (16) pretax earnings; (17) pretax earnings before interest, depreciation, and amortization; (18) pretax operating earnings after interest expense and before incentives, service fees, and extraordinary or special items; (19) total unitholder return; (20) debt reduction; (21) market share; (22) change in the Fair Market Value of the Units; (23) operating income; and (24) any of the above goals determined on an absolute or relative basis or as compared to the performance of a published or special index deemed applicable by the Committee including, but not limited to, the Standard & Poor’s 500 Stock Index or a group of comparable companies.

(ii)    Individual Performance Criteria. The grant, exercise, and/or settlement of Performance Awards may also be contingent on achievement of individual performance goals established by the Committee.

(b)    Unless otherwise stated, such a Performance Goal need not be based upon an increase or positive result under a particular business criterion and could include, for example, maintaining the status quo, performance relative to a peer group determined by the Committee, or limiting economic losses (measured, in each case, by reference to specific business criteria). Prior to the payment of any compensation based on the achievement of Performance Goals applicable to Performance Awards, the Committee or its delegate must certify in writing that applicable Performance Goals and any of the material terms thereof were, in fact, satisfied.

(c)    After the end of each performance period, the Committee shall determine the amount, if any, of the amount of the potential Performance Award payable to each Participant. Settlement of such Performance Awards shall be in cash, Units, other Awards, or other property (or combination thereof), in the discretion of the Committee. The Committee may, in its discretion, reduce the amount of a settlement otherwise to be made in connection with such Performance Awards. The Committee shall specify the circumstances in which such Performance Awards shall be paid or forfeited in the event of termination of employment by the Participant prior to the end of a performance period or settlement of Performance Awards.

(d)    The Committee shall adjust the Performance Goals (either up or down) and the level of the Performance Award that a Participant may earn under this Plan if it determines that the occurrence of external changes or other unanticipated business conditions have materially affected the fairness of the goals and have unduly influenced the Company’s ability to meet them, including without limitation, events such as material acquisitions, changes in the capital structure of the Company, and extraordinary accounting changes. In addition, Performance Goals and Performance Awards shall be calculated without regard to any changes in accounting standards that may be required by the Financial Accounting Standards Board after such Performance Goals are established. Further, in the event a period of service to which a Performance Goal relates is less than twelve months, the Committee shall have the right, in its sole discretion, to adjust the Performance Goals and the level of Performance Award opportunity.

ARTICLE XIV.

CHANGE OF CONTROL

14.1    Definition of Change of Control. A “Change of Control” means the occurrence of any one or more of the following: (a) the consummation of any transaction (including a merger or consolidation), the result of which is that any Person (other than GIP) becomes the “beneficial owner” (as defined in Rule 13d-3 under the Exchange Act), directly or indirectly, of 50% or more of the Voting Stock of EnLink Midstream or EnLink

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Manager, measured by voting power rather than number of shares, units, or the like; (b) the sale, transfer, or other disposition of all or substantially all of the assets of EnLink Midstream and the Working Subsidiaries of EnLink Midstream on an aggregate basis to any Person (other than one or more members of the Working Group and any of their respective direct or indirect Working Subsidiaries); or (c) the adoption of a plan relating to the liquidation or dissolution of EnLink Midstream. For the avoidance of doubt (and without limitation to the authority conferred on the Committee pursuant to the Plan), the definition of “Change of Control” contained in this Article XIV, shall apply to any Award Agreement under this Plan (or other agreement to the extent such agreement specifically references this Plan), whether described as “Change of Control” or ‘Change in Control”.

14.2    Effect on Outstanding Awards. Upon a Change of Control, and except as otherwise provided in an Award Agreement, the Committee, acting in its sole discretion without the consent or approval of any holder, shall affect one or more of the following alternatives, which may vary among individual holders and which may vary among Options or UARs (collectively “Grants”) held by any individual holder: (a) accelerate the time at which Grants then outstanding may be exercised so that such Grants may be exercised in full for a limited period of time on or before a specified date (before or after such Change of Control) fixed by the Committee, after which specified date all unexercised Grants and all rights of holders thereunder shall terminate; (b) require the mandatory surrender to the Company by selected holders of some or all of the outstanding Grants held by such holders (irrespective of whether such Grants are then exercisable under the provisions of this Plan) as of a date, before or after such Change of Control, specified by the Committee, in which event the Committee shall thereupon cancel such Grants and pay to each holder an amount of cash (or other consideration including securities or other property) per Unit equal to the excess, if any, of the amount calculated in Section 14.3 (the “Change of Control Price”) of the Units subject to such Grants over the exercise price(s) under such Grants for such Units (except that to the extent the exercise price under any such Grant is equal to or exceeds the Change of Control Price, in which case no amount shall be payable with respect to such Grant); or (c) make such adjustments to Grants then outstanding as the Committee deems appropriate to reflect such Change of Control; provided, however, that the Committee may determine in its sole discretion that no adjustment is necessary to Grants then outstanding; provided, further, however, that the right to make such adjustments shall include, but not require or be limited to, the modification of Grants such that the holder of the Grant shall be entitled to purchase or receive (in lieu of the total number of Units as to which an Option or UAR is exercisable (the “Total Units”) or other consideration that the holder would otherwise be entitled to purchase or receive under the Grant (the “Total Consideration”)), the number of units, other securities, cash, or property to which the Total Consideration would have been entitled to in connection with the Change of Control (i) (in the case of Options), at an aggregate exercise price equal to the exercise price that would have been payable if the Total Units had been purchased upon the exercise of the Grant immediately before the consummation of the Change of Control and (ii) in the case of UARs, if the UARs had been exercised immediately before the occurrence of the Change of Control.

14.3    Change of Control Price. The “Change of Control Price” shall equal the amount determined in the following clause (a), (b), (c), (d), or (e), whichever is applicable, as follows: (a) the price per Unit offered to holders of Units in any merger or consolidation; (b) the per Unit Fair Market Value of the Units immediately before the Change of Control without regard to assets sold in the Change of Control and assuming the Company has received the consideration paid for the assets in the case of a sale of the assets; (c) the amount distributed per Unit in a dissolution transaction; (d) the price per Unit offered to holders of Units in any tender offer or exchange offer whereby a Change of Control takes place; or (e) if such Change of Control occurs other than pursuant to a transaction described in clauses (a), (b), (c), or (d) of this Section 14.3, the per Unit Fair Market Value that may otherwise be obtained with respect to such Grants or to which such Grants track, as determined by the Committee as of the date determined by the Committee to be the date of cancellation and surrender of such Grants. In the event that the consideration offered to unitholders of the Company in any transaction described in this Section 14.3 or in Section 14.2 consists of anything other than cash, the Committee shall determine the fair cash equivalent of the portion of the consideration offered which is other than cash and such determination shall be binding on all affected Participants to the extent applicable to Awards held by such Participants.

14.4    Impact of Corporate Events on Awards Generally. In the event of a Change of Control or changes in the outstanding Units by reason of a recapitalization, reorganization, merger, consolidation, combination,

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exchange, or other relevant change in capitalization occurring after the date of the grant of any Award and except as otherwise provided for by this Section 14 or in an Award Agreement, any outstanding Awards and any Award Agreements evidencing such Awards shall be subject to adjustment by the Committee at its discretion, which adjustment may, in the Committee’s discretion, be described in the Award Agreement and may include, but not be limited to, adjustments as to the number and price of Units or other consideration subject to such Awards, accelerated vesting (in full or in part) of such Awards, conversion of such Awards into awards denominated in the securities or other interests of any successor Person, or the cash settlement of such Awards in exchange for the cancellation thereof; provided, however, if such Awards are unvested, they may be canceled without consideration. In the event of any such change in the outstanding Units, the aggregate number of Units available under this Plan may be appropriately adjusted by the Committee, whose determination shall be conclusive.

ARTICLE XV.

AMENDMENT AND TERMINATION

15.1    Plan Amendment and Termination. The Board may at any time suspend, terminate, amend, or modify the Plan, in whole or in part; provided, however, that no amendment or modification of the Plan shall become effective without the approval of such amendment or modification by the unitholders of EnLink Midstream (a) if such amendment or modification increases the maximum number of Units subject to the Plan (except as provided in Article IV) or changes the designation or class of persons eligible to receive Awards under the Plan, or (b) if counsel for EnLink Midstream determines that such approval is otherwise required by or necessary to comply with applicable law. The Plan shall terminate upon the earlier of (i) the termination of the Plan by the Board, or (ii) the expiration of ten years from September 17, 2020. Upon termination of the Plan, the terms and provisions of the Plan shall, notwithstanding such termination, continue to apply to Awards granted prior to such termination. No suspension, termination, amendment, or modification of the Plan shall adversely affect in any material way any Award previously granted under the Plan, without the consent of the Participant (or the Permitted Transferee (as defined below)) holding such Award.

15.2    Award Amendment. The Committee may amend the terms of any outstanding Award granted pursuant to this Plan, but no such amendment shall adversely affect in any material way the Participant’s (or a Permitted Transferee’s) rights under an outstanding Award without the consent of the Participant (or the Permitted Transferee) holding such Award; provided, however, that no amendment shall be made that would cause the exercise price of an Option or UAR to be less than the Fair Market Value of the Unit subject to the Option or UAR on the Grant Date.

ARTICLE XVI.

MISCELLANEOUS

16.1    Award Agreements and Termination of Employment. After the Committee grants an Award under the Plan to a Participant, EnLink Midstream, and the Participant shall enter into an Award Agreement setting forth the terms, conditions, restrictions, and/or limitations applicable to the Award and such other matters as the Committee may determine to be appropriate, it being understood that no such Award Agreement shall be necessary, if so determined in the Committee’s discretion, with respect to fully vested Unit Awards granted pursuant to Section 11.2. The terms and provisions of the respective Award Agreements need not be identical, but shall set forth (a) the number of Units subject to the Award, (b) the period during which the Award shall become vested or exercisable, as applicable, and (c) the date on which the Award shall expire if not previously exercised, as applicable. All Award Agreements shall be subject to the provisions of the Plan, and in the event of any conflict between an Award Agreement and the Plan, the terms of the Plan shall govern. Except as provided herein, the treatment of an Award upon a termination of employment or any other service relationship by and between a Participant and the Company shall be specified in the Award Agreement controlling such Award.

16.2    Stand-Alone, Additional, Tandem, and Substitute Awards. Awards granted under this Plan may, in the discretion of the Committee, be granted either alone or in addition to and subject to Section 409A of the Code, in tandem with, or, subject to Section 3.2, in substitution or exchange for, any other Award or any award granted under another plan of the Company, or of any business entity to be acquired by the Company, or any other

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right of a Participant to receive payment from the Company. Notwithstanding Article VII, such additional, tandem, and substitute or exchange Awards may be granted at any time. Such substitute Awards that are Options or Unit Appreciation Rights may have exercise prices less than the Fair Market Value of a Unit on the date of the substitution if such substitution complies with the requirements of Section 409A of the Code and other applicable laws and exchange rules. If an Award is granted in substitution or exchange for another Award, the Committee shall require the surrender of such other Award in consideration for the grant of the new Award.

16.3    Listing Conditions

(a)    As long as the Units are listed on a national securities exchange or system sponsored by a national securities association, the issuance of any Units pursuant to an Award shall be conditioned upon such Units being listed on such exchange or system and in compliance with the rules of such exchange. EnLink Midstream shall have no obligation to issue such Units unless and until such Units are so listed and the issuance would be in compliance with the rules of the exchange, and the right to exercise any Option or other Award with respect to such Units shall be suspended until such listing and compliance has been effected.

(b)    If at any time counsel to EnLink Midstream or its Affiliates shall be of the opinion that any sale or delivery of Units pursuant to an Award is or may in the circumstances be unlawful or result in the imposition of excise taxes on EnLink Midstream or its Affiliates under the statutes, rules, or regulations of any applicable jurisdiction, EnLink Midstream or its Affiliates shall have no obligation to make such sale or delivery, or to make any application or to effect or to maintain any qualification or registration under the Securities Act of 1933, as amended, or otherwise, with respect to Units or Awards, and the right to exercise any Option or other Award shall be suspended until, in the opinion of said counsel, such sale or delivery shall be lawful or will not result in the imposition of excise taxes on EnLink Midstream or its Affiliates.

(c)    Upon termination of any period of suspension under this Section 16.3, any Award affected by such suspension which shall not then have expired or terminated shall be reinstated as to all Units available before such suspension and as to Units which would otherwise have become available during the period of such suspension, but no such suspension shall extend the term of any Award.

16.4    Additional Conditions

(a)    Notwithstanding anything in the Plan to the contrary: (i) EnLink Midstream may, if it shall determine it necessary or desirable for any reason, at the time of grant of any Award or the issuance of any Units pursuant to any Award, require the recipient of the Award or such Units, as a condition to the receipt thereof, to deliver to EnLink Midstream a written representation of present intention to acquire the Award or such Units for his or her own account for investment and not for distribution; (ii) the certificate for Units issued to a Participant may include any legend which the Committee deems appropriate to reflect any restrictions on transfer; and (iii) all certificates for Units delivered under the Plan shall be subject to such stop transfer orders and other restrictions as the Committee may deem advisable under the rules, regulations, and other requirements of the SEC, any stock exchange upon which the Units are then quoted, any applicable federal or state securities law, and any applicable corporate law, and the Committee may cause a legend or legends to be put on any such certificates to make appropriate reference to such restrictions.

(b)    Each Participant to whom an Award is granted under this Plan may be required to agree in writing as a condition to the granting of such Award not to engage in conduct in competition with the Company during, and for a period after the termination of, such Participant’s employment with the Company as determined by the Committee (a “Non-Competition Agreement”); provided, however, to the extent a legally binding right to an Award within the meaning of Section 409A of the Code is created with respect to a Participant, the Non-Competition Agreement must be entered into by such Participant within 30 days following the creation of such legally binding right.

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16.5    Transferability

(a)    Permitted Transferees. The Committee may, in its discretion, permit a Participant to transfer all or any portion of an Option or UAR, or authorize all or a portion of an Option or UAR to be granted to a Participant to be on terms which permit transfer by such Participant; provided that, in either case the transferee or transferees must be any child, stepchild, grandchild, parent, stepparent, grandparent, spouse, former spouse, sibling, niece, nephew, mother-in-law, father-in-law, son-in-law, daughter-in-law, brother-in-law, or sister-in-law, including adoptive relationships, in each case with respect to the Participant, an individual sharing the Participant’s household (other than a tenant or employee of the Company), a trust in which any of the foregoing individuals have more than 50% of the beneficial interest, a foundation in which any of the foregoing individuals (or the Participant) control the management of assets, and any other entity in which any of the foregoing individuals (or the Participant) own more than 50% of the voting interests (collectively, “Permitted Transferees”); provided, further, that (i) there may be no consideration for any such transfer and (ii) subsequent transfers of Options or UARs transferred as provided above shall be prohibited except subsequent transfers back to the original holder of the Option or UAR and transfers to other Permitted Transferees of the original holder. Agreements evidencing Options or UARs with respect to which such transferability is authorized at the time of grant must be approved by the Committee and must expressly provide for transferability in a manner consistent with this Section 16.5.

(b)    Domestic Relations Orders. All Awards contemplated under this Plan may be transferred to a Permitted Transferee pursuant to a domestic relations order entered or approved by a court of competent jurisdiction upon delivery to the Company of written notice of such transfer and a certified copy of such order.

(c)    Other Transfers. Except as expressly permitted by Sections 16.5(a) and 16.5(b), Awards shall not be transferable other than by will or the laws of descent and distribution. Notwithstanding anything to the contrary in this Section 16.5, an Incentive Unit Option shall not be transferable other than by will or the laws of descent and distribution.

(d)    Effect of Transfer. Following the transfer of any Award as contemplated by Sections 16.5(a), 16.5(b), and 16.5(c), (i) such Award shall continue to be subject to the same terms and conditions as were applicable immediately prior to transfer; provided that the term “Participant” shall be deemed to refer to the Permitted Transferee, the recipient under a domestic relations order described in Section 16.5(b), or the estate or heirs of a deceased Participant or other transferee, as applicable, to the extent appropriate to enable the Participant to exercise the transferred Award in accordance with the terms of this Plan and applicable law, and (ii) the provisions of the Award relating to exercisability shall continue to be applied with respect to the original Participant and, following the occurrence of any applicable events described therein the Awards shall be exercisable by the Permitted Transferee, the recipient under a qualified domestic relations order, or the estate or heirs of a deceased Participant, as applicable, only to the extent and for the periods that would have been applicable in the absence of the transfer.

(e)    Procedures and Restrictions. Any Participant desiring to transfer an Award as permitted under Sections 16.5(a), 16.5(b), or 16.5(c) shall make application therefor in the manner and time specified by the Committee and shall comply with such other requirements as the Committee may require to assure compliance with all applicable securities laws. The Committee shall not give permission for such a transfer if (i) it would give rise to short swing liability under Section 16(b) of the Exchange Act or (ii) it may not be made in compliance with all applicable federal, state and foreign securities laws.

(f)    Registration. To the extent the issuance to any Permitted Transferee of any Units issuable pursuant to Awards transferred as permitted in this Section 16.5 is not registered pursuant to the effective registration statement of the Company generally covering the Units to be issued pursuant to this Plan to initial holders of Awards, the Company shall not have any obligation to register the issuance of any such Units to any such transferee.

16.6    Withholding Taxes. The Company and its Affiliates shall be entitled to deduct from any payment made under the Plan, regardless of the form of such payment, the amount of all applicable income and employment taxes required by law to be withheld with respect to such payment, may require the Participant to pay to the

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Company or an Affiliate thereof such withholding taxes prior to and as a condition of the making of any payment or the issuance or delivery of any Units under the Plan, and shall be entitled to deduct from any other compensation payable to the Participant any withholding obligations with respect to Awards under the Plan. In accordance with any applicable administrative guidelines it establishes, the Committee may allow a Participant to pay the amount of taxes required by law to be withheld from or with respect to an Award by (a) withholding Units from any payment of Units due as a result of such Award, or (b) permitting the Participant to deliver to the Company previously acquired Units, in each case having a Fair Market Value equal to the amount of such required withholding taxes. No payment shall be made and no Units shall be issued pursuant to any Award unless and until the applicable tax withholding obligations have been satisfied.

16.7    No Fractional Units. No fractional Units shall be issued or delivered pursuant to the Plan or any Award granted hereunder, and except as otherwise provided herein, no payment or other adjustment shall be made in respect of any such fractional Unit.

16.8    Notices. All notices required or permitted to be given or made under the Plan or any Award Agreement shall be in writing and shall be deemed to have been duly given or made if (a) delivered personally, (b) transmitted by first class registered or certified United States mail, postage prepaid, return receipt requested, (c) sent by prepaid overnight courier service, or (d) sent by email, telecopy, or facsimile transmission, answer back requested, to the Person who is to receive it at the address that such Person has theretofore specified by written notice delivered in accordance herewith. Such notices shall be effective (i) if delivered personally or sent by courier service, upon actual receipt by the intended recipient, (ii) if mailed, upon the earlier of five days after deposit in the mail or the date of delivery as shown by the return receipt therefor, or (iii) if sent by email, telecopy, or facsimile transmission, when the answer back is received. EnLink Midstream or a Participant may change, at any time and from time to time, by written notice to the other, the address that it or such Participant had theretofore specified for receiving notices. Until such address is changed in accordance herewith, notices hereunder or under an Award Agreement shall be delivered or sent (a) to a Participant at his or her address as set forth in the records of the Company or (b) to EnLink Midstream at the principal executive offices of EnLink Midstream clearly marked “Attention: LTIP Administrator.”

16.9    Binding Effect. The obligations of EnLink Midstream under the Plan shall be binding upon any successor corporation or organization resulting from the merger, consolidation, or other reorganization of EnLink Midstream, or upon any successor corporation or organization succeeding to all or substantially all of the assets and business of EnLink Midstream. The terms and conditions of the Plan shall be binding upon each Participant and his or her heirs, legatees, distributees, and legal representatives.

16.10    Severability. If any provision of the Plan or any Award Agreement is held to be illegal or invalid for any reason, the illegality or invalidity shall not affect the remaining provisions of the Plan or such agreement, as the case may be, but such provision shall be fully severable and the Plan or such agreement, as the case may be, shall be construed and enforced as if the illegal or invalid provision had never been included herein or therein.

16.11    No Restriction of Corporate Action. Nothing contained in the Plan shall be construed to prevent EnLink Midstream or any Affiliate from taking any corporate action (including any corporate action to suspend, terminate, amend, or modify the Plan) that is deemed by EnLink Midstream or such Affiliate to be appropriate or in its best interest, whether or not such action would have an adverse effect on the Plan or any Awards made or to be made under the Plan. No Participant or other Person shall have any claim against EnLink Midstream or any Affiliate as a result of such action.

16.12    Governing Law. The Plan shall be governed by and construed in accordance with the internal laws (and not the principles relating to conflicts of laws) of the State of Delaware except as superseded by applicable federal law.

16.13    No Right, Title or Interest in Company Assets. No Participant shall have any rights as a unitholder of EnLink Midstream as a result of participation in the Plan until the date of issuance of a unit certificate in his or her name and, in the case of Restricted Units, unless and until such rights are granted to the Participant

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pursuant to the Plan. To the extent any Participant acquires a right to receive payments from the Company under the Plan, such rights shall be no greater than the rights of an unsecured general creditor of the Company, and such Participant shall not have any rights in or against any specific assets of the Company. All of the Awards granted under the Plan shall be unfunded.

16.14    Risk of Participation. Nothing contained in the Plan shall be construed either as a guarantee by EnLink Midstream or its Affiliates, or their respective unitholders, directors, officers, or employees, of the value of any assets of the Plan or as an agreement by EnLink Midstream or its Affiliates, or their respective unitholders, directors, officers, or employees, to indemnify anyone for any losses, damages, costs, or expenses resulting from participation in the Plan.

16.15    Section 409A of the Code. All Awards under this Plan are intended either to be exempt from, or to comply with the requirements of Section 409A of the Code, and this Plan and all Awards shall be interpreted and operated in a manner consistent with that intention. Notwithstanding anything in this Plan to the contrary, if any Plan provision or Award under this Plan would result in the imposition of an applicable tax under Section 409A of the Code, that Plan provision or Award shall be reformed (or, if applicable, a provision from the Prior Plan shall remain in effect for an Award granted thereunder to the extent necessary) to avoid imposition of the applicable tax and no such action shall be deemed to adversely affect the Participant’s rights to an Award.

16.16    No Guarantee of Tax Consequences. No Person connected with the Plan in any capacity, including, but not limited to, EnLink Midstream and its Affiliates and their respective directors, officers, agents, and employees, makes any representation, commitment, or guarantee that any tax treatment, including, but not limited to, federal, state, and local income, estate, and gift tax treatment, will be applicable with respect to any Awards or payments thereunder made to or for the benefit of a Participant under the Plan or that such tax treatment will apply to or be available to a Participant on account of participation in the Plan.

16.17    Continued Employment or Service. Nothing contained in the Plan or in any Award Agreement shall confer upon any Participant the right to continue in the employ or service of the Company, or interfere in any way with the rights of the Company to terminate a Participant’s employment or service at any time, with or without cause.

16.18    Miscellaneous. Headings are given to the articles and sections of the Plan solely as a convenience to facilitate reference. Such headings shall not be deemed in any way material or relevant to the construction of the Plan or any provisions hereof. The use of the masculine gender shall also include within its meaning the feminine. Wherever the context of the Plan dictates, the use of the singular shall also include within its meaning the plural, and vice versa.

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EX-10.13

Exhibit 10.13

PERFORMANCE UNIT AGREEMENT

THIS PERFORMANCE UNIT AGREEMENT (this “Agreement”) is entered into by and between EnLink Midstream, LLC, a Delaware limited liability company (the “Company”), and _____________ (“Participant”) as of the Grant Date (as defined below).

WITNESSETH:

WHEREAS, the EnLink Midstream, LLC 2014 Long-Term Incentive Plan was adopted by the Company, effective February 5, 2014 (as amended, the “Plan”), for the benefit of certain employees and consultants of the Company or its Affiliates (as defined in the Plan), and non-employee directors of EnLink Manager (as defined in the Plan), the managing member of the Company; and

WHEREAS, the Committee (as defined in the Plan) is responsible for granting Awards (as defined in the Plan) in accordance with the Plan; and

WHEREAS, Participant is eligible to participate in the Plan and the Committee has authorized the grant to Participant of the “Subject Award” (as defined in Section 2 of this Agreement), which shall be subject to certain restrictions pursuant to the Plan and upon the terms set forth herein.

NOW, THEREFORE, in consideration of the premises and the mutual covenants and agreements hereinafter set forth, the Company and Participant hereby agree as follows:

1.    Definitions. Capitalized terms used herein and not otherwise defined herein shall have the meaning ascribed to them in the Plan.

“Cause” shall have the meaning ascribed to such term (i) in the Severance Agreement (which meaning shall include any procedural aspects for establishing a termination for Cause pursuant to the Severance Agreement), or (ii) in the Plan if no Severance Agreement exists.

“CF Tranche RIUs” means the Tranche RIUs with a Performance Goal based on Cash Flow.

“Change in Control” shall have the meaning ascribed to such term (i) in the Change in Control Agreement (which meaning shall include any procedural aspects for establishing a termination for Change in Control pursuant to the Change in Control Agreement), or (ii) in the Plan if no Change in Control Agreement exists.

“Change in Control Agreement” means (i) the Change in Control Agreement, as amended, if any, between Participant and EnLink Midstream Operating, LP, a Delaware limited partnership (or its successor), that is in effect as of the Grant Date or (ii) if Participant is not a party to a Change in Control Agreement contemplated in clause (i) of this definition, the most recent form of change in control agreement that has been included as an exhibit to the Company’s filings with the U.S. Securities and Exchange Commission (the “SEC”) prior to the Grant Date.

“Company Group” means the Company, EnLink Midstream Manager, LLC, EnLink Midstream Partners, LP, EnLink Midstream GP, LLC, EnLink Midstream Operating, LP and each of their respective direct or indirect subsidiaries.

“Early Retirement” means (i) Participant’s Retirement on or after his or her attainment of age 55, and (ii) immediately prior to such Retirement, the number of such Participant’s years of continuous service with the Company or its Affiliates (including continuous service with a predecessor employer that is taken into account pursuant to an acquisition or other transaction agreement) equals or exceeds 10 years. For the avoidance of doubt, a Normal Retirement shall be deemed to occur, if at all, to the extent Participant meets the applicable age and service requirements to be eligible for both Early Retirement and Normal Retirement.

“End Date” means the date on which the Cumulative Performance Period ends.

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“Good Reason” (i) shall have the meaning ascribed to such term in the Severance Agreement (which meaning shall include any procedural aspects for establishing a termination for Good Reason pursuant to the Severance Agreement), or, (ii) if no Severance Agreement exists, then shall mean any of the following, without Participant’s consent: (w) a material reduction in Participant’s base annual salary; (x) a material adverse change in Participant’s authority, duties, or responsibilities (other than temporarily while Participant is physically or mentally incapacitated or as required by applicable law); (y) a material breach by the Company of any material provision of this Agreement (or by a member of the Company Group of any material provision of any other written agreement between Participant and any member of the Company regarding his or her services thereto); or (z) the Company requires that Participant move his or her principal place of service to a location that is thirty (30) or more miles from his or her current principal place of service and the new location is farther from his or her primary residence. Participant may not terminate his or her employment for “Good Reason” unless (A) Participant gives the Company written notice of the event within thirty (30) days of the occurrence of the event, (B) the Company fails to remedy the event within thirty (30) days following its receipt of the notice, and (C) Participant terminates his or her service with the Company and its Affiliates within sixty (60) days following the Company’s receipt of written notice.

“Grant Date” means [●].

“Intermediate Retirement” means (i) Participant’s Retirement on or after his or her attainment of age 60, and (ii) immediately prior to such Retirement, the number of such Participant’s years of continuous service with the Company or its Affiliates (including continuous service with a predecessor employer that is taken into account pursuant to an acquisition or other transaction agreement) is less than five years.

“Normal Retirement” means (i) Participant’s Retirement on or after his or her attainment of age 60, and (ii) immediately prior to such Retirement, the number of such Participant’s years of continuous service with the Company or its Affiliates (including continuous service with a predecessor employer that is taken into account pursuant to an acquisition or other transaction agreement) equals or exceeds five years; provided, however, that, a Normal Retirement will not occur if Participant’s Retirement occurs prior to the one-year anniversary of the commencement of the First Performance Period unless the Committee approves the same in its sole discretion. For the avoidance of doubt, a Normal Retirement shall be deemed to occur, if at all, to the extent Participant meets the applicable age and service requirements to be eligible for both Early Retirement and Normal Retirement.

“Performance Goal” means, with respect to a Subject Tranche, the applicable Performance Goal as set forth in Schedule B to this Agreement.

“Performance Period” means the applicable measurement period under this Agreement for purposes of determining attainment of the Performance Goal with respect to a Subject Tranche.

Under this Agreement, the following four Performance Periods shall apply to the Performance Goal based on TSR:

•The “First Performance Period” shall comprise the period commencing on January 1, [●] and ending on December 31st of that same year;

•The “Second Performance Period” shall comprise the period commencing on January 1, [●] and ending on December 31st of that same year;

•The “Third Performance Period” shall comprise the period commencing on January 31, [●] and ending on December 31st of that same year; and

•The “Cumulative Performance Period” shall comprise the period commencing on January 1, [●] and ending on December 31, [●].

Under this Agreement, the following three Performance Periods shall apply to the Performance Goal based on Cash Flow:

•The First Performance Period;

•The Second Performance Period; and

•The Third Performance Period.

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“Prorated Amount” means a number equal to the total number of Certified RIUs multiplied by a fraction (i) the numerator of which is the number of days that elapse from the commencement of the Cumulative Performance Period to, as applicable, the date of a Qualifying Termination or the date of an Early Retirement or an Intermediate Retirement, and (ii) the denominator of which is the total number of days in the Cumulative Performance Period.

“Qualifying Disability” means, as applicable, the earliest to occur of: (i) Participant’s “disability” within the meaning of Treas. Reg. Section 1.409A-3(i)(4), or (ii) Participant’s Separation from Service that is incurred after Participant has become disabled and qualified to receive benefits under the Company’s long-term disability plan.

“Qualifying Termination” means Participant’s Separation from Service with the Company and its Affiliates due to (i) an involuntary termination of Participant by the Company or its Affiliates for reasons other than Cause or Qualifying Disability or (ii) a termination by Participant for Good Reason.

“Retirement” means Participant’s Separation from Service with the Company and its Affiliates for reasons other than Cause due to his or her retirement; provided that (i) Participant provides the Company with at least 90 days’ advance written notice of such retirement, which notice may be waived by the Chief Executive Officer of EnLink Manager and (ii) such retirement is otherwise approved by the Chief Executive Officer of EnLink Manager in his or her sole discretion. Notwithstanding any provision herein to the contrary, Participant will not be eligible to receive any benefits hereunder with respect to Early Retirement or Intermediate Retirement, if such Participant is eligible to receive benefits with respect to Normal Retirement under any other Award.

“Retirement Conditions” means, with respect to Participant’s Retirement, (i) Participant’s compliance with Schedule D through the date of his or her Retirement and (ii) solely if requested by the Company in its sole discretion, Participant shall deliver to the Company, prior to his or her Retirement, an acknowledgment of his or her obligations to comply with Schedule D (it being understood that Participant agrees to the terms and conditions set forth in Schedule D if he or she engages in Early Retirement, Intermediate Retirement, or Normal Retirement regardless of whether he or she delivers any such acknowledgment).

“Separation from Service” shall have the meaning ascribed to such term in the guidance issued under Section 409A of the Code.

“Severance Agreement” means (i) the Severance Agreement, as amended, if any, between Participant and EnLink Midstream Operating, LP, a Delaware limited partnership (or its successor), that is in effect as of the Grant Date or (ii) if Participant is not a party to a Severance Agreement contemplated in clause (i) of this definition, the most recent form of severance agreement that has been included as an exhibit to the Company’s filings with the SEC prior to the Grant Date.

“Subject Tranche” means, as further specified in Schedule A, the portion of the Subject Award (i.e., a designated number of Restricted Incentive Units) that relates to a particular Performance Period and particular Performance Goal.

“TrancheRIUs” means the Restricted Incentive Units that comprise a Subject Tranche.

“TrancheValuation Date” means, with respect to a Subject Tranche, the last day of the Performance Period applicable to the Subject Tranche.

“TSR Tranche RIUs” means the Tranche RIUs with a Performance Goal based on TSR.

2.    Performance Unit Award. On the terms and conditions and subject to the restrictions, including forfeiture, hereinafter set forth, the Company hereby grants to Participant, and Participant hereby accepts, an award of [●] Restricted Incentive Units (the “Subject Award”). The Restricted Incentive Units granted hereunder shall be evidenced by the Committee in a book entry or in such other manner as the Committee may determine.

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3.    Vesting; Forfeiture.

(a)    In General. The number of Tranche RIUs, if any, that are eligible for vesting as Certified RIUs hereunder shall be based on the Committee’s determination of attainment and associated certification of the applicable Performance Goal, in each case, made in accordance with this Section 3, Schedule B, and Section 4 below. The Committee shall make Performance Goal attainment and certification determinations separately with respect to each Subject Tranche. If at least a “Threshold” performance level (“Qualifying Performance”) is attained and certified, then the applicable number of Tranche RIUs determined under Schedule B and Section 4 below (the “Certified RIUs”) shall vest and Units applicable to such Certified RIUs shall be paid out to Participant in accordance with Section 4 below so long as Participant remains in the continuous service of the Company or its Affiliates until the earlier of (i) the End Date or (ii) the date on which the earliest event occurs in accordance with and pursuant to Section 3(c) or Section 3(d) below whereby the relevant Certified RIUs or Tranche RIUs vest or expressly remain eligible for vesting. For the avoidance of doubt: (x) if a “Below Threshold” performance level is attained and certified, then no Certified RIUs shall relate to the Tranche RIUs and all such Tranche RIUs shall be forfeited; (y) if at least Qualifying Performance is attained and certified, but such performance does not equal or exceed the “Target” performance level pursuant to Schedule B, then the number of Tranche RIUs that exceeds the applicable number of the Certified RIUs shall be forfeited; and (z) if at least Qualifying Performance is attained and certified, but the Certified RIUs are adjusted for the Prorated Amount pursuant to Section 3(c) below, then the number of Tranche RIUs, if any, that exceeds the applicable number of the Certified RIUs, as adjusted for the Prorated Amount, shall be forfeited. All forfeitures under this Agreement shall be at no cost to the Company or Participant.

(b)    Separation from Service in General. Except as otherwise provided in Section 3(c) below, if Participant experiences a Separation from Service with the Company and its Affiliates prior to the End Date, then he or she will forfeit the Subject Award.

(c)    Special Vesting/Forfeiture Conditions. Tranche RIUs and Certified RIUs, if any, shall be subject to the following vesting and forfeiture conditions, which shall apply in connection with a Qualifying Termination, Retirement, Change in Control, Participant’s death, or Qualifying Disability that occurs at a time when there are no grounds in existence for the involuntary termination of Participant (in good faith) by the Company or its Affiliates for Cause:

(i)    General. Except as otherwise provided in this Section 3(c), if a Qualifying Termination, an Early Retirement, an Intermediate Retirement, or a Normal Retirement occurs while the Subject Award is outstanding, then the Tranche RIUs or Certified RIUs, if any, as applicable, shall remain eligible for vesting or vest, if at all, pursuant to clause (x), (y), or (z) below and subclauses (1) or (2) thereunder as follows:

(x)    Qualifying Termination:

(1)    If such a Qualifying Termination occurs on or after a given Tranche Valuation Date for which Qualifying Performance is attained and certified, then such Certified RIUs shall vest (without adjustment for the Prorated Amount) as of the date of such Qualifying Termination.

(2)    If such a Qualifying Termination occurs prior to a given Tranche Valuation Date, then the applicable Tranche RIUs shall remain eligible for vesting, subject to the attainment and certification of Qualifying Performance and any Certified RIUs relating to such Tranche RIUs shall be adjusted for the Prorated Amount.

(y)    Early Retirement or Intermediate Retirement:

(1)    If such an Early Retirement or Intermediate Retirement occurs on or after a given Tranche Valuation Date for which Qualifying Performance is attained and certified, then, subject to Participant satisfying the Retirement Conditions, such Certified RIUs shall vest(without adjustment for the Prorated Amount) as of the date of such Early Retirement or Intermediate Retirement, as applicable.

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(2)    If such an Early Retirement or Intermediate Retirement occurs prior to a given Tranche Valuation Date, then, subject to Participant satisfying the Retirement Conditions, the applicable Tranche RIUs shall remain eligible for vesting, subject to the attainment and certification of Qualifying Performance and any Certified RIUs relating to such Tranche RIUs shall be adjusted for the Prorated Amount.

(z)    Normal Retirement:

(1)    If such a Normal Retirement occurs on or after a given Tranche Valuation Date for which Qualifying Performance is attained and certified, then, subject to Participant satisfying the Retirement Conditions, such Certified RIUs shall vest (without adjustment for the Prorated Amount) as of the date of such Normal Retirement.

(2)    If such a Normal Retirement occurs prior to a given Tranche Valuation Date, then, subject to Participant satisfying the Retirement Conditions, such Tranche RIUs shall remain eligible for vesting, subject to the attainment and certification of Qualifying Performance (without adjustment for the Prorated Amount).

(ii)    Double Trigger - Advance/Concurrent Change in Control. If a Change in Control occurs while the Subject Award is outstanding and, on or after such Change in Control, a Qualifying Termination, an Early Retirement, an Intermediate Retirement, or a Normal Retirement occurs during a Performance Period, then the Tranche RIUs or Certified RIUs, if any, as applicable, shall remain eligible for vesting or vest, if at all, pursuant to clause (x) or (y) as follows:

(x)    Qualifying Termination: If such a Qualifying Termination occurs prior to a given Tranche Valuation Date, then (A) the relevant TSR Tranche RIUs shall remain eligible for vesting subject to the attainment and certification of Qualifying Performance (without adjustment for the Prorated Amount) and (B) the relevant CF Tranche RIUs shall be deemed to vest as Certified RIUs at the “Target” performance level (without adjustment for the Prorated Amount) as of the date of such Qualifying Termination. For the avoidance of doubt, such a Qualifying Termination that occurs on or after a given Tranche Valuation Date is addressed in Section 3(c)(i)(x)(1) above or Section 3(d) below, as applicable.

(y)    Early Retirement, Intermediate Retirement, or Normal Retirement: If such an Early Retirement, an Intermediate Retirement, or a Normal Retirement occurs prior to a given Tranche Valuation Date, then, subject to Participant satisfying the Retirement Conditions, (A) the relevant TSR Tranche RIUs shall remain eligible for vesting subject to the attainment and certification of Qualifying Performance (without adjustment for the Prorated Amount) and (B) the relevant CF Tranche RIUs shall be deemed to vest as Certified RIUs at the “Target” performance level (without adjustment for the Prorated Amount) as of the date of such Early Retirement, Intermediate Retirement, or Normal Retirement, as applicable. For the avoidance of doubt, each of such an Early Retirement, an Intermediate Retirement, or a Normal Retirement that occurs on or after a given Tranche Valuation Date is addressed in Section 3(c)(i)(y)(1) above, 3(c)(i)(z)(1) above, or Section 3(d) below, as applicable.

(iii)    Double Trigger – Subsequent Change in Control. If, subsequent to the occurrence of a Qualifying Termination, an Early Retirement, an Intermediate Retirement, or a Normal Retirement during a Performance Period, a Change in Control occurs while the Subject Award is outstanding, then the Tranche RIUs or Certified RIUs, if any, as applicable, shall remain eligible for vesting or vest, if at all, pursuant to clause (x), (y), or (z) as follows:

(x)    Qualifying Termination: If such a Qualifying Termination occurs prior to a given Tranche Valuation Date, then (A) the relevant TSR Tranche RIUs shall remain eligible for vesting, subject to the attainment and certification of Qualifying Performance and any Certified RIUs relating to such TSR Tranche RIUs shall be adjusted for the Prorated Amount and (B) the relevant CF Tranche RIUs shall be deemed to vest as Certified RIUs at the “Target” performance level, as adjusted for the Prorated Amount, as of the date of such Change in Control. For the avoidance of doubt, such a Qualifying Termination that occurs on or after a given Tranche Valuation Date is addressed in Section 3(c)(i)(x)(1) above or Section 3(d) below, as applicable.

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(y)    Early Retirement or Intermediate Retirement: If such an Early Retirement or Intermediate Retirement occurs prior to a given Tranche Valuation Date, then, subject to Participant satisfying the Retirement Conditions, (A) the relevant TSR Tranche RIUs shall remain eligible for vesting, subject to the attainment and certification of Qualifying Performance and any Certified RIUs relating to such TSR Tranche RIUs shall be adjusted for the Prorated Amount and (B) the relevant CF Tranche RIUs shall be deemed to vest as Certified RIUs at the “Target” performance level, as adjusted for the Prorated Amount, as of the date of such Change in Control. For the avoidance of doubt, such an Early Retirement or Intermediate Retirement that occurs on or after a given Tranche Valuation Date is addressed in Section 3(c)(i)(y)(1) above or Section 3(d) below, as applicable.

(z)    Normal Retirement: If such a Normal Retirement occurs prior to a given Tranche Valuation Date, then, subject to Participant satisfying the Retirement Conditions, (A) the relevant TSR Tranche RIUs shall remain eligible for vesting, subject to the attainment and certification of Qualifying Performance (without adjustment for the Prorated Amount) and (B) the relevant CF Tranche RIUs shall be deemed to vest as Certified RIUs at the “Target” performance level (without adjustment for the Prorated Amount) as of the date of such Change in Control. For the avoidance of doubt, such a Normal Retirement that occurs on or after a given Tranche Valuation Date is addressed in Section 3(c)(i)(z)(1) above or Section 3(d) below, as applicable.

(iv)    Death. If Participant’s death occurs while the Subject Award is outstanding, then the Tranche RIUs or Certified RIUs, if any, as applicable, shall vest, if at all, pursuant to clause (x) or (y) as follows:

(x)    If such a death occurs on or after a given Tranche Valuation Date for which Qualifying Performance is attained and certified, then the relevant Certified RIUs shall vest (without adjustment for the Prorated Amount) as of the date of such death.

(y)    If such a death occurs prior to a given Tranche Valuation Date, then the relevant Tranche RIUs shall be deemed to vest as Certified RIUs at the “Target” performance level (without adjustment for the Prorated Amount) as of the date of such death.

(v)    Disability. If the Participant’s Qualifying Disability occurs while the Subject Award is outstanding, then the Tranche RIUs or Certified RIUs, if any, as applicable, shall vest, if at all, pursuant to clause (x) or (y) as follows:

(x)    If such Qualifying Disability occurs on or after a given Tranche Valuation Date for which Qualifying Performance is attained and certified, then the relevant Certified RIUs shall vest (without adjustment for the Prorated Amount) as of the date of such Qualifying Disability.

(y)    If such Qualifying Disability occurs prior to a given Tranche Valuation Date, then the relevant Tranche RIUs shall be deemed to vest as Certified RIUs at the “Target” performance level (without adjustment for the Prorated Amount) as of the date of such Qualifying Disability.

(vi)    Section 409A Considerations.

(x)    Change in Control. To the extent that the vesting under Section 3(c)(iii) or Section 3(d) relates to any Subject Tranche that is subject to Section 409A of the Code (a “409A Subject Tranche”), such vesting shall occur only if the applicable Change in Control constitutes “change in the ownership or effective control” of the Company within the meaning of Treas. Reg. Section 1.409A-3(i)(5). If such Change in Control does not constitute such a “change in the ownership or effective control” of the Company, the Tranche RIUs with respect to such 409A Subject Tranche shall remain eligible for vesting in accordance with the other provisions of this Section 3, as applicable.

(y)    Qualifying Disability. To the extent that the vesting under Section 3(c)(vi) relates to any 409A Subject Tranche, (A) such vesting shall occur only if Participant incurs a “disability”

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within the meaning of Treas. Reg. Section 1.409A-3(i)(4), or (B) if clause (A) is not applicable, such vesting of the Certified RIUs described in Section 3(c)(vi) shall be dependent on Participant incurring a Separation from Service in connection with his or her Qualifying Disability. In such event, the Separation from Service shall be deemed as a Normal Retirement that is not subject to the Retirement Conditions solely for purposes of establishing the timing for when such vesting is deemed to occur for purposes of this Agreement.

(d)    Change in Control Resulting in Delisting. Anything to the contrary herein notwithstanding, if a Change in Control occurs while the Subject Award is outstanding that results in the Company ceasing to be listed on a national securities exchange (a “Delisting Change in Control”), then the Tranche RIUs or Certified RIUs, if any, as applicable, shall vest, if at all, as follows:

(i)    If such a Delisting Change in Control occurs on or after a given Tranche Valuation Date for which Qualifying Performance is attained and certified, then, subject to Participant satisfying the Retirement Conditions applicable to his or her Retirement, if any, the relevant Certified RIUs (without adjustment for the Prorated Amount) shall be deemed to vest as of (A) the applicable date pursuant to Section 3(c) if such Delisting Change in Control occurs on or after a Qualifying Termination, Retirement, death, or Qualifying Disability, (B) the date of a Qualifying Termination, Retirement, death, or Qualifying Disability, as applicable, if the Delisting Change in Control occurs prior to a Qualifying Termination, Retirement, death, or Qualifying Disability, as applicable, or (C) the applicable date pursuant to Section 3(a) above if not otherwise vested pursuant to the foregoing clauses.

(ii)    If such a Delisting Change in Control occurs prior to a given Tranche Valuation Date, then, subject to Participant satisfying the Retirement Conditions applicable to his or her Retirement, if any, the relevant Tranche RIUs shall be deemed to vest as Certified RIUs at the “Target” performance level as of (A) the date of such Delisting Change in Control if the Delisting Change in Control occurs on or after a Qualifying Termination, Retirement, death, or Qualifying Disability, as applicable (in which case, such vesting shall be adjusted for the Prorated Amount for a Qualifying Termination, an Early Retirement, and an Intermediate Retirement and otherwise occur without adjustment for the Prorated Amount), (B) the date of a Qualifying Termination, Retirement, death, or Qualifying Disability, as applicable, if the Delisting Change in Control occurs prior to the Qualifying Termination, Retirement, death, or Qualifying Disability, as applicable, which vesting shall occur without adjustment for the Prorated Amount, or (C) the applicable date pursuant to Section 3(a) above if not otherwise vested pursuant to the foregoing clauses.

To the extent vesting applies pursuant to preceding paragraphs (i) and (ii) and the relevant Delisting Change in Control occurs prior to the delivery of Units, if any, described in Section 4 below, then the Company shall pay (in securities of a successor or surviving Person that are listed on a national securities exchange or if no such securities exist, then in cash) Participant an amount equal to the Change of Control Price (as defined in the Plan) for each of the relevant Certified RIUs for purposes of Section 4 below.

4.    Certification of Performance; Payment.

(a)    Certification. As soon as reasonably practicable following the close of a Performance Period that relates to a Subject Tranche, the Committee shall determine and certify (i) the extent to which the applicable Performance Goal as described on Schedule B is attained, and (ii) if at least Qualifying Performance is attained with respect to such Performance Goal (i.e., Qualifying Performance applies for such Subject Tranche), the number of the Certified RIUs that relate to such Subject Tranche. Such certification shall be final, conclusive, and binding on Participant, and on all other Persons, to the maximum extent permitted by law; provided, however, that Participant shall have the right at all reasonable times prior to or after any such certification to audit the books and records of the Committee and the Company, including the ability to make and retain copies of same, to the extent reasonably necessary to verify compliance with the terms and conditions of this Agreement, including, in particular, the calculations, workpapers, or other documents prepared and used in connection with making any such certification. For the avoidance of doubt, the Committee shall be deemed to have completed the certifications with respect to clauses (i) and (ii) above when vesting is deemed to occur at the “Target” performance level pursuant to Section 3(c) or Section 3(d).

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(b)    Payment. Subject to the “Six-Month Delay Toggle” (as defined in Section 15 of this Agreement), Units representing Certified RIUs shall be delivered to Participant no later than (i) if vesting occurs pursuant to Section 3(c), the 15th day of the third calendar month following the date on which vesting occurs (it being understood that in circumstances where Tranche RIUs remain eligible for vesting as Certified RIUs pursuant to Section 3(c), Units relating to the applicable Certified RIUs shall be delivered no later than the 15th day of the third calendar month following the relevant Tranche Valuation Date) and (ii) otherwise, 75 days following the End Date. Such Units representing Certified RIUs shall be delivered free of all restrictions to Participant or Participant’s beneficiary or estate, as the case may be (it being understood that the entry on the transfer agent’s books or the delivery of the certificate(s) with respect to such Units shall constitute delivery of such Units for purposes of this Agreement).

5.    Distribution Equivalent Payment Rights. Each Subject Tranche hereunder includes a tandem award of Distribution Equivalent Rights that shall apply throughout the period in which the Subject Award is outstanding. Such Distribution Equivalent Rights shall entitle Participant to receive cash payments equal to the cash distributions made by the Company (on a per Unit basis) in respect of its outstanding Units generally (“General Distributions”). Except as provided below, such cash payments (“Distribution Equivalent Payments”) shall be payable to the extent the Tranche RIUs that relate to such Subject Tranche ultimately vest as Certified RIUs pursuant to this Agreement. No Distribution Equivalent Payments shall be made if such Tranche RIUs do not vest as Certified RIUs, are forfeited, or are otherwise canceled. Accordingly, (i) payment of such Distribution Equivalent Payments shall be made at the same time, and shall be subject to the same conditions, as are applicable to the delivery of Units with respect to such Certified RIUs (the “Delivered Units”), and (ii) the amount of such Distribution Equivalent Payments shall be equal to the aggregate General Distributions that would have been made on the Delivered Units if such Delivered Units were held by Participant from the Grant Date through the date on which such Delivered Units are delivered to Participant. No interest shall be credited on any Distribution Equivalent Payments.

6.    Taxes.

(a)    REPRESENTATION. PARTICIPANT REPRESENTS THAT PARTICIPANT IS NOT RELYING ON THE COMPANY OR ITS AFFILIATES FOR ANY TAX ADVICE IN CONNECTION WITH THE RESTRICTED INCENTIVE UNITS AND THAT PARTICIPANT HAS BEEN, OR IS OTHERWISE HEREBY, ADVISED TO CONSULT WITH ITS OWN TAX ADVISOR WITH RESPECT TO THE AWARD OF RESTRICTED INCENTIVE UNITS UNDER THIS AGREEMENT.

(b)    Withholding Matters.

(i)    The Company, its Affiliates, as applicable, and Participant shall comply with all federal and state laws and regulations respecting the withholding, deposit, and payment of any income, employment (including Federal Insurance Contributions Act (“FICA”) taxes), or other taxes relating to the Subject Award, including with respect to Distribution Equivalent Payments described in Section 5 of this Agreement. Such withholding shall be made by the Company or its Affiliates in accordance with the applicable withholding laws and regulations that are in effect at the time such withholding is required. Participant shall pay to the Company or its Affiliates, or make arrangements satisfactory to the Company or its Affiliates regarding payment of, any such withholding with respect to (A) Distribution Equivalent Payments and (B) the Restricted Incentive Units.

(ii)    Participant shall, to the extent permitted by law, have the right to elect for the Company or its Affiliates to withhold Units to which Participant is otherwise entitled upon the vesting of the Restricted Incentive Units (or Participant may deliver to the Company other unrestricted Units owned by Participant or deliver to the Company or its Affiliates Units that Participant has previously acquired), in each case valued at the Fair Market Value of such Units at the time of such withholding by, or delivery to, the Company or its Affiliates, to satisfy the obligation of Participant under Section 6(b)(i) of this Agreement (it being understood that the Fair Market Value of all such Units withheld or delivered may not exceed the amount of withholding due based on the withholding rate(s) applied by the Company, in its discretion, in accordance with the applicable withholding laws and regulations that are in effect at the time such withholding is required); provided, however, that in no event shall any Units (or cash) that may be delivered hereunder be used to satisfy any FICA taxes that become due as a result of Participant being or becoming eligible for Retirement, Qualifying Termination or Qualifying Disability without

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having undergone such termination. Any payment of required withholding taxes by Participant in the form of Units shall not be permitted if it would result in an accounting charge with respect to such Units used to pay such taxes unless otherwise approved by the Committee.

(iii)    Any provision of this Agreement to the contrary notwithstanding, if Participant does not otherwise satisfy the obligations of Participant under Section 6(b)(i) of this Agreement, Participant acknowledges and agrees that the Company and its Affiliates shall, to the extent permitted by law, have the right to deduct from any payments of any kind otherwise due from the Company or its Affiliates to or with respect to Participant, whether or not pursuant to this Agreement or the Plan and regardless of the form of payment, any federal, state, or local taxes of any kind required by law to be withheld with respect to any Distribution Equivalent Payments or Restricted Incentive Units hereunder.

7.    Non-Assignability. Neither the Subject Award nor the Restricted Incentive Units is assignable or transferable by Participant, and, the Restricted Incentive Units shall not be assigned, alienated, pledged, attached, sold, or otherwise transferred or encumbered by Participant in any manner.

8.    Entirety and Modification. This Agreement (including all schedules hereto) contains the entire agreement between the parties hereto with respect to the subject matter hereof and supersedes any and all prior agreements, whether written or oral, between such parties relating to such subject matter. Subject to Section 15.2 of the Plan, no modification, alteration, amendment, or supplement to this Agreement shall be valid or effective unless the same is in writing and signed by the party against whom it is sought to be enforced.

9.    Severability. If any provision of this Agreement is held to be unenforceable, this Agreement shall be considered divisible, and such provision shall be deemed inoperative to the extent it is unenforceable, and in all other respects this Agreement shall remain in full force and effect; provided, however, that if any such provision may be made enforceable by limitation thereof, then such provision shall be deemed to be so limited and shall be enforceable to the maximum extent permitted by applicable law.

10.    Gender. Words used in this Agreement which refer to Participant and denote the male gender shall also be deemed to include the female gender or the neuter gender when appropriate.

11.    Employment or Service. Nothing in this Agreement shall confer upon Participant any right to continue in the employ or service of the Company or its Affiliates, nor shall this Agreement interfere in any manner with the right of the Company or its Affiliates to terminate the employment or service of Participant with or without Cause at any time.

12.    Incorporation of Plan Provisions. This Agreement is made pursuant to the Plan and is subject to all of the terms and provisions of the Plan as if the same were fully set forth herein. In the event that any provision of this Agreement conflicts with the Plan, the provisions of the Plan shall control. Participant acknowledges receipt of a copy of the Plan and agrees that all decisions under and interpretations of the Plan by the Committee shall be final, binding, and conclusive upon Participant.

13.    Headings. The headings of the various sections and subsections of this Agreement have been inserted for convenient reference only and shall not be construed to enlarge, diminish, or otherwise change the express provisions hereof.

14.    Governing Law. This Agreement shall be governed by and construed in accordance with the laws of the state of Delaware (regardless of the laws that might otherwise govern under applicable Delaware principles of conflicts of law).

15.    Section 409A. The compensation payable pursuant to the Subject Award is intended to be exempt from, or otherwise in compliance with, Section 409A of the Code and this Agreement shall be administered and construed to the fullest extent possible to reflect and implement such intent. For purposes of Section 409A of the Code, each Subject Tranche shall be treated as a right to receive a separate and distinct payment. Anything to the contrary herein notwithstanding, if, at the time of a Participant’s Separation from Service with the Company and its Affiliates, such Participant is a “specified employee” (as defined in Section 409A of the Code), and the deferral of

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the commencement of any amount of the payments or benefits otherwise payable pursuant to the Plan is necessary in order to prevent any accelerated or additional tax under Section 409A of the Code, then, to the extent permitted by Section 409A of the Code, such payments or benefits hereunder (without any reduction in the payments or benefits ultimately paid or provided to Participant) will be deferred until the earlier to occur of (i) Participant’s death or (ii) the first business day that is six months following Participant’s Separation from Service with the Company and its Affiliates(the “Six-Month Delay Toggle”). Any payments or benefits deferred due to the Six-Month Delay Toggle will be paid in a lump sum (without interest) to Participant on the earliest to occur of clause (i) or (ii) in the immediately preceding sentence.

16.    No Voting Rights. Anything to the contrary herein notwithstanding, in no event shall Participant have any right to vote any, or to exercise any other rights, powers, and privileges of a holder of the Units with respect to any Restricted Incentive Units granted hereunder until such time that (i) the Performance Period applicable to such Restricted Incentive Units or a portion thereof shall have expired (and all other conditions to payment with respect thereto have been fulfilled), (ii) such Restricted Incentive Units are converted into the right to receive Units, and (iii) such Units are delivered to Participant.

17.    Counterparts. This Agreement may be signed in counterparts, each of which shall be deemed an original and all of which shall constitute one and the same agreement.

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IN WITNESS WHEREOF, the parties hereto have executed this Agreement as of the Grant Date.

ENLINK MIDSTREAM, LLC

By: EnLink Midstream Manager, LLC

By:__________________________________________

Barry E. Davis

Chairman and Chief Executive Officer

PARTICIPANT:

__________________________________________

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SCHEDULE A

SUBJECT TRANCHE LISTING

Tranche Number	Relevant Performance Period for Subject Tranche	Relevant Performance Goal for Subject Tranche	Number of Restricted Incentive Units under Subject Tranche
1	First Performance Period	TSR	[●]
2	Second Performance Period	TSR	[●]
3	Third Performance Period	TSR	[●]
4	Cumulative Performance Period	TSR	[●]
5	First Performance Period	Cash Flow	[●]
6	Second Performance Period	Cash Flow	[●]
7	Third Performance Period	Cash Flow	[●]

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SCHEDULE B

PERFORMANCE PERIOD, PERFORMANCE GOALS, AND PAYOUT AMOUNTS

1.    Performance Period. The number of Tranche RIUs that relate to a Subject Tranche, which can vest as Certified RIUs pursuant to the Subject Award, shall be calculated based on the level of Performance Goal achievement over the Performance Period that relates to such Subject Tranche.

2.    Performance Goals. The Performance Goal with respect to a Subject Tranche shall be based on either total shareholder return (“TSR”) or Cash Flow as such terms are further described below.

3.    TSR-Related Definitional Matters and Vesting Requirements. At the end of each Performance Period, the TSR for the Company and for each Peer Company (as described below) shall be determined pursuant to the following formula and in accordance with the following definitions and rules:

TSR = ((Closing Average Value - Opening Average Value) + Reinvested Dividends) ÷ Opening Average Value*

*The result shall be rounded to the nearest hundredth of one percent (.01%).

(a)    “Closing Average Value” means the average value of the common equity security for the 30 trading days ending on the last day of the Performance Period, which shall be calculated as follows: (A) determine the closing price of the common equity security on each trading date during 30-day period and (B) average the amounts so determined for the 30-day period.

(b)    “Opening Average Value” means the average value of the common equity security for the 30 trading days preceding the start of the Performance Period, which shall be calculated as follows: (A) determine the closing price of the common equity security on each trading date during the 30-day period and (B) average the amounts so determined for the 30-day period.

(c)    “Reinvested Dividends” means the dollar amount equal to (A) the aggregate number of the Company’s common units / shares (including fractional common units / shares) that could have been purchased during the Performance Period had each cash distribution / dividend paid on one common unit / share at the beginning of the Performance Period been immediately reinvested in additional units / shares (or fractional common units / shares) at the closing selling price per common unit / share on the applicable distribution / dividend payment date (it being understood that the calculation in this clause (A) will include a compounding of distributions / dividends paid on common units / shares (or fractional common units / shares) “purchased” during the Performance Period from prior distribution / dividend “reinvestments”) multiplied by (B) the Closing Average Value.

(d)    Each of the foregoing amounts shall be equitably adjusted for share / unit splits, stock dividends or unit distributions, recapitalizations, and other similar events affecting the common equity securities in question.

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(e)    The Committee shall determine the number of Tranche RIUs that vest, if at all, as Certified RIUs pursuant to this Agreement based on the Company’s relative TSR ranking in respect of the Performance Period as compared to the TSR ranking of the Peer Companies as follows:

Performance Level	The Company’s Achieved TSR Percentile Position Relative to Peer Companies*	Associated Individual Payout Level (expressed as a percentage of the Tranche RIUs)
Below Threshold	Less than 25%	0%
Threshold	Equal to 25%	50%
Target	Equal to 50%	100%
Maximum	Greater than or Equal to 75%	200%

*If the Company’s achieved TSR percentile position is between the Threshold and Target performance levels or if the Company’s achieved TSR percentile position is between the Target and Maximum performance levels, then the associated individual payout level will be interpolated on a linear basis. If the Company’s final TSR value is equal to the TSR value of a Peer Company, the Committee shall assign the Company the higher ranking.

(f)    The Peer Companies are the companies set forth on Schedule C to this Agreement; provided, however, that the Peer Companies will be subject to change as follows:

(i)    If on or before the date that is 30-trading days into a given Performance Period, a Peer Company enters into, becomes subject to, or is the subject of a definitive agreement or a filing made with the SEC contemplating an acquisition, merger, tender offer, or other similar transaction (regardless of whether such transaction is a Simplification Transaction or otherwise) (collectively, a “Transaction”) that involves such Peer Company and that, if consummated, would result (or reasonably be expected to result) in such Peer Company ceasing to be traded on a national securities exchange (“Traded”), then such Peer Company will be eliminated from the TSR calculations for all Performance Periods that end on a date subsequent to the date of such definitive agreement or SEC filing, as applicable (it being understood that previously certified results for a Performance Period will be unimpacted by the foregoing). If, however, such Transaction is rescinded, revoked, terminated, or abandoned, then such Peer Company will remain a Peer Company and again be subject to all of the terms set forth herein (it being understood that previously certified results for a Performance Period will be unimpacted by the foregoing).

(ii)    If on or after the date that is 31-trading days into a given Performance Period and before the last day of the relevant Performance Period, a Peer Company enters into, becomes subject to, or is the subject of a definitive agreement or a filing made with the SEC contemplating a Transaction (other than a Simplification Transaction, which is addressed below) that involves such Peer Company and that, if consummated, would result (or reasonably be expected to result) in such Peer Company ceasing to be Traded, then such Peer Company will be fixed above or below the Company for relative TSR purposes calculating the Company’s and the applicable Peer Company’s TSRs using the trading day preceding the date on which the public became aware of such a definitive agreement or SEC filing, as applicable, as the end date for “Closing Average Value” purposes. If such calculation results in such Peer Company being fixed above the Company, then the Committee shall assign the Peer Company with a TSR that places such Peer Company at the top of the TSR rankings, and if fixed below the Company, then the Committee shall assign the Peer Company with a TSR that places such Peer Company at the bottom of the TSR rankings, in each case, for all Performance Periods that end on a date subsequent to the date of the definitive agreement or SEC filing, as applicable (it being understood that previously certified results for a Performance Period will be unimpacted by the foregoing). If, however, such Transaction is rescinded, revoked, terminated, or abandoned, then such Peer Company will remain a Peer Company and again be subject to all of the terms set forth herein (it being understood that previously certified results for a Performance Period will be unimpacted by the foregoing).

(iii)    If on or after the date that is 31-trading days into a given Performance Period and before the last day of the relevant Performance Period, a Peer Company enters into, becomes subject to, or is the subject of

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a definitive agreement or a filing made with the SEC contemplating a Simplification Transaction that involves such Peer Company and that, if consummated, would result (or reasonably be expected to result) in such Peer Company ceasing to be Traded, then the survivor of such Simplification Transaction that remains Traded shall be deemed to have been and to be a Peer Company (in each case, for purposes of each component of the TSR calculation) for all Performance Periods that end on a date subsequent to the date of such definitive agreement or SEC filing, as applicable (it being understood that previously certified results for a Performance Period will be unimpacted by the foregoing). If, however, such Simplification Transaction is rescinded, revoked, terminated, or abandoned, then such Peer Company will remain a Peer Company and again be subject to all of the terms set forth herein (it being understood that previously certified results for a Performance Period will be unimpacted by the foregoing).

(iv)    A Peer Company that is both involved in a bankruptcy proceeding and ceases to be Traded during a Performance Period will remain a Peer Company but shall be deemed to have a TSR of negative 100% (-100%) for all Performance Periods that end on a date subsequent to the date of such delisting. A Peer Company that is involved in a bankruptcy proceeding, but remains Traded will remain a Peer Company and no adjustment shall be made.

(v)    A Peer Company that ceases to be Traded during a Performance Period for a reason other than one contemplated in clauses (i) through (iv) above will remain a Peer Company but shall be deemed to have a TSR of negative 100% (-100%) for all Performance Periods that end on a date subsequent to the date of such delisting.

(g)    “Simplification Transaction” means a transaction in the form of what is known in the MLP space as a “simplification” transaction and where the operating assets of the master limited partnership involved in such transaction constitute substantially all of the assets owned by the relevant parent entity involved in such transaction.

4.    Cash Flow-Related Definitional Matters and Vesting Requirements.

(a)“Cash Flow” with respect to any relevant Performance Period shall consist of the measurement “free cash flow after distributions” (“FCFAD”) and shall be calculated consistent with the Company’s most relevant published financial results or guidance for a given Performance Period (the applicable “Reference Year”) and means, (A) the Company’s Adjusted EBITDA (as defined and calculated consistent with the Company’s most relevant published financial results or guidance) minus (B) the sum of (w) interest expense, net of interest income, (x) accrued cash distributions on Series B Preferred Units and Series C Preferred Units paid or expected to be paid, (y) cash distributions paid or expected to be paid on the Company’s common units, and (z) capital expenditures (including both maintenance and capital expenditures, but excluding capital expenditures that were contributed by other entities and relate to the non-controlling interest share of the Company’s consolidated entities) plus (C) proceeds from sales of property and equipment. For the avoidance of doubt, actual FCFAD for any applicable Reference Year shall be calculated on a pre-bonus basis (i.e., before the STI payout).

(b)Prior to the certification of FCFAD performance by the Committee for a given Reference Year, Target FCFAD (as set forth in the chart below) may be adjusted for the following items: (i) changes in the common distribution rate, or special distributions, each as approved by the Board, (ii) growth capital expenditures for unbudgeted projects approved during the Reference Year for which primary financial benefits will be realized after the Reference Year as well as any cash flow amounts from such projects which are realized in the Reference Year, and (iii) other extraordinary events or items occurring during the Reference Year. Management shall prepare a list of such adjustments, if any, on a quarterly basis for consideration by the Committee. If the Committee, acting in its discretion, approves any such adjustments, the Target FCFAD for such Reference Year shall be adjusted by the amount so approved.

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(c)The Committee shall determine the number of Tranche RIUs that vest, if at all, as Certified RIUs pursuant to this Agreement based on the Company’s actual achieved FCFAD for the Performance Period ending December 31, 2022, as compared to the Target FCFAD as follows:

Performance Level	Target FCFAD*‡	Associated Individual Payout Level (expressed as a percentage of the Tranche RIUs)
Below Threshold	Less than $278	0%
Threshold	Equal to $278	50%
Target	Equal to $334	100%
Maximum	Greater than or equal to $390	200%

*If the Company’s actual achieved FCFAD is between the Threshold and Target performance levels or if the Company’s achieved FCFAD is between the Target and Maximum performance levels, then the associated individual payout level will be interpolated on a linear basis.

‡Amounts shown above as Target FCFAD apply for the First Performance Period, are shown on a pre-bonus basis, and are shown before adjustments, if any, are made pursuant to paragraph (b), above. The successive Performance Period Target FCFAD will be updated as set forth in paragraph (d) below.

(d)    For the Second Performance Period and the Third Performance Period, the Board, or the Committee, will establish the figures to be included in the column titled “Target FCFAD” in the chart above and will notify Participant of the same in writing no later than March 31 of the year in which the relevant Performance Period begins.

5.    Other Vesting Terms. Any fractional Certified RIUs resulting from the vesting thereof in accordance with this Agreement shall be rounded down to the nearest whole number. Any portion of the Tranche RIUs that does not vest as Certified RIUs of the end of the Performance Period shall be forfeited as of the end of the Performance Period.

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SCHEDULE C

PEER COMPANIES

Antero Midstream GP	MPLX, LP
Cheniere Energy, Inc.	NGL Energy Partners
Crestwood Equity Partners, LP	NuStar Energy, LP
DCP Midstream, LP	ONEOK, Inc.
Energy Transfer, LP	Phillips 66 Partners, LP
Enterprise Products Partners, LP	Plains All American Pipeline, LP
Equitrans Midstream Corp.	Plains GP Holdings
Genesis Energy, LP	Shell Midstream Partners
Hess Midstream Partners LP	Targa Resources Corp.
Holly Energy Partners	The Williams Companies, Inc.
Kinder Morgan, Inc.	TC Pipelines, LP
Magellan Midstream Partners, LP	Western Gas Equity Partners, LP

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SCHEDULE D

RESTRICTIVE COVENANTS

For the avoidance of doubt, Participant only makes the agreements contemplated in, and is only bound by, this Schedule D in connection with his or her Early Retirement, Intermediate Retirement, or Normal Retirement. In partial consideration for Participant’s access to confidential information (the access to which Participant hereby acknowledges) and eligibility for and receipt of the benefits provided by Early Retirement, Intermediate Retirement, or Normal Retirement by that certain Performance Unit Agreement to which this Schedule D is attached (the “Agreement”), Participant hereby agrees as follows:

1.Restrictive Covenants.

(i)    Covenant Not to Solicit Customers. Participant agrees that while employed by a member of the Company Group and for a period of twelve (12) months after his or her Early Retirement, Intermediate Retirement, or Normal Retirement, as applicable, Participant shall not (i) persuade or encourage any Person that was a client or customer of EnLink Midstream, LLC or any of its direct or indirect subsidiaries (collectively, the “Company Group”) at any time during the twelve (12) months prior to his or her Early Retirement, Intermediate Retirement, or Normal Retirement, as applicable, to cease conducting or fail to renew existing business with that member of the Company Group, or (ii) use any confidential or proprietary information of any member of the Company Group to directly or indirectly solicit business from, or to interrupt, disturb, or interfere with any member of the Company Group’s relationships with, any Person that was a client or customer of any member of the Company Group at any time during the twelve (12) months prior to his or her Early Retirement, Intermediate Retirement, or Normal Retirement, as applicable.

(ii)    Covenant not to Solicit Employees. Participant agrees that while employed by any member of the Company Group and for a period of twenty-four (24) months after his or her Early Retirement, Intermediate Retirement, or Normal Retirement, as applicable, Participant shall not solicit, endeavor to entice, or induce any employee of any member of the Company Group to terminate such Person’s employment or service with such member or accept employment with anyone else; provided, however, that a general solicitation of the public for employment shall not constitute a solicitation hereunder.

2.    Specific Performance. Recognizing that irreparable damage will result to the Company Group in the event of the breach or threatened breach of any of the foregoing covenants and assurances by Participant contained in paragraph 1 of this Schedule D, and that the Company Group’s remedies at law for any such breach or threatened breach will be inadequate, the members of the Company Group and their successors and assigns, in addition to such other remedies that may be available to them, shall be entitled to an injunction, including a mandatory injunction (without the necessity of (i) proving irreparable harm, (ii) establishing that monetary damages are inadequate, or (iii) posting any bond with respect thereto), to be issued by any court of competent jurisdiction ordering compliance with the Agreement or enjoining and restraining Participant, and each and every Person, firm, or company acting in concert or participation with him or her, from the continuation of such breach and, in addition thereto, he or she shall pay to such affected member of the Company Group all ascertainable damages, including costs and reasonable attorneys’ fees sustained by such affected member or members of the Company Group by reason of the breach or threatened breach of said covenants and assurances.

3.    Clawback. Participant agrees that in the event that the Committee determines that Participant has breached any term of this Schedule D, in addition to any other remedies at law or in equity that any affected member of the Company Group may have available to it or them, the Committee may in its sole discretion require that Participant, within five (5) business days of receipt of written demand therefor, repay to the Company the amount of any Distribution Equivalent Payments paid to Participant pursuant to Section 5 of the Agreement and return to the Company the Units (or other benefits) delivered to Participant in connection with Section 4 of the Agreement (or in the event Participant has ceased to hold such Units (or other benefits), an amount equal to the Fair Market Value thereof as in effect as of the date of such written demand).

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4.    Miscellaneous.

(a)    Participant has carefully read and considered the provisions of this Schedule D and, having done so, agrees that the restrictions set forth in this Schedule D (including the relevant time periods, scope of activity to be restrained, and the geographical scope) are fair and reasonable and are reasonably required for the protection of the interests of the Company Group and their respective officers, directors, managers, employees, creditors, partners, members, and unitholders. Participant understands that the restrictions contained in this Schedule D may limit his or her ability to engage in a business similar to the business of any member of the Company Group, but acknowledges that he or she will receive sufficiently high remuneration and other benefits from the Company Group to justify such restrictions.

(b)    The covenants and obligations of Participant set forth in this Schedule D are in addition to and not in lieu of or exclusive of, any other obligations and duties of Participant to the Company Group, whether express or implied in fact or in law.

(c)    In the event that any provision of this Schedule D relating to the relevant time periods, scope of activity, and/or the areas of restriction hereunder shall be declared by a court of competent jurisdiction to exceed the maximum time period, scope, or areas such court deems reasonable and enforceable, the relevant time periods, scope of activity, and/or areas of restriction deemed reasonable and enforceable by the court shall become and thereafter be the maximum time period, scope of activity, and/or areas of restriction.

(d)    The restrictive covenants set forth in this Schedule D are personal and not assignable by Participant but they may be assigned by the Company without notice to or consent of Participant to, and shall thereafter be binding upon and enforceable by, (i) any member of the Company Group, or (ii) any Person that acquires or succeeds to substantially all of the business or assets of any member of the Company Group (and such Person shall be deemed included to be in the definition of the “Company” and the “Company Group” for all purposes of this Schedule D).

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EX-10.15

Exhibit 10.15

ENLINK MIDSTREAM OPERATING, LP

[AMENDED AND RESTATED] CHANGE IN CONTROL AGREEMENT

THIS [AMENDED AND RESTATED] CHANGE IN CONTROL AGREEMENT (this “Agreement”) dated as of ____________, 20__ (the “Effective Date”) is made by and between EnLink Midstream Operating, LP, a Delaware limited partnership (the “Company”) and ________________, an individual (“Individual”).

W I T N E S S E T H:

WHEREAS, the Company and Individual desire to [amend and restate that certain Change in Control Agreement dated as of _____________, 20__ (the “Original Agreement”)][enter into a Change in Control arrangement] on the terms and conditions set forth herein.

NOW, THEREFORE, in consideration of the premises and the mutual covenants and agreements hereinafter set forth, Individual and the Company hereby amend and restate the Original Agreement as follows:

ARTICLE I

Definitions

1.1    Definitions. For purposes of this Agreement, except as otherwise expressly provided herein or unless the context otherwise requires, the following terms shall have the following respective meanings:

“Accounting Firm” shall have the meaning set forth in Section 2.4(b).

“Agreement” shall have the meaning set forth in the preamble hereto.

“Board” means the Board of Directors of ENLC Manager (or such other managing member of ENLC or such other applicable governing body of ENLC).

“Cause” means any one or more of the following: (i) a material violation by Individual of the Company’s Code of Business Conduct and Ethics or any trading or other policy applicable to employees of the Company (which may include, but is not limited to, matters specifically mentioned below in the definition of Cause); (ii) willful engagement in serious or material misconduct or illegal conduct by Individual; (iii) a failure by Individual to perform the duties assigned to him or her that continues following notice from the Company to Individual of such failure; (iv) Individual is formally charged, indicted or convicted of a felony or a misdemeanor involving moral turpitude; (v) Individual has engaged in acts or omissions constituting dishonesty, breach of fiduciary obligation, gross misconduct, gross negligence, intentional wrongdoing, or misfeasance; (vi) Individual has failed to comply with any valid, legal, and material directive of the Company or the Board; (vii) Individual has engaged in embezzlement, misappropriation, or fraud, whether or not related to Individual’s employment with the Company; (viii) a material breach by Individual of any material obligation under this Agreement or any other written agreement between Individual and the Company Group; or (ix) Individual has acted intentionally or in bad faith in a manner that results or could be reasonably expected to result in a material detriment to the assets, business, prospects or reputation of any member of the Company Group. Any act, or failure to act, based upon the express or implied authority given pursuant to a resolution duly adopted by the Board or upon the advice of counsel for the Company shall be conclusively presumed to be done, or omitted to be done, by Individual in good faith and in the best interests of the Company Group. Individual will be considered to have been terminated for Cause if the Company determines in its sole good faith judgment that he or she engaged in an act prior to termination that constituted Cause, regardless of whether Individual terminated employment voluntarily or is terminated involuntarily, and regardless of whether Individual’s termination initially was considered to have been without Cause. The Company may place Individual on paid leave while it is determining whether there is a basis to terminate Individual’s employment for Cause, it being understood that, any such action by the Company will not constitute Good Reason.

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“Change in Control” means the occurrence of any one or more of the following on or after the Effective Date: (i) the consummation of any transaction (including a merger or consolidation), the result of which is that any Person (other than GIP) becomes the “beneficial owner” (as defined in Rule 13d-3 under the Exchange Act), directly or indirectly, of fifty percent (50%) or more of the Voting Stock of ENLC or ENLC Manager, measured by voting power rather than number of shares, units, or the like; (ii) the sale, transfer, or other disposition of all or substantially all of the assets of ENLC and its Subsidiaries on an aggregate basis to any Person (other than one or more members of the Company Group); or (iii) the adoption of a plan relating to the liquidation or dissolution of ENLC. Notwithstanding the foregoing, to the extent any amounts hereunder are subject to Section 409A of the Code and such amounts are payable upon the occurrence of a Change in Control following a Qualifying Termination, no such payments shall be made unless such Change in Control qualifies as a “change in control event” within the meaning of Treas. Reg. Section 1.409A-3(i)(5).

“Change in Control Benefit” means, as of the date of a Qualifying Termination, a one-time lump sum payment equal to: (i) one and a half (1.5)1 times the sum of (A) Individual’s then current base annual salary and (B) the Target Bonus for the year that includes the effective date of termination; plus (ii) an amount equal to the cost to Individual under COBRA to extend his or her then-current medical insurance benefits (i.e., the health, dental and/or vision benefits as elected by Individual under the Company’s health plan as of the time of such termination) for eighteen (18) months following the effective date of termination.

“COBRA” means the Consolidated Omnibus Budget Reconciliation Act of 1985, as amended.

“Code” means the Internal Revenue Code of 1986, as amended, and any successor statute or statutes.

“Committee” means the Governance and Compensation Committee of the Board.

“Company” shall have the meaning set forth in the preamble hereto.

“Company Group” means the Company, ENLC, ENLK MLP, ENLK GP, ENLC Manager and each of their respective direct or indirect Subsidiaries.

“Confidential Information” shall have the meaning set forth in Section 3.1.

“Disability” means a physical or mental condition of Individual that, (i) in the good faith judgment of the Company, (A) prevents Individual from being able to perform the responsibilities of his or her position with the Company Group, (B) has continued for a period of at least one hundred eighty (180) days (whether consecutive or non-consecutive) during any twelve (12) month period, and (C) is expected to continue, or (ii) qualifies Individual to receive benefits under the Company’s long-term disability plan.

“Effective Date” shall have the meaning set forth in the preamble hereto.

“ENLC” means EnLink Midstream, LLC, a Delaware limited liability company.

“ENLC Manager” means EnLink Midstream Manager, LLC, a Delaware limited liability company.

“ENLK GP” means EnLink Midstream GP, LLC, a Delaware limited liability company.

“ENLK MLP” means EnLink Midstream Partners, LP, a Delaware limited partnership.

“Exchange Act” means the Securities and Exchange Act of 1934, as amended.

1 Executive Chairman and CEO = 3 times; EVPs = 2.5 times; SVP = 1.5 times

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“GIP” means Global Infrastructure Partners III-A/B, L.P., Global Infrastructure Partners III-C Intermediate, L.P., Global Infrastructure Partners III-C2 Intermediate, L.P., Global Infrastructure Partners II-C Stetson AIV, L.P. and each of their affiliates, and any funds, partnerships or other investment vehicles managed by Global Infrastructure Management, LLC or their affiliates (including in each case, any portfolio companies of such entities).

“Good Reason” means any one or more of the following without Individual’s consent: (i) a material reduction in Individual’s base annual salary; (ii) a material adverse change in Individual’s authority, duties or responsibilities (other than temporarily while Individual is physically or mentally incapacitated or as required by applicable law); (iii) a material breach by the Company of any material provision of this Agreement (or by a member of the Company Group of any material provision or any other written agreement between Individual and the Company Group member regarding his or her services thereto); or (iv) the Company requires that Individual move his or her principal place of employment to a location that is thirty (30) or more miles from his or her current principal place of employment and the new location is farther from his or her primary residence. Individual may not terminate his or her employment for “Good Reason” unless (A) Individual gives the Company written notice of the event within thirty (30) days of the occurrence of the event, (B) the Company fails to remedy the event within thirty (30) days following its receipt of the notice, and (C) Individual terminates his or her employment with the Company within sixty (60) days following the Company’s receipt of written notice. A non-renewal of this Agreement shall not alone constitute Good Reason.

“Individual” shall have the meaning set forth in the preamble hereto.

“Original Agreement” shall have the meaning set forth in the recitals.

“Other Arrangement” shall have the meaning set forth in Section 5.3.

“Person” means any individual, partnership, joint venture, limited liability company, corporation, trust, unincorporated organization or any other entity, provided, that for the purposes of the definition of “Change in Control” hereunder, “Person” shall also include any “person“ or any “group” within the meaning of Sections 13(d) and 14(d)(2) of the Exchange Act.

“Protection Period” means the period beginning one hundred twenty (120) days prior to, and ending twenty-four (24) months following, the date on which a Change in Control takes place.

“Qualifying Termination” means the termination of Individual’s employment during a Protection Period (i) by the Company for a reason other than Cause, Disability, or death, or (ii) by Individual for Good Reason. The transfer of Individual from the Company to another member of the Company Group shall not constitute a termination of employment.

“Renewal Date” shall have the meaning set forth in Section 5.1.

“Severance Agreement” shall have the meaning set forth in Section 2.3.

“Severance Plan” shall have the meaning set forth in Section 2.3.

“Subsidiary” means (i) in the case of a corporation, any corporation of which an applicable Person directly or indirectly owns shares representing more than fifty percent (50%) of the combined voting power of the shares of all classes or series of capital stock of such corporation which have the right to vote generally on matters submitted to a vote of the stockholders of such corporation and (ii) in the case of a partnership, limited liability company, or other business entity not organized as a corporation, any such business entity of which an applicable Person (A) directly or indirectly owns more than fifty percent (50%) of the voting, capital or profits interests (whether in the form of partnership interests, membership interests, or otherwise) or (B) has the power to elect or direct the election of directors with a majority of the voting power of the board of directors (or other governing body) of such partnership, limited liability company, or other business entity or the sole member or managing member of such partnership, limited liability company, or other business entity, as applicable.

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“Target Bonus” means the amount of bonus that would be payable to Individual for the year in question if paid at one-hundred percent (100%) of Individual’s assigned bonus target percentage for such year as determined annually by the Committee or the Board, as applicable.

“Total Payment” shall have the meaning set forth in Section 2.4(a).

“Voting Stock” of any specified Person as of any date means the capital stock (or comparable equity securities) of such Person that is at the time entitled (without regard to the occurrence of any contingency) to vote in the election of the Board of Directors (or comparable governing body) of such Person.

ARTICLE II

Change in Control Payments

2.1    Change in Control Benefit; Release.

(a)If Individual has a Qualifying Termination and Individual satisfies the conditions to the payment of a Change in Control Benefit as described below, the Company shall pay the Change in Control Benefit to Individual.

(b)Any amounts payable under Section 2.1(a) shall be paid to Individual on the sixtieth (60th) day after the date Individual’s Qualifying Termination becomes effective for purposes of this Agreement; provided, however, that as a condition to receiving any such payment or payments, Individual (or Individual’s estate, as applicable) will be required to do both of the following: (i) execute and not revoke a general release of claims against the Company Group, with such general release becoming effective (and any applicable revocation period having lapsed) on or before the sixtieth (60th) day after the date Individual’s Qualifying Termination becomes effective for purposes of this Agreement, and (ii) execute a certification of compliance with his or her obligations to return Confidential Information.

2.2    Additional Benefits.

(a)In the event of a Qualifying Termination, the Change in Control Benefit will be paid in addition to any accrued and unpaid compensation due to Individual as of his or her termination date, which may include (i) any unpaid bonus for any calendar year ending before Individual’s termination date that is actually earned by Individual (without regard to any requirement that Individual must remain employed by Company on the date such bonus is paid), and calculated in accordance with the terms of the applicable bonus arrangement that is in effect with respect to Individual during that year, (ii) accrued base salary and (iii) such other fringe benefits (other than any bonus, severance pay benefit, or medical insurance benefit) normally provided to similarly situated employees of the Company that shall have been earned up to the date of termination, including pay for accrued and unused paid-time-off (in accordance with the benefit policies then in effect).

(b)Individual shall also be entitled to a prorated amount of the bonus (to the date of such Individual’s Qualifying Termination) for the calendar year in which Individual’s Qualifying Termination occurs to the extent such bonus would have otherwise been earned by Individual (had his or her employment not terminated due to a Qualifying Termination) in accordance with the terms of the applicable bonus arrangement that is in effect with respect to Individual during that year. Such prorated bonus shall not be made unless and until Individual has, as of such date, satisfied the conditions described in Section 2.1(b) above and shall be payable on the later of (i) the date that the bonus would have been paid under such applicable bonus arrangement (had Individual’s employment not terminated due to a Qualifying Termination), or (ii) the date on which Individual has satisfied the conditions described in Section 2.1(b) above.

(c)For a period of twelve (12) months following Individual’s Qualifying Termination, or if Individual has not satisfied the conditions described in Section 2.1(b) above, for a period of sixty (60) days after the date of Individual’s termination, the Company shall, at its sole expense, provide Individual with outplacement services, the

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scope and provider of which shall be selected by Individual in his or her discretion; provided, however, that (i) any expense for such outplacement services shall be paid or reimbursed by the Company as soon as practicable after such expense is incurred, but in no event later than (A) thirty (30) days after such expense is incurred if incurred directly by the Company, or (B) thirty (30) days after such expense is submitted by Individual to Company for reimbursement, and (ii) the total amount of the expenses paid or reimbursed by the Company pursuant to this Section 2.2(c) shall not exceed $50,000.

(d)To the extent Individual is eligible to earn a Target Bonus, Individual’s assigned bonus target percentage shall not be materially reduced during any time (i) that Individual is employed during a Protection Period by a member of the Company Group or (ii) following Individual’s termination or separation for any reason that occurs within a Protection Period other than his or her involuntary termination for Cause or voluntary termination without Good Reason.

2.3    Non-duplication. The amount payable to Individual under Sections 2.1 and 2.2 is in lieu of, and not in addition to, any severance payment due or to become due to Individual under (i) any separate agreement or contract between Individual and the Company or any other member of the Company Group, (ii) any severance payment plan, program, policy or practice of the Company or any other member of the Company Group or (iii) any severance benefit required by law (collectively clauses (i)-(iii), a “Severance Plan”), it being understood that any equity-related award granted to Individual under the long-term incentive plans of a member of the Company Group shall not constitute a Severance Plan for purposes of this Section 2.3. In particular, no amounts shall be payable under the Severance Agreement between the Company and Individual in effect as of the date hereof (the “Severance Agreement”) if benefits are payable pursuant to this Agreement.

2.4    Potential Parachute Payment Adjustment.

(a)If the payments and benefits provided to Individual under this Agreement or under any other agreement with, or plan of, the Company or any Person or entity which is a party to a transaction involving the Company or its affiliates (the “Total Payment”) (i) constitute a “parachute payment” as defined in Code Section 280G and exceed three (3) times Individual’s “base amount” as defined under Code Section 280G(b)(3), and (ii) would, but for this Section 2.4(a), be subject to the excise tax imposed by Code Section 4999, then Individual’s payments and benefits under this Agreement shall be either (A) paid in full, or (B) reduced and payable only as to the maximum amount which would result in no portion of such payments and benefits being subject to excise tax under Code Section 4999, whichever results in the receipt by Individual on an after-tax basis of the greatest amount of Total Payment (taking into account the applicable federal, state and local income taxes, the excise tax imposed by Code Section 4999 and all other taxes (including any interest and penalties) payable by Individual). If a reduction of the Total Payment is necessary, cash payments provided for herein shall first be reduced (such reduction to be applied first to the earliest payments otherwise scheduled to occur), and the non-cash benefits provided for herein shall thereafter be reduced (such reduction to be applied first to the benefits otherwise scheduled to occur the earliest). If, as a result of any reduction required by this Section 2.4(a), amounts previously paid to Individual exceed the amount to which Individual is entitled, Individual will promptly return the excess amount to the Company.

(b)All determinations required to be made under this Section 2.4, including whether reductions are necessary, may be made, in the discretion of the Company, by an accounting or financial consulting firm selected by the Company for such purposes (the “Accounting Firm”). The Accounting Firm shall provide detailed supporting calculations both to the Company and to Individual. All fees and expenses of the Accounting Firm shall be borne solely by the Company.

2.5    Death or Disability of Individual. Except as otherwise provided in this Section 2.5, if Individual’s employment terminates due to death or Disability, then this Agreement shall terminate without further obligations to Individual or his or her estate, as applicable, under this Agreement. In either event, however, the Company, in addition to any obligations owed to Individual under any other applicable agreement with any member of the Company Group (i) will pay any accrued and unpaid compensation due to Individual as of his or her termination date, as described in Section 2.2(a) as if Individual’s termination of employment had been a Qualifying Termination,

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and (ii) will pay the prorated bonus described in Section 2.2(b) as if Individual’s termination of employment had been a Qualifying Termination; provided that payment of such compensation and benefits with respect to Section 2.2(b) shall only be made if Individual or his or her legal representative or his or her estate, as applicable, has satisfied the conditions described in Section 2.1(b).

ARTICLE III

Confidential Information and Non-Competition; Other Covenants

3.1    Covenant Not to Disclose Confidential Information. Individual acknowledges that, during the course of his or her employment with the Company, he or she has or will have access to and knowledge of certain information and data that the Company or other members of the Company Group consider confidential and that the release of such information or data to unauthorized Persons would be extremely detrimental to the Company Group. As a consequence, Individual hereby agrees and acknowledges that he or she owes a duty to the Company not to disclose, and agrees that, during or after the term of his or her employment, without the prior written consent of the Company, he or she will not communicate, publish or disclose, to any Person anywhere or use any Confidential Information (as hereinafter defined) for any purpose other than carrying out his or her duties as contemplated in connection with his or her employment with respect to the Company or any Company Group member. Individual will use his or her best efforts at all times to hold in confidence and to safeguard any Confidential Information from falling into the hands of any unauthorized Person and, in particular, will not permit any Confidential Information to be read, duplicated, or copied. Notwithstanding the foregoing, Individual may disclose such Confidential Information to the extent required by applicable law or as a consequence of any judicial or regulatory proceeding, based upon the opinion of legal counsel and only after Individual has requested that such Confidential Information be preserved to the maximum extent practicable. To the extent permitted by law, Individual will advise the Company in advance of any intended disclosure to comply with legal requirements. Individual will return to the Company all Confidential Information in Individual’s possession or under Individual’s control when the duties of Individual no longer require Individual’s possession thereof, or whenever the Company shall so request, and in any event will promptly return all such Confidential Information if Individual’s relationship with the Company is terminated for any reason and will not retain any copies thereof. Notwithstanding the foregoing, nothing herein prohibits Individual from reporting possible violations of law or regulation to any governmental agency or entity, including but not limited to the Department of Justice, the Securities and Exchange Commission, the Congress, and any agency Inspector General, or making other disclosures that are protected under the whistleblower provisions of federal or state law or regulation. Individual does not need the prior authorization of the Company to make any such reports or disclosures, and Individual is not required to notify the Company that he or she has made such reports or disclosures. Individual shall not be held criminally or civilly liable under any federal or state trade secret law for the disclosure of a trade secret that (i) is made (A) in confidence to a federal, state, or local government official, either directly or indirectly, or to an attorney; and (B) solely for the purpose of reporting or investigating a suspected violation of law; or (ii) is made in a complaint or other document filed in a lawsuit or other proceeding, if such filing is made under seal. For purposes hereof, the term “Confidential Information” shall mean any information or data used by or belonging or relating to the Company or any other member of the Company Group or any of their representatives that is not known generally to the industry in which any member of the Company Group is or may be engaged (other than as a result of disclosure by Individual in violation of this Agreement), including without limitation, any and all trade secrets, proprietary data and information relating to any member of the Company Group’s past, present, or future business and products, price lists, customer lists, processes, procedures or standards, know-how, manuals, business strategies, records, drawings, specifications, designs, financial information, whether or not reduced to writing, or information or data that the Company or any other member of the Company Group advises Individual should be treated as confidential information.

3.2    Covenant Not to Compete. In partial consideration for Individual’s access to Confidential Information and the benefits provided by this Agreement, Individual agrees that while employed by the Company, Individual shall not, unless Individual receives the prior written consent of the Board, own an interest in, manage, operate, join, control, lend money or render financial or other assistance to or participate in or be connected with, as an officer, manager, employee, partner, stockholder, consultant, or otherwise, any Person that competes with any member of the Company Group in (i) the purchasing, selling, brokering or marketing of natural gas, natural gas liquids, oil, hydrocarbons, brine, water or any derivative product thereof, including, without limitation, locating buyers and

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sellers, or negotiating purchase and sales contracts; (ii) the gathering, processing, fractionation, stabilization, and/or transporting of natural gas, natural gas liquids, oil, hydrocarbons, brine, water, or any derivative product thereof; or (iii) the conduct of a business enterprise that is in a business segment that contributes five percent (5%) or more to the Company’s gross revenue or deploys five percent (5%) or more of the Company’s fixed assets. Ownership by Individual, as a passive investment, of less than one half of one percent (0.5%) of the outstanding securities of any organization with securities listed on a national securities exchange or publicly traded in the over-the-counter market shall not constitute a breach of this Section 3.2.

3.3    Covenant not to Solicit Customers. In partial consideration for Individual’s access to Confidential Information and the benefits provided by this Agreement, Individual agrees that while employed by the Company and for a period of twelve (12) months after the termination of such employment (for any reason), Individual shall not (i) persuade or encourage any Person that was a client or customer of any member of the Company Group at any time during the twelve (12) months prior to the termination of Individual’s employment to cease conducting or fail to renew existing business with that member of the Company Group, or (ii) use any confidential or proprietary information of any member of the Company Group to directly or indirectly solicit business from, or to interrupt, disturb, or interfere with any member of the Company Group’s relationships with, any Person that was a client or customer of any member of the Company Group at any time during the twelve (12) months prior to the termination of Individual’s employment.

3.4    Covenant not to Solicit Employees. In partial consideration for Individual’s access to Confidential Information and the benefits provided by this Agreement, Individual agrees that while employed by the Company and for a period of twenty-four (24) months after the termination of such employment (for any reason), Individual shall not solicit, endeavor to entice or induce any employee of any member of the Company Group to terminate such Person’s employment or service with such member or accept employment with anyone else; provided, however, that a general solicitation of the public for employment shall not constitute a solicitation hereunder.

3.5    Covenant Against Disparagement. In partial consideration for Individual’s access to Confidential Information and the benefits provided by this Agreement, Individual agrees that while employed by the Company and thereafter, he or she will not make any statements disparaging any member of the Company Group or any of their officers, directors, or employees that could reasonably be expected to be harmful to the interests of the Company or the Company Group. This covenant shall not apply to any statement made in the context of any legal or regulatory proceeding or the reporting of possible violations of law or regulation to a governmental agency or entity, as described in Section 3.1.

3.6    Specific Performance. Recognizing that irreparable damage will result to the Company in the event of the breach or threatened breach of any of the foregoing covenants and assurances by Individual contained in this Article III, and that the Company’s remedies at law for any such breach or threatened breach will be inadequate, the Company and its successors and assigns, in addition to such other remedies that may be available to them, shall be entitled to an injunction, including a mandatory injunction (without the necessity of (i) proving irreparable harm, (ii) establishing that monetary damages are inadequate, or (iii) posting any bond with respect thereto), to be issued by any court of competent jurisdiction ordering compliance with this Agreement or enjoining and restraining Individual, and each and every Person, firm, or company acting in concert or participation with him or her, from the continuation of such breach and, in addition thereto, he or she shall pay to the Company all ascertainable damages, including costs and reasonable attorneys’ fees sustained by the Company or any other member of the Company Group by reason of the breach or threatened breach of said covenants and assurances.

3.7    Clawback. Individual agrees that in the event that the Company determines that Individual has breached any term of this Article III, in addition to any other remedies at law or in equity the Company may have available to it, the Company may in its sole discretion require that Individual repay to the Company, within five (5) business days of receipt of written demand therefor, an amount equal to the amounts paid to or on behalf of Individual pursuant to Sections 2.1, 2.2(b) and 2.2(c).

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3.7    Miscellaneous.

a.Individual has carefully read and considered the provisions of this Article III and, having done so, agrees that the restrictions set forth in this Article III (including the relevant time periods, scope of activity to be restrained, and the geographical scope) are fair and reasonable and are reasonably required for the protection of the interests of the Company Group and their respective officers, directors, managers, employees, creditors, partners, members, and unitholders. Individual understands that the restrictions contained in Article III may limit his or her ability to engage in a business similar to the business of any member of the Company Group but acknowledges that he or she will receive sufficiently high remuneration and other benefits from the Company Group to justify such restrictions.

b.The covenants and obligations of Individual set forth in this Article III are in addition to, and not in lieu of, or exclusive of, any other obligations and duties of Individual to the Company Group, whether express or implied in fact or in law.

c.In the event that any provision of this Article III relating to the relevant time periods, scope of activity and/or the areas of restriction hereunder shall be declared by a court of competent jurisdiction to exceed the maximum time period, scope or areas such court deems reasonable and enforceable, the relevant time periods, scope of activity, and/or areas of restriction deemed reasonable and enforceable by the court shall become and thereafter be the maximum time period, scope of activity, and/or areas.

ARTICLE IV

Dodd-Frank Clawback

Individual agrees and acknowledges that any and all compensation Individual receives pursuant to this Agreement shall be subject to clawback by the Company to the extent provided in policies adopted by the Board to comply with the requirements of Section 954 of the Dodd-Frank Wall Street Reform and Consumer Protection Act.

ARTICLE IV

Miscellaneous

5.1    Term; Termination or Amendment.

(a)Unless, this Agreement is terminated in accordance with Section 5.1(b) below, this Agreement shall extend for a term (the “Term”) commencing on the Effective Date and ending on December 31, 20__ (the “Initial Expiration Date”). If this Agreement is not previously terminated, the Term shall automatically renew for one (1) additional year beginning on the day following the Initial Expiration Date and each subsequent anniversary thereof (each, a “Renewal Date”), unless the Company elects not to extend the Term by providing Individual with written notice (a “Non-Renewal Notice”) of such election not less than ninety (90) days prior to the last day of the then-current Term (each of the Initial Expiration Date and the last day of any then-current extended Term, the “Expiration Date”). Except as otherwise provided in the preceding sentence, no such termination or any amendment of this Agreement shall become effective during the term of this Agreement without Individual’s written consent, and any such purported termination or amendment of this Agreement during a Protection Period, whether pursuant to the preceding sentence or otherwise, without Individual’s written consent shall become effective no earlier than the expiration of the Protection Period.

(b)If this Agreement is not previously terminated, this Agreement shall terminate upon the termination of Individual’s employment; provided that, all obligations and liabilities of the parties hereto arising in connection with such termination of employment or otherwise accruing under this Agreement shall survive such termination.

(c)The Company shall have the right to amend this Agreement without Individual’s consent, which amendment shall be evidenced in writing and be effective as of the relevant Renewal Date; provided that, (i)

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Individual is provided with written notice of the Company’s election to amend the Agreement at least ninety (90) days prior to such Renewal Date, and (ii) no such amendment adversely affects Individual.

5.2    Interpretation. The Article and Section headings herein are for convenience only and shall not affect the construction hereof. In this Agreement, unless a clear contrary intention appears, (i) the words “herein,” “hereof,” and “hereunder” and other words of similar import refer to this Agreement as a whole and not to any particular Article, Section or other subdivision, (ii) reference to any Article or Section, means such Article or Section hereof, (iii) the word “including” (and with correlative meaning “include”) means including, without limiting the generality of any description preceding such term, and (iv) where any provision of this Agreement refers to action to be taken by either party, or which such party is prohibited from taking, such provision shall be applicable whether such action is taken directly or indirectly by such party.

5.3    Effect on Other Plans. Except in the case of a Severance Plan, as defined in Section 2.3, nothing in this Agreement shall prevent or limit Individual’s continuing or future participation in any other plan, program, policy or practice provided by the Company or any other member of the Company Group for which Individual may qualify, nor shall anything herein limit or otherwise affect such rights as Individual may have under any other contract or agreement with the Company or any other member of the Company Group. Amounts which are vested benefits or which Individual is otherwise entitled to receive under any such other plan, policy, practice, program, contract or agreement (“Other Arrangement”) at or subsequent to the termination of Individual’s employment shall be payable in accordance with such Other Arrangement except as explicitly modified by this Agreement; provided, however, the time period after such termination shall not be credited as continued employment of Individual for any purpose under any such Other Arrangement.

5.4    Overpayments. Individual agrees that the Company, in its sole discretion, may require repayment by Individual of any amount erroneously made in excess of the amounts that should have been paid under the terms of this Agreement.

5.5    Severability. The invalidity or unenforceability of any provision of this Agreement shall not affect the validity or enforceability of any other provision of this Agreement, which shall remain in full force and effect.

5.6    No Breach. Individual represents and warrants to the Company that neither the execution nor delivery of this Agreement, nor the performance of Individual’s obligations hereunder will conflict with, or result in a breach of, any term, condition, or provision of, or constitute a default under, any obligation, contract, agreement, covenant, or instrument to which Individual is a party or under which Individual is bound, including without limitation, the breach by Individual of a fiduciary or contractual duty to any former employers.

5.7    Entire Agreement; Manner of Amendment. Except with respect to the Severance Agreement, and subject to Section 2.3, this Agreement cancels and supersedes all previous agreements relating to the subject matter of this Agreement, written or oral, between the parties hereto and their respective affiliates and contains the entire understanding of the parties hereto. This Agreement shall not be amended, modified or supplemented in any manner whatsoever except by mutual written agreement of the parties hereto or in accordance with Section 5.1. Failure of the Company to demand strict compliance with any of the terms, covenants or conditions hereof shall not be deemed a waiver of the term, covenant or condition, nor shall any waiver or relinquishment by the Company of any right or power hereunder at any one time or more times be deemed a waiver or relinquishment of the right or power at any other time or times.

5.8    Governing Law; Venue. This Agreement and all rights and obligations of the parties hereunder shall be governed by, and construed and interpreted in accordance with, the laws of the State of Texas, including all matters of enforcement, validity, and performance without regard to conflict or choice of law principles. Except for injunction actions or proceedings initiated by the Company pursuant to Section 3.6, venue for any action or proceeding relating to this Agreement and/or Individual’s employment relationship with the Company and the Company Group, as applicable, shall lie exclusively in courts in Dallas County, Texas.

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5.9    Notices. All notices and all other communications provided for in the Agreement shall be in writing and addressed (i) if to the Company, at its principal office address or such other address as it may have designated by written notice to Individual for purposes hereof, directed to the attention of the Board with a copy to the Secretary of the Company and (ii) if to Individual, at his or her residence address on the records of the Company or to such other address as he or she may have designated to the Company in writing for purposes hereof. Each such notice or other communication shall be deemed to have been duly given when personally delivered or sent by United States registered mail, return receipt requested, postage prepaid, or by a nationally recognized overnight delivery service, with delivery confirmed.

5.10    Assignment. This Agreement is personal and not assignable by Individual but it may be assigned by the Company without notice to or consent of Individual to, and shall thereafter be binding upon and enforceable by, (i) any member of the Company Group, or (ii) any Person that acquires or succeeds to substantially all of the business or assets of any member of the Company Group (and such Person shall be deemed included in the definition of the “Company” and the “Company Group” for all purposes of this Agreement).

5.11    Tax Withholdings. The Company shall withhold from all payments hereunder all applicable taxes (federal, state or other) that it is required to withhold therefrom.

5.12    Employment with Affiliates. For purposes of this Agreement, employment with any member of the Company Group shall be deemed to be employment with the Company.

5.13    Company Actions. Actions taken hereunder by the Company, including any determinations or exercises of discretion pursuant to this Agreement, shall be undertaken (i) with the approval of the Board, with respect to (A) the adoption of any amendment hereto under Sections 5.1 or 5.7 of this Agreement, (B) an election not to extend the Term under Section 5.1 of this Agreement, and (C) in the event Individual is an “executive officer” under the Securities Exchange Act of 1934, as amended, (1) the determination to terminate Individual’s employment for Cause when applicable and for purposes of this Agreement, (2) the determination of whether any other termination of Individual’s employment constitutes a Qualifying Termination or arises due to his or her Disability, and (3) the exercise of the clawback, repayment and similar remedies of the Company under Article IV and Sections 3.7 and 5.4 of this Agreement; (ii) in the event Individual is an “executive officer” under the Securities Exchange Act of 1934, as amended, with the approval of the Board or the Committee with respect to (A) the placement of Individual on paid leave while a determination is being made as to whether there is a basis to terminate Individual’s employment for Cause, and (B) the determination of which actions, if any, are appropriate to remedy an event pursuant to clause (B) of the definition of Good Reason herein; and (iii) with the approval of the Board or the Committee or by the Chief Executive Officer of EnLink Midstream, LLC with respect to (A) the selection of the Accounting Firm pursuant to Section 2.4(b) of this Agreement; (B) the seeking of an injunction pursuant to Section 3.6 of this Agreement, and (C) in the event Individual is not an “executive officer” under the Securities Exchange Act of 1934, as amended, (1) the determination to terminate Individual’s employment for Cause when applicable and for purposes of this Agreement, (2) the determination of whether any other termination of Individual’s employment constitutes a Qualifying Termination or arises due to his or her Disability, (3) the placement of Individual on paid leave while a determination is being made as to whether there is a basis to terminate Individual’s employment for Cause, (4) the determination of which actions, if any, are appropriate to remedy an event pursuant to clause (B) of the definition of Good Reason herein, (5) the exercise of the clawback, repayment and similar remedies of the Company under Article IV and Sections 3.7 and 5.4 of this Agreement, and (6) the exercise of any other authority or discretion that is not described above, but is otherwise necessary or appropriate in order to satisfy the obligations and duties of, or to exercise the rights of, the Company for purposes of this Agreement. Notwithstanding any provision herein to the contrary, to the extent such actions relate only to Individual, and Individual is then serving as the Chief Executive officer of EnLink Midstream, LLC or as a member of the Board or Committee, such actions shall be undertaken by the Board or Committee without the participation of Individual in the authorization thereof.

5.14    Expenses. If any action at law or in equity is necessary to enforce or interpret the terms of this Agreement, the prevailing party shall be entitled to reasonable attorneys’ fees, in addition to any other relief to which such party may be entitled.

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5.15    Section 409A. This Agreement is intended to provide payments that are (i) exempt from the provisions of Code Section 409A and related regulations and Treasury pronouncements, by complying with (among other things) the short-term deferral exception as specified in Treasury Regulation § 1.409A-1(b)(4) and the involuntary separation pay exception within the meaning of Treasury Regulation § 1.409A-1(b)(9)(iii), or (ii) compliant with the provisions of Code Section 409A and related regulations and Treasury pronouncements, and this Agreement shall be administered, interpreted and construed accordingly. Any other provision of this Agreement to the contrary notwithstanding, the parties agree that any benefit or benefits under this Agreement that the Company determines are subject to the suspension period under Code Section 409A(a)(2)(B) shall not be paid or commence until such date that constitutes the first business day following six (6) months after Individual’s termination date, or if earlier, Individual’s death.

5.16    Counterparts. This Agreement may be executed in one or more counterparts, each of which shall be deemed to be an original, but all of which together will constitute one and the same instrument.

[Remainder of Page Intentionally Left Blank]

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IN WITNESS WHEREOF, the Company has caused this Agreement to be duly executed, and Individual has hereunto set his or her hand, as of the Effective Date.

ENLINK MIDSTREAM OPERATING, LP

By: ENLINK MIDSTREAM OPERATING GP, LLC,

Its general partner

Name:

Title:

INDIVIDUAL:

Name:

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EX-10.20

Exhibit 10.20

UNIT REPURCHASE AGREEMENT

This UNIT REPURCHASE AGREEMENT (this “Agreement”), dated as of February 15, 2022 (the “Effective Date”), is entered into by and between EnLink Midstream, LLC, a Delaware limited liability company (the “Company”), on the one hand, and GIP III Stetson I, L.P., a Delaware limited partnership (“GIP Stetson I”) and GIP III Stetson II, L.P., a Delaware limited partnership (“GIP Stetson II” and, together with GIP Stetson I, the “GIP Parties”), on the other hand. The Company and each of the GIP Parties are sometimes individually referred to herein as a “Party” and collectively as the “Parties.” Capitalized terms used but not defined herein shall have the meanings assigned to such terms in Article I of this Agreement.

RECITALS

WHEREAS, GIP Stetson I and GIP Stetson II are the record and beneficial owners of 108,859,690 and 115,495,669 common units representing limited liability company interests in the Company, respectively (the “GIP Units”);

WHEREAS, prior to the Effective Date, the Board of Directors of EnLink Midstream Manager, LLC, a Delaware limited liability company and the sole managing member of the Company, authorized a common unit repurchase program for the repurchase of up to $100 million (the “Authorized Repurchase Funds”) of the outstanding common units representing limited liability company interests in the Company (the “Common Units”), with such repurchases to be made from time to time in open market or private transactions in accordance with applicable securities laws and depending on market conditions;

WHEREAS, the Parties desire to establish a repurchase arrangement pursuant to which the Company will purchase from each of GIP Stetson I and GIP Stetson II a number of GIP Units representing a fixed percentage of the Common Units bought through the common unit repurchase program, on the terms and subject to the conditions of this Agreement;

WHEREAS, in connection with the repurchase by the Company of GIP Units from time to time, each of the GIP Parties will enter into an Assignment Agreement with the Company in the form attached as Exhibit A hereto (each, an “Assignment”), which Assignment shall provide for the assignment of the applicable GIP Units from such GIP Parties to the Company; and

WHEREAS, the Conflicts Committee has reviewed and approved this Agreement, the other Transaction Documents and the transactions contemplated hereby and thereby, with such approval constituting Special Approval (as defined in the Company Agreement).

NOW, THEREFORE, in consideration of the mutual covenants, representations, warranties and agreements herein contained, the Parties agree as follows:

ARTICLE I

DEFINITIONS

As used in this Agreement:

“Affiliate” means, with respect to any Person, any other Person that, directly or indirectly, Controls, is Controlled by or is under common Control with, such specified Person through one or more intermediaries or otherwise; provided, however, that (a) with respect to any GIP Party, the term “Affiliate” shall not include the Company or any of its subsidiaries, and (b) with respect to the Company, the term “Affiliate” shall not include either GIP Party or any of its Affiliates (other than the Company and its subsidiaries).

“Agreement” has the meaning given to such term in the preamble hereof.

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“Aggregate GIP Ownership Percentage” means the aggregate ownership percentage of the Common Units held by GIP Stetson I and GIP Stetson II at the close of business on the last business day prior to the start of the applicable Repurchase Quarter and after giving effect to the GIP Units to be purchased in respect of such prior quarter in accordance with Section 2.1 of this Agreement. For the avoidance of doubt, the Aggregate GIP Ownership Percentage shall reflect GIP Stetson I’s and GIP Stetson II’s aggregate economic ownership percentage in the Common Units and shall not take into account the ownership interest represented by any non-economic units, such as the Class C Common Units.

“Applicable Law” or “Law” means any applicable statute, law, regulation, ordinance, rule, judgment, rule of law (including common law), decree, permit, requirement, or other governmental restriction or any similar form of decision of, or any provision or condition issued under any of the foregoing by, or any determination by any Governmental Authority having or asserting jurisdiction over the matter or matters in question, whether now or hereafter in effect and in each case as amended (including all of the terms and provisions of the common law of such Governmental Authority), as interpreted and enforced at the time in question.

“Applicable Distribution Amount” means, for any Repurchase Quarter, a dollar amount equal to the number of Quarterly Repurchase Units multiplied by the per unit amount of the Company’s distribution for such Repurchase Quarter.

“Applicable Quarterly Percentage” means for any Repurchase Quarter, a percentage equal to (i) the applicable Aggregate GIP Ownership Percentage divided by (ii) 100% minus the applicable Aggregate GIP Ownership Percentage. For the first Repurchase Quarter, the Applicable Quarterly Percentage shall be 86.4074%. Attached as Exhibit B is an illustration of the calculation of the Applicable Quarterly Percentage for the first Repurchase Quarter. Applicable Quarterly Percentages for each subsequent Repurchase Quarter shall be calculated on the same basis.

“Assignment” has the meaning given to such term in the recitals hereto.

“Authorized Repurchase Funds” has the meaning given to such term in the recitals hereto.

“Business Day” means any day except a Saturday, Sunday or other day on which commercial banks in Dallas, Texas are authorized or required by Applicable Law to be closed.

“Common Units” has the meaning given to such term in the recitals hereto.

“Company” has the meaning set forth in the preamble.

“Company Agreement” means the Second Amended and Restated Operating Agreement of the Company, dated as of January 25, 2019.

“Conflicts Committee” has the meaning set forth in the Company Agreement.

“Contract” means any written contract, agreement, indenture, instrument, note, bond, loan, lease, sublease, easement, mortgage, deed of trust, franchise, license agreement, purchase order, binding bid or offer, binding term sheet or letter of intent or memorandum, commitment, letter of credit or any other legally binding arrangement, including any amendments or modifications thereof and waivers relating thereto.

“Daily Repurchase Units” means a number of Common Units equal to (i) the aggregate number of Common Units purchased by the Company in Open Market Repurchases on a Repurchase Date, multiplied by (ii) the Applicable Quarterly Percentage, rounded to the nearest whole Common Unit.

“Daily Repurchase Price” means (i) (A) the aggregate purchase price of the Open Market Units repurchased by the Company on the applicable Repurchase Date (excluding commissions paid to brokers to execute the open market

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repurchases) divided by (B) the aggregate number of Open Market Units repurchased by the Company on the applicable Repurchase Date, multiplied by (ii) the Daily Repurchase Units.

“Enforceability Exceptions” has the meaning given to such term in Section 3.2.

“GIP Parties” has the meaning set forth in the preamble.

“GIP Stetson I” has the meaning set forth in the preamble.

“GIP Stetson II” has the meaning set forth in the preamble.

“GIP Units” has the meaning given to such term in the recitals hereto.

“Governmental Authority” means any applicable multinational, foreign, federal, state, local or other governmental statutory or administrative authority, regulatory body or commission or any court, tribunal or judicial or arbitral authority which has any jurisdiction over a matter.

“Lien” means (a) any lien, hypothecation, pledge, collateral assignment, security interest, charge or encumbrance of any kind, whether such interest is based on the common law, statute or contract, and whether such obligation or claim is fixed or contingent (including any agreement to give any of the foregoing) and any option, trust or other preferential arrangement having the practical effect of any of the foregoing, other than in each case, the restrictions under applicable federal, state and other securities laws, the limited liability company agreement or limited partnership agreement, as applicable, of either of the GIP Parties, and (b) any purchase option, right of first refusal, right of first offer, call or similar right of a third party.

“Open Market Repurchase” means a repurchase by the Company of its Common Units on the open market at prevailing market prices.

“Open Market Units” means Common Units repurchased by the Company pursuant to an Open Market Repurchase.

“Party” and “Parties” have the meanings given to such terms in the preamble hereto.

“Person” means any natural person, corporation, limited partnership, general partnership, limited liability company, joint stock company, joint venture, association, company, estate, trust, bank trust company, land trust, business trust, or other organization, whether or not a legal entity, custodian, trustee-executor, administrator, nominee or entity in a representative capacity and any Governmental Authority.

“Proceeding” means any action, suit, claim, hearing, proceeding, arbitration, investigation, audit, inquiry, litigation or mediation (whether civil, criminal, administrative or investigative) commenced, brought, conducted or heard by or before any Governmental Authority, arbitrator or mediator.

“Quarterly Closing” has the meaning given to such term in Section 2.1(b).

“Quarterly Closing Date” has the meaning given to such term in Section 2.1(b).

“Quarterly Earnings Date” means the publicly announced date of the Company’s earnings release for the applicable Repurchase Quarter.

“Quarterly Repurchase Price” means an amount equal to the sum of all Daily Repurchase Prices in the applicable Repurchase Quarter less the Applicable Distribution Amount.

“Quarterly Repurchase Units” means Common Units equal to the aggregate number of Daily Repurchase Units in the applicable Repurchase Quarter.

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“Repurchase Date” means each Business Day on which the Company repurchases Open Market Units.

“Repurchase Quarter” means each three (3)-month calendar quarter; provided, however, that the first Repurchase Quarter shall be the period commencing on the Effective Date and ending on March 31, 2022.

“Transaction Documents” means, collectively, this Agreement and the Assignments.

ARTICLE II

THE TRANSACTIONS

Section 2.1    Repurchase, Delivery and Cancellation of the Quarterly Repurchase Units.

(a)At each Quarterly Closing, the Company agrees to purchase from GIP, and GIP agrees to sell, transfer, assign and deliver to the Company, free and clear of any Liens (other than as imposed by applicable securities laws or by the Company Agreement), the applicable Quarterly Repurchase Units in exchange for the Quarterly Repurchase Price, in accordance with the provisions of this Agreement. The Quarterly Repurchase Units and the Quarterly Repurchase Price shall be allocated between the GIP Parties on a pro rata basis based on their respective ownership percentages of the Common Units at the close of business on the last business day prior to the start of the applicable Repurchase Quarter and after giving effect to the GIP Units to be purchased in respect of such prior quarter in accordance with Section 2.1 of this Agreement. Following each repurchase of the Quarterly Repurchase Units hereunder, the Quarterly Repurchase Units shall be cancelled and shall no longer be deemed to be outstanding.

(b)No later than fifteen (15) Business Days after the end of each Repurchase Quarter, the Company shall provide to GIP a schedule reflecting the Applicable Quarterly Percentage for the Repurchase Quarter, the Applicable Distribution Amount, and for each Repurchase Date during the Repurchase Quarter, the number of Daily Repurchase Units and the Daily Repurchase Price with respect to such Repurchase Date, as well as the Quarterly Repurchase Units and Quarterly Repurchase Price for such Repurchase Quarter. One (1) Business Day prior to the Quarterly Earnings Date for such Repurchase Quarter, the Parties shall execute and deliver the items described in Section 2.2 and Section 2.3, as applicable, and consummate the closing with respect to the Quarterly Repurchase Units for such Repurchase Quarter (each, a “Quarterly Closing” and the date on which such Quarterly Closing occurs, a “Quarterly Closing Date”).

Section 2.2    GIP Party Closing Deliverables. At each Quarterly Closing, each of the GIP Parties shall deliver (or cause to be delivered) to the Company:

(a)a counterpart to an Assignment, duly executed on behalf of each GIP Party, and such other transfer documents or instruments that may be reasonably necessary to be delivered by such GIP parties in order to effect a sale, transfer, assignment and delivery of the Quarterly Repurchase Units to the Company in accordance with Section 2.1(a); and

(b)a duly completed Internal Revenue Service Form W-9.

Section 2.3    Company Closing Deliverables. At each Quarterly Closing, the Company shall deliver (or cause to be delivered) to the GIP Parties:

(a)the Quarterly Repurchase Price payable to each GIP Party in accordance with Section 2.1(a) by wire transfer of immediately available funds to the account or accounts designated by such GIP Parties in writing and provided to the Company at least two (2) Business Day prior to the applicable Quarterly Closing Date; and

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(b)counterparts to the Assignments, and such other transfer documents or instruments that may be reasonably necessary to be delivered by the Company in order to effect the repurchase of the Quarterly Repurchase Units in accordance with Section 2.1(a).

ARTICLE III

REPRESENTATIONS AND WARRANTIES OF THE GIP PARTIES

Each of the GIP Parties, severally and not jointly, and solely with respect to itself, represents and warrants to the Company as of the date hereof and, as of each Quarterly Closing Date, upon the delivery of an Assignment at each such Quarterly Closing Date, that:

Section 3.1    Organization. Such GIP Party is a limited partnership duly formed, validly existing and in good standing under the Laws of the State of Delaware.

Section 3.2    Authorization. Such GIP Party has all requisite limited partnership power and authority to execute, deliver, and perform each Transaction Document to which it is a party. The execution, delivery, and performance by such GIP Party of the Transaction Documents to which it is a party and the consummation by such GIP Party of the transactions contemplated hereby and thereby, have been duly authorized by all necessary limited partnership or limited liability company action, as the case may be. Each Transaction Document executed or to be executed by such GIP Party has been, or when executed will be, duly executed and delivered by such GIP Party and, assuming the execution and delivery by the other parties thereto, constitutes, or when executed and delivered by the other parties thereto will constitute, a valid and legally binding obligation of such GIP Party, enforceable against such GIP Party in accordance with its terms, except to the extent that such enforceability may be limited by (a) applicable bankruptcy, insolvency, reorganization, moratorium, fraudulent conveyance, or other similar Applicable Laws affecting creditors’ rights and remedies generally and (b) equitable principles that may limit the availability of certain equitable remedies (such as specific performance) in certain instances (the “Enforceability Exceptions”).

Section 3.3    No Conflicts or Violations. The execution, delivery, and performance of each of the Transaction Documents to which such GIP Party is a party, and the consummation of the transactions contemplated hereby and thereby, do not: (a) violate or conflict with any provision of the organizational documents of such GIP Party; (b) violate any Law applicable to such GIP Party; (c) violate, result in a breach of, constitute (with due notice or lapse of time or both) a default or cause any obligation, penalty or premium to arise or accrue under any Contract to which such GIP Party is a party; or (d) result in the creation or imposition of any Lien upon any of the properties or assets of such GIP Party, except, in the case of clauses (b) through (d), as would not, individually or in the aggregate, reasonably be expected to materially impede the ability of such GIP Party to consummate any of the transactions contemplated by this Agreement.

Section 3.4    Consents and Approvals. Except (a) as would not, individually or in the aggregate, reasonably be expected to materially impede the ability of such GIP Party to consummate any of the transactions contemplated hereby, or (b) for any filings required for compliance with any applicable requirements of the federal securities Laws, any applicable state or other local securities Laws and any applicable requirements of a national securities exchange, neither the execution and delivery by such GIP Party of any of the Transaction Documents to which such GIP Party is a party, nor the performance by such GIP Party of its respective obligations thereunder, requires the consent, approval, waiver or authorization of, or declaration, filing, registration or qualification with any Governmental Authority by such GIP Party.

Section 3.5    Ownership of Common Units. As of the date hereof, GIP Stetson I and GIP Stetson II are the record and beneficial owners of 108,859,690 and 115,495,669 Common Units, respectively, and prior to giving effect to the sale and transfer of the Quarterly Repurchase Units on each Quarterly Closing Date, each of GIP Stetson I and GIP Stetson II shall be, the record and beneficial owner of all the Quarterly Repurchase Units to be delivered to the Company, with each GIP Party having the full power to sell and transfer to the Company all such Quarterly Repurchase Units. On each Quarterly Closing Date, such GIP Parties shall deliver the applicable Quarterly Repurchase Units to the Company, free and clear of all Liens (other than as imposed by applicable securities laws or by the Company Agreement). None of the Quarterly Repurchase Units is subject to any voting

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trust or other contract, agreement, arrangement, commitment or understanding, written or oral, restricting or otherwise relating to the voting or disposition of the Quarterly Repurchase Units, other than this Agreement and the organizational documents or other voting arrangements among the GIP Parties. No proxies or powers of attorney have been granted with respect to the Quarterly Repurchase Units to be delivered by such GIP Parties to the Company. Except as contemplated by this Agreement, there are no outstanding warrants, options, agreements, convertible or exchangeable securities or other commitments pursuant to which such GIP Party is or may become obligated to transfer any of the Quarterly Repurchase Units, except as (a) would not reasonably be expected to impair the ability of such GIP Party to deliver the applicable Quarterly Repurchase Units to the Company as contemplated by this Agreement and (b) would not apply to the Quarterly Repurchase Units following the delivery of the Quarterly Repurchase Units to the Company pursuant to this Agreement.

Section 3.6    Litigation. There is no Proceeding pending or, to the knowledge of such GIP Party, threatened against such GIP Party, or against any officer, manager or director of such GIP Party, in each case related to the Quarterly Repurchase Units to be delivered by such GIP Party to the Company or the transactions contemplated hereby. Such GIP Party is not a party or subject to any order, writ, injunction, judgment or decree of any court or Governmental Authority relating to the Quarterly Repurchase Units to be delivered by such GIP Party to the Company or the transactions contemplated by this Agreement.

Section 3.7    Brokers and Finders. No investment banker, broker, finder, financial advisor or other intermediary is entitled to any broker’s, finder’s, financial advisor’s or other similar based fee or commission in connection with the transactions contemplated hereby as a result of being engaged by such GIP Party or any of its Affiliates.

Section 3.8    Acknowledgments. Such GIP Party acknowledges (for itself and on behalf of its Affiliates and representatives) that it has not relied on any advice or recommendation by the Company or its managers, directors, officers, agents or Affiliates with respect to its decision to enter into this Agreement and to consummate the transactions contemplated hereby. Such GIP Party (i) is a sophisticated seller with respect to the GIP Units and has sufficient knowledge, including but not limited to knowledge of the Company, and expertise, including with respect to investments in and dispositions of securities issued by the Company and comparable entities, to evaluate the business and financial condition of the Company and its subsidiaries and the merits and risks of the sale of the GIP Units, (ii) has had sufficient opportunity and time to investigate and review the business, management and financial affairs of the Company, and it has conducted, to its satisfaction, its own independent investigation, before its decision to enter into this Agreement, and further has had the opportunity to consult with all advisers it deems appropriate or necessary to consult with in connection with this Agreement and any action arising hereunder, including investment, legal, tax and accounting advisers and (iii) acknowledges and understands that the Company may, as of the Effective Date or as of any Quarterly Closing Date, possess or have access to material nonpublic information regarding the Company and the Common Units not known to GIP that may affect the value of the GIP Units and that the Company is or may be unable to disclose such information. Such GIP Party acknowledges that, in connection with its entry into this Agreement and consummation of the transactions contemplated hereby, it has not relied on any express or implied representations or warranties of any nature, oral or written, made by or on behalf of the Company or any of its managers, directors, officers, Affiliates or representatives, except for the representations or warranties of the Company set forth in Article IV.

ARTICLE IV

REPRESENTATIONS AND WARRANTIES OF THE COMPANY

The Company represents and warrants to each of the GIP Parties, as of the date hereof and, as of each Quarterly Closing Date, upon the delivery of a counterpart signature to the Assignment at each such Quarterly Closing Date, that:

Section 4.1    Organization. The Company is a limited liability company, duly formed, validly existing and in good standing under the Laws of the State of Delaware.

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Section 4.2    Authorization. The Company has all requisite limited liability company power and authority to execute, deliver, and perform each Transaction Document to which it is a party. The execution, delivery, and performance by the Company of the Transaction Documents to which it is a party and the consummation by the Company of the transactions contemplated hereby and thereby, have been duly authorized by all necessary limited liability company action on the part of the Company. Each Transaction Document executed or to be executed by the Company has been, or when executed will be, duly executed and delivered by the Company and, assuming the execution and delivery by the other parties thereto, constitutes, or when executed and delivered by the other parties thereto will constitute, a valid and legally binding obligation of the Company, enforceable against the Company in accordance with its terms, except to the extent that such enforceability may be limited by the Enforceability Exceptions.

Section 4.3    No Conflicts or Violations. The execution, delivery, and performance of each of the Transaction Documents to which the Company is a party, and the consummation of the transactions contemplated hereby and thereby, do not: (a) violate or conflict with any provision of the organizational documents of the Company; (b) violate any Law applicable to the Company; (c) violate, result in a breach of, constitute (with due notice or lapse of time or both) a default or cause any obligation, penalty or premium to arise or accrue under any Contract to which the Company is a party; or (d) result in the creation or imposition of any Lien upon any of the properties or assets of the Company, except, in the case of clauses (b) through (d), as would not, individually or in the aggregate, reasonably be expected to materially impede the ability of the Company to consummate any of the transactions contemplated by this Agreement.

Section 4.4    Consents and Approvals. Except (a) as would not, individually or in the aggregate, reasonably be expected to materially impede the ability of the Company to consummate any of the transactions contemplated hereby, or (b) for any filings required for compliance with any applicable requirements of the federal securities Laws, any applicable state or other local securities Laws and any applicable requirements of a national securities exchange, neither the execution and delivery by the Company of any of the Transaction Documents to which the Company is a party, nor the performance by the Company of its respective obligations thereunder, requires the consent, approval, waiver, or authorization of, or declaration, filing, registration, or qualification with any Governmental Authority by the Company.

Section 4.5    Litigation. There is no Proceeding pending or, to the knowledge of the Company, threatened against the Company, or against any officer, manager or director of the Company, in each case related to the Quarterly Repurchase Units to be delivered by the GIP Parties to the Company or the transactions contemplated hereby. The Company is not a party or subject to any order, writ, injunction, judgment or decree of any court or Governmental Authority relating to the Quarterly Repurchase Units to be delivered by the GIP Parties to the Company or the transactions contemplated by this Agreement.

Section 4.6    Brokers and Finders. No investment banker, broker, finder, financial advisor or other intermediary is entitled to any broker’s, finder’s, financial advisor’s or other similar based fee or commission in connection with the transactions contemplated hereby as a result of being engaged by the Company or any of its Affiliates.

Section 4.7    Acknowledgments. The Company acknowledges that it has not relied on any advice or recommendation by the GIP Parties or their respective partners, directors, officers, agents or affiliates with respect to the Company’s decision to enter into this Agreement and to consummate the transactions contemplated hereby. The Company has had the opportunity to consult with all advisors it deems appropriate or necessary to consult with in connection with this agreement and any action arising hereunder. The Company acknowledges that, in connection with its entry into this Agreement and consummation of the transactions contemplated hereby, it has not relied on any express or implied representations or warranties of any nature, oral, or written, made by or on behalf of any GIP Party or any of their respective Affiliates or representatives, except for the representations or warranties of the GIP Parties set forth in Article III.

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ARTICLE V

COVENANTS

Section 5.1    Further Assurances. On and after the Effective Date, the Parties shall use their respective commercially reasonable efforts to take or cause to be taken all appropriate actions and do, or cause to be done, all things reasonably necessary or appropriate to make effective the transactions contemplated hereby, including the execution of any assignment or similar documents or instruments of transfer of any kind at each Quarterly Closing Date, the obtaining of consents that may be reasonably necessary or appropriate to carry out any of the provisions hereof and the taking of all such other actions as such Party may reasonably request to be taken by the other Party from time to time, consistent with the terms of this Agreement, in order to effectuate the provisions and purposes of this Agreement and the transactions contemplated hereby.

Section 5.2    Quarterly Distributions. Each GIP Party shall be entitled to receive, and the Company shall pay to each GIP Party, any cash distribution payable under the Company Agreement with respect to the Quarterly Repurchase Units transferred by such GIP Party on the applicable Quarterly Closing Date and as and when paid to the holders of the Common Units pursuant to the Company Agreement, so long as such GIP Party is the record and beneficial owner of such Quarterly Repurchase Units as of the Record Date (as defined in the Company Agreement) for such cash distribution.

ARTICLE VI

TERMINATION

Section 6.1    Termination Notice. Subject to the proviso in Section 6.2, below, this Agreement may be terminated and the transactions contemplated hereby may be abandoned at any time by:

(i) the mutual written agreement of the Parties, effective as of the date designated as the termination date in such written agreement, or

(ii) either the Company or the GIP Parties upon the delivery of a written notice (the “Termination Notice”) of such termination to the other party or their representative, which notice shall set forth an effective date for such termination; provided, however, that, in the case of this clause (ii), the effective date of such termination shall be no earlier than 10 days from the date of delivery of the Termination Notice; or

(iii) the date on which all of the Authorized Repurchase Funds have been exhausted by the Company’s repurchase of Open Market Units and GIP Units under this Agreement.

Section 6.2    Effect of Termination. On the effective date of the termination pursuant to Section 6.1 (the “Termination Date”), this Agreement shall terminate, and there shall be no further liability or obligation hereunder or thereunder on the part of any Party hereto; provided, however, that (i) the Parties shall effect a “Quarterly Closing” of Quarterly Repurchase Units with respect to any Repurchase Dates effected during the Repurchase Quarter in which the Termination Date occurs, by applying the provisions of Section 2.1(b) as if the Termination Date were the end of the applicable Repurchase Quarter (mutatis mutandis), and (ii) nothing contained in this Agreement (including this sentence) will relieve any party from liability for any breach of any of its representations, warranties, covenants or agreements set forth in this Agreement.

ARTICLE VII

SURVIVAL

Section 7.1    All representations and warranties of the Parties contained in this Agreement shall terminate as of each Quarterly Closing Date in respect of the Quarterly Repurchase Units delivered by the GIP Parties to the Company as of such Quarterly Closing Date.

Section 7.2    All covenants and agreements of the Parties contemplated to be performed prior to each Quarterly Closing Date shall terminate as of such Quarterly Closing Date in respect of the Quarterly Repurchase Units delivered by the GIP Parties to the Company as of such Quarterly Closing Date.

8

Section 7.3    All covenants and agreements of the Parties contemplated to be performed following each Quarterly Closing Date shall survive such Quarterly Closing Date until performed in accordance with their respective terms.

Section 7.4    Regardless of any purported general termination of this Agreement, the provisions of Sections 6.2 and Article 8 shall remain operative and in full force and effect as between the Company and each GIP Party, unless the Company and each GIP Party execute a writing that expressly terminates such rights and obligations as between the Company and each GIP Party.

ARTICLE VIII

MISCELLANEOUS

Section 8.1    Headings; References; Interpretation. All Article and Section headings in this Agreement are for convenience only and shall not be deemed to control or affect the meaning or construction of any of the provisions hereof. The words “hereof,” “herein” and “hereunder” and words of similar import, when used in this Agreement, shall refer to this Agreement as a whole, and not to any particular provision of this Agreement. All references herein to Articles and Sections shall, unless the context requires a different construction, be deemed to be references to the Articles and Sections of this Agreement. All personal pronouns used in this Agreement, whether used in the masculine, feminine or neuter gender, shall include all other genders, and the singular shall include the plural and vice versa. The use herein of the word “including” following any general statement, term or matter shall not be construed to limit such statement, term or matter to the specific items or matters set forth immediately following such word or to similar items or matters, whether or not non-limiting language (such as “without limitation,” “but not limited to” or other words of similar import) is used with reference thereto, but rather shall be deemed to refer to all other items or matters that could reasonably fall within the broadest possible scope of such general statement, term or matter.

Section 8.2    No Third-Party Rights. The provisions of this Agreement are intended to bind the Parties as to each other and are not intended to, and do not, create rights in any other Person or confer upon any other Person any benefits, rights or remedies, and no Person is or is intended to be a third-party beneficiary of any of the provisions of this Agreement. Without limiting the generality of the foregoing, the Parties agree that their respective representations, warranties and covenants set forth in this Agreement are the product of negotiations among the Parties and are for the sole benefit of the Parties, in accordance with and subject to the terms of this Agreement, and no other Person has the right to rely upon the representations and warranties, or the right to enforce any covenants, set forth herein. Any inaccuracies in such representations and warranties are subject to waiver by the Parties in accordance with Section 8.6 without notice or liability to any other Person. In some instances, the representations and warranties in this Agreement may represent an allocation among the Parties of risks associated with particular matters regardless of the knowledge of any of the Parties. Consequently, Persons other than the Parties may not rely upon the representations and warranties in this Agreement as characterizations of actual facts or circumstances as of the date of this Agreement or as of any other date.

Section 8.3    Successors and Assigns. This Agreement shall be binding upon and inure to the benefit of the Parties and their respective successors and assigns. No Party may assign, in whole or in part, either this Agreement or any of its rights, interests or obligations hereunder without the prior written approval of the other Parties.

9

Section 8.4    Notices. All notices and demands provided for hereunder shall be in writing and shall be given by registered or certified mail, return receipt requested, electronic mail, air courier guaranteeing overnight delivery or personal delivery to the following addresses:

If to the Company:

EnLink Midstream, LLC

1722 Routh Street

Suite 1300

Dallas, TX, 75201

Attention: General Counsel

Email: legal@enlink.com

If to the GIP Parties:

GIP III Stetson I, L.P.

GIP III Stetson II, L.P.

c/o Global Infrastructure Management, LLC

1345 Avenue of the Americas

New York, New York 10105

Attention: Julie Ashworth

Email: GIPLegal@global-infra.com

Section 8.5    Severability. Whenever possible, each provision of this Agreement shall be interpreted in such manner as to be valid and effective under Applicable Law, but if any provision of this Agreement or the application of any such provision to any Person or circumstance shall be held invalid, illegal or unenforceable in any respect by a court of competent jurisdiction, such invalidity, illegality or unenforceability shall not affect any other provision hereof, and the Parties shall negotiate in good faith with a view to substitute for such provision a suitable and equitable solution in order to carry out, so far as may be valid and enforceable, the intent and purpose of such invalid, illegal or unenforceable provision.

Section 8.6    Amendment or Modification; Waiver. This Agreement may be amended, supplemented or modified from time to time only by the written agreement of all the Parties. Each such instrument shall be reduced to writing and shall be designated on its face as an amendment to this Agreement. Any extension or waiver of the obligations herein of any Party shall be valid only if set forth in an instrument in writing referring to this section and executed by the Party to be bound thereby. Any waiver of any term or condition shall not be construed as a waiver of any subsequent breach or a subsequent waiver of the same term or condition, or a waiver of any other term or condition, of this Agreement. The failure of any Party to assert any of its rights hereunder shall not constitute a waiver of any of such rights.

Section 8.7    Integration. This Agreement, each of the other Transaction Documents and each of the other instruments referenced herein and therein and in the exhibits attached hereto supersede all previous understandings or agreements among the Parties, whether oral or written, with respect to the subject matter of this Agreement, each of the other Transaction Documents and such other instruments. This Agreement, each of the other Transaction Documents and each of the other instruments referenced herein or therein contain the entire understanding of the Parties with respect to the subject matter hereof and thereof. There are no unwritten oral agreements between the parties. No understanding, representation, promise or agreement, whether oral or written, is intended to be or shall be included in or form part of this Agreement unless it is contained in a written amendment hereto executed by the Parties after the date of this Agreement.

Section 8.8    Expenses. Except as otherwise provided in this Agreement, each of the Parties will bear and pay all other costs and expenses incurred by it or on its behalf in connection with the transactions contemplated pursuant to this Agreement.

10

Section 8.9    Applicable Law. This Agreement shall be construed in accordance with and governed by the Laws of the State of Delaware, without regard to the principles of conflicts of law. EACH OF THE PARTIES AGREES THAT THIS AGREEMENT INVOLVES AT LEAST U.S. $100,000.00 AND THAT THIS AGREEMENT HAS BEEN ENTERED INTO IN EXPRESS RELIANCE UPON 6 Del. C. § 2708. EACH OF THE PARTIES IRREVOCABLY AND UNCONDITIONALLY AGREES (a) TO BE SUBJECT TO THE JURISDICTION OF THE COURTS OF THE STATE OF DELAWARE AND OF THE FEDERAL COURTS SITTING IN THE STATE OF DELAWARE, AND (b) TO THE EXTENT SUCH PARTY IS NOT OTHERWISE SUBJECT TO SERVICE OF PROCESS IN THE STATE OF DELAWARE, TO APPOINT AND MAINTAIN AN AGENT IN THE STATE OF DELAWARE AS SUCH PARTY’S AGENT FOR ACCEPTANCE OF LEGAL PROCESS AND TO NOTIFY THE OTHER PARTIES OF THE NAME AND ADDRESS OF SUCH AGENT.

Section 8.10    Specific Performance. The Parties agree that irreparable damage would occur and that there would be no adequate remedy at Law in the event that any of the provisions of this Agreement were not performed prior to termination of this Agreement in accordance with their specific terms or were otherwise breached. It is accordingly agreed that the Parties shall be entitled to an injunction or injunctions to prevent breaches of this Agreement and to enforce specifically the terms and provisions of this Agreement in the Court of Chancery of the State of Delaware without bond or other security being required, this being in addition to any other remedy to which they are entitled at law or in equity.

Section 8.11    Withholding. All payments and distributions under this Agreement shall be subject to withholding and backup withholding of tax to the extent required by Applicable Law, and amounts withheld, if any, shall be treated as received by the GIP Parties. The Company shall notify each GIP Party if it intends to withhold, pursuant to this Section 8.11, any amounts payable to such GIP Party.

Section 8.12    No Presumption Against Drafting Party. Each of the Parties acknowledge that it has been represented by counsel in connection with this Agreement and the transactions contemplated by this Agreement. Accordingly, any rule of law or any legal decision that would require interpretation of any claimed ambiguities in this Agreement against the drafting party has no application and is expressly waived.

Section 8.13    Counterparts. This Agreement may be executed in one or more counterparts, each of which shall be deemed an original, and all of which, when taken together, shall be deemed one agreement. The exchange of copies of this Agreement and of signature pages by facsimile or electronically including by PDF transmission shall constitute effective execution and delivery of this Agreement for all purposes. Signatures of the Parties hereto transmitted by facsimile or electronically including by PDF transmission shall be deemed to be their original signatures for all purposes. The words “execution,” “signed,” “signature” and words of like import in this Agreement or in any other certificate, agreement or document related to this Agreement shall include images of manually executed signatures transmitted by facsimile or other electronic format (including “pdf,” “tif” or “jpg”) and other electronic signatures (including DocuSign and AdobeSign). The use of electronic signatures and electronic records (including any contract or other record created, generated, sent, communicated, received or stored by electronic means) shall be of the same legal effect, validity and enforceability as a manually executed signature or use of a paper-based record-keeping system to the fullest extent permitted by applicable law, including the Federal Electronic Signatures in Global and National Commerce Act, the Delaware Uniform Electronic Transactions Act, the New York State Electronic Signatures and Records Act, and any other applicable law.

[Signature page follows]

11

IN WITNESS WHEREOF, each of the Parties has duly executed this Agreement as of the date first written above.

ENLINK MIDSTREAM, LLC

By: EnLink Midstream Manager, LLC, its Managing Member

By:

/s/ Pablo G. Mercado

Pablo G. Mercado

Executive Vice President and

Chief Financial Officer

12

GIP III STETSON I, L.P.

By: GIP III Stetson GP, LLC, its general partner

By:

/s/ Mark Levitt

Name:    Mark Levitt

Title:    Managing Director

GIP III STETSON II, L.P.

By: GIP III Stetson GP, LLC, its general partner

By:

/s/ Mark Levitt

Name:    Mark Levitt

Title:    Managing Director

13

Exhibit A

Assignment of Common Units

[See attached]

14

ASSIGNMENT OF COMMON UNITS

THIS ASSIGNMENT OF COMMON UNITS (this “Agreement”) is made effective as of [●] (the “Effective Date”), by and between EnLink Midstream, LLC, a Delaware limited liability company (the “Company”), on the one hand, and GIP III Stetson I, L.P., a Delaware limited partnership, GIP III Stetson II, L.P., a Delaware limited partnership (the “Assignor”), on the other hand. Capitalized terms used but not defined herein shall have the meanings assigned to such terms in the Purchase Agreement (as defined below).

RECITALS

WHEREAS, Assignor is the record and beneficial owner of [●] Common Units of the Company;

WHEREAS, the Company and Assignor have entered into that certain Unit Repurchase Agreement (the “Purchase Agreement”), dated as of February 15, 2022, pursuant to which, among other things, (a) the Company agreed to purchase from Assignor a number of Common Units as determined in accordance with Section 2.1(a) thereof (the “Subject Units”) and (b) Assignor agreed to sell, transfer, assign and deliver all of its right, title and interest in and to the Subject Units to the Company;

WHEREAS, Assignor desires to assign all of its right, title and interest in and to the Subject Units to the Company, and the Company desires to accept Assignor’s assignment of the Subject Units (the “Assignment”);

WHEREAS, immediately following the Assignment, the Company shall cancel the Subject Units, and the Subject Units shall cease to be outstanding; and

WHEREAS, in order to effectuate the Assignment, the Company and Assignor are executing and delivering this Agreement.

NOW, THEREFORE, in consideration of the mutual agreements contained herein, and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, and intending to be legally bound hereby, the parties hereto agree as follows:

1.Assignment. Effective as of the Effective Date, Assignor hereby irrevocably assigns, transfers and delivers to the Company all of Assignor’s right, title and interest in and to the Subject Units, together with all rights and obligations existing or arising with respect to the Subject Units, whether arising or attributable to periods prior to or after the Effective Date.

2.Acceptance, Assumption and Acknowledgment. Effective as of the Effective Date, the Company hereby accepts Assignor’s assignment of the Subject Units pursuant to Section 1.

3.Effect of Assignment. Effective as of the Effective Date, (a) Assignor shall cease to have any right, title or interest in or to the Subject Units and shall have no further rights or obligations with respect to the Subject Units under the Company Agreement or otherwise and (b) each of the Subject Units shall cease to be outstanding.

4.Choice of Law. This Agreement shall be governed by and construed in accordance with the laws of the State of Delaware, without giving effect to the principles of conflict of laws of that state.

5.Further Assurances. Each of Assignor and the Company agrees to take such further action as may be necessary or appropriate to effect the purposes of this Agreement.

6.General. This Agreement is binding on and shall inure to the benefit of the signatories hereto and their respective successors and assigns. This Agreement is expressly subject to the terms, provisions and limitations of the Purchase Agreement and, in the event of any conflict between the terms of this Agreement and the terms of the Purchase Agreement, the terms of the Purchase Agreement shall control.

15

This Agreement may be executed in one or more counterparts, each of which shall be deemed an original, and all of which, when taken together, shall be deemed one agreement. The exchange of copies of this Agreement and of signature pages by facsimile or electronically including by PDF transmission shall constitute effective execution and delivery of this Agreement for all purposes. Signatures of the Parties hereto transmitted by facsimile or electronically including by PDF transmission shall be deemed to be their original signatures for all purposes. The words “execution,” “signed,” “signature” and words of like import in this Agreement or in any other certificate, agreement or document related to this Agreement shall include images of manually executed signatures transmitted by facsimile or other electronic format (including “pdf,” “tif” or “jpg”) and other electronic signatures (including DocuSign and AdobeSign). The use of electronic signatures and electronic records (including any contract or other record created, generated, sent, communicated, received or stored by electronic means) shall be of the same legal effect, validity and enforceability as a manually executed signature or use of a paper-based record-keeping system to the fullest extent permitted by applicable law, including the Federal Electronic Signatures in Global and National Commerce Act, the Delaware Uniform Electronic Transactions Act, the New York State Electronic Signatures and Records Act, and any other applicable law. Each provision of this Agreement shall be considered severable and if for any reason any provision or provisions herein are determined to be invalid, unenforceable or illegal under any existing or future law, such invalidity, unenforceability or illegality shall not impair the operation of or affect those portions of this Agreement which are valid, enforceable and legal.

[Remainder of page intentionally left blank]

16

IN WITNESS WHEREOF, each of the Parties has duly executed this Agreement as of the date first written above.

ENLINK MIDSTREAM, LLC

By: EnLink Midstream Manager, LLC, its Managing Member

By:

Pablo G. Mercado

Executive Vice President and

Chief Financial Officer

17

[Signature Page to Assignment]

GIP III STETSON I, L.P.

By: GIP III Stetson GP, LLC, its general partner

By:

Name:    Mark Levitt

Title:    Managing Director

GIP III STETSON II, L.P.

By: GIP III Stetson GP, LLC, its general partner

By:

Name:    Mark Levitt

Title:    Managing Director

18

[Signature Page to Assignment]

Exhibit B

Applicable Quarterly Percentage Calculation

[See attached]

19

[Signature Page to Assignment]

EX-21.1

Exhibit 21.1

LIST OF SUBSIDIARIES

Name of Subsidiary	State of Organization
Acacia Natural Gas, L.L.C.	Delaware
Ascension Pipeline Company, LLC	Delaware
Bridgeline Holdings, L.P.	Delaware
Cedar Cove Midstream LLC	Delaware
Coronado Midstream LLC	Texas
Delaware G&P LLC	Delaware
Delaware Processing LLC	Delaware
EnLink Appalachia, LLC	Delaware
EnLink Appalachian Compression, LLC	Delaware
EnLink Calcasieu, LLC	Delaware
EnLink Crude Marketing, LLC	Delaware
EnLink Crude Pipeline, LLC	Delaware
EnLink Delaware Crude Pipeline, LLC	Texas
EnLink Energy GP, LLC	Delaware
EnLink Gas Marketing, LP	Texas
EnLink LIG, LLC	Louisiana
EnLink LIG Liquids, LLC	Louisiana
EnLink Louisiana Gathering, LLC	Louisiana
EnLink Matli Holdings, LLC	Delaware
EnLink Midstream Finance Corporation	Delaware
EnLink Midstream Funding, LLC	Delaware
EnLink Midstream GP, LLC	Delaware
EnLink Midstream Holdings GP, LLC	Delaware
EnLink Midstream Holdings, LP	Delaware
EnLink Midstream Operating GP, LLC	Delaware
EnLink Midstream Operating, LP	Delaware
EnLink Midstream Partners, LP	Delaware
EnLink Midstream Services, LLC	Texas
EnLink NGL Marketing, LP	Texas
EnLink NGL Pipeline, LP	Texas
EnLink Nominee Corp.	Delaware
EnLink North Texas Gathering, LP	Texas
EnLink Ohio Compression, LLC	Delaware
EnLink Oklahoma Crude Gathering, LLC	Delaware
EnLink Oklahoma Gas Processing, LP	Delaware
EnLink Oklahoma Pipeline, LLC	Delaware
EnLink Pelican, LLC	Delaware
EnLink Permian, LLC	Texas
EnLink Permian II, LLC	Texas
EnLink Processing Services, LLC	Delaware
EnLink Texas NGL Pipeline, LLC	Texas
EnLink Texas Processing, LP	Texas
EnLink Tuscaloosa, LLC	Louisiana
Gulf Coast Fractionators	Texas
Jefferson Island Storage & Hub, L.L.C.	Delaware
Ohio River Valley Pipeline, LLC	Delaware
OOGC Disposal Company I, LLC	Delaware
Sabine Hub Services LLC	Delaware
Sabine Pass Plant Facility Joint Venture	Texas
Sabine Pipe Line LLC	Delaware
SWG Pipeline, L.L.C.	Texas
TOM-STACK, LLC	Delaware

EX-22.1

Exhibit 22.1

List of Subsidiary Guarantors

The following subsidiary (the “Subsidiary Guarantor”) of EnLink Midstream, LLC, a Delaware limited liability company (the “Company”), has guaranteed on a full, irrevocable, unconditional, and absolute basis, the debt securities of the Company listed below. The Company owns all of the outstanding common units representing limited partnership interests in the Subsidiary Guarantor.

Subsidiary Guarantor

•EnLink Midstream Partners, LP, a Delaware limited partnership.

Debt Securities of the Company Guaranteed by the Subsidiary Guarantor

•5.375% Senior Notes due June 1, 2029

•5.625% Senior Notes due January 15, 2028

1

EX-23.1

Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

The Board of Directors of EnLink Midstream Manager, LLC:

We consent to the incorporation by reference in the registration statement No. 333-194395, No. 333-229347, and No. 333-229393 on Form S-8, No. 333-229806 on Form S-3 and No. 333-228278 on Form S-4 of EnLink Midstream, LLC of our report dated February 16, 2022, with respect to the consolidated financial statements of EnLink Midstream, LLC and subsidiaries, and the effectiveness of internal control over financial reporting which report appears in the Form 10-K of EnLink Midstream, LLC dated February 16, 2022.

/s/ KPMG LLP

Dallas, Texas

February 16, 2022

EX-31.1

Exhibit 31.1

CERTIFICATIONS

I, Barry E. Davis, certify that:

1.I have reviewed this annual report on Form 10-K of EnLink Midstream, LLC;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

(c)Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.    The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: February 16, 2022	/s/ BARRY E. DAVIS
	BARRY E. DAVIS
	Chairman and Chief Executive Officer
	(principal executive officer)

EX-31.2

Exhibit 31.2

CERTIFICATIONS

I, Pablo G. Mercado, certify that:

1.I have reviewed this annual report on Form 10-K of EnLink Midstream, LLC;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

(c)Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.    The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: February 16, 2022	/s/ PABLO G. MERCADO
	Pablo G. Mercado
	Executive Vice President and Chief Financial Officer
	(principal financial officer)

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of EnLink Midstream, LLC (the “Registrant”) on Form 10-K of the Registrant for the year ended December 31, 2021 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), each of the undersigned, Barry E. Davis, Chairman and Chief Executive Officer of EnLink Midstream Manager, LLC, and Pablo G. Mercado, Executive Vice President and Chief Financial Officer of EnLink Midstream Manager, LLC, certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to his knowledge:

(1)The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Registrant.

Date: February 16, 2022	/s/ BARRY E. DAVIS
	Barry E. Davis
	Chairman and Chief Executive Officer
Date: February 16, 2022	/s/ PABLO G. MERCADO
	Pablo G. Mercado
	Executive Vice President and Chief Financial Officer

A signed original of this written statement required by Section 906 has been provided to the Registrant and will be retained by the Registrant and furnished to the Securities and Exchange Commission or its staff upon request. The foregoing certification is being furnished to the Securities and Exchange Commission as an exhibit to the Report.

XML

Cover Page - USD ($) $ in Billions	12 Months Ended
	Dec. 31, 2021	Feb. 09, 2022	Jun. 30, 2021
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2021
Document Transition Report	false
Entity File Number	001-36336
Entity Registrant Name	ENLINK MIDSTREAM, LLC
Document Fiscal Year Focus	2021
Amendment Flag	false
Entity Central Index Key	0001592000
Current Fiscal Year End Date	--12-31
Document Fiscal Period Focus	FY
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	46-4108528
Entity Address, Address Line One	1722 Routh St.,
Entity Address, Address Line Two	Suite 1300
Entity Address, City or Town	Dallas,
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	75201
City Area Code	214
Local Phone Number	953-9500
Title of 12(b) Security	Common Units Representing LimitedLiability Company Interests
Trading Symbol	ENLC
Security Exchange Name	NYSE
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
ICFR Auditor Attestation Flag	true
Entity Shell Company	false
Entity Public Float			$ 1.7
Entity Common Stock, Shares Outstanding		484,003,750

XML

Audit Information	12 Months Ended
	Dec. 31, 2021
Audit Information [Abstract]
Auditor Firm ID	185
Auditor Location	Dallas, TX
Auditor Name	KPMG LLP

XML

Consolidated Balance Sheets - USD ($) $ in Millions		Dec. 31, 2021	Dec. 31, 2020
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, respectively		94.9	80.6
Accrued revenue and other		693.3	447.5
Fair value of derivative assets		22.4	25.0
Other current assets		83.6	58.7
Total current assets		920.4	651.4
Property and equipment, net of accumulated depreciation of $4,332.0 and $3,863.0, respectively		6,388.3	6,652.1
Intangible assets, net of accumulated amortization of $795.1 and $668.8, respectively		1,049.7	1,125.4
Investment in unconsolidated affiliates		28.0	41.6
Fair value of derivative assets		0.2	4.9
Other assets, net		96.6	75.5
Total assets		8,483.2	8,550.9
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 liabilities		34.9	37.1
Current maturities of long-term debt		0.0	349.8
Other current liabilities		202.9	149.1
Total current liabilities		898.9	888.0
Long-term debt		4,363.7	4,244.0
Other long-term liabilities		93.9	94.8
Deferred tax liability, net		137.5	108.6
Fair value of derivative liabilities		2.2	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 interest		1,662.6	1,719.5
Total members’ equity		2,987.0	3,213.0
Commitments and contingencies (Note 14)
Total liabilities and members’ equity		$ 8,483.2	$ 8,550.9

[1] Includes related party accounts payable balances of $1.6 million and $1.0 million at December 31, 2021 and December 31, 2020, respectively.

XML

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
ASSETS
Accounts receivable, allowance for credit loss, current	$ 0.3	$ 0.5
Accumulated depreciation	4,332.0	3,863.0
Accumulated amortization	$ 795.1	$ 668.8
Members’ equity:
Common units issued (in shares)	484,277,258	489,381,149
Common units outstanding (in shares)	484,277,258	489,381,149
Accounts payable, related parties	$ 1.6	$ 1.0

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Consolidated Statements of Operations - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Revenues:
Revenue from contracts with customers		$ 6,845.0	$ 3,915.8	$ 6,038.5
Gain (loss) on derivative activity		(159.1)	(22.0)	14.4
Total revenues		6,685.9	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 expenses		362.9	373.8	467.1
Depreciation and amortization		607.5	638.6	617.0
Impairments		0.8	362.8	1,133.5
(Gain) loss on disposition of assets		(1.5)	8.8	(1.9)
General and administrative		107.8	103.3	152.6
Loss on secured term loan receivable		0.0	0.0	52.9
Total operating costs and expenses		6,267.4	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		0.0	32.0	0.0
Income (loss) from unconsolidated affiliates		(11.5)	0.6	(16.8)
Other income		0.0	0.3	0.9
Total other expense		(250.2)	(190.4)	(231.9)
Income (loss) before non-controlling interest and income taxes		168.3	(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 interest		120.5	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 (in dollars per share)		$ 0.05	$ (0.86)	$ (2.41)
Diluted common unit (in dollars per share)		$ 0.05	$ (0.86)	$ (2.41)
Product sales
Revenues:
Revenue from contracts with customers		$ 5,994.0	$ 2,977.5	$ 5,030.1
Midstream services
Revenues:
Revenue from contracts with customers		$ 851.0	$ 938.3	$ 1,008.4

[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.

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Consolidated Statements of Operations (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Income Statement [Abstract]
Related party cost of sales	$ 17.9	$ 8.7	$ 21.7

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Consolidated Statements of Comprehensive Income (Loss) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2021		Dec. 31, 2020		Dec. 31, 2019
Statement of Comprehensive Income [Abstract]
Net income (loss)		$ 142.9		$ (315.6)		$ (999.6)
Unrealized gain (loss) on designated cash flow hedge	[1]	13.9	[2]	(4.3)	[3]	(9.0)	[4]
Comprehensive income (loss)		156.8		(319.9)		(1,008.6)
Comprehensive income attributable to non-controlling interest		120.5		105.9		119.7
Comprehensive income (loss) attributable to ENLC		$ 36.3		$ (425.8)		$ (1,128.3)

[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.

[2] Includes a tax expense of $4.3 million.

[3] Includes a tax benefit of $1.3 million.

[4] Includes a tax benefit of $3.4 million.

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Consolidated Statements of Comprehensive Income (Loss) (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Statement of Comprehensive Income [Abstract]
Income tax expense (benefit)	$ 4.3	$ (1.3)	$ (3.4)

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Consolidated Statements of Changes in Members' Equity - USD ($) $ in Millions		Total		Cumulative Effect, Period of Adoption, Adjustment	Cumulative Effect, Period of Adoption, Adjusted Balance	Common Units	Common Units Cumulative Effect, Period of Adoption, Adjustment	Common Units Cumulative Effect, Period of Adoption, Adjusted Balance	Accumulated Other Comprehensive Loss	Accumulated Other Comprehensive Loss Cumulative Effect, Period of Adoption, Adjusted Balance	Non-Controlling Interest	Non-Controlling Interest Cumulative Effect, Period of Adoption, Adjusted Balance	Redeemable Non-controlling interest (Temporary Equity)	Redeemable Non-controlling interest (Temporary Equity) Cumulative Effect, Period of Adoption, Adjusted Balance
Member equity, beginning balance at Dec. 31, 2018		$ 4,974.2		$ 0.3	$ 4,974.5	$ 1,730.9	$ 0.3	$ 1,731.2	$ (2.0)	$ (2.0)	$ 3,245.3	$ 3,245.3
Units outstanding, beginning balance (in shares) at Dec. 31, 2018						181,300,000		181,300,000
Increase (Decrease) in Members' Equity
Issuance of common units for ENLK public common units related to the Merger		399.0				$ 1,958.1					(1,559.1)
Issuance of common units for ENLK public common units related to the Merger (in shares)						304,900,000
Conversion of restricted units for common units, net of units withheld for taxes		(10.6)				$ (7.8)					(2.8)
Conversion of restricted units for common units, net of units withheld for taxes (in shares)						1,600,000
Unit-based compensation		38.9				$ 37.5					1.4
Contributions from non-controlling interests		97.5									97.5
Distributions		(687.4)				(467.2)					(220.2)		$ (0.3)
Unrealized gain (loss) on designated cash flow hedge	[1]	(9.0)	[2]						(9.0)
Fair value adjustment related to redeemable non-controlling interest		3.0				3.0							(4.0)
Net income (loss)		(999.8)				(1,119.3)					119.5		0.2
Member equity, end balance at Dec. 31, 2019		3,806.1				$ 2,135.5			(11.0)		1,681.6
Units outstanding, end balance (in shares) at Dec. 31, 2019						487,800,000
Redeemable noncontrolling interest, beginning balance at Dec. 31, 2018													9.3	$ 9.3
Increase (Decrease) in Temporary Equity
Fair value adjustment related to redeemable non-controlling interest		3.0				$ 3.0							(4.0)
Net income (loss)		(999.8)				(1,119.3)					119.5		0.2
Redeemable noncontrolling interest, ending balance at Dec. 31, 2019													5.2
Increase (Decrease) in Members' Equity
Conversion of restricted units for common units, net of units withheld for taxes		(4.7)				$ (4.7)					0.0
Conversion of restricted units for common units, net of units withheld for taxes (in shares)						2,000,000.0
Unit-based compensation		33.0				$ 33.0					0.0
Contributions from non-controlling interests		52.6									52.6
Distributions		(353.3)				(232.7)					(120.6)		(0.6)
Unrealized gain (loss) on designated cash flow hedge	[3]	(4.3)	[2]						(4.3)
Fair value adjustment related to redeemable non-controlling interest		0.4				0.4							(0.6)
Common units repurchased		$ (1.2)				$ (1.2)
Common units repurchased (in shares)		(383,614)				(400,000)
Net income (loss)		$ (315.6)				$ (421.5)					105.9
Member equity, end balance at Dec. 31, 2020		$ 3,213.0				$ 1,508.8			(15.3)		1,719.5
Units outstanding, end balance (in shares) at Dec. 31, 2020		489,381,149				489,400,000
Increase (Decrease) in Temporary Equity
Fair value adjustment related to redeemable non-controlling interest		$ 0.4				$ 0.4							(0.6)
Redemption of non-controlling interest		(4.0)
Net income (loss)		(315.6)				(421.5)					105.9
Redeemable noncontrolling interest, ending balance at Dec. 31, 2020													0.0
Increase (Decrease) in Members' Equity
Issuance of common units for ENLK public common units related to the Merger		399.0
Conversion of restricted units for common units, net of units withheld for taxes		(2.0)				$ (2.0)
Conversion of restricted units for common units, net of units withheld for taxes (in shares)						1,000,000.0
Unit-based compensation		23.6				$ 23.6
Contributions from non-controlling interests		3.2									3.2
Distributions		(317.4)				(186.8)					(130.6)		(0.2)
Unrealized gain (loss) on designated cash flow hedge	[4]	13.9	[2]						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)				$ (40.1)
Common units repurchased (in shares)		(6,091,001)				(6,100,000)
Net income (loss)		$ 142.9				$ 22.4					120.5
Member equity, end balance at Dec. 31, 2021		$ 2,987.0				$ 1,325.8			$ (1.4)		1,662.6
Units outstanding, end balance (in shares) at Dec. 31, 2021		484,277,258				484,300,000
Increase (Decrease) in Temporary Equity
Fair value adjustment related to redeemable non-controlling interest		$ (0.1)				$ (0.1)							0.2
Net income (loss)		$ 142.9				$ 22.4					$ 120.5
Redeemable noncontrolling interest, ending balance at Dec. 31, 2021													$ 0.0

[1] Includes a tax benefit of $3.4 million.

[2] 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.

[3] Includes a tax benefit of $1.3 million.

[4] Includes a tax expense of $4.3 million.

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Consolidated Statements of Changes in Members' Equity (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Statement of Stockholders' Equity [Abstract]
Income tax expense (benefit)	$ 4.3	$ (1.3)	$ (3.4)

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Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
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 amortization	607.5	638.6	617.0
Impairments	0.8	362.8	1,133.5
(Gain) loss on disposition of assets	(1.5)	8.8	(1.9)
Loss on secured term loan receivable	0.0	0.0	52.9
Non-cash unit-based compensation	25.3	28.4	39.4
Utility credits, net of usage	(32.6)	0.0	0.0
Non-cash loss on derivatives recognized in net income (loss)	10.3	14.8	2.5
Gain on extinguishment of debt	0.0	(32.0)	0.0
Amortization of debt issuance costs and net discount of senior unsecured notes	5.2	4.6	4.9
Amortization of designated cash flow hedge	12.5	0.5	0.1
Payments to terminate interest rate swaps	(1.8)	(10.9)	0.0
Deferred income tax expense	24.6	142.1	6.9
Distribution of earnings from unconsolidated affiliates	0.0	1.6	16.5
(Income) loss from unconsolidated affiliates	11.5	(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 liabilities	328.3	(104.8)	(245.5)
Net cash provided by operating activities	857.3	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)	0.0
Proceeds from sale of property	4.8	17.6	14.3
Distribution from unconsolidated affiliates in excess of earnings	3.9	0.5	3.7
Other investing activities	0.6	(1.3)	(4.6)
Net cash used in investing activities	(231.4)	(317.7)	(741.5)
Cash flows from financing activities:
Proceeds from borrowings	1,234.5	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)	0.0	0.0
Common unit repurchases	(40.1)	(1.2)	0.0
Contributions by non-controlling interests	3.2	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 activities	2.5	(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 period	39.6	77.4	100.4
Cash and cash equivalents, end of period	$ 26.2	$ 39.6	$ 77.4

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Organization and Nature of Business

12 Months Ended

Dec. 31, 2021

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization and Nature of Business

(1) Organization and Nature of Business

(a) Organization of Business

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

Devon Transaction

In 2014, we completed a series of transactions with Devon pursuant to which Devon contributed certain subsidiaries and assets to us in exchange for a 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, ENLC, and the Managing Member to GIP. As a result of the transaction:

•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 23.1% of the outstanding limited partner interests in ENLK;

•GIP, through GIP III Stetson II, L.P., acquired all of the equity interests held by subsidiaries of Devon in ENLC, which, as of the closing date, amounted to approximately 63.8% of the outstanding limited liability company interests in ENLC; and

•Through this transaction, GIP acquired control of (i) the Managing Member, (ii) ENLC, and (iii) ENLK, as a result of ENLC’s ownership of the General Partner.

Simplification of the Corporate Structure

On January 25, 2019, we completed the Merger, an internal reorganization pursuant to which ENLC owns all of the outstanding common units of ENLK. As a result 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 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 8—Certain Provisions of the Partnership Agreement” for additional information regarding the modified terms of the Series B Preferred Units.

•ENLC issued to the holder of the 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.

•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 ENLC. In connection with the Merger, we entered into the Consolidated Credit Facility, with respect to which ENLK is a guarantor. See “Note 6—Long-Term Debt” for additional information regarding the Consolidated Credit Facility.

•We were required to allocate the goodwill in our Corporate reporting unit previously associated with the incentive distribution rights in 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.

•We reduced our deferred tax liability by $399.0 million related to ENLC’s step-up in 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, and selling NGLs; and

•gathering, transporting, stabilizing, storing, trans-loading, and selling crude oil and condensate, in addition to brine disposal services.

Our midstream energy asset network includes approximately 12,100 miles of pipelines, 22 natural gas processing plants with approximately 5.5 Bcf/d of processing capacity, seven fractionators with approximately 320,000 Bbls/d of fractionation capacity, barge and rail terminals, product storage facilities, purchasing and marketing capabilities, brine disposal wells, a crude oil trucking fleet, and equity investments in certain joint ventures. Our operations are based in the United States, and our sales are derived primarily from domestic customers.

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

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

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

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.

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Significant Accounting Policies

12 Months Ended

Dec. 31, 2021

Accounting Policies [Abstract]

Significant Accounting Policies

(2) Significant Accounting Policies

(a)Basis of Presentation

The accompanying consolidated financial statements have been prepared in accordance with GAAP. All significant intercompany balances and transactions have been eliminated in consolidation. Certain reclassifications were made to the financial statements for the prior period to conform to current period presentation. The effect of these reclassifications had no impact on previously reported members’ equity or net income (loss).

(b)Management’s Use of Estimates

The preparation of financial statements in accordance with 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.

(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 most of our transactions is the use of our assets to transport a product or provide a processed product to an end-user or marketer at the tailgate of the plant, pipeline, or barge, truck, or rail terminal. Revenues from both “Product sales” and “Midstream services” represent revenues from contracts with customers and are reflected on the consolidated statements of operations as follows:

•Product sales—Product 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

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.

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 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 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 commodity 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 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. We typically receive payment for invoiced 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 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).

Minimum Volume Commitments and Firm Transportation Contracts

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

transportation contracts, as we generally do not expect volume shortfalls to equal the full amount of the contractual MVCs and firm transportation contracts during these periods.

Contractually Committed Fees	Commitments
2022	$	138.8
2023	126.5
2024	108.9
2025	63.8
2026	57.8
Thereafter	289.6
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 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.

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 payable	10.0
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 equipment	16.3
Intangible assets	50.6
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.

(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 $16.3 million and $6.1 million at December 31, 2021 and 2020, respectively, which approximate the fair value of these imbalances. We had imbalance receivables of $14.5 million and $7.5 million at December 31, 2021 and 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.

(g)Cash and Cash Equivalents

We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents.

(h)Income Taxes

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.”

(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.

(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. Routine repairs and maintenance are charged against income when incurred. Renewals and improvements 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.

The components of property and equipment, net of accumulated depreciation are as follows (in millions):

	Year Ended December 31,
	2021		2020
Transmission assets	$	1,442.2	$	1,410.5
Gathering systems	4,903.8		4,782.9
Gas processing plants	4,119.1		4,082.1
Other property and equipment	161.0		161.0
Construction in process	94.2		78.6
Property and equipment	10,720.3		10,515.1
Accumulated depreciation	(4,332.0)		(3,863.0)
Property and equipment, net of accumulated depreciation	$	6,388.3	$	6,652.1

Depreciation Expense. Depreciation is calculated using the straight-line method based on the estimated useful life of each asset, as follows:

	Useful Lives
Transmission assets	20 - 25 years
Gathering systems	20 - 25 years
Gas processing plants	20 - 25 years
Other property and equipment	3 - 25 years

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 consolidated statements of operations. For the years ended December 31, 2021, 2020, and 2019, dispositions primarily related to the sale of certain non-core assets. The (gain) loss on disposition of assets are as follows (in millions):

	Year Ended December 31,
	2021		2020		2019
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 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.

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, 2021, we recognized a $0.6 million impairment on property and equipment.

For the year ended December 31, 2020, we recognized a $168.0 million impairment on property and equipment related to a portion of our Louisiana reporting segment because the carrying amounts were not recoverable based on our expected future cash flows, and $3.4 million of impairments related to certain cancelled projects.

For the year ended December 31, 2019, we recognized a $7.9 million impairment on property and equipment related to certain decommissioned and removed non-core assets.

(k)Comprehensive Income (Loss)

Comprehensive income (loss) is comprised of net income (loss) and the effective portion of gains or losses on derivative financial instruments that qualify as cash flow hedges pursuant to ASC 815. For additional information about the effect of financial instruments on comprehensive income (loss), see “Note 12—Derivatives.”

(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 10—Investment in Unconsolidated Affiliates.”

(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 evaluated goodwill for impairment annually as of October 31 and whenever events or changes in circumstances indicated it was more likely than not that the fair value of a reporting unit is less than its carrying amount. For additional information regarding our previous assessments of goodwill for impairment, see “Note 3—Goodwill and Intangible Assets.”

(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 3—Goodwill and Intangible Assets.”

(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 more information, see “Note 5—Leases.”

(r)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. 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 to hedge variability in interest rates and effectively lock in the benchmark interest rate at the inception of the swap.

In 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 repayments of the Term Loan, which was one of our floating-rate, LIBOR-based borrowings. The following table presents the interest rate swaps terminations and the associated cash payments during 2021 and 2020 (in millions):

	Interest Rate Swaps Terminations		Cash Payments Associated with Interest Rate Swaps Terminations
December 2021	$	150.0	$	—
September 2021	100.0		0.5
May 2021	100.0		1.3
December 2020	500.0		10.9
Total termination of interest rate swaps	$	850.0	$	12.7

For additional information, see “Note 12—Derivatives.”

(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 significant customers discussed below, since our customers represent a broad and diverse group of energy marketers and end users.

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,
	2021		2020		2019
Devon	6.7	%	14.4	%	10.5	%
Dow Hydrocarbons and Resources LLC	14.5	%	13.2	%	10.0	%
Marathon Petroleum Corporation	13.4	%	12.2	%	13.8	%

We continually monitor and review the credit exposure of our counter-parties based on various credit quality indicators and metrics. We obtain letters of credit or other appropriate security 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 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 $0.5 million, respectively.

(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 not material for the years ended December 31, 2021, 2020, and 2019.

(u)Unit-Based Awards

We recognize compensation cost related to all unit-based awards in our consolidated financial statements in accordance with ASC 718. Unit-based compensation associated with ENLC’s unit-based compensation plan awarded to directors, officers, and employees of the General Partner is recorded by ENLK since ENLC has no substantial or managed operating activities other than its interests in ENLK. For additional information, see “Note 11—Employee Incentive Plans.”

(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 14—Commitments and Contingencies.”

(w)Debt Issuance Costs

Costs incurred in connection with the issuance of long-term debt are deferred and amortized 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 $27.8 million and $32.6 million as of December 31, 2021 and 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 the debt.

(x)Redeemable Non-Controlling Interest

Non-controlling interests that contain an option for the non-controlling interest holder to require us to purchase 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 interests are not considered to be a component of members’ equity and are 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.

During the first quarter of 2020, the non-controlling interest holder in one of our non-wholly owned subsidiaries exercised its option to require us to purchase its remaining interest. We have recorded an estimated $4.0 million related to the redemption of the non-controlling interest included in “Other current liabilities” on the consolidated balance sheets as of December 31, 2021 and 2020, but we have not yet agreed to a redemption value with the non-controlling interest holder.

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Goodwill and Intangible Assets

12 Months Ended

Dec. 31, 2021

Goodwill and Intangible Assets Disclosure [Abstract]

Goodwill and Intangible Assets

(3) Goodwill and Intangible Assets

Goodwill Impairments

Goodwill Impairment Analysis for the Year Ended December 31, 2020

During the first quarter of 2020, we determined that a sustained decline in our unit price and weakness in the overall energy sector, driven by low commodity prices and lower consumer demand due to the 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 Permian reporting unit. Based on this analysis, a goodwill impairment loss for our Permian reporting unit in the amount of $184.6 million was recognized as 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 no goodwill remaining as of December 31, 2020.

Goodwill Impairment Analysis for the Year Ended December 31, 2019

During the first quarter of 2019, 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 the 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, 2019. The goodwill for our North Texas and Oklahoma reporting units primarily related to the goodwill reallocated from our Corporate reporting unit as a result of the Merger in January 2019.

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.

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

	Gross Carrying Amount		Accumulated Amortization		Net 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 business	50.6		—		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

____________________________

(1)Intangible assets retired as a result of the disposition of certain non-core assets.

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

2022	$	127.6
2023	127.6
2024	127.6
2025	110.3
2026	106.4
Thereafter	450.2
Total	$	1,049.7

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Related Party Transactions

12 Months Ended

Dec. 31, 2021

Related Party Transactions [Abstract]

Related Party Transactions

(4) Related Party Transactions

(a)Transactions with Cedar Cove JV

For the years ended December 31, 2021, 2020, and 2019, we recorded cost of sales of $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. Additionally, we had accounts payable balances related to transactions with the Cedar Cove JV of $1.6 million and $1.0 million at December 31, 2021 and 2020, respectively.

(b)Transactions with GIP

For the years ended December 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.

(c)Transactions with ENLK

On January 25, 2019, we completed the Merger, an internal reorganization pursuant to which ENLC owns all of the 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.

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Leases

12 Months Ended

Dec. 31, 2021

Leases [Abstract]

Leases

(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 have the right to control the use of the compressors and 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.

Lease balances are recorded on the consolidated balance sheets as follows (in millions):

Operating leases:	December 31, 2021			December 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 leases	10.3 years			11.1 years
Weighted-average discount rate—Operating leases	4.9		%	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,
	2021		2020		2019
Finance lease expense:
Amortization of right-of-use asset	$	—	$	—	$	5.2
Interest on lease liability	—		—		0.1
Operating lease expense:
Long-term operating lease expense	21.7		23.1		28.7
Short-term lease expense	17.5		22.1		32.0
Variable lease expense	15.6		11.8		7.7
Impairments	0.2		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 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.

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 Midland offices. We are attempting to sublease the vacated space; however, as we believe 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 for the year ended December 31, 2020.

Lease Maturities

The following table summarizes the maturity of our lease liability as of December 31, 2021 (in millions):

	Total		2022		2023		2024		2025		2026		Thereafter
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

Leases

(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 have the right to control the use of the compressors and 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.

Lease balances are recorded on the consolidated balance sheets as follows (in millions):

Operating leases:	December 31, 2021			December 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 leases	10.3 years			11.1 years
Weighted-average discount rate—Operating leases	4.9		%	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,
	2021		2020		2019
Finance lease expense:
Amortization of right-of-use asset	$	—	$	—	$	5.2
Interest on lease liability	—		—		0.1
Operating lease expense:
Long-term operating lease expense	21.7		23.1		28.7
Short-term lease expense	17.5		22.1		32.0
Variable lease expense	15.6		11.8		7.7
Impairments	0.2		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 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.

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 Midland offices. We are attempting to sublease the vacated space; however, as we believe 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 for the year ended December 31, 2020.

Lease Maturities

The following table summarizes the maturity of our lease liability as of December 31, 2021 (in millions):

	Total		2022		2023		2024		2025		2026		Thereafter
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

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Long-Term Debt

12 Months Ended

Dec. 31, 2021

Debt Disclosure [Abstract]

Long-Term Debt

(6) Long-Term Debt

As of December 31, 2021 and 2020, long-term debt consisted of the following (in millions):

	December 31, 2021						December 31, 2020
	Outstanding Principal		Premium (Discount)		Long-Term Debt		Outstanding Principal		Premium (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 2024	521.8		0.7		522.5		521.8		1.1		522.9
ENLK’s 4.15% Senior unsecured notes due 2025	720.8		(0.4)		720.4		720.8		(0.6)		720.2
ENLK’s 4.85% Senior unsecured notes due 2026	491.0		(0.3)		490.7		491.0		(0.4)		490.6
ENLC’s 5.625% Senior unsecured notes due 2028	500.0		—		500.0		500.0		—		500.0
ENLC’s 5.375% Senior unsecured notes due 2029	498.7		—		498.7		498.7		—		498.7
ENLK’s 5.60% Senior unsecured notes due 2044	350.0		(0.2)		349.8		350.0		(0.2)		349.8
ENLK’s 5.05% Senior unsecured notes due 2045	450.0		(5.5)		444.5		450.0		(5.7)		444.3
ENLK’s 5.45% Senior unsecured notes due 2047	500.0		(0.1)		499.9		500.0		(0.1)		499.9
Debt classified as long-term	$	4,397.3	$	(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.

Maturities

Maturities for the long-term debt as of December 31, 2021 are as follows (in millions):

2022	$	—
2023	—
2024	886.8
2025	720.8
2026	491.0
Thereafter	2,298.7
Subtotal	4,397.3
Less: net discount	(5.8)
Less: debt issuance cost	(27.8)
Long-term debt, net of unamortized issuance cost	$	4,363.7

Term Loan

On December 11, 2018, ENLK entered into the Term Loan 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. 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.

Consolidated Credit Facility

The Consolidated Credit Facility permits ENLC to borrow up to $1.75 billion on a revolving credit basis and includes a $500.0 million letter of credit subfacility. The Consolidated Credit Facility 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 Consolidated Credit Facility are accelerated due to a default, ENLK will be liable for the entire outstanding balance and 105% of the outstanding letters of credit under the Consolidated Credit Facility. 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, 2021.

The Consolidated Credit Facility will mature on January 25, 2024, unless ENLC requests, and the requisite lenders agree, to extend it pursuant to its terms. The Consolidated 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. The financial covenants include (i) maintaining a ratio of consolidated EBITDA (as defined in the Consolidated Credit Facility, which term includes projected EBITDA from certain capital expansion projects) to consolidated interest charges of no less than 2.5 to 1.0 at all times prior to the occurrence of an investment grade event (as defined in the Consolidated Credit Facility) 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 Consolidated Credit Facility bear interest at ENLC’s option at the Eurodollar Rate (LIBOR) plus an applicable margin (ranging from 1.125% to 2.00%) or the Base Rate (the highest of the Federal Funds Rate plus 0.50%, the 30-day Eurodollar Rate plus 1.0% or the administrative agent’s prime rate) plus an applicable margin (ranging from 0.125%

to 1.00%). The applicable margins vary depending on ENLC’s debt rating. Upon breach by ENLC of certain covenants governing the Consolidated Credit Facility, amounts outstanding under the Consolidated Credit Facility, if any, may become due and payable immediately.

At December 31, 2021, we were in compliance with and expect to be in compliance with the financial covenants of the Consolidated Credit Facility for at least the next twelve months.

AR Facility

On October 21, 2020, EnLink Midstream Funding, LLC, a bankruptcy-remote special purpose entity that is an indirect subsidiary of ENLC (the “SPV”) entered into the AR Facility 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 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 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, 2021, the AR Facility had a borrowing base of $350.0 million. Borrowings under the AR Facility bear interest (based on LIBOR or LMIR (as defined in the AR 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 the obligations under the AR Facility must be repaid in full by no later than (i) the date that is ninety (90) days following such date or (ii) such earlier date on which the loans under the AR Facility become due and 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, 2021, we were in compliance with and expect to be in compliance with the financial covenants of the AR Facility for at least the next twelve months.

Issuances and Redemptions of Senior Unsecured Notes

On December 14, 2020, ENLC issued $500.0 million in aggregate principal amount of ENLC’s 5.625% senior unsecured notes due January 15, 2028 (the “2028 Notes”) at a price to the public of 100% of their face value. Interest payments on the 2028 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 $494.7 million were used to repay a portion of the borrowings under the Term Loan, which matured in December 2021.

All interest payments for senior unsecured notes are due semi-annually, in arrears.

Senior Unsecured Notes Redemption Provisions

Each issuance of the senior unsecured notes may be fully or partially redeemed prior to an early redemption date (see “Early Redemption 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 Point 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 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:

Issuance	Maturity Date of Notes	Early Redemption Date	Basis Point Premium
2024 Notes	April 1, 2024	Prior to January 1, 2024	25 Basis Points
2025 Notes	June 1, 2025	Prior to March 1, 2025	30 Basis Points
2026 Notes	July 15, 2026	Prior to April 15, 2026	50 Basis Points
2028 Notes	January 15, 2028	Prior to July 15, 2027	50 Basis Points
2029 Notes	June 1, 2029	Prior to March 1, 2029	50 Basis Points
2044 Notes	April 1, 2044	Prior to October 1, 2043	30 Basis Points
2045 Notes	April 1, 2045	Prior to October 1, 2044	30 Basis Points
2047 Notes	June 1, 2047	Prior to December 1, 2046	40 Basis Points

Senior Unsecured Notes 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, 2021, ENLC and ENLK were in compliance and expect to be in compliance with the covenants in the senior unsecured notes for at least the next twelve months.

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 debt	0.6
Gain on extinguishment of debt	$	32.0

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Income Taxes

12 Months Ended

Dec. 31, 2021

Income Tax Disclosure [Abstract]

Income Taxes

(7) Income Taxes

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

	Year Ended December 31,
	2021		2020		2019
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)

The following schedule reconciles total income tax expense and the amount calculated by applying the statutory U.S. federal tax rate to income before income taxes (in millions):

	Year Ended December 31,
	2021		2020		2019
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.

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, 2021 and 2020 are as follows (in millions):

	December 31, 2021		December 31, 2020
Deferred income tax assets:
Federal net operating loss carryforward	$	573.6	$	488.3
State net operating loss carryforward	59.6		61.0
Total deferred tax assets, gross	633.2		549.3
Valuation allowance	(151.6)		(153.3)
Total deferred tax assets, net of valuation allowance	481.6		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)

____________________________

(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, 2021, we had federal net operating loss (“NOL”) carryforwards of $2.7 billion that represent a net deferred tax asset of $573.6 million. As of December 31, 2021, we had state NOL carryforwards of $1.3 billion that represent a net deferred tax asset of $59.6 million. These carryforwards will begin expiring in 2028 through 2040. 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 it is more likely than not that the Company will realize the benefits of the deferred tax assets, net of valuation allowance.

For the years ended December 31, 2021 and 2020, there was no recorded unrecognized tax benefit. Per our accounting policy election, penalties and interest related to unrecognized tax benefits are recorded to income tax expense. As of December 31, 2021, tax years 2017 through 2021 remain subject to examination by various taxing authorities.

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Certain Provisions of the Partnership Agreement

12 Months Ended

Dec. 31, 2021

Partners' Capital [Abstract]

Certain Provisions of the Partnership Agreement

(8) Certain Provisions of the Partnership Agreement

(a) 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 in a private placement for a cash purchase price of $15.00 per Series B Preferred Unit (the “Issue Price”). On August 4, 2021, Enfield Holdings, L.P. (“Enfield”) sold all of its Series B Preferred Units and ENLC Class C Common

Units representing limited liability company interests in ENLC 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 $50.0 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.

Conversion and Distributions

Series B Preferred Units are exchangeable for ENLC common units 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 (the “Series B Exchange Ratio”). The exchange is subject to ENLK’s option to pay cash instead of issuing additional ENLC common units, and can occur in whole or in part at the option of the holder of the Series B Preferred Units at any time, or in whole at our option, provided the daily volume-weighted average closing price of the ENLC common units for the 30 trading days ending two trading days prior to the exchange is greater than 150% of the Issue Price divided by the conversion ratio of 1.15.

The holder of the Series B Preferred Units is entitled to quarterly cash distributions and distributions in-kind of additional Series B Preferred Units. The quarterly in-kind distribution (the “Series B PIK Distribution”) equals the greater of (A) 0.0025 Series B Preferred Units per Series B Preferred Unit and (B) the number of Series B Preferred Units equal to the quotient of (x) the excess (if any) of (1) the distribution that would have been payable by ENLC had the Series B Preferred Units been 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 plus 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 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).

A summary of the distribution activity relating to the Series B Preferred Units for the years ended December 31, 2021, 2020, and 2019 is provided below:

Declaration period	Distribution paid as additional Series B Preferred Units	Cash distribution (in millions)		Date paid/payable
2021
First Quarter of 2021	150,871	$	17.0	May 14, 2021
Second Quarter of 2021	151,248	$	17.0	August 13, 2021
Third Quarter of 2021	151,626	$	17.1	November 12, 2021
Fourth Quarter of 2021	—	$	19.2	February 11, 2022 (1)
2020
First Quarter of 2020	149,371	$	16.8	May 13, 2020
Second Quarter of 2020	149,745	$	16.8	August 13, 2020
Third Quarter of 2020	150,119	$	16.9	November 13, 2020
Fourth Quarter of 2020	150,494	$	16.9	February 12, 2021
2019
First Quarter of 2019	147,887	$	16.7	May 14, 2019
Second Quarter of 2019	148,257	$	17.1	August 13, 2019
Third Quarter of 2019	148,627	$	17.1	November 13, 2019
Fourth Quarter of 2019	148,999	$	16.8	February 13, 2020

____________________________

(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.

(b) Series C Preferred Units

In September 2017, ENLK issued 400,000 Series C Preferred Units representing ENLK limited partner interests at a price to the public of $1,000 per unit. 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’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 the 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 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.

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Members' Equity

12 Months Ended

Dec. 31, 2021

Earnings Per Share [Abstract]

Members' Equity

(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, 2021, ENLC repurchased 6,091,001 outstanding ENLC common units for an aggregate cost, including commissions, of $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 the Merger

In connection with the consummation of the Merger, we issued 304,822,035 ENLC common units in exchange for all of the outstanding ENLK common units not previously owned by us.

(c) ENLC Equity Distribution Agreement

On February 22, 2019, ENLC entered into the ENLC EDA with 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. Under the ENLC EDA, ENLC may also sell common units to any ENLC Sales Agent as principal for the ENLC Sales Agent’s own account at a price agreed upon at the time of sale. ENLC has no obligation to sell any ENLC common units under the ENLC EDA and may at any time suspend solicitation and offers under the ENLC EDA. As of February 9, 2022, ENLC has not sold any common units under the ENLC EDA.

(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,
	2021		2020		2019
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 units	0.5		(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)

____________________________

(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,
	2021	2020	2019
Basic weighted average units outstanding:
Weighted average common units outstanding	488.8	489.3	463.9
Diluted weighted average units outstanding:
Weighted average basic common units outstanding	488.8	489.3	463.9
Dilutive effect of non-vested restricted units (1)	5.5	—	—
Total weighted average diluted common units outstanding	494.3	489.3	463.9

____________________________

(1)For the years ended December 31, 2020 and 2019, all common unit equivalents were antidilutive because a net loss existed for those periods.

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.

(e) Distributions

A summary of our distribution activity related to the ENLC common units for the years ended December 31, 2021, 2020, and 2019, respectively, is provided below:

Declaration period	Distribution/unit		Date 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

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Investment in Unconsolidated Affiliates

12 Months Ended

Dec. 31, 2021

Equity Method Investments and Joint Ventures [Abstract]

Investment in Unconsolidated Affiliates

(10) Investment in Unconsolidated Affiliates

As of December 31, 2021, our unconsolidated investments consisted of a 38.75% ownership in GCF and a 30% ownership in 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,
	2021		2020		2019
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)

___________________________

(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.

The following table shows the balances related to our investment in unconsolidated affiliates as of December 31, 2021 and 2020 (in millions):

	December 31, 2021		December 31, 2020
GCF	$	28.0	$	40.6
Cedar Cove JV (1)	(1.8)		1.0
Total investment in unconsolidated affiliates	$	26.2	$	41.6

___________________________

(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.

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Employee Incentive Plans

12 Months Ended

Dec. 31, 2021

Share-based Payment Arrangement [Abstract]

Employee Incentive Plans

(11) Employee Incentive Plans

(a) Long-Term Incentive Plans

We account for unit-based compensation in accordance with ASC 718, which requires that compensation related to all unit-based awards be recognized in the consolidated financial statements. Unit-based compensation cost is valued at fair value at the date of grant, and that grant date fair value is recognized as expense over each award’s requisite service period with a corresponding increase to equity or liability based on the terms of each award and the appropriate accounting treatment under ASC 718. Unit-based compensation associated with ENLC’s unit-based compensation plan awarded to directors, officers, and employees of the General Partner is recorded by ENLK since ENLC has no substantial or managed operating activities other than its interests in ENLK.

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

	Year Ended December 31,
	2021		2020		2019
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 expense	6.6		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

____________________________

(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.

(b) ENLC Restricted Incentive Units

ENLC restricted incentive units were valued at their fair value at the date of grant, which is equal to the market value of ENLC common units on such date. A summary of the restricted incentive unit activity for the year ended December 31, 2021 is provided below:

	Year Ended December 31, 2021
ENLC Restricted Incentive Units:	Number of Units		Weighted Average Grant-Date Fair Value
Non-vested, beginning of period	5,350,086		$	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 period	7,507,471		$	5.46
Aggregate intrinsic value, end of period (in millions)	$	51.7

____________________________

(1)Restricted incentive units typically vest at the end of three years.

(2)Vested units included 382,343 units withheld for payroll taxes paid on behalf of employees.

A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for the years ended December 31, 2021, 2020, and 2019 is provided below (in millions):

	Year Ended December 31,
ENLC Restricted Incentive Units:	2021		2020		2019
Aggregate intrinsic value of units vested	$	5.6	$	12.1	$	17.3
Fair value of units vested	$	16.3	$	31.5	$	22.8

As of December 31, 2021, there were $13.0 million of unrecognized compensation costs that related to non-vested ENLC restricted incentive units. These costs are expected to be recognized over a weighted average period of 1.6 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

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) ENLC Performance Units

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

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 performance 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 Cumulative Performance Period. In short, the TSR for a given performance period is defined as (i)(A) the average closing price of a common equity security at the end of the relevant performance period minus (B) the average closing price of a common equity security at the beginning of the relevant performance period plus (C) reinvested dividends divided by (ii) the average closing price of a common equity security at the beginning of the relevant performance period.

The following table sets 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 Designated Peer Companies:

Performance Level	Achieved ENLC TSR Position Relative to Designated Peer Companies	Vesting percentage of the Tranche TSR Units
Below Threshold	Less than 25%	0%
Threshold	Equal to 25%	50%
Target	Equal to 50%	100%
Maximum	Greater 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 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 Level	ENLC’s Achieved FCFAD	Vesting percentage of the Tranche CF Units
Below Threshold	Less than $205 million	0%
Threshold	Equal to $205 million	50%
Target	Equal to $256 million	100%
Maximum	Greater than or Equal to $300 million	200%

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 Level	ENLC’s Achieved  Distributable Cash Flow per Unit	Vesting percentage of the Tranche CF Units
Below Threshold	Less than $1.345	0%
Threshold	Equal to $1.345	50%
Target	Equal to $1.494	100%
Maximum	Greater than or Equal to $1.643	200%

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 Level	ENLC’s Achieved  Distributable Cash Flow per Unit	Vesting percentage of the Tranche CF Units
Below Threshold	Less than $1.43	0%
Threshold	Equal to $1.43	50%
Target	Equal to $1.55	100%
Maximum	Greater than or Equal to $1.72	200%

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 Designated Peer 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 value assumptions by performance unit grant date:

ENLC Performance Units:	January 2021			July 2020			March 2020			January 2020			October 2019			June 2019			March 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 rate	0.17		%	0.17		%	0.42		%	1.62		%	1.44		%	1.72		%	2.42		%
Volatility factor	71.00		%	67.00		%	51.00		%	37.00		%	35.00		%	33.50		%	33.86		%

The following table presents a summary of the performance units:

	Year Ended December 31, 2021
ENLC Performance Units:	Number of Units		Weighted Average Grant-Date Fair Value
Non-vested, beginning of period	2,351,241		$	8.82
Granted	1,388,139		4.70
Vested (1)	(164,553)		26.73
Non-vested, end of period	3,574,827		$	6.40
Aggregate intrinsic value, end of period (in millions)	$	24.6

____________________________

(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:	2021		2020		2019
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, 2021, there were $10.4 million of unrecognized compensation costs that related to non-vested ENLC performance units. These costs are expected to be recognized over a weighted-average period of 1.6 years.

(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 eligible compensation. Contributions of $7.0 million, $7.2 million, and $9.4 million were made to the plan for the years ended December 31, 2021, 2020, and 2019, respectively.

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Derivatives

12 Months Ended

Dec. 31, 2021

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivatives

(12) Derivatives

Interest Rate Swaps

In 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 repayments of the Term Loan, which was one of our floating-rate, LIBOR-based borrowings. The following table presents the interest rate swaps terminations and the associated cash payments during 2021 and 2020 (in millions):

	Interest Rate Swaps Terminations		Cash Payments Associated with Interest Rate Swaps Terminations
December 2021	$	150.0	$	—
September 2021	100.0		0.5
May 2021	100.0		1.3
December 2020	500.0		10.9
Total termination of interest rate swaps	$	850.0	$	12.7

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 follows (in millions):

	Year Ended December 31,
	2021		2020		2019
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, recognized from accumulated other comprehensive loss from the monthly settlement of our interest rate swaps and amortization of the termination payments, included in our consolidated statements of operations were as follows (in millions):

	Year Ended December 31,
	2021		2020		2019
Interest expense	$	18.3	$	14.5	$	0.4

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

The fair value of our interest rate swaps included in our consolidated balance sheets were as follows (in millions):

	December 31, 2021		December 31, 2020
Fair value of derivative liabilities—current	$	—	$	(7.6)

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 and to manage margins on offsetting fixed-price purchase or sale commitments for physical quantities of crude, condensate, natural gas, and NGLs. We do not designate commodity swaps 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. For condensate, crude oil, and natural gas, index swaps are also used to hedge the basis location price risk resulting from supply and markets being priced on different indices. 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.

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

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

	Year Ended December 31,
	2021		2020		2019
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, 2021		December 31, 2020
Fair value of derivative assets—current	$	22.4	$	25.0
Fair value of derivative assets—long-term	0.2		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, 2021 (in millions). The remaining term of the contracts extend no later than January 2023.

		December 31, 2021
Commodity	Instruments	Unit	Volume	Net Fair Value
NGL (short contracts)	Swaps	Gals	(63.0)	$	(10.6)
NGL (long contracts)	Swaps	Gals	—	—
Natural gas (short contracts)	Swaps	MMbtu	(7.5)	2.7
Natural gas (long contracts)	Swaps	MMbtu	13.2	(7.8)
Crude and condensate (short contracts)	Swaps	MMbbls	(3.9)	(4.4)
Crude and condensate (long contracts)	Swaps	MMbbls	3.9	5.6
Total fair value of commodity swaps				$	(14.5)

On all transactions where we are exposed to counterparty risk, we analyze the counterparty’s financial condition prior to entering into an agreement, establish limits, and monitor the appropriateness of these limits on an ongoing basis. We primarily deal with financial institutions when entering into financial derivatives on commodities. We have entered into Master ISDAs that allow for netting of swap contract receivables and payables in the event of default by either party. If our counterparties failed to perform under existing commodity swap contracts, the maximum loss on our gross receivable position of $22.6 million as of December 31, 2021 would be reduced to $0.8 million due to the offsetting of gross fair value payables against gross fair value receivables as allowed by the ISDAs.

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Fair Value Measurements

12 Months Ended

Dec. 31, 2021

Fair Value Disclosures [Abstract]

Fair Value Measurements

(13) Fair Value Measurements

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.

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.

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

	Level 2
	December 31, 2021		December 31, 2020
Interest rate swaps (1)	$	—	$	(7.6)
Commodity swaps (2)	$	(14.5)	$	(2.1)

____________________________

(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.

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, 2021				December 31, 2020
	Carrying Value		Fair Value		Carrying Value		Fair 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	$	—	$	—

____________________________

(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.”

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

The fair values of all senior unsecured notes as of December 31, 2021 and 2020 were based on Level 2 inputs from third-party market quotations.

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2021

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

(14) Commitments and Contingencies

(a) 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

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.

(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.

(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. We may also be involved from time to time in the future in various proceedings in the normal course of business, including litigation on disputes related to contracts, property rights, property use or damage (including nuisance claims), personal injury, or the value of pipeline easements or other rights obtained through the exercise of eminent domain or common carrier rights.

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Segment Information

12 Months Ended

Dec. 31, 2021

Segment Reporting [Abstract]

Segment Information

(15) Segment Information

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 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:

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

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

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

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

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

We evaluate the performance of our operating segments based on segment profit and adjusted gross margin. Adjusted gross margin is a non-GAAP financial measure. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures” for additional information. Summarized financial information for our reportable segments is shown in the following tables (in millions):

	Permian		Louisiana		Oklahoma		North Texas		Corporate		Totals
Year Ended December 31, 2021
Natural gas sales	$	609.4	$	693.5	$	213.4	$	150.0	$	—	$	1,666.3
NGL sales	0.9		3,353.1		2.0		1.1		—		3,357.1
Crude oil and condensate sales	677.4		212.0		81.2		—		—		970.6
Product sales	1,287.7		4,258.6		296.6		151.1		—		5,994.0
NGL sales—related parties	1,008.4		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 parties	1,008.4		129.7		630.9		454.1		(2,223.1)		—
Gathering and transportation	46.8		64.7		186.9		157.0		—		455.4
Processing	29.1		2.4		98.7		108.3		—		238.5
NGL services	—		82.6		—		0.3		—		82.9
Crude services	18.4		39.3		12.8		0.7		—		71.2
Other services	0.2		1.7		0.6		0.5		—		3.0
Midstream services	94.5		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 customers	2,390.6		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 margin	311.2		448.6		407.6		328.6		—		1,496.0
Operating expenses	(81.5)		(123.7)		(80.0)		(77.7)		—		(362.9)
Segment profit	229.7		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

____________________________

(1)Includes related party cost of sales of $17.9 million for the year ended December 31, 2021.

	Permian		Louisiana		Oklahoma		North Texas		Corporate		Totals
Year Ended December 31, 2020
Natural gas sales	$	150.1	$	330.5	$	153.1	$	70.3	$	—	$	704.0
NGL sales	0.2		1,545.4		2.8		—		—		1,548.4
Crude oil and condensate sales	558.1		126.7		40.3		—		—		725.1
Product sales	708.4		2,002.6		196.2		70.3		—		2,977.5
NGL sales—related parties	312.6		31.4		296.4		115.2		(755.6)		—
Crude oil and condensate sales—related parties	0.6		—		(0.1)		3.6		(4.1)		—
Product sales—related parties	313.2		31.4		296.3		118.8		(759.7)		—
Gathering and transportation	42.8		46.5		228.7		179.2		—		497.2
Processing	24.1		2.0		123.6		132.6		—		282.3
NGL services	—		75.8		—		0.2		—		76.0
Crude services	16.8		45.2		16.5		0.2		—		78.7
Other services	1.2		1.6		0.4		0.9		—		4.1
Midstream services	84.9		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 customers	1,106.5		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 derivatives	1.1		(6.5)		(4.5)		(0.6)		—		(10.5)
Adjusted gross margin	264.3		405.6		487.6		347.8		—		1,505.3
Operating expenses	(94.2)		(120.0)		(82.2)		(77.4)		—		(373.8)
Segment profit	170.1		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

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(1)Includes related party cost of sales of $8.7 million for the year ended December 31, 2020.

	Permian		Louisiana		Oklahoma		North Texas		Corporate		Totals
Year Ended December 31, 2019
Natural gas sales	$	94.3	$	416.6	$	236.4	$	129.3	$	—	$	876.6
NGL sales	0.9		1,725.6		19.6		30.9		—		1,777.0
Crude oil and condensate sales	1,975.0		291.9		109.6		—		—		2,376.5
Product sales	2,070.2		2,434.1		365.6		160.2		—		5,030.1
Natural gas sales—related parties	0.4		—		—		—		(0.4)		—
NGL sales—related parties	347.7		25.7		421.1		94.8		(889.3)		—
Crude oil and condensate sales—related parties	13.5		1.7		—		5.5		(20.7)		—
Product sales—related parties	361.6		27.4		421.1		100.3		(910.4)		—
Gathering and transportation	48.8		58.3		234.5		196.4		—		538.0
Processing	30.5		3.2		138.2		143.0		—		314.9
NGL services	—		50.6		—		0.1		—		50.7
Crude services	19.2		51.9		19.8		—		—		90.9
Other services	12.0		0.7		0.1		1.1		—		13.9
Midstream services	110.5		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 customers	2,542.3		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 derivatives	9.4		5.1		—		—		—		14.5
Change in fair value of derivatives	1.5		(1.8)		—		0.2		—		(0.1)
Adjusted gross margin	269.3		444.5		554.1		392.5		—		1,660.4
Operating expenses	(112.9)		(147.3)		(104.0)		(102.9)		—		(467.1)
Segment profit	156.4		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

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(1)Includes related party cost of sales of $21.7 million for the year ended December 31, 2019.

The table below represents information about segment assets as of December 31, 2021 and 2020 (in millions):

Segment Identifiable Assets:	December 31, 2021		December 31, 2020
Permian	$	2,358.6	$	2,236.3
Louisiana	2,428.6		2,312.4
Oklahoma	2,619.5		2,847.6
North Texas	896.8		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.

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Supplemental Cash Flow Information

12 Months Ended

Dec. 31, 2021

Supplemental Cash Flow Elements [Abstract]

Supplemental Cash Flow Information

(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:	2021		2020		2019
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)	$	—

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Other Information

12 Months Ended

Dec. 31, 2021

Other Liabilities Disclosure [Abstract]

Other Information

(17) Other Information

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

Other current assets:	December 31, 2021		December 31, 2020
Natural gas and NGLs inventory	$	49.4	$	44.9
Prepaid expenses and other	34.2		13.8
Other current assets	$	83.6	$	58.7

Other current liabilities:	December 31, 2021		December 31, 2020
Accrued interest	$	47.2	$	35.7
Accrued wages and benefits, including taxes	33.1		22.5
Accrued ad valorem taxes	28.3		26.5
Capital expenditure accruals	23.2		10.6
Short-term lease liability	18.1		16.3
Installment payable (1)	10.0		—
Inactive easement commitment (2)	9.8		—
Operating expense accruals	9.6		8.4
Other	23.6		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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Subsequent Event

12 Months Ended

Dec. 31, 2021

Subsequent Events [Abstract]

Subsequent Event

(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.

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Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2021

Accounting Policies [Abstract]

Basis of Presentation

Basis of PresentationThe accompanying consolidated financial statements have been prepared in accordance with GAAP. All significant intercompany balances and transactions have been eliminated in consolidation. Certain reclassifications were made to the financial statements for the prior period to conform to current period presentation. The effect of these reclassifications had no impact on previously reported members’ equity or net income (loss).

Management's Use of Estimates

Management’s Use of EstimatesThe preparation of financial statements in accordance with 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.

Revenue Recognition

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 most of our transactions is the use of our assets to transport a product or provide a processed product to an end-user or marketer at the tailgate of the plant, pipeline, or barge, truck, or rail terminal. Revenues from both “Product sales” and “Midstream services” represent revenues from contracts with customers and are reflected on the consolidated statements of operations as follows:

•Product sales—Product 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

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.

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 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 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 commodity 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 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. We typically receive payment for invoiced 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 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).

Minimum Volume Commitments and Firm Transportation Contracts

Acquisition of Business

Acquisition of BusinessOn April 30, 2021, we completed the 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.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

Loss on Secured Term Loan Receivable

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.

Gas Imbalance Accounting

Gas Imbalance AccountingQuantities 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 $16.3 million and $6.1 million at December 31, 2021 and 2020, respectively, which approximate the fair value of these imbalances. We had imbalance receivables of $14.5 million and $7.5 million at December 31, 2021 and 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.

Cash and Cash Equivalents

Cash and Cash EquivalentsWe consider all highly liquid investments with an original maturity of three months or less to be cash equivalents.

Income Taxes

Income TaxesWe 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.”

Natural Gas, Natural Gas Liquids, Crude Oil, and Condensate Inventory

Natural Gas, Natural Gas Liquids, Crude Oil, and Condensate InventoryOur 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.

Property and Equipment

Property and EquipmentProperty and equipment are stated at historical cost less accumulated depreciation. Assets acquired in a business combination are recorded at fair value. Routine repairs and maintenance are charged against income when incurred. Renewals and improvements 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.

The components of property and equipment, net of accumulated depreciation are as follows (in millions):

	Year Ended December 31,
	2021		2020
Transmission assets	$	1,442.2	$	1,410.5
Gathering systems	4,903.8		4,782.9
Gas processing plants	4,119.1		4,082.1
Other property and equipment	161.0		161.0
Construction in process	94.2		78.6
Property and equipment	10,720.3		10,515.1
Accumulated depreciation	(4,332.0)		(3,863.0)
Property and equipment, net of accumulated depreciation	$	6,388.3	$	6,652.1

Depreciation Expense. Depreciation is calculated using the straight-line method based on the estimated useful life of each asset, as follows:

	Useful Lives
Transmission assets	20 - 25 years
Gathering systems	20 - 25 years
Gas processing plants	20 - 25 years
Other property and equipment	3 - 25 years

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 consolidated statements of operations. For the years ended December 31, 2021, 2020, and 2019, dispositions primarily related to the sale of certain non-core assets. The (gain) loss on disposition of assets are as follows (in millions):

	Year Ended December 31,
	2021		2020		2019
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 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.

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.

Comprehensive Income (Loss)

Comprehensive Income (Loss)Comprehensive income (loss) is comprised of net income (loss) and the effective portion of gains or losses on derivative financial instruments that qualify as cash flow hedges pursuant to ASC 815.

Equity Method of Accounting

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.

Non-controlling Interests

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.

Goodwill

Goodwill Goodwill is the cost of an acquisition less the fair value of the net identifiable assets of the acquired business. We evaluated goodwill for impairment annually as of October 31 and whenever events or changes in circumstances indicated it was more likely than not that the fair value of a reporting unit is less than its carrying amount.

Intangible Assets

Intangible AssetsIntangible 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.

Asset Retirement Obligations

Asset Retirement ObligationsWe 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.

Leases

LeasesEffective 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.

Derivatives

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. 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 to hedge variability in interest rates and effectively lock in the benchmark interest rate at the inception of the swap.

Concentrations of Credit Risk

Concentrations of Credit RiskFinancial 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 significant customers discussed below, since our customers represent a broad and diverse group of energy marketers and end users.

Environmental Costs

Environmental CostsEnvironmental 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.

Unit-Based Awards

Unit-Based AwardsWe recognize compensation cost related to all unit-based awards in our consolidated financial statements in accordance with ASC 718. Unit-based compensation associated with ENLC’s unit-based compensation plan awarded to directors, officers, and employees of the General Partner is recorded by ENLK since ENLC has no substantial or managed operating activities other than its interests in ENLK.

Commitments and Contingencies

Commitments and ContingenciesLiabilities 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.

Debt Issuance Costs

Debt Issuance CostsCosts incurred in connection with the issuance of long-term debt are deferred and amortized 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.

Redeemable Non-Controlling Interest

Redeemable Non-Controlling InterestNon-controlling interests that contain an option for the non-controlling interest holder to require us to purchase 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 interests are not considered to be a component of members’ equity and are 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.

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Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2021

Accounting Policies [Abstract]

Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction

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

transportation contracts, as we generally do not expect volume shortfalls to equal the full amount of the contractual MVCs and firm transportation contracts during these periods.

Contractually Committed Fees	Commitments
2022	$	138.8
2023	126.5
2024	108.9
2025	63.8
2026	57.8
Thereafter	289.6
Total	$	785.4

Schedule of Assets Acquired and Liabilities Assumed

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 payable	10.0
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 equipment	16.3
Intangible assets	50.6
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.

Property, Plant and Equipment

The components of property and equipment, net of accumulated depreciation are as follows (in millions):

	Year Ended December 31,
	2021		2020
Transmission assets	$	1,442.2	$	1,410.5
Gathering systems	4,903.8		4,782.9
Gas processing plants	4,119.1		4,082.1
Other property and equipment	161.0		161.0
Construction in process	94.2		78.6
Property and equipment	10,720.3		10,515.1
Accumulated depreciation	(4,332.0)		(3,863.0)
Property and equipment, net of accumulated depreciation	$	6,388.3	$	6,652.1

Depreciation Expense. Depreciation is calculated using the straight-line method based on the estimated useful life of each asset, as follows:

	Useful Lives
Transmission assets	20 - 25 years
Gathering systems	20 - 25 years
Gas processing plants	20 - 25 years
Other property and equipment	3 - 25 years

Schedule of Gain or Loss on Disposition of Assets

The (gain) loss on disposition of assets are as follows (in millions):

	Year Ended December 31,
	2021		2020		2019
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)

Schedule of Interest Rate Swaps

During 2021 and 2020, we terminated the interest rate swaps in several increments in connection with repayments of the Term Loan, which was one of our floating-rate, LIBOR-based borrowings. The following table presents the interest rate swaps terminations and the associated cash payments during 2021 and 2020 (in millions):

	Interest Rate Swaps Terminations		Cash Payments Associated with Interest Rate Swaps Terminations
December 2021	$	150.0	$	—
September 2021	100.0		0.5
May 2021	100.0		1.3
December 2020	500.0		10.9
Total termination of interest rate swaps	$	850.0	$	12.7

The following table presents the interest rate swaps terminations and the associated cash payments during 2021 and 2020 (in millions):

	Interest Rate Swaps Terminations		Cash Payments Associated with Interest Rate Swaps Terminations
December 2021	$	150.0	$	—
September 2021	100.0		0.5
May 2021	100.0		1.3
December 2020	500.0		10.9
Total termination of interest rate swaps	$	850.0	$	12.7

Schedules of Concentration of Risk, by Risk Factor

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,
	2021		2020		2019
Devon	6.7	%	14.4	%	10.5	%
Dow Hydrocarbons and Resources LLC	14.5	%	13.2	%	10.0	%
Marathon Petroleum Corporation	13.4	%	12.2	%	13.8	%

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Goodwill and Intangible Assets (Tables)

12 Months Ended

Dec. 31, 2021

Goodwill and Intangible Assets Disclosure [Abstract]

Summary of Changes in Carrying Value

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

	Gross Carrying Amount		Accumulated Amortization		Net 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 business	50.6		—		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

____________________________

(1)Intangible assets retired as a result of the disposition of certain non-core assets.

Schedule of Amortization Expense

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

2022	$	127.6
2023	127.6
2024	127.6
2025	110.3
2026	106.4
Thereafter	450.2
Total	$	1,049.7

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Leases (Tables)

12 Months Ended

Dec. 31, 2021

Leases [Abstract]

Assets and Liabilities, Lessee

Lease balances are recorded on the consolidated balance sheets as follows (in millions):

Operating leases:	December 31, 2021			December 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 leases	10.3 years			11.1 years
Weighted-average discount rate—Operating leases	4.9		%	5.1		%

Lease, Cost

The components of total lease expense are as follows (in millions):

	Year Ended December 31,
	2021		2020		2019
Finance lease expense:
Amortization of right-of-use asset	$	—	$	—	$	5.2
Interest on lease liability	—		—		0.1
Operating lease expense:
Long-term operating lease expense	21.7		23.1		28.7
Short-term lease expense	17.5		22.1		32.0
Variable lease expense	15.6		11.8		7.7
Impairments	0.2		6.8		—
Total lease expense	$	55.0	$	63.8	$	68.4

Lessee, Operating Lease, Liability, Maturity

The following table summarizes the maturity of our lease liability as of December 31, 2021 (in millions):

	Total		2022		2023		2024		2025		2026		Thereafter
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

Finance Lease, Liability, Maturity

The following table summarizes the maturity of our lease liability as of December 31, 2021 (in millions):

	Total		2022		2023		2024		2025		2026		Thereafter
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

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Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2021

Debt Disclosure [Abstract]

Summary of Debt

As of December 31, 2021 and 2020, long-term debt consisted of the following (in millions):

	December 31, 2021						December 31, 2020
	Outstanding Principal		Premium (Discount)		Long-Term Debt		Outstanding Principal		Premium (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 2024	521.8		0.7		522.5		521.8		1.1		522.9
ENLK’s 4.15% Senior unsecured notes due 2025	720.8		(0.4)		720.4		720.8		(0.6)		720.2
ENLK’s 4.85% Senior unsecured notes due 2026	491.0		(0.3)		490.7		491.0		(0.4)		490.6
ENLC’s 5.625% Senior unsecured notes due 2028	500.0		—		500.0		500.0		—		500.0
ENLC’s 5.375% Senior unsecured notes due 2029	498.7		—		498.7		498.7		—		498.7
ENLK’s 5.60% Senior unsecured notes due 2044	350.0		(0.2)		349.8		350.0		(0.2)		349.8
ENLK’s 5.05% Senior unsecured notes due 2045	450.0		(5.5)		444.5		450.0		(5.7)		444.3
ENLK’s 5.45% Senior unsecured notes due 2047	500.0		(0.1)		499.9		500.0		(0.1)		499.9
Debt classified as long-term	$	4,397.3	$	(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.See applicable redemption provision terms below:

Issuance	Maturity Date of Notes	Early Redemption Date	Basis Point Premium
2024 Notes	April 1, 2024	Prior to January 1, 2024	25 Basis Points
2025 Notes	June 1, 2025	Prior to March 1, 2025	30 Basis Points
2026 Notes	July 15, 2026	Prior to April 15, 2026	50 Basis Points
2028 Notes	January 15, 2028	Prior to July 15, 2027	50 Basis Points
2029 Notes	June 1, 2029	Prior to March 1, 2029	50 Basis Points
2044 Notes	April 1, 2044	Prior to October 1, 2043	30 Basis Points
2045 Notes	April 1, 2045	Prior to October 1, 2044	30 Basis Points
2047 Notes	June 1, 2047	Prior to December 1, 2046	40 Basis Points

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 debt	0.6
Gain on extinguishment of debt	$	32.0

Schedule of Maturities of Long-term Debt

Maturities for the long-term debt as of December 31, 2021 are as follows (in millions):

2022	$	—
2023	—
2024	886.8
2025	720.8
2026	491.0
Thereafter	2,298.7
Subtotal	4,397.3
Less: net discount	(5.8)
Less: debt issuance cost	(27.8)
Long-term debt, net of unamortized issuance cost	$	4,363.7

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2021

Income Tax Disclosure [Abstract]

Schedule of Components of Income Tax Expense (Benefit)

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

	Year Ended December 31,
	2021		2020		2019
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)

Reconciliation of Total Income Tax Expense to Income before Income Taxes

The following schedule reconciles total income tax expense and the amount calculated by applying the statutory U.S. federal tax rate to income before income taxes (in millions):

	Year Ended December 31,
	2021		2020		2019
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.

Schedule of Deferred Tax Assets and Liabilities

ur deferred income tax assets and liabilities as of December 31, 2021 and 2020 are as follows (in millions):

	December 31, 2021		December 31, 2020
Deferred income tax assets:
Federal net operating loss carryforward	$	573.6	$	488.3
State net operating loss carryforward	59.6		61.0
Total deferred tax assets, gross	633.2		549.3
Valuation allowance	(151.6)		(153.3)
Total deferred tax assets, net of valuation allowance	481.6		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)

____________________________

(1)Includes our investment in ENLK and primarily relates to differences between the book and tax bases of property and equipment.

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Certain Provisions of the Partnership Agreement (Tables)

12 Months Ended

Dec. 31, 2021

Partners' Capital [Abstract]

Summary of Distribution Activity

A summary of the distribution activity relating to the Series B Preferred Units for the years ended December 31, 2021, 2020, and 2019 is provided below:

Declaration period	Distribution paid as additional Series B Preferred Units	Cash distribution (in millions)		Date paid/payable
2021
First Quarter of 2021	150,871	$	17.0	May 14, 2021
Second Quarter of 2021	151,248	$	17.0	August 13, 2021
Third Quarter of 2021	151,626	$	17.1	November 12, 2021
Fourth Quarter of 2021	—	$	19.2	February 11, 2022 (1)
2020
First Quarter of 2020	149,371	$	16.8	May 13, 2020
Second Quarter of 2020	149,745	$	16.8	August 13, 2020
Third Quarter of 2020	150,119	$	16.9	November 13, 2020
Fourth Quarter of 2020	150,494	$	16.9	February 12, 2021
2019
First Quarter of 2019	147,887	$	16.7	May 14, 2019
Second Quarter of 2019	148,257	$	17.1	August 13, 2019
Third Quarter of 2019	148,627	$	17.1	November 13, 2019
Fourth Quarter of 2019	148,999	$	16.8	February 13, 2020

____________________________

(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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Members' Equity (Tables)

12 Months Ended

Dec. 31, 2021

Earnings Per Share [Abstract]

Computation of Basic and Diluted Earnings per Limited Partner Unit

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,
	2021		2020		2019
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 units	0.5		(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)

____________________________

(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,
	2021	2020	2019
Basic weighted average units outstanding:
Weighted average common units outstanding	488.8	489.3	463.9
Diluted weighted average units outstanding:
Weighted average basic common units outstanding	488.8	489.3	463.9
Dilutive effect of non-vested restricted units (1)	5.5	—	—
Total weighted average diluted common units outstanding	494.3	489.3	463.9

____________________________

(1)For the years ended December 31, 2020 and 2019, all common unit equivalents were antidilutive because a net loss existed for those periods.

Summary of Distribution Activity

A summary of our distribution activity related to the ENLC common units for the years ended December 31, 2021, 2020, and 2019, respectively, is provided below:

Declaration period	Distribution/unit		Date 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

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Investment in Unconsolidated Affiliates (Tables)

12 Months Ended

Dec. 31, 2021

Equity Method Investments and Joint Ventures [Abstract]

Activity Related to Investments in Unconsolidated Affiliates

The following table shows the activity related to our investment in unconsolidated affiliates for the periods indicated (in millions):

	Year Ended December 31,
	2021		2020		2019
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)

___________________________

(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.

The following table shows the balances related to our investment in unconsolidated affiliates as of December 31, 2021 and 2020 (in millions):

	December 31, 2021		December 31, 2020
GCF	$	28.0	$	40.6
Cedar Cove JV (1)	(1.8)		1.0
Total investment in unconsolidated affiliates	$	26.2	$	41.6

___________________________

(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.

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Employee Incentive Plans (Tables)

12 Months Ended

Dec. 31, 2021

Share-based Payment Arrangement [Abstract]

Schedule of Amounts Recognized in Consolidated Financial Statements

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

	Year Ended December 31,
	2021		2020		2019
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 expense	6.6		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

____________________________

(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.

Summary of Restricted Incentive Unit Activity

A summary of the restricted incentive unit activity for the year ended December 31, 2021 is provided below:

	Year Ended December 31, 2021
ENLC Restricted Incentive Units:	Number of Units		Weighted Average Grant-Date Fair Value
Non-vested, beginning of period	5,350,086		$	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 period	7,507,471		$	5.46
Aggregate intrinsic value, end of period (in millions)	$	51.7

____________________________

(1)Restricted incentive units typically vest at the end of three years.

(2)Vested units included 382,343 units withheld for payroll taxes paid on behalf of employees.

Summary of Restricted Units' Aggregate Intrinsic Value

A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for the years ended December 31, 2021, 2020, and 2019 is provided below (in millions):

	Year Ended December 31,
ENLC Restricted Incentive Units:	2021		2020		2019
Aggregate intrinsic value of units vested	$	5.6	$	12.1	$	17.3
Fair value of units vested	$	16.3	$	31.5	$	22.8

Summary of Grant-Date Fair Values

The following table sets 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 Designated Peer Companies:

Performance Level	Achieved ENLC TSR Position Relative to Designated Peer Companies	Vesting percentage of the Tranche TSR Units
Below Threshold	Less than 25%	0%
Threshold	Equal to 25%	50%
Target	Equal to 50%	100%
Maximum	Greater than or Equal to 75%	200%

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 Level	ENLC’s Achieved FCFAD	Vesting percentage of the Tranche CF Units
Below Threshold	Less than $205 million	0%
Threshold	Equal to $205 million	50%
Target	Equal to $256 million	100%
Maximum	Greater than or Equal to $300 million	200%

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 Level	ENLC’s Achieved  Distributable Cash Flow per Unit	Vesting percentage of the Tranche CF Units
Below Threshold	Less than $1.345	0%
Threshold	Equal to $1.345	50%
Target	Equal to $1.494	100%
Maximum	Greater than or Equal to $1.643	200%

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 Level	ENLC’s Achieved  Distributable Cash Flow per Unit	Vesting percentage of the Tranche CF Units
Below Threshold	Less than $1.43	0%
Threshold	Equal to $1.43	50%
Target	Equal to $1.55	100%
Maximum	Greater than or Equal to $1.72	200%

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 Designated Peer 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 value assumptions by performance unit grant date:

ENLC Performance Units:	January 2021			July 2020			March 2020			January 2020			October 2019			June 2019			March 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 rate	0.17		%	0.17		%	0.42		%	1.62		%	1.44		%	1.72		%	2.42		%
Volatility factor	71.00		%	67.00		%	51.00		%	37.00		%	35.00		%	33.50		%	33.86		%

Summary of Performance Units

The following table presents a summary of the performance units:

	Year Ended December 31, 2021
ENLC Performance Units:	Number of Units		Weighted Average Grant-Date Fair Value
Non-vested, beginning of period	2,351,241		$	8.82
Granted	1,388,139		4.70
Vested (1)	(164,553)		26.73
Non-vested, end of period	3,574,827		$	6.40
Aggregate intrinsic value, end of period (in millions)	$	24.6

____________________________

(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:	2021		2020		2019
Aggregate intrinsic value of units vested	$	0.6	$	0.9	$	3.4
Fair value of units vested	$	4.4	$	5.5	$	7.9

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Derivatives (Tables)

12 Months Ended

Dec. 31, 2021

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Interest Rate Swaps

During 2021 and 2020, we terminated the interest rate swaps in several increments in connection with repayments of the Term Loan, which was one of our floating-rate, LIBOR-based borrowings. The following table presents the interest rate swaps terminations and the associated cash payments during 2021 and 2020 (in millions):

	Interest Rate Swaps Terminations		Cash Payments Associated with Interest Rate Swaps Terminations
December 2021	$	150.0	$	—
September 2021	100.0		0.5
May 2021	100.0		1.3
December 2020	500.0		10.9
Total termination of interest rate swaps	$	850.0	$	12.7

The following table presents the interest rate swaps terminations and the associated cash payments during 2021 and 2020 (in millions):

	Interest Rate Swaps Terminations		Cash Payments Associated with Interest Rate Swaps Terminations
December 2021	$	150.0	$	—
September 2021	100.0		0.5
May 2021	100.0		1.3
December 2020	500.0		10.9
Total termination of interest rate swaps	$	850.0	$	12.7

Components of Gain (Loss) on Derivative Activity

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 follows (in millions):

	Year Ended December 31,
	2021		2020		2019
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, recognized from accumulated other comprehensive loss from the monthly settlement of our interest rate swaps and amortization of the termination payments, included in our consolidated statements of operations were as follows (in millions):

	Year Ended December 31,
	2021		2020		2019
Interest expense	$	18.3	$	14.5	$	0.4

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,
	2021		2020		2019
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

Fair Value of Derivative Assets and Liabilities Related to Commodity Swaps

The fair value of our interest rate swaps included in our consolidated balance sheets were as follows (in millions):

	December 31, 2021		December 31, 2020
Fair value of derivative liabilities—current	$	—	$	(7.6)

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

	December 31, 2021		December 31, 2020
Fair value of derivative assets—current	$	22.4	$	25.0
Fair value of derivative assets—long-term	0.2		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)

Notional Amount and Fair Value of Derivative Instruments

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, 2021 (in millions). The remaining term of the contracts extend no later than January 2023.

		December 31, 2021
Commodity	Instruments	Unit	Volume	Net Fair Value
NGL (short contracts)	Swaps	Gals	(63.0)	$	(10.6)
NGL (long contracts)	Swaps	Gals	—	—
Natural gas (short contracts)	Swaps	MMbtu	(7.5)	2.7
Natural gas (long contracts)	Swaps	MMbtu	13.2	(7.8)
Crude and condensate (short contracts)	Swaps	MMbbls	(3.9)	(4.4)
Crude and condensate (long contracts)	Swaps	MMbbls	3.9	5.6
Total fair value of commodity swaps				$	(14.5)

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Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2021

Fair Value Disclosures [Abstract]

Schedule of Net Assets (Liabilities) Measured on a Recurring Basis

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

	Level 2
	December 31, 2021		December 31, 2020
Interest rate swaps (1)	$	—	$	(7.6)
Commodity swaps (2)	$	(14.5)	$	(2.1)

____________________________

(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.

Schedule of the Estimated Fair Value of Financial Instruments

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, 2021				December 31, 2020
	Carrying Value		Fair Value		Carrying Value		Fair 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	$	—	$	—

____________________________

(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.”

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Segment Information (Tables)

12 Months Ended

Dec. 31, 2021

Segment Reporting [Abstract]

Summary of Financial Information

Summarized financial information for our reportable segments is shown in the following tables (in millions):

	Permian		Louisiana		Oklahoma		North Texas		Corporate		Totals
Year Ended December 31, 2021
Natural gas sales	$	609.4	$	693.5	$	213.4	$	150.0	$	—	$	1,666.3
NGL sales	0.9		3,353.1		2.0		1.1		—		3,357.1
Crude oil and condensate sales	677.4		212.0		81.2		—		—		970.6
Product sales	1,287.7		4,258.6		296.6		151.1		—		5,994.0
NGL sales—related parties	1,008.4		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 parties	1,008.4		129.7		630.9		454.1		(2,223.1)		—
Gathering and transportation	46.8		64.7		186.9		157.0		—		455.4
Processing	29.1		2.4		98.7		108.3		—		238.5
NGL services	—		82.6		—		0.3		—		82.9
Crude services	18.4		39.3		12.8		0.7		—		71.2
Other services	0.2		1.7		0.6		0.5		—		3.0
Midstream services	94.5		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 customers	2,390.6		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 margin	311.2		448.6		407.6		328.6		—		1,496.0
Operating expenses	(81.5)		(123.7)		(80.0)		(77.7)		—		(362.9)
Segment profit	229.7		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

____________________________

(1)Includes related party cost of sales of $17.9 million for the year ended December 31, 2021.

	Permian		Louisiana		Oklahoma		North Texas		Corporate		Totals
Year Ended December 31, 2020
Natural gas sales	$	150.1	$	330.5	$	153.1	$	70.3	$	—	$	704.0
NGL sales	0.2		1,545.4		2.8		—		—		1,548.4
Crude oil and condensate sales	558.1		126.7		40.3		—		—		725.1
Product sales	708.4		2,002.6		196.2		70.3		—		2,977.5
NGL sales—related parties	312.6		31.4		296.4		115.2		(755.6)		—
Crude oil and condensate sales—related parties	0.6		—		(0.1)		3.6		(4.1)		—
Product sales—related parties	313.2		31.4		296.3		118.8		(759.7)		—
Gathering and transportation	42.8		46.5		228.7		179.2		—		497.2
Processing	24.1		2.0		123.6		132.6		—		282.3
NGL services	—		75.8		—		0.2		—		76.0
Crude services	16.8		45.2		16.5		0.2		—		78.7
Other services	1.2		1.6		0.4		0.9		—		4.1
Midstream services	84.9		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 customers	1,106.5		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 derivatives	1.1		(6.5)		(4.5)		(0.6)		—		(10.5)
Adjusted gross margin	264.3		405.6		487.6		347.8		—		1,505.3
Operating expenses	(94.2)		(120.0)		(82.2)		(77.4)		—		(373.8)
Segment profit	170.1		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.

	Permian		Louisiana		Oklahoma		North Texas		Corporate		Totals
Year Ended December 31, 2019
Natural gas sales	$	94.3	$	416.6	$	236.4	$	129.3	$	—	$	876.6
NGL sales	0.9		1,725.6		19.6		30.9		—		1,777.0
Crude oil and condensate sales	1,975.0		291.9		109.6		—		—		2,376.5
Product sales	2,070.2		2,434.1		365.6		160.2		—		5,030.1
Natural gas sales—related parties	0.4		—		—		—		(0.4)		—
NGL sales—related parties	347.7		25.7		421.1		94.8		(889.3)		—
Crude oil and condensate sales—related parties	13.5		1.7		—		5.5		(20.7)		—
Product sales—related parties	361.6		27.4		421.1		100.3		(910.4)		—
Gathering and transportation	48.8		58.3		234.5		196.4		—		538.0
Processing	30.5		3.2		138.2		143.0		—		314.9
NGL services	—		50.6		—		0.1		—		50.7
Crude services	19.2		51.9		19.8		—		—		90.9
Other services	12.0		0.7		0.1		1.1		—		13.9
Midstream services	110.5		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 customers	2,542.3		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 derivatives	9.4		5.1		—		—		—		14.5
Change in fair value of derivatives	1.5		(1.8)		—		0.2		—		(0.1)
Adjusted gross margin	269.3		444.5		554.1		392.5		—		1,660.4
Operating expenses	(112.9)		(147.3)		(104.0)		(102.9)		—		(467.1)
Segment profit	156.4		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

____________________________

(1)Includes related party cost of sales of $21.7 million for the year ended December 31, 2019.

Schedule of Segment Assets

The table below represents information about segment assets as of December 31, 2021 and 2020 (in millions):

Segment Identifiable Assets:	December 31, 2021		December 31, 2020
Permian	$	2,358.6	$	2,236.3
Louisiana	2,428.6		2,312.4
Oklahoma	2,619.5		2,847.6
North Texas	896.8		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.

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Supplemental Cash Flow Information (Tables)

12 Months Ended

Dec. 31, 2021

Supplemental Cash Flow Elements [Abstract]

Summary of Non-Cash Financing Activities

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:	2021		2020		2019
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)	$	—

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Other Information (Tables)

12 Months Ended

Dec. 31, 2021

Other Liabilities Disclosure [Abstract]

Schedule of Other Current Assets

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

Other current assets:	December 31, 2021		December 31, 2020
Natural gas and NGLs inventory	$	49.4	$	44.9
Prepaid expenses and other	34.2		13.8
Other current assets	$	83.6	$	58.7

Schedule of Other Current Liabilities

Other current liabilities:	December 31, 2021		December 31, 2020
Accrued interest	$	47.2	$	35.7
Accrued wages and benefits, including taxes	33.1		22.5
Accrued ad valorem taxes	28.3		26.5
Capital expenditure accruals	23.2		10.6
Short-term lease liability	18.1		16.3
Installment payable (1)	10.0		—
Inactive easement commitment (2)	9.8		—
Operating expense accruals	9.6		8.4
Other	23.6		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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Organization and Nature of Business (Details) bbl in Thousands, $ in Millions			12 Months Ended
	Jan. 25, 2019 USD ($) shares	Jul. 18, 2018	Dec. 31, 2021 Bcf / d processingPlant fractionator mi bbl
Related Party Transaction [Line Items]
Common units conversion ratio	1.15
Increase (decrease) in deferred income taxes | $	$ 399.0
Number of miles of pipeline | mi			12,100
Number of natural gas processing plants | processingPlant			22
Amount of processing capacity | Bcf / d			5.5
Number of fractionators | fractionator			7
Capacity of fractionators per day, barrels | bbl			320
Merger
Related Party Transaction [Line Items]
Business acquisition, equity interest issued or issuable, number of shares (in shares) | shares	304,822,035
EnLink Midstream Partners, LP
Related Party Transaction [Line Items]
Common units conversion ratio	1.15
EnLink Midstream Partners GP, LLC | GIP Stetson I
Related Party Transaction [Line Items]
Membership interest in the General Partner as a percent		100.00%
EnLink Midstream Partners, LP | GIP Stetson I
Related Party Transaction [Line Items]
Membership interest in the General Partner as a percent		23.10%
ENLC | GIP Stetson II
Related Party Transaction [Line Items]
Membership interest in the General Partner as a percent		63.80%

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Significant Accounting Policies - Narrative (Details) - USD ($)		12 Months Ended
	Apr. 30, 2021	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	May 31, 2019	Apr. 30, 2019
Property, Plant and Equipment [Line Items]
Financing receivable, gross					$ 58,000,000
Loss on secured term loan receivable		$ 0	$ 0	$ 52,900,000
Net book value of assets disposed		3,300,000	36,400,000	12,400,000
Proceeds from sales		4,800,000	27,600,000	14,300,000
(Gain) loss on disposition of assets		1,500,000	(8,800,000)	1,900,000
Tangible asset impairment charges				7,900,000
Derivative, notional amount						$ 850,000,000
Derivative, fixed interest rate						2.28%
Interest Rate Swaps Terminations		850,000,000.0
Allowance for doubtful accounts receivable		300,000	500,000
Environmental remediation expense		0	0	0
Debt issuance costs, noncurrent, net		27,800,000	32,600,000
Installment payable		10,000,000.0	0
Amarillo Rattler, LLC
Property, Plant and Equipment [Line Items]
Cash	$ 50,000,000
Installment payable	10,000,000	10,000,000
Business combination, maximum earnout	$ 15,000,000
Certain Cancelled Projects
Property, Plant and Equipment [Line Items]
Tangible asset impairment charges			3,400,000
Redeemable Non-controlling interest (Temporary Equity)
Property, Plant and Equipment [Line Items]
Partners' capital account, redemptions			(4,000,000)
Louisiana
Property, Plant and Equipment [Line Items]
Loss on secured term loan receivable				0
Tangible asset impairment charges		600,000	168,000,000
Cedar Cove JV
Property, Plant and Equipment [Line Items]
Tangible asset impairment charges		$ 31,400,000		31,400,000
Minimum
Property, Plant and Equipment [Line Items]
Intangible asset, useful life		10 years
Maximum
Property, Plant and Equipment [Line Items]
Intangible asset, useful life		20 years
EnLink Midstream Partners, LP
Property, Plant and Equipment [Line Items]
Gas balancing payable		$ 16,300,000	6,100,000
Gas balancing receivable		$ 14,500,000	$ 7,500,000
Delaware Basin JV | NPG
Property, Plant and Equipment [Line Items]
Noncontrolling interest, ownership percentage by parent		49.90%
Ascension JV | Marathon Petroleum Corporation
Property, Plant and Equipment [Line Items]
Noncontrolling interest, ownership percentage by parent		50.00%
White Star
Property, Plant and Equipment [Line Items]
Loss on secured term loan receivable				$ 52,900,000

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Significant Accounting Policies - Summary of Remaining Performance Obligations (Details) $ in Millions	Dec. 31, 2021 USD ($)
Accounting Policies [Abstract]
Revenue, remaining performance obligation	$ 785.4
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Accounting Policies [Abstract]
Revenue, remaining performance obligation	$ 138.8
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Accounting Policies [Abstract]
Revenue, remaining performance obligation	$ 126.5
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Accounting Policies [Abstract]
Revenue, remaining performance obligation	$ 108.9
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Accounting Policies [Abstract]
Revenue, remaining performance obligation	$ 63.8
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01
Accounting Policies [Abstract]
Revenue, remaining performance obligation	$ 57.8
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01
Accounting Policies [Abstract]
Revenue, remaining performance obligation	$ 289.6
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation, expected timing of satisfaction, period

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Significant Accounting Policies - Fair Value of Identified Assets Received and Liabilities Assumed (Details) - USD ($) $ in Millions	Apr. 30, 2021	Dec. 31, 2021	Dec. 31, 2020
Consideration
Installment payable		$ 10.0	$ 0.0
Amarillo Rattler, LLC
Consideration
Cash (including working capital payment)	$ 50.6
Installment payable	10.0	$ 10.0
Contingent consideration fair value	6.9
Total consideration:	67.5
Purchase price allocation
Cash acquired	1.3
Current assets (including $1.3 million in cash)	1.4
Property and equipment	16.3
Intangible assets	50.6
Other assets, net	0.6
Current liabilities	(0.8)
Other long-term liabilities	(0.6)
Net assets acquired	$ 67.5

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Significant Accounting Policies - Components of Property and Equipment (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Property, Plant and Equipment [Line Items]
Property and equipment	$ 10,720.3	$ 10,515.1
Accumulated depreciation	(4,332.0)	(3,863.0)
Property and equipment, net of accumulated depreciation	6,388.3	6,652.1
Transmission assets
Property, Plant and Equipment [Line Items]
Property and equipment	$ 1,442.2	1,410.5
Transmission assets | Minimum
Property, Plant and Equipment [Line Items]
Useful life	20 years
Transmission assets | Maximum
Property, Plant and Equipment [Line Items]
Useful life	25 years
Gathering systems
Property, Plant and Equipment [Line Items]
Property and equipment	$ 4,903.8	4,782.9
Gathering systems | Minimum
Property, Plant and Equipment [Line Items]
Useful life	20 years
Gathering systems | Maximum
Property, Plant and Equipment [Line Items]
Useful life	25 years
Gas processing plants
Property, Plant and Equipment [Line Items]
Property and equipment	$ 4,119.1	4,082.1
Gas processing plants | Minimum
Property, Plant and Equipment [Line Items]
Useful life	20 years
Gas processing plants | Maximum
Property, Plant and Equipment [Line Items]
Useful life	25 years
Other property and equipment
Property, Plant and Equipment [Line Items]
Property and equipment	$ 161.0	161.0
Other property and equipment | Minimum
Property, Plant and Equipment [Line Items]
Useful life	3 years
Other property and equipment | Maximum
Property, Plant and Equipment [Line Items]
Useful life	25 years
Construction in process
Property, Plant and Equipment [Line Items]
Property and equipment	$ 94.2	$ 78.6

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Significant Accounting Policies - (Gain) Loss on Disposition of Assets (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Accounting Policies [Abstract]
Net book value of assets disposed	$ 3.3	$ 36.4	$ 12.4
Proceeds from sales	(4.8)	(27.6)	(14.3)
(Gain) loss on disposition of assets	$ (1.5)	$ 8.8	$ (1.9)

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Significant Accounting Policies - Interest Rate Swaps (Details) $ in Millions	Dec. 31, 2021 USD ($)
Derivatives
Interest Rate Swaps Terminations	$ 850.0
Cash Payments Associated with Interest Rate Swaps Terminations	12.7
December 2021
Derivatives
Interest Rate Swaps Terminations	150.0
Cash Payments Associated with Interest Rate Swaps Terminations	0.0
September 2021
Derivatives
Interest Rate Swaps Terminations	100.0
Cash Payments Associated with Interest Rate Swaps Terminations	0.5
May 2021
Derivatives
Interest Rate Swaps Terminations	100.0
Cash Payments Associated with Interest Rate Swaps Terminations	1.3
December 2020
Derivatives
Interest Rate Swaps Terminations	500.0
Cash Payments Associated with Interest Rate Swaps Terminations	$ 10.9

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Significant Accounting Policies - Schedule of Revenue Concentration Risk (Details) - Customer Concentration Risk - Sales Revenue, Net	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Devon
Concentration Risk [Line Items]
Concentration risk	6.70%	14.40%	10.50%
Dow Hydrocarbons and Resources LLC
Concentration Risk [Line Items]
Concentration risk	14.50%	13.20%	10.00%
Marathon Petroleum Corporation
Concentration Risk [Line Items]
Concentration risk	13.40%	12.20%	13.80%

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Goodwill and Intangible Assets - Narrative (Details) - USD ($)	3 Months Ended	12 Months Ended
	Mar. 31, 2019	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Finite-Lived Intangible Assets [Line Items]
Goodwill			$ 0
Minimum
Finite-Lived Intangible Assets [Line Items]
Intangible asset, useful life		10 years
Maximum
Finite-Lived Intangible Assets [Line Items]
Intangible asset, useful life		20 years
Weighted Average
Finite-Lived Intangible Assets [Line Items]
Intangible asset, weighted average remaining amortization period		14 years 10 months 24 days
Corporate | Louisiana | EnLink Midstream Partners, LP
Finite-Lived Intangible Assets [Line Items]
Goodwill impairment loss recognized	$ 186,500,000
Operating Segments | Permian | EnLink Midstream Partners, LP
Finite-Lived Intangible Assets [Line Items]
Goodwill impairment loss recognized			$ 184,600,000
Operating Segments | North Texas | EnLink Midstream Partners, LP
Finite-Lived Intangible Assets [Line Items]
Goodwill impairment loss recognized				$ 125,700,000
Operating Segments | Oklahoma | EnLink Midstream Partners, LP
Finite-Lived Intangible Assets [Line Items]
Goodwill impairment loss recognized				$ 813,400,000

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Goodwill and Intangible Assets - Changes in Carrying Value of Intangible Assets (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Finite-lived Intangible Assets [Roll Forward]
Accumulated amortization, beginning of period	$ (668.8)
Accumulated amortization, end of period	(795.1)	$ (668.8)
EnLink Midstream Partners, LP
Finite-lived Intangible Assets [Roll Forward]
Customer relationships, end of period, net	1,049.7
Customer Relationships | EnLink Midstream Partners, LP
Finite-lived Intangible Assets [Roll Forward]
Customer relationships, beginning of period, gross	1,794.2	1,795.8	$ 1,795.8
Accumulated amortization, beginning of period	(668.8)	(545.9)	(422.2)
Customer relationships, beginning of period, net	1,125.4	1,249.9	1,373.6
Customer relationships obtained from acquisition of business		50.6
Amortization expense	(126.3)	(123.5)	(123.7)
Retirements, gross carrying amount		(1.6)
Retirements, accumulated amortization		0.6
Retirements, net carrying amount		(1.0)
Customer relationships, end of period, gross	1,844.8	1,794.2	1,795.8
Accumulated amortization, end of period	(795.1)	(668.8)	(545.9)
Customer relationships, end of period, net	$ 1,049.7	$ 1,125.4	$ 1,249.9

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Goodwill and Intangible Assets - Amortization Expense (Details) - EnLink Midstream Partners, LP $ in Millions	Dec. 31, 2021 USD ($)
Finite-Lived Intangible Assets [Line Items]
2022	$ 127.6
2023	127.6
2024	127.6
2025	110.3
2026	106.4
Thereafter	450.2
Total	$ 1,049.7

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Related Party Transactions (Details) - USD ($)		12 Months Ended
		Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Related Party Transaction [Line Items]
Cost of sales	[1]	$ 5,189,900,000	$ 2,388,500,000	$ 4,392,500,000
Accounts payable, related parties		1,600,000	1,000,000
Cedar Cove Joint Venture
Related Party Transaction [Line Items]
Accounts payable, related parties		1,600,000	1,000,000
Cedar Cove Joint Venture
Related Party Transaction [Line Items]
Cost of sales		17,900,000	8,700,000	21,700,000
GIP
Related Party Transaction [Line Items]
Selling, general and administrative expenses, related party		$ 500,000	$ 200,000	$ 0

[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.

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Leases - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Lessee, Lease, Description [Line Items]
Lease liability	$ 85.2
Right-of-use assets	60.1	$ 59.8
Impairments	0.2	6.8	$ 0.0
Office Lease
Lessee, Lease, Description [Line Items]
Lease liability	51.8	57.6
Right-of-use assets	27.9	32.4
Compression and Other Field Equipment
Lessee, Lease, Description [Line Items]
Lease liability	17.7	14.6
Right-of-use assets	19.5	14.6
Land
Lessee, Lease, Description [Line Items]
Lease liability	15.6	15.1
Right-of-use assets	12.6	12.5
Office Equipment
Lessee, Lease, Description [Line Items]
Lease liability	0.1	0.3
Right-of-use assets	$ 0.1	$ 0.3
Minimum | Compression and Other Field Equipment
Lessee, Lease, Description [Line Items]
Term of contract	1 year
Maximum | Compression and Other Field Equipment
Lessee, Lease, Description [Line Items]
Term of contract	3 years

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Leases - Leases Balances on Consolidated Balance Sheet (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Operating leases:
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration]	Other Assets, Noncurrent	Other Assets, Noncurrent
Other assets, net	$ 60.1	$ 59.8
Operating Lease, Liability, Current, Statement of Financial Position [Extensible List]	Other current liabilities	Other current liabilities
Other current liabilities	$ 18.1	$ 16.3
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]	Other Liabilities, Noncurrent	Other Liabilities, Noncurrent
Other long-term liabilities	$ 67.1	$ 71.3
Other lease information
Weighted-average remaining lease term—Operating leases	10 years 3 months 18 days	11 years 1 month 6 days
Weighted-average discount rate—Operating leases	4.90%	5.10%

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Leases - Components of Total Lease Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Finance lease expense:
Amortization of right-of-use asset	$ 0.0	$ 0.0	$ 5.2
Interest on lease liability	0.0	0.0	0.1
Operating lease expense:
Long-term operating lease expense	21.7	23.1	28.7
Short-term lease expense	17.5	22.1	32.0
Variable lease expense	15.6	11.8	7.7
Impairments	0.2	6.8	0.0
Total lease expense	$ 55.0	$ 63.8	$ 68.4

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Leases - Maturity (Details) $ in Millions	Dec. 31, 2021 USD ($)
Undiscounted operating lease liability
Total	$ 115.6
2022	21.1
2023	15.3
2024	10.1
2025	9.8
2026	8.9
Thereafter	50.4
Reduction due to present value
Total	(30.4)
2022	(3.7)
2023	(3.2)
2024	(2.8)
2025	(2.4)
2026	(2.0)
Thereafter	(16.3)
Operating Lease, Liability [Abstract]
Total	85.2
2022	17.4
2023	12.1
2024	7.3
2025	7.4
2026	6.9
Thereafter	$ 34.1

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Long-Term Debt - Summary of Long-Term Debt (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Debt Instrument
Subtotal	$ 4,397.3	$ 4,632.3
Premium (discount)	(5.8)	(5.9)
Long-term debt	4,391.5	4,626.4
Less: debt issuance cost	(27.8)	(32.6)
Less: Current maturities of long-term debt	0.0	(349.8)
Long-term debt, net of unamortized issuance cost	4,363.7	4,244.0
Debt issuance cost accumulated amortization	18.4	14.1
Term Loan due 2021
Debt Instrument
Subtotal	0.0	350.0
Premium (discount)	0.0	0.0
Long-term debt	0.0	$ 350.0
Effective interest rate		1.70%
Credit Facility Due 2024
Debt Instrument
Subtotal	15.0	$ 0.0
Premium (discount)	0.0	0.0
Long-term debt	15.0	$ 0.0
Effective interest rate		3.90%
AR Facility due 2024
Debt Instrument
Subtotal	350.0	$ 250.0
Premium (discount)	0.0	0.0
Long-term debt	$ 350.0	$ 250.0
Effective interest rate	1.20%	2.00%
4.4% Senior Notes due 2024
Debt Instrument
Stated interest rate	4.40%
Subtotal	$ 521.8	$ 521.8
Premium (discount)	0.7	1.1
Long-term debt	$ 522.5	522.9
4.15% Senior Notes due 2025
Debt Instrument
Stated interest rate	4.15%
Subtotal	$ 720.8	720.8
Premium (discount)	(0.4)	(0.6)
Long-term debt	$ 720.4	720.2
4.85 Senior Unsecured Notes Due 2026
Debt Instrument
Stated interest rate	4.85%
Subtotal	$ 491.0	491.0
Premium (discount)	(0.3)	(0.4)
Long-term debt	$ 490.7	490.6
5.625% Senior unsecured notes due 2028
Debt Instrument
Stated interest rate	5.625%
Subtotal	$ 500.0	500.0
Premium (discount)	0.0	0.0
Long-term debt	$ 500.0	500.0
5.375% Senior unsecured notes due 2029
Debt Instrument
Stated interest rate	5.375%
Subtotal	$ 498.7	498.7
Premium (discount)	0.0	0.0
Long-term debt	$ 498.7	498.7
5.6% Senior Notes due 2044
Debt Instrument
Stated interest rate	5.60%
Subtotal	$ 350.0	350.0
Premium (discount)	(0.2)	(0.2)
Long-term debt	$ 349.8	349.8
5.05 Senior Notes due 2045
Debt Instrument
Stated interest rate	5.05%
Subtotal	$ 450.0	450.0
Premium (discount)	(5.5)	(5.7)
Long-term debt	$ 444.5	444.3
Senior Unsecured Notes, 5.45%, Due 2047
Debt Instrument
Stated interest rate	5.45%
Subtotal	$ 500.0	500.0
Premium (discount)	(0.1)	(0.1)
Long-term debt	$ 499.9	$ 499.9

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Long-Term Debt - Schedule of Maturities (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Debt Disclosure [Abstract]
2022	$ 0.0
2023	0.0
2024	886.8
2025	720.8
2026	491.0
Thereafter	2,298.7
Subtotal	4,397.3	$ 4,632.3
Less: net discount	(5.8)	(5.9)
Less: debt issuance cost	(27.8)	(32.6)
Long-term debt	$ 4,363.7	$ 4,244.0

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Long-Term Debt - Narrative (Details)								1 Months Ended			12 Months Ended
	Dec. 10, 2021 USD ($)	Sep. 24, 2021 USD ($)	Apr. 30, 2021 USD ($)	Feb. 26, 2021 USD ($)	Dec. 14, 2020 USD ($)	Oct. 21, 2020 USD ($)	Dec. 11, 2018 USD ($)	Sep. 30, 2021 USD ($)	May 31, 2021 USD ($)	Dec. 31, 2020 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)
Debt Instrument
Repayments of debt											$ 36,000,000.0
Increase in accounts receivable due to consolidation											773,600,000
Proceeds from issuance of long-term debt					$ 494,700,000						$ 1,234,500,000	$ 1,650,000,000	$ 3,310,000,000
Repurchase price as a percent of principal											101.00%
Amarillo Rattler, LLC
Debt Instrument
Payments to acquire gathering and processing system			$ 50,000,000
Line of Credit | Asset-backed Securities
Debt Instrument
Maximum borrowing capacity		$ 350,000,000		$ 300,000,000		$ 250,000,000					$ 350,000,000
Drawn fee percentage		1.10%		1.25%		1.625%
Line of credit facility, increase in period		$ 50,000,000		$ 50,000,000
LIBOR | Line of Credit | Minimum | Asset-backed Securities
Debt Instrument
Variable rate				0.00%		0.375%					1.10%
Revolviing Credit Facility Unsecured
Debt Instrument
Additional amount available (not to exceed)							$ 1,750,000,000
ENLK Credit Facility
Debt Instrument
Fair value of amount outstanding											$ 15,000,000
ENLK Credit Facility | Letter of Credit | ENLC
Debt Instrument
Fair value of amount outstanding											$ 41,300,000
ENLK Credit Facility | LIBOR | Maximum | EnLink Midstream Partners, LP
Debt Instrument
Variable rate											2.00%
ENLK Credit Facility | LIBOR | Minimum | EnLink Midstream Partners, LP
Debt Instrument
Variable rate											1.125%
5.625% Senior unsecured notes due 2028
Debt Instrument
Stated interest rate											5.625%
Unsecured Debt
Debt Instrument
Percentage price of debt issued					100.00%
Unsecured Debt | Revolviing Credit Facility Unsecured
Debt Instrument
Consolidated EBITDA to consolidated interest charges, ratio							2.5
Consolidated indebtedness to consolidated EBITDA, ratio							5.0
Unsecured Debt | Revolviing Credit Facility Unsecured | Federal Funds
Debt Instrument
Variable rate							0.50%
Unsecured Debt | Revolviing Credit Facility Unsecured | Eurodollar
Debt Instrument
Variable rate							1.00%
Unsecured Debt | Revolviing Credit Facility Unsecured | Eurodollar | Minimum
Debt Instrument
Variable rate							0.125%
Unsecured Debt | ENLK Credit Facility
Debt Instrument
Consolidated indebtedness to consolidated EBITDA, during an acquisition period, ratio			5.5
Unsecured Debt | ENLK Credit Facility | Maximum
Debt Instrument
Consolidated indebtedness to consolidated EBITDA, during an acquisition period, ratio											5.5
Unsecured Debt | ENLK Credit Facility | Minimum
Debt Instrument
Conditional acquisition purchase price (or more)											$ 50,000,000
Unsecured Debt | ENLK Credit Facility | Eurodollar
Debt Instrument
Variable rate											1.00%
Unsecured Debt | Term Loan due 2021
Debt Instrument
Repayments of debt	$ 150,000,000							$ 100,000,000	$ 100,000,000	$ 500,000,000
Unsecured Debt | 5.625% Senior unsecured notes due 2028
Debt Instrument
Stated interest rate					5.625%
Percentage price of debt issued					100.00%
Debt instrument, face amount					$ 500,000,000
Letter of Credit | Revolviing Credit Facility Unsecured
Debt Instrument
Maximum borrowing capacity							$ 500,000,000
Percentage of letter of credits guaranteed											105.00%

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Long-Term Debt - Summary of Redemption Provision Terms (Details) - EnLink Midstream Partners, LP - Treasury Rate	12 Months Ended
	Dec. 31, 2021
4.4% Senior Notes due 2024
Debt Instrument
Redemption premium, percentage	25.00%
4.15% Senior Notes due 2025
Debt Instrument
Redemption premium, percentage	30.00%
4.85 Senior Unsecured Notes Due 2026
Debt Instrument
Redemption premium, percentage	50.00%
5.625% Senior unsecured notes due 2028
Debt Instrument
Redemption premium, percentage	50.00%
5.375% Senior unsecured notes due 2029
Debt Instrument
Redemption premium, percentage	50.00%
5.6% Senior Notes due 2044
Debt Instrument
Redemption premium, percentage	30.00%
5.05 Senior Notes due 2045
Debt Instrument
Redemption premium, percentage	30.00%
Senior Unsecured Notes, 5.45%, Due 2047
Debt Instrument
Redemption premium, percentage	40.00%

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Long-Term Debt - Senior Unsecured Notes Repurchases (Details) $ in Millions	12 Months Ended
	Dec. 31, 2021 USD ($)
Debt Disclosure [Abstract]
Debt repurchased	$ 67.7
Aggregate payments	(36.0)
Net discount on repurchased debt	(0.3)
Accrued interest on repurchased debt	0.6
Gain on extinguishment of debt	$ 32.0

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Income Taxes - Components of The Provision For Income Tax Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Current income tax expense	$ (0.8)	$ (1.1)	$ 0.0
Deferred tax expense	(24.6)	(142.1)	(6.9)
Total income tax expense	$ (25.4)	$ (143.2)	$ (6.9)

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Income Taxes - Book Income Reconciliation To Income Tax Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Effective Income Tax Rate Reconciliation, Amount [Abstract]
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	(3.1)	(6.0)	(2.2)
Non-deductible expense related to impairments	0.0	(43.4)	(264.5)
Statutory rate changes	(10.2)	0.0	0.0
Change in valuation allowance	(1.7)	153.3	0.0
Other	(2.4)	(5.5)	(0.8)
Total income tax expense	(25.4)	$ (143.2)	$ (6.9)
Oklahoma
Effective Income Tax Rate Reconciliation, Amount [Abstract]
Deferred state income tax expense (benefit)	7.6
Louisiana
Effective Income Tax Rate Reconciliation, Amount [Abstract]
Deferred state income tax expense (benefit)	$ 2.6

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Income Taxes - Summary of Deferred Income Tax Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Deferred income tax assets:
Federal net operating loss carryforward	$ 573.6	$ 488.3
State net operating loss carryforward	59.6	61.0
Total deferred tax assets, gross	633.2	549.3
Valuation allowance	(151.6)	(153.3)
Total deferred tax assets, net of valuation allowance	481.6	396.0
Deferred tax liabilities:
Property, plant, equipment, and intangible assets	(619.1)	(504.6)
Total deferred tax liabilities	(619.1)	(504.6)
Deferred tax liability, net	$ (137.5)	$ (108.6)

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Income Taxes - Narrative (Details) - USD ($)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Income Taxes [Line Items]
Issuance of common units for ENLK public common units related to the Merger	$ 399,000,000		$ 399,000,000.0
Valuation allowance	151,600,000	$ 153,300,000
Change in valuation allowance	(1,700,000)	153,300,000	$ 0
Unrecognized tax benefits	0	$ 0
Domestic Tax Authority
Income Taxes [Line Items]
Operating loss carryforwards	2,700,000,000
Deferred tax assets, operating loss carryforwards, domestic	573,600,000
Operating loss carryforwards, amount carried indefinitely	2,500,000,000
Operating loss carryforwards, amount carried for a maximum of twenty years	200,000,000
State and Local Jurisdiction
Income Taxes [Line Items]
Operating loss carryforwards	1,300,000,000
Deferred tax assets, operating loss carryforwards, domestic	$ 59,600,000

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Certain Provisions of the Partnership Agreement - Narrative (Details) $ / shares in Units, $ in Millions			1 Months Ended				3 Months Ended													12 Months Ended
	Feb. 11, 2022 USD ($)	Jan. 25, 2019	Jan. 31, 2022 USD ($) shares	Dec. 31, 2021 USD ($)	Sep. 30, 2017 $ / shares shares	Jan. 31, 2016 $ / shares shares	Dec. 31, 2021 USD ($) shares	Sep. 30, 2021 USD ($) shares	Jun. 30, 2021 USD ($) shares	Mar. 31, 2021 USD ($) shares	Dec. 31, 2020 USD ($) shares	Sep. 30, 2020 USD ($) shares	Jun. 30, 2020 USD ($) shares	Mar. 31, 2020 USD ($) shares	Dec. 31, 2019 USD ($) shares	Sep. 30, 2019 USD ($) shares	Jun. 30, 2019 USD ($) shares	Mar. 31, 2019 USD ($) shares	Sep. 30, 2018 $ / shares	Dec. 31, 2021 USD ($) shares	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)
Partnership agreement
Redemption of Series B Preferred Units																				$ 50.0	$ 0.0	$ 0.0
Common units conversion ratio		1.15
EnLink Midstream Partners, LP
Partnership agreement
Common units conversion ratio		1.15
Series B Preferred Units
Partnership agreement
Stock redeemed during period (in shares) | shares																				3,300,330
Redemption of Series B Preferred Units																				$ 50.0
Redemption price of preferred stock, percent																				101.00%
Series B Preferred Units | Subsequent Event
Partnership agreement
Stock redeemed during period (in shares) | shares			3,333,334
Redemption of Series B Preferred Units			$ 50.5
Redemption price of preferred stock, percent			101.00%
Series B Preferred Units | EnLink Midstream Partners, LP
Partnership agreement
Partners' capital account, units, sold in private placement (in shares) | shares						50,000,000
Shares issued, price per share (in dollars per share) | $ / shares						$ 15.00
Annual rate on issue price																				0.25%
Annual rate on issue price payable in cash																			28.125%
Series C Preferred Units | EnLink Midstream Partners, LP
Partnership agreement
Shares issued, price per share (in dollars per share) | $ / shares																			$ 1,000
Partners' capital account, units, sold in public offering (in shares) | shares					400,000
Partners capital account, redemption price (in dollars per share) | $ / shares					$ 1,000
Partners' capital account, redemption period following review or appeal					120 days
Partners' capital account, redemption price following review or appeal | $ / shares					$ 1,020
Partners' capital account, dividend rate, percentage					6.00%
Distributions to preferred unitholders																				$ 24.0	$ 24.0	$ 24.0
Series C Preferred Units | EnLink Midstream Partners, LP | LIBOR
Partnership agreement
Partners' capital account, distributions, variable floating rate percentage					4.11%
Limited Partner | Series B Preferred Units
Partnership agreement
Partners' capital, conversion obligation period of consecutive trading days																				30 days
Partners' capital, average trading price, number of trading days																				2 days
Percent of issue price																				150.00%
Preferred units distributions (in shares) | shares							0	151,626	151,248	150,871	150,494	150,119	149,745	149,371	148,999	148,627	148,257	147,887
Proceeds from issuance of ENLK Preferred Units							$ 19.2	$ 17.1	$ 17.0	$ 17.0	$ 16.9	$ 16.9	$ 16.8	$ 16.8	$ 16.8	$ 17.1	$ 17.1	$ 16.7
Dividends, preferred stock				$ 0.9
Limited Partner | Series B Preferred Units | Subsequent Event
Partnership agreement
Dividends, preferred stock	$ 17.3		$ 1.0

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Members' Equity (Details) - USD ($)			3 Months Ended												12 Months Ended
	Feb. 22, 2019	Jan. 25, 2019	Dec. 31, 2021	Sep. 30, 2021	Jun. 30, 2021	Mar. 31, 2021	Dec. 31, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Nov. 30, 2020
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Stock repurchase program, authorized amount																		$ 100,000,000
Common units repurchased (in shares)															6,091,001	383,614
Payments for repurchase of common stock															$ 40,100,000	$ 1,200,000	$ 0
Payments for repurchase of common stock (in dollars per share)															$ 6.59	$ 3.02
Sale of stock, maximum amount allowed to be sold through agent	$ 400,000,000
Distributed earnings allocated to:
Total distributed earnings															$ 197,000,000.0	$ 186,600,000	484,700,000
Undistributed loss allocated to:
Total undistributed loss, basic															(174,600,000)	(608,100,000)	(1,604,000,000)
Total undistributed loss, diluted															(174,600,000)	(608,100,000)	(1,604,000,000)
Net income (loss) attributable to ENLC allocated to:
Total net income (loss), basic															22,400,000	(421,500,000)	(1,119,300,000)
Total net income (loss), diluted															$ 22,400,000	$ (421,500,000)	$ (1,119,300,000)
Basic and diluted net income (loss) per unit attributable to ENLC:
Basic (in dollars per share)															$ 0.05	$ (0.86)	$ (2.41)
Diluted (in dollars per share)															$ 0.05	$ (0.86)	$ (2.41)
Weighted average basic common units outstanding (in units)															488,800,000	489,300,000	463,900,000
Dilutive effect of non-vested restricted units (in units)															5,500,000	0	0
Total weighted average diluted common units outstanding (in units)															494,300,000	489,300,000	463,900,000
Distribution declared/unit (in dollars per share)			$ 0.11250	$ 0.09375	$ 0.09375	$ 0.09375	$ 0.09375	$ 0.09375	$ 0.09375	$ 0.09375	$ 0.1875	$ 0.283	$ 0.283	$ 0.279
Merger
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Business acquisition, equity interest issued or issuable, number of shares (in shares)		304,822,035
Unvested restricted units
Distributed earnings allocated to:
Total distributed earnings															$ 4,500,000	$ 3,100,000	$ 5,700,000
Undistributed loss allocated to:
Total undistributed loss, basic															(4,000,000.0)	(9,700,000)	(19,200,000)
Total undistributed loss, diluted															(4,000,000.0)	(9,700,000)	(19,200,000)
Net income (loss) attributable to ENLC allocated to:
Total net income (loss), basic															500,000	(6,600,000)	(13,500,000)
Total net income (loss), diluted															500,000	(6,600,000)	(13,500,000)
Common units
Distributed earnings allocated to:
Total distributed earnings															192,500,000	183,500,000	479,000,000.0
Undistributed loss allocated to:
Total undistributed loss, basic															(170,600,000)	(598,400,000)	(1,584,800,000)
Total undistributed loss, diluted															(170,600,000)	(598,400,000)	(1,584,800,000)
Net income (loss) attributable to ENLC allocated to:
Total net income (loss), basic															21,900,000	(414,900,000)	(1,105,800,000)
Total net income (loss), diluted															$ 21,900,000	$ (414,900,000)	$ (1,105,800,000)

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Investment in Unconsolidated Affiliates (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Equity method investments
Distributions	$ 3.9	$ 2.1	$ 20.2
Equity in income (loss)	(11.5)	0.6	(16.8)
Tangible asset impairment charges			7.9
EnLink Midstream Partners, LP
Equity method investments
Total investment in unconsolidated affiliates	26.2	41.6
Cedar Cove JV
Equity method investments
Tangible asset impairment charges	$ 31.4		31.4
Gulf Coast Fractionators
Equity method investments
Ownership interest	38.75%
Distributions	$ 3.5	1.6	19.2
Equity in income (loss)	(9.1)	3.0	16.5
Gulf Coast Fractionators | EnLink Midstream Partners, LP
Equity method investments
Total investment in unconsolidated affiliates	$ 28.0	40.6
Cedar Cove JV
Equity method investments
Ownership interest	30.00%
Distributions	$ 0.4	0.5	1.0
Equity in income (loss)	(2.4)	(2.4)	$ (33.3)
Cedar Cove JV | EnLink Midstream Partners, LP
Equity method investments
Total investment in unconsolidated affiliates	$ (1.8)	$ 1.0

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Employee Incentive Plans - Amounts Recognized in Consolidated Financial Statements (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Allocation
Compensation expense	$ 25.3	$ 28.4	$ 39.4
Amount of related income tax benefit recognized in net income	5.9	6.7	9.1
Unit-based compensation, related income tax expense (benefit)	3.1	6.0	2.2
Unvested restricted units
Allocation
Unit-based compensation, related income tax expense (benefit)	3.1	6.0	2.2
Non-Controlling Interest
Allocation
Compensation expense	0.0	0.0	0.5
Cost of unit-based compensation charged to general and administrative expense
Allocation
Compensation expense	18.7	21.3	32.7
Cost of unit-based compensation charged to operating expense
Allocation
Compensation expense	$ 6.6	$ 7.1	$ 6.7

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Employee Incentive Plans - Restricted and Performance Awards (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended							12 Months Ended
	Jan. 31, 2021	Jul. 31, 2020	Mar. 31, 2020	Jan. 31, 2020	Oct. 31, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Jul. 31, 2021
Restricted incentive units
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Unrecognized compensation cost related to non-vested restricted incentive units								$ 13.0
Unrecognized compensation costs, weighted average period for recognition								1 year 7 months 6 days
Vesting period								3 years
Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Non-vested, beginning of period (in shares)	2,351,241							2,351,241
Granted (in shares)								1,388,139
Vested (in shares)								(164,553)
Non-vested, end of period (in shares)								3,574,827	2,351,241
Aggregate intrinsic value, end of period (in millions)								$ 24.6
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Non-vested, beginning of period (in dollars per share)	$ 8.82							$ 8.82
Granted (in dollars per share)								4.70
Vested (in dollars per share)								26.73
Non-vested, end of period (in dollars per share)								$ 6.40	$ 8.82
Fair value of units vested								$ 4.4	$ 5.5	$ 7.9
Aggregate intrinsic value of units vested								0.6	$ 0.9	3.4
Unrecognized compensation cost related to non-vested restricted incentive units								$ 10.4
Unrecognized compensation costs, weighted average period for recognition								1 year 7 months 6 days
Vesting period								3 years
ENLC | Restricted incentive units
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Non-vested, beginning of period (in shares)	5,350,086							5,350,086
Granted (in shares)								3,937,301
Vested (in shares)								(1,268,801)
Forfeited (in shares)								(511,115)
Non-vested, end of period (in shares)								7,507,471	5,350,086
Aggregate intrinsic value, end of period (in millions)								$ 51.7
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Non-vested, beginning of period (in dollars per share)	$ 8.45							$ 8.45
Granted (in dollars per share)								3.86
Vested (in dollars per share)								12.85
Forfeited (in dollars per share)								6.10
Non-vested, end of period (in dollars per share)								$ 5.46	$ 8.45
Fair value of units vested								$ 16.3	$ 31.5	22.8
Units withheld for payroll taxes (in shares)								382,343
Aggregate intrinsic value of units vested								$ 5.6	$ 12.1	$ 17.3
ENLC | Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Units withheld for payroll taxes (in shares)								63,901
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Grant-date fair value (in dollars per share)	4.70		$ 1.13	$ 7.69	$ 7.29	$ 9.92	$ 13.10				$ 2.33
Beginning TSR price (in dollars per share)	$ 3.71	$ 2.52	$ 1.25	$ 6.13	$ 7.42	$ 9.84	$ 10.92
Risk-free interest rate	0.17%	0.17%	0.42%	1.62%	1.44%	1.72%	2.42%
Volatility factor	71.00%	67.00%	51.00%	37.00%	35.00%	33.50%	33.86%
ENLC | Performance Shares | Minimum
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Percent of units vesting								0.00%
ENLC | Performance Shares | Maximum
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Percent of units vesting								200.00%

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Employee Incentive Plans - Summary of Tranche Vesting Levels (Details) - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2021
Below Threshold | TSR Performance Unit
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage of the Tranche CF Units			0.00%
Below Threshold | Cash Flow Performance Unit
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
ENLC’s Achieved FCFAD			$ 205
ENLC’s Achieved Cash Flow per Unit (in dollars per share)	$ 1.345	$ 1.43
Vesting percentage of the Tranche CF Units	0.00%	0.00%	0.00%
Threshold | TSR Performance Unit
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage of the Tranche CF Units			50.00%
Threshold | Cash Flow Performance Unit
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
ENLC’s Achieved FCFAD			$ 205
ENLC’s Achieved Cash Flow per Unit (in dollars per share)	$ 1.345	$ 1.43
Vesting percentage of the Tranche CF Units	50.00%	50.00%	50.00%
Target | TSR Performance Unit
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage of the Tranche CF Units			100.00%
Target | Cash Flow Performance Unit
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
ENLC’s Achieved FCFAD			$ 256
ENLC’s Achieved Cash Flow per Unit (in dollars per share)	$ 1.494	$ 1.55
Vesting percentage of the Tranche CF Units	100.00%	100.00%	100.00%
Maximum | TSR Performance Unit
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage of the Tranche CF Units			200.00%
Maximum | Cash Flow Performance Unit
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
ENLC’s Achieved FCFAD			$ 300
ENLC’s Achieved Cash Flow per Unit (in dollars per share)	$ 1.643	$ 1.72
Vesting percentage of the Tranche CF Units	200.00%	200.00%	200.00%

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Employee Incentive Plans - Benefit Plan (Details) - EnLink Midstream Partners, LP - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Defined Contribution Plan Disclosure [Line Items]
Employer matching contribution, percent	100.00%
Employer matching contribution, percent of employees' gross pay	6.00%
Employer benefit plan contributions	$ 7.0	$ 7.2	$ 9.4

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Derivatives - Interest Rate Swaps (Details) - USD ($)		12 Months Ended
		Dec. 31, 2021		Dec. 31, 2020		Dec. 31, 2019		Apr. 30, 2019
Derivatives
Derivative, notional amount								$ 850,000,000
Derivative, fixed interest rate								2.28%
Interest Rate Swaps Terminations		$ 850,000,000.0
Cash Payments Associated with Interest Rate Swaps Terminations		12,700,000
Change in fair value of derivatives		(12,400,000)		$ (10,500,000)		$ (100,000)
Tax benefit (expense)		(4,300,000)		1,300,000		3,400,000
Unrealized gain (loss) on designated cash flow hedge	[1]	13,900,000	[2]	(4,300,000)	[3]	(9,000,000.0)	[4]
Cash flow hedge gain (loss) amortized into interest rate expense		18,300,000		14,500,000		400,000
Cash flow hedge gain (loss) amortized into interest rate expense in the next 12 months		100,000
Fair value of derivative liabilities—current		(34,900,000)		(37,100,000)
December 2021
Derivatives
Interest Rate Swaps Terminations		150,000,000.0
Cash Payments Associated with Interest Rate Swaps Terminations		0
September 2021
Derivatives
Interest Rate Swaps Terminations		100,000,000.0
Cash Payments Associated with Interest Rate Swaps Terminations		500,000
May 2021
Derivatives
Interest Rate Swaps Terminations		100,000,000.0
Cash Payments Associated with Interest Rate Swaps Terminations		1,300,000
December 2020
Derivatives
Interest Rate Swaps Terminations		500,000,000.0
Cash Payments Associated with Interest Rate Swaps Terminations		10,900,000
Interest rate swaps
Derivatives
Change in fair value of derivatives		18,200,000		(5,600,000)		$ (12,400,000)
Fair value of derivative liabilities—current		$ 0		$ (7,600,000)

[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.

[2] Includes a tax expense of $4.3 million.

[3] Includes a tax benefit of $1.3 million.

[4] Includes a tax benefit of $3.4 million.

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Derivatives - Components of Gain (Loss) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Derivatives
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	(10.3)	(14.8)	(2.5)
EnLink Midstream Partners, LP | Commodity Swaps
Derivatives
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

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Derivatives - Fair Value of Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Derivatives
Fair value of derivative assets—current	$ 22.4	$ 25.0
Fair value of derivative assets—long-term	0.2	4.9
Fair value of derivative liabilities—current	(34.9)	(37.1)
Fair value of derivative liabilities—long-term	(2.2)	(2.5)
Commodity Swaps
Derivatives
Net fair value of commodity swaps	(14.5)
EnLink Midstream Partners, LP | Commodity Swaps
Derivatives
Fair value of derivative assets—current	22.4	25.0
Fair value of derivative assets—long-term	0.2	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)

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Derivatives - Commodities (Details) - Commodity Swaps gal in Millions, bbl in Millions, MMBTU in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2021 USD ($) MMBTU gal bbl	Dec. 31, 2020 USD ($)
Derivatives
Net Fair Value	$ (14.5)
EnLink Midstream Partners, LP
Derivatives
Net Fair Value	(14.5)	$ (2.1)
Maximum loss if counterparties fail to perform	22.6
Maximum potential exposure to credit losses net exposure	$ 0.8
EnLink Midstream Partners, LP | NGL | Short
Derivatives
Notional amount (in gallons or MMbbls) | gal	63.0
Net Fair Value	$ (10.6)
EnLink Midstream Partners, LP | NGL | Long
Derivatives
Notional amount (in gallons or MMbbls) | gal	0.0
Net Fair Value	$ 0.0
EnLink Midstream Partners, LP | Natural Gas | Short
Derivatives
Notional amount (in mmbtu) | MMBTU	7.5
Net Fair Value	$ 2.7
EnLink Midstream Partners, LP | Natural Gas | Long
Derivatives
Notional amount (in mmbtu) | MMBTU	13.2
Net Fair Value	$ (7.8)
EnLink Midstream Partners, LP | Condensate | Short
Derivatives
Notional amount (in gallons or MMbbls) | bbl	3.9
Net Fair Value	$ (4.4)
EnLink Midstream Partners, LP | Crude and condensate | Long
Derivatives
Notional amount (in gallons or MMbbls) | bbl	3.9
Net Fair Value	$ 5.6

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Fair Value Measurements - Recurring (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Commodity Swaps
Fair Value
Net Fair Value	$ (14.5)
Level 2 | Interest rate swaps | Recurring
Fair Value
Net Fair Value	0.0	$ (7.6)
Level 2 | Commodity Swaps | Recurring
Fair Value
Net Fair Value	$ (14.5)	$ (2.1)

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Fair Value Measurements - Financial Instruments (Details) - USD ($)	Dec. 31, 2021	Apr. 30, 2021	Dec. 31, 2020
Fair Value
Installment payable	$ 10,000,000.0		$ 0
Debt issuance costs	27,800,000		32,600,000
Amarillo Rattler, LLC
Fair Value
Installment payable	10,000,000	$ 10,000,000
Business combination, maximum earnout		$ 15,000,000
Carrying Value
Fair Value
Long-term debt	4,363,700,000		4,593,800,000
Installment payable	10,000,000.0		0
Contingent consideration	6,900,000		0
Fair Value
Fair Value
Long-term debt	4,520,000,000		4,318,200,000
Installment payable	10,000,000.0		0
Contingent consideration	$ 6,900,000		$ 0

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Commitments and Contingencies - Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2021 USD ($)
Koch | EnLink Gas Marketing, LP
Commitments and Contingencies
Loss contingency, damages sought, value	$ 53.9

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Segment Information - Financial Information and Assets (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Segment Reporting Information [Line Items]
Revenue from contracts with customers		$ 6,845.0	$ 3,915.8	$ 6,038.5
Cost of sales, exclusive of operating expenses and depreciation and amortization	[1]	(5,189.9)	(2,388.5)	(4,392.5)
Realized gain (loss) on derivatives		(146.7)	(11.5)	14.5
Change in fair value of derivatives		(12.4)	(10.5)	(0.1)
Adjusted gross margin		1,496.0	1,505.3	1,660.4
Operating expenses		(362.9)	(373.8)	(467.1)
Segment profit		1,133.1	1,131.5	1,193.3
Depreciation and amortization		(607.5)	(638.6)	(617.0)
Impairments		(0.8)	(362.8)	(1,133.5)
Gain (loss) on disposition of assets		1.5	(8.8)	1.9
General and administrative		(107.8)	(103.3)	(152.6)
Loss on secured term loan receivable		0.0	0.0	(52.9)
Interest expense, net of interest income		(238.7)	(223.3)	(216.0)
Gain on extinguishment of debt		0.0	32.0	0.0
Income (loss) from unconsolidated affiliates		(11.5)	0.6	(16.8)
Other income		0.0	0.3	0.9
Income (loss) before non-controlling interest and income taxes		168.3	(172.4)	(992.7)
Related parties amount in cost of sales		17.9	8.7	21.7
Capital expenditures		196.0	262.6	748.4
Permian
Segment Reporting Information [Line Items]
Revenue from contracts with customers		2,390.6	1,106.5	2,542.3
Cost of sales, exclusive of operating expenses and depreciation and amortization		(1,996.1)	(842.2)	(2,283.9)
Realized gain (loss) on derivatives		(75.6)	(1.1)	9.4
Change in fair value of derivatives		(7.7)	1.1	1.5
Adjusted gross margin		311.2	264.3	269.3
Operating expenses		(81.5)	(94.2)	(112.9)
Segment profit		229.7	170.1	156.4
Depreciation and amortization		(139.9)	(125.2)	(119.8)
Impairments		0.0	(184.6)	(3.5)
Gain (loss) on disposition of assets		0.0	(11.2)	(0.3)
General and administrative		0.0	0.0	0.0
Loss on secured term loan receivable				0.0
Interest expense, net of interest income		0.0	0.0	0.0
Gain on extinguishment of debt			0.0
Income (loss) from unconsolidated affiliates		0.0	0.0	0.0
Other income			0.0	0.0
Income (loss) before non-controlling interest and income taxes		89.8	(150.9)	32.8
Capital expenditures		141.6	181.1	364.5
Louisiana
Segment Reporting Information [Line Items]
Revenue from contracts with customers		4,581.4	2,205.1	2,622.8
Cost of sales, exclusive of operating expenses and depreciation and amortization		(4,091.2)	(1,787.0)	(2,181.6)
Realized gain (loss) on derivatives		(42.3)	(6.0)	5.1
Change in fair value of derivatives		0.7	(6.5)	(1.8)
Adjusted gross margin		448.6	405.6	444.5
Operating expenses		(123.7)	(120.0)	(147.3)
Segment profit		324.9	285.6	297.2
Depreciation and amortization		(141.0)	(145.8)	(154.1)
Impairments		(0.6)	(170.0)	(188.7)
Gain (loss) on disposition of assets		1.2	0.1	2.6
General and administrative		0.0	0.0	0.0
Loss on secured term loan receivable				0.0
Interest expense, net of interest income		0.0	0.0	0.0
Gain on extinguishment of debt			0.0
Income (loss) from unconsolidated affiliates		0.0	0.0	0.0
Other income			0.0	0.0
Income (loss) before non-controlling interest and income taxes		184.5	(30.1)	(43.0)
Capital expenditures		9.3	44.6	99.9
Oklahoma
Segment Reporting Information [Line Items]
Revenue from contracts with customers		1,226.8	862.0	1,181.1
Cost of sales, exclusive of operating expenses and depreciation and amortization		(796.6)	(365.5)	(627.0)
Realized gain (loss) on derivatives		(22.6)	(4.4)	0.0
Change in fair value of derivatives		0.0	(4.5)	0.0
Adjusted gross margin		407.6	487.6	554.1
Operating expenses		(80.0)	(82.2)	(104.0)
Segment profit		327.6	405.4	450.1
Depreciation and amortization		(204.3)	(216.9)	(194.9)
Impairments		0.0	(0.7)	(813.5)
Gain (loss) on disposition of assets		0.0	0.3	0.1
General and administrative		0.0	0.0	0.0
Loss on secured term loan receivable				0.0
Interest expense, net of interest income		0.0	0.0	0.0
Gain on extinguishment of debt			0.0
Income (loss) from unconsolidated affiliates		0.0	0.0	0.0
Other income			0.0	0.0
Income (loss) before non-controlling interest and income taxes		123.3	188.1	(558.2)
Capital expenditures		30.4	17.9	238.1
North Texas
Segment Reporting Information [Line Items]
Revenue from contracts with customers		872.0	502.2	601.1
Cost of sales, exclusive of operating expenses and depreciation and amortization		(531.8)	(153.8)	(208.8)
Realized gain (loss) on derivatives		(6.2)	0.0	0.0
Change in fair value of derivatives		(5.4)	(0.6)	0.2
Adjusted gross margin		328.6	347.8	392.5
Operating expenses		(77.7)	(77.4)	(102.9)
Segment profit		250.9	270.4	289.6
Depreciation and amortization		(114.3)	(143.4)	(139.8)
Impairments		0.0	0.0	(127.8)
Gain (loss) on disposition of assets		0.3	2.0	(0.5)
General and administrative		0.0	0.0	0.0
Loss on secured term loan receivable				0.0
Interest expense, net of interest income		0.0	0.0	0.0
Gain on extinguishment of debt			0.0
Income (loss) from unconsolidated affiliates		0.0	0.0	0.0
Other income			0.0	0.0
Income (loss) before non-controlling interest and income taxes		136.9	129.0	21.5
Capital expenditures		11.9	16.9	39.0
Corporate
Segment Reporting Information [Line Items]
Revenue from contracts with customers		(2,225.8)	(760.0)	(908.8)
Cost of sales, exclusive of operating expenses and depreciation and amortization		2,225.8	760.0	908.8
Realized gain (loss) on derivatives		0.0	0.0	0.0
Change in fair value of derivatives		0.0	0.0	0.0
Adjusted gross margin		0.0	0.0	0.0
Operating expenses		0.0	0.0	0.0
Segment profit		0.0	0.0	0.0
Depreciation and amortization		(8.0)	(7.3)	(8.4)
Impairments		(0.2)	(7.5)	0.0
Gain (loss) on disposition of assets		0.0	0.0	0.0
General and administrative		(107.8)	(103.3)	(152.6)
Loss on secured term loan receivable				(52.9)
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
Income (loss) before non-controlling interest and income taxes		(366.2)	(308.5)	(445.8)
Capital expenditures		2.8	2.1	6.9
Product sales
Segment Reporting Information [Line Items]
Revenue from contracts with customers		5,994.0	2,977.5	5,030.1
Product sales | Permian
Segment Reporting Information [Line Items]
Revenue from contracts with customers		1,287.7	708.4	2,070.2
Product sales | Louisiana
Segment Reporting Information [Line Items]
Revenue from contracts with customers		4,258.6	2,002.6	2,434.1
Product sales | Oklahoma
Segment Reporting Information [Line Items]
Revenue from contracts with customers		296.6	196.2	365.6
Product sales | North Texas
Segment Reporting Information [Line Items]
Revenue from contracts with customers		151.1	70.3	160.2
Product sales | Corporate
Segment Reporting Information [Line Items]
Revenue from contracts with customers		0.0	0.0	0.0
Natural gas sales
Segment Reporting Information [Line Items]
Revenue from contracts with customers		1,666.3	704.0	876.6
Natural gas sales | Permian
Segment Reporting Information [Line Items]
Revenue from contracts with customers		609.4	150.1	94.3
Natural gas sales | Louisiana
Segment Reporting Information [Line Items]
Revenue from contracts with customers		693.5	330.5	416.6
Natural gas sales | Oklahoma
Segment Reporting Information [Line Items]
Revenue from contracts with customers		213.4	153.1	236.4
Natural gas sales | North Texas
Segment Reporting Information [Line Items]
Revenue from contracts with customers		150.0	70.3	129.3
Natural gas sales | Corporate
Segment Reporting Information [Line Items]
Revenue from contracts with customers		0.0	0.0	0.0
NGL sales
Segment Reporting Information [Line Items]
Revenue from contracts with customers		3,357.1	1,548.4	1,777.0
NGL sales | Permian
Segment Reporting Information [Line Items]
Revenue from contracts with customers		0.9	0.2	0.9
NGL sales | Louisiana
Segment Reporting Information [Line Items]
Revenue from contracts with customers		3,353.1	1,545.4	1,725.6
NGL sales | Oklahoma
Segment Reporting Information [Line Items]
Revenue from contracts with customers		2.0	2.8	19.6
NGL sales | North Texas
Segment Reporting Information [Line Items]
Revenue from contracts with customers		1.1	0.0	30.9
NGL sales | Corporate
Segment Reporting Information [Line Items]
Revenue from contracts with customers		0.0	0.0	0.0
Crude oil and condensate sales
Segment Reporting Information [Line Items]
Revenue from contracts with customers		970.6	725.1	2,376.5
Crude oil and condensate sales | Permian
Segment Reporting Information [Line Items]
Revenue from contracts with customers		677.4	558.1	1,975.0
Crude oil and condensate sales | Louisiana
Segment Reporting Information [Line Items]
Revenue from contracts with customers		212.0	126.7	291.9
Crude oil and condensate sales | Oklahoma
Segment Reporting Information [Line Items]
Revenue from contracts with customers		81.2	40.3	109.6
Crude oil and condensate sales | North Texas
Segment Reporting Information [Line Items]
Revenue from contracts with customers		0.0	0.0	0.0
Crude oil and condensate sales | Corporate
Segment Reporting Information [Line Items]
Revenue from contracts with customers		0.0	0.0	0.0
Product sales—related parties
Segment Reporting Information [Line Items]
Revenue from contracts with customers		0.0	0.0	0.0
Product sales—related parties | Permian
Segment Reporting Information [Line Items]
Revenue from contracts with customers		1,008.4	313.2	361.6
Product sales—related parties | Louisiana
Segment Reporting Information [Line Items]
Revenue from contracts with customers		129.7	31.4	27.4
Product sales—related parties | Oklahoma
Segment Reporting Information [Line Items]
Revenue from contracts with customers		630.9	296.3	421.1
Product sales—related parties | North Texas
Segment Reporting Information [Line Items]
Revenue from contracts with customers		454.1	118.8	100.3
Product sales—related parties | Corporate
Segment Reporting Information [Line Items]
Revenue from contracts with customers		(2,223.1)	(759.7)	(910.4)
Natural gas sales—related parties
Segment Reporting Information [Line Items]
Revenue from contracts with customers				0.0
Natural gas sales—related parties | Permian
Segment Reporting Information [Line Items]
Revenue from contracts with customers				0.4
Natural gas sales—related parties | Louisiana
Segment Reporting Information [Line Items]
Revenue from contracts with customers				0.0
Natural gas sales—related parties | Oklahoma
Segment Reporting Information [Line Items]
Revenue from contracts with customers				0.0
Natural gas sales—related parties | North Texas
Segment Reporting Information [Line Items]
Revenue from contracts with customers				0.0
Natural gas sales—related parties | Corporate
Segment Reporting Information [Line Items]
Revenue from contracts with customers				(0.4)
NGL sales—related parties
Segment Reporting Information [Line Items]
Revenue from contracts with customers		0.0	0.0	0.0
NGL sales—related parties | Permian
Segment Reporting Information [Line Items]
Revenue from contracts with customers		1,008.4	312.6	347.7
NGL sales—related parties | Louisiana
Segment Reporting Information [Line Items]
Revenue from contracts with customers		129.7	31.4	25.7
NGL sales—related parties | Oklahoma
Segment Reporting Information [Line Items]
Revenue from contracts with customers		630.8	296.4	421.1
NGL sales—related parties | North Texas
Segment Reporting Information [Line Items]
Revenue from contracts with customers		447.0	115.2	94.8
NGL sales—related parties | Corporate
Segment Reporting Information [Line Items]
Revenue from contracts with customers		(2,215.9)	(755.6)	(889.3)
Crude oil and condensate sales—related parties
Segment Reporting Information [Line Items]
Revenue from contracts with customers		0.0	0.0	0.0
Crude oil and condensate sales—related parties | Permian
Segment Reporting Information [Line Items]
Revenue from contracts with customers		0.0	0.6	13.5
Crude oil and condensate sales—related parties | Louisiana
Segment Reporting Information [Line Items]
Revenue from contracts with customers		0.0	0.0	1.7
Crude oil and condensate sales—related parties | Oklahoma
Segment Reporting Information [Line Items]
Revenue from contracts with customers		0.1	(0.1)	0.0
Crude oil and condensate sales—related parties | North Texas
Segment Reporting Information [Line Items]
Revenue from contracts with customers		7.1	3.6	5.5
Crude oil and condensate sales—related parties | Corporate
Segment Reporting Information [Line Items]
Revenue from contracts with customers		(7.2)	(4.1)	(20.7)
Midstream services
Segment Reporting Information [Line Items]
Revenue from contracts with customers		851.0	938.3	1,008.4
Midstream services | Permian
Segment Reporting Information [Line Items]
Revenue from contracts with customers		94.5	84.9	110.5
Midstream services | Louisiana
Segment Reporting Information [Line Items]
Revenue from contracts with customers		190.7	171.1	164.7
Midstream services | Oklahoma
Segment Reporting Information [Line Items]
Revenue from contracts with customers		299.0	369.2	392.6
Midstream services | North Texas
Segment Reporting Information [Line Items]
Revenue from contracts with customers		266.8	313.1	340.6
Midstream services | Corporate
Segment Reporting Information [Line Items]
Revenue from contracts with customers		0.0	0.0	0.0
Gathering and transportation
Segment Reporting Information [Line Items]
Revenue from contracts with customers		455.4	497.2	538.0
Gathering and transportation | Permian
Segment Reporting Information [Line Items]
Revenue from contracts with customers		46.8	42.8	48.8
Gathering and transportation | Louisiana
Segment Reporting Information [Line Items]
Revenue from contracts with customers		64.7	46.5	58.3
Gathering and transportation | Oklahoma
Segment Reporting Information [Line Items]
Revenue from contracts with customers		186.9	228.7	234.5
Gathering and transportation | North Texas
Segment Reporting Information [Line Items]
Revenue from contracts with customers		157.0	179.2	196.4
Gathering and transportation | Corporate
Segment Reporting Information [Line Items]
Revenue from contracts with customers		0.0	0.0	0.0
Processing
Segment Reporting Information [Line Items]
Revenue from contracts with customers		238.5	282.3	314.9
Processing | Permian
Segment Reporting Information [Line Items]
Revenue from contracts with customers		29.1	24.1	30.5
Processing | Louisiana
Segment Reporting Information [Line Items]
Revenue from contracts with customers		2.4	2.0	3.2
Processing | Oklahoma
Segment Reporting Information [Line Items]
Revenue from contracts with customers		98.7	123.6	138.2
Processing | North Texas
Segment Reporting Information [Line Items]
Revenue from contracts with customers		108.3	132.6	143.0
Processing | Corporate
Segment Reporting Information [Line Items]
Revenue from contracts with customers		0.0	0.0	0.0
NGL services
Segment Reporting Information [Line Items]
Revenue from contracts with customers		82.9	76.0	50.7
NGL services | Permian
Segment Reporting Information [Line Items]
Revenue from contracts with customers		0.0	0.0	0.0
NGL services | Louisiana
Segment Reporting Information [Line Items]
Revenue from contracts with customers		82.6	75.8	50.6
NGL services | Oklahoma
Segment Reporting Information [Line Items]
Revenue from contracts with customers		0.0	0.0	0.0
NGL services | North Texas
Segment Reporting Information [Line Items]
Revenue from contracts with customers		0.3	0.2	0.1
NGL services | Corporate
Segment Reporting Information [Line Items]
Revenue from contracts with customers		0.0	0.0	0.0
Crude services
Segment Reporting Information [Line Items]
Revenue from contracts with customers		71.2	78.7	90.9
Crude services | Permian
Segment Reporting Information [Line Items]
Revenue from contracts with customers		18.4	16.8	19.2
Crude services | Louisiana
Segment Reporting Information [Line Items]
Revenue from contracts with customers		39.3	45.2	51.9
Crude services | Oklahoma
Segment Reporting Information [Line Items]
Revenue from contracts with customers		12.8	16.5	19.8
Crude services | North Texas
Segment Reporting Information [Line Items]
Revenue from contracts with customers		0.7	0.2	0.0
Crude services | Corporate
Segment Reporting Information [Line Items]
Revenue from contracts with customers		0.0	0.0	0.0
Other services
Segment Reporting Information [Line Items]
Revenue from contracts with customers		3.0	4.1	13.9
Other services | Permian
Segment Reporting Information [Line Items]
Revenue from contracts with customers		0.2	1.2	12.0
Other services | Louisiana
Segment Reporting Information [Line Items]
Revenue from contracts with customers		1.7	1.6	0.7
Other services | Oklahoma
Segment Reporting Information [Line Items]
Revenue from contracts with customers		0.6	0.4	0.1
Other services | North Texas
Segment Reporting Information [Line Items]
Revenue from contracts with customers		0.5	0.9	1.1
Other services | Corporate
Segment Reporting Information [Line Items]
Revenue from contracts with customers		0.0	0.0	0.0
Midstream services—related parties
Segment Reporting Information [Line Items]
Revenue from contracts with customers		0.0	0.0	0.0
Midstream services—related parties | Permian
Segment Reporting Information [Line Items]
Revenue from contracts with customers		0.0	0.0	0.0
Midstream services—related parties | Louisiana
Segment Reporting Information [Line Items]
Revenue from contracts with customers		2.4	0.0	(3.4)
Midstream services—related parties | Oklahoma
Segment Reporting Information [Line Items]
Revenue from contracts with customers		0.3	0.3	1.8
Midstream services—related parties | North Texas
Segment Reporting Information [Line Items]
Revenue from contracts with customers		0.0	0.0	0.0
Midstream services—related parties | Corporate
Segment Reporting Information [Line Items]
Revenue from contracts with customers		(2.7)	(0.3)	1.6
NGL services—related parties
Segment Reporting Information [Line Items]
Revenue from contracts with customers				0.0
NGL services—related parties | Permian
Segment Reporting Information [Line Items]
Revenue from contracts with customers				0.0
NGL services—related parties | Louisiana
Segment Reporting Information [Line Items]
Revenue from contracts with customers				(3.4)
NGL services—related parties | Oklahoma
Segment Reporting Information [Line Items]
Revenue from contracts with customers				0.0
NGL services—related parties | North Texas
Segment Reporting Information [Line Items]
Revenue from contracts with customers				0.0
NGL services—related parties | Corporate
Segment Reporting Information [Line Items]
Revenue from contracts with customers				3.4
Crude services—related parties
Segment Reporting Information [Line Items]
Revenue from contracts with customers		0.0	0.0	0.0
Crude services—related parties | Permian
Segment Reporting Information [Line Items]
Revenue from contracts with customers		0.0	0.0	0.0
Crude services—related parties | Louisiana
Segment Reporting Information [Line Items]
Revenue from contracts with customers		0.0	0.0	0.0
Crude services—related parties | Oklahoma
Segment Reporting Information [Line Items]
Revenue from contracts with customers		0.3	0.3	1.8
Crude services—related parties | North Texas
Segment Reporting Information [Line Items]
Revenue from contracts with customers		0.0	0.0	0.0
Crude services—related parties | Corporate
Segment Reporting Information [Line Items]
Revenue from contracts with customers		(0.3)	$ (0.3)	$ (1.8)
Other services—related parties
Segment Reporting Information [Line Items]
Revenue from contracts with customers		0.0
Other services—related parties | Permian
Segment Reporting Information [Line Items]
Revenue from contracts with customers		0.0
Other services—related parties | Louisiana
Segment Reporting Information [Line Items]
Revenue from contracts with customers		2.4
Other services—related parties | Oklahoma
Segment Reporting Information [Line Items]
Revenue from contracts with customers		0.0
Other services—related parties | North Texas
Segment Reporting Information [Line Items]
Revenue from contracts with customers		0.0
Other services—related parties | Corporate
Segment Reporting Information [Line Items]
Revenue from contracts with customers		$ (2.4)

[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.

XML

Segment Information - Amortization Expense (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Segment Reporting Information [Line Items]
Assets	$ 8,483.2	$ 8,550.9
Permian
Segment Reporting Information [Line Items]
Assets	2,358.6	2,236.3
Louisiana
Segment Reporting Information [Line Items]
Assets	2,428.6	2,312.4
Oklahoma
Segment Reporting Information [Line Items]
Assets	2,619.5	2,847.6
North Texas
Segment Reporting Information [Line Items]
Assets	896.8	1,008.6
Corporate
Segment Reporting Information [Line Items]
Assets	$ 179.7	$ 146.0

XML

Supplemental Cash Flow Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Supplemental disclosures of cash flow information:
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	0.0	0.0	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	0.0	0.0
Non-cash financing activities:
Receivable from sale of VEX	0.0	10.0	0.0
Redemption of non-controlling interest	$ 0.0	$ (4.0)	$ 0.0

XML

Other Information - Other Current Assets (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Other current assets:
Natural gas and NGLs inventory	$ 49.4	$ 44.9
Prepaid expenses and other	34.2	13.8
Other current assets	$ 83.6	$ 58.7

XML

Other Information - Other Current Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Other current liabilities:
Accrued interest	$ 47.2	$ 35.7
Accrued wages and benefits, including taxes	33.1	22.5
Accrued ad valorem taxes	28.3	26.5
Capital expenditure accruals	23.2	10.6
Short-term lease liability	18.1	16.3
Installment payable	10.0	0.0
Inactive easement commitment	9.8	0.0
Operating expense accruals	9.6	8.4
Other	23.6	29.1
Other current liabilities	$ 202.9	$ 149.1

XML

Subsequent Event (Details) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Jan. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Subsequent Event [Line Items]
Redemption of Series B Preferred Units		$ 50.0	$ 0.0	$ 0.0
Series B Preferred Units
Subsequent Event [Line Items]
Stock redeemed during period (in shares)		3,300,330
Redemption of Series B Preferred Units		$ 50.0
Redemption price of preferred stock, percent		101.00%
Subsequent Event | Series B Preferred Units
Subsequent Event [Line Items]
Stock redeemed during period (in shares)	3,333,334
Redemption of Series B Preferred Units	$ 50.5
Redemption price of preferred stock, percent	101.00%

XML

Label	Element	Value
Accounting Standards Update [Extensible Enumeration]	us-gaap_AccountingStandardsUpdateExtensibleList	Accounting Standards Update 2016-02 [Member]