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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, 2019

☐ 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: 001-36340

ENLINK MIDSTREAM PARTNERS, LP

(Exact name of registrant as specified in its charter)



Delaware		16-1616605
(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
None.	None.	None.

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

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

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

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

Indicate by check mark whether the registrant has submitted electronically 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 x 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	x	Smaller reporting company	☐
Emerging growth company	☐		☐

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

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

At February 19, 2020, the Registrant had 144,358,720 common units outstanding, all of which were held by our affiliate, EnLink Midstream, LLC.

DOCUMENTS INCORPORATED BY REFERENCE:

None.

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TABLE OF CONTENTS



Item	Description	Page

	PART I
1.	BUSINESS	6
1A.	RISK FACTORS	31
1B.	UNRESOLVED STAFF COMMENTS	54
2.	PROPERTIES	54
3.	LEGAL PROCEEDINGS	54
4.	MINE SAFETY DISCLOSURES	55

	PART II
5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED UNITHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES	56
6.	SELECTED FINANCIAL DATA	56
7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	58
7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	75
8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	79
9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	132
9A.	CONTROLS AND PROCEDURES	132
9B.	OTHER INFORMATION	132

	PART III
10.	DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE	133
11.	EXECUTIVE COMPENSATION	135
12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS	150
13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE	153
14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	154

	PART IV
15.	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES	156

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DEFINITIONS

The following terms as defined are used in this document:



Defined Term		Definition
/d		Per day.
2014 EDA		Equity Distribution Agreement entered into by ENLK in November 2014 with BMO Capital Markets Corp., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Citigroup Global Markets Inc., Jefferies LLC, Raymond James & Associates, Inc. and RBC Capital Markets, LLC to sell up to $350.0 million in aggregate gross sales of ENLK’s common units from time to time through an “at the market” equity offering program.
2014 Plan		ENLC’s 2014 Long-Term Incentive Plan.
2017 EDA		Equity Distribution Agreement entered into by ENLK in August 2017 with UBS Securities LLC, Barclays Capital Inc., BMO Capital Markets Corp., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Citigroup Global Markets Inc., Jefferies LLC, Mizuho Securities USA LLC, RBC Capital Markets, LLC, SunTrust Robinson Humphrey, Inc., and Wells Fargo Securities, LLC (collectively, the “ENLK Sales Agents”) to sell up to $600.0 million in aggregate gross sales of ENLK’s common units from time to time through an “at the market” equity offering program.
Acacia		Acacia Natural Gas Corp. I, Inc.
AMZ		Alerian MLP Index for Master Limited Partnerships.
ASC		The FASB Accounting Standards Codification.
ASC 606		ASC 606, Revenue from Contracts with Customers.
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.
ASU		The FASB Accounting Standards Update.
Avenger		Avenger crude oil gathering system, a crude oil gathering system in the northern Delaware Basin.
Bbls		Barrels.
Bcf		Billion cubic feet.
Black Coyote		Black Coyote crude oil gathering system, a crude oil gathering system in the STACK.
BLM		Bureau of Land Management.
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 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 located in the Delaware Basin in Texas.
Devon		Devon Energy Corporation.
ECP System		EnLink Crude Purchasing System. The ECP System includes assets that were acquired through the acquisition of LPC Crude Oil Marketing LLC in January 2015.
EMI		EnLink Midstream, Inc.
Enfield		Enfield Holdings, L.P.
ENLC		EnLink Midstream, LLC.
ENLC Class C Common Units		A class of non-economic ENLC common units issued to Enfield immediately prior to the Merger equal to the number of Series B Preferred Units held by Enfield immediately prior to the effective time of the Merger, in order to provide Enfield with certain voting rights with respect to ENLC.
ENLK		EnLink Midstream Partners, LP or, when applicable, EnLink Midstream Partners, LP together with its consolidated subsidiaries. Also referred to as the “Partnership.”

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ENLK Credit Facility		A $1.5 billion unsecured revolving credit facility entered into by ENLK that would have matured on March 6, 2020, which included a $500.0 million letter of credit subfacility. The ENLK Credit Facility was terminated on January 25, 2019 in connection with the consummation of the Merger.
EOGP		EnLink Oklahoma Gas Processing, LP or EnLink Oklahoma Gas Processing, LP together with, when applicable, its consolidated subsidiaries. Since January 31, 2019, EOGP has been a wholly-owned subsidiary of the Operating Partnership.
FASB		Financial Accounting Standards Board.
FERC		Federal Energy Regulatory Commission.
GAAP		Generally accepted accounting principles in the United States of America.
Gal		Gallons.
GCF		Gulf Coast Fractionators, which owns an NGL fractionator in Mont Belvieu, Texas. ENLK owns 38.75% of GCF.
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 of ENLC to GIP.
Goldman Sachs		Goldman Sachs Group, Inc.
GP Plan		EnLink Midstream GP, LLC’s Long-Term Incentive Plan.
Greater Chickadee		Crude oil gathering system in Upton and Midland counties, Texas in the Permian Basin.
Gross Operating Margin		Revenue less cost of sales. Gross Operating 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 other information.
HEP		Howard Energy Partners, LP. ENLK sold its 31% ownership interest in HEP in March 2017.
ISDAs		International Swaps and Derivatives Association Agreements.
Mcf		Thousand cubic feet.
MEGA system		Midland Energy Gathering Area system in Midland, Martin, and Glasscock counties, Texas.
Merger		On January 25, 2019, NOLA Merger Sub merged with and into ENLK with ENLK continuing as the surviving entity and a subsidiary of ENLC.
Merger Agreement		The Agreement and Plan of Merger, dated as of October 21, 2018, by and among ENLK, the general partner of ENLK, ENLC, the managing member of ENLC, and NOLA Merger Sub related to the Merger.
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.
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.
Redbud		Redbud crude oil gathering system, a crude oil gathering system in the STACK.
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		An $850.0 million term loan 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 guarantees.

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Thunderbird Plant		A gas processing plant in Central Oklahoma.
Tiger Plant		A gas processing plant in the Delaware Basin.
TPG		TPG Global, LLC.
VEX		ENLK’s Victoria Express Pipeline and related truck terminal and storage assets located in the Eagle Ford Shale in South Texas.
White Star		White Star Petroleum, LLC.

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

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ENLINK MIDSTREAM PARTNERS, LP

PART I

Item 1. Business

General

ENLK is a Delaware limited partnership formed in 2002. Our business activities are conducted through the Operating Partnership and the subsidiaries of the Operating Partnership. 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 term “Partnership,” as well as the terms “ENLK,” “our,” “we,” and “us” or like terms are sometimes used as references to EnLink Midstream Partners, LP itself or EnLink Midstream Partners, LP together with its consolidated subsidiaries, including the Operating Partnership.

EnLink Midstream GP, LLC, a Delaware limited liability company, is our general partner. Our general partner manages our operations and activities. Our general partner is a direct, wholly-owned subsidiary of ENLC. ENLC’s units are traded on the NYSE under the symbol “ENLC.” ENLC’s managing member is a wholly-owned subsidiary of GIP.

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 of ENLC to GIP. As a result of the transaction, GIP acquired control of (i) the managing member of ENLC, (ii) ENLC, and (iii) ENLK, as a result of ENLC’s ownership of our general partner. See “Item 8. Financial Statements and Supplementary Data—Note 1” for more information on the GIP Transaction.

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 ENLC owning all of the remaining outstanding ENLK common units.


•	Our 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 “Item 8. Financial Statements and Supplementary Data—Note 8” for additional information regarding the modified terms of the Series B Preferred Units.

•

ENLC issued to Enfield, the current 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 by Enfield immediately prior to the effective time of the Merger, in order to provide Enfield 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, an ENLC Class C Common Unit will be canceled.

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•	The Series C Preferred Units and all of our then-existing senior notes continue to be issued and outstanding following the Merger.


•	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 “Item 8. Financial Statements and Supplementary Data—Note 6” for additional information regarding the Term Loan.


•	We refinanced our existing revolving credit facilities at ENLK and ENLC. In connection with the Merger, ENLC entered into the Consolidated Credit Facility, with respect to which ENLK is a guarantor. See “Item 8. Financial Statements and Supplementary Data—Note 6” for additional information regarding the Consolidated Credit Facility.

For additional information on the organization of our business, see “Item 8. Financial Statements and Supplementary Data—Note 1.”

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The following diagram depicts our organization and ownership as of December 31, 2019:

____________________________


(1)	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.


(2)	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.


(3)	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.

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 12,000 miles of pipelines, 21 natural gas processing plants with approximately 5.3 Bcf/d of processing capacity, seven fractionators with approximately 290,000 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

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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. 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, barge, truck, or rail terminal.

Effective January 1, 2019, we changed our reportable operating segments to reflect how we currently make financial decisions and allocate resources. Prior to January 1, 2019, our reportable operating segments consisted of the following: (i) natural gas gathering, processing, transmission, and fractionation operations located in North Texas and the Permian Basin, primarily in West Texas, (ii) natural gas pipelines, processing plants, storage facilities, NGL pipelines, and fractionation assets in Louisiana, (iii) natural gas gathering and processing operations located throughout Oklahoma, and (iv) crude rail, truck, pipeline, and barge facilities in West Texas, South Texas, Louisiana, Oklahoma, and ORV. Effective January 1, 2019, we report our financial performance in five 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 and our crude operations in South Texas;


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


•	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;


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

For more information about our segment reporting, see “Item 8. Financial Statements and Supplementary Data—Note 14.”

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Our Business Strategies

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


•	Enhance the Profitability of Existing Business. We are focused on enhancing the profitability of current operations and our strong, integrated base of assets by:


•	Filling available capacity of our assets and optimizing assets to support increasing demand.


•	Growing market share in areas across our footprint.


•	Reducing costs across our assets.


•	Capitalizing on opportunities to expand and capture business opportunities with customers.

•

Position to Capture Long-term Opportunities. We believe our assets are positioned in some of the most economically advantageous basins in the U.S., as well as key demand centers with growing end-use customers. We expect to grow certain of our systems organically over time by meeting our customers’ midstream service needs that result from their drilling activity in our areas of operation or growth in supply needs. We continually evaluate economically attractive organic expansion opportunities in our areas of operation that allow us to leverage our existing infrastructure, operating expertise, and customer relationships by constructing and expanding systems to meet new or increased demand for our services.

•

Optimize Strong Financial Position. We are focused on strengthening our financial position by achieving long-term capital structure priorities, increasing cash flows, and maintaining balance sheet strength. We believe that maintaining a conservative and balanced capital structure, appropriate leverage, and other key financial metrics will afford us better access to the capital markets at a competitive cost of capital. We also believe a strong financial position provides us the opportunity to grow our business in a prudent manner throughout the cycles in our industry.


•	Drive Organizational Efficiency. We are committed to optimizing costs and efficiencies company-wide, while maintaining a high level of customer service and safety.

Recent Developments

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. See “Item 8. Financial Statements and Supplementary Data—Note 1” for more information on the Merger and related transactions.

Transfer of EOGP Interest. On January 31, 2019, ENLC transferred its 16.1% limited partner interest in EOGP to the Operating Partnership. See “Item 8. Financial Statements and Supplementary Data—Note 1” for more information regarding this transaction.

Organic Growth

Riptide Processing Plant. In September 2019, we completed construction of a 65 MMcf/d expansion to our Riptide processing plant in the Midland Basin, bringing the total operational processing capacity at the plant to 165 MMcf/d. We are currently in the process of further expanding our Riptide processing plant and expect an additional 55 MMcf/d of operational capacity to be completed during the fourth quarter of 2020.

Delaware Basin Processing Plant. In August 2019, we commenced construction of our Tiger Plant, which will expand our Delaware Basin processing capacity by an additional 200 MMcf/d. We expect the plant to be operational in the second half of 2020. This processing plant is owned by the Delaware Basin JV.

Central Oklahoma Plants. In June 2019, we commenced operations on our Thunderbird Plant, which expands our Central Oklahoma gas processing capacity by an additional 200 MMcf/d, bringing our total processing capacity at our Central Oklahoma facilities to 1.2 Bcf/d.

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Cajun-Sibon Pipeline. In April 2019, we completed the expansion of our Cajun-Sibon NGL pipeline capacity, which connects the Mont Belvieu NGL hub to our fractionation facilities in Louisiana. This is the third phase of our Cajun-Sibon system referred to as Cajun Sibon III, which increases throughput capacity from 130,000 bbls/d to 185,000 bbls/d.

Lobo Natural Gas Gathering and Processing Facilities. In early April 2019, we completed construction of a 100 MMcf/d expansion to our Lobo III cryogenic gas processing plant, bringing the total operational processing capacity at our Lobo facilities to 375 MMcf/d.

Avenger Crude Oil Gathering System. Avenger is a crude oil gathering system in the northern Delaware Basin 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. We commenced initial operations on Avenger during the third quarter of 2018 and began full-service operations during the second quarter of 2019.

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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. Except as stated otherwise, the following tables provide information about our assets as of and for the year ended December 31, 2019:



				Year Ended
				December 31, 2019
Gathering and Transmission Pipelines	Approximate Length (Miles)	Compression (HP)	Estimated Capacity (1)	Average Throughput (2)
Gas Pipelines
Permian assets:
MEGA System gathering facilities	765	132,500	447	407,000
Lobo gathering system (3)	180	46,900	160	316,400
Permian gas assets (3)	945	179,400	607	723,400

North Texas assets:
Bridgeport rich and lean gathering systems	2,800	206,700	900	762,700
Johnson County gathering system	390	49,000	400	111,700
Silver Creek gathering system	910	53,800	260	285,800
Acacia transmission system	130	16,000	920	491,700
North Texas gas assets	4,230	325,500	2,480	1,651,900

Oklahoma assets:
Central Oklahoma gathering system	1,825	258,700	1,137	1,270,200
Northridge gathering system	140	14,000	65	32,000
Oklahoma gas assets	1,965	272,700	1,202	1,302,200

Louisiana assets:
Louisiana gas gathering and transmission system	3,010	97,400	3,975	2,050,000
Total Gas Pipelines	10,150	875,000	8,264	5,727,500

NGL, Crude Oil, and Condensate Pipelines
Permian assets:
Victoria Express Pipeline	60	—	90,000	16,400
Permian Basin gathering (4)	455	—	238,500	115,600
Permian Crude Oil and Condensate assets	515	—	328,500	132,000

Oklahoma assets:
Central Oklahoma crude oil gathering systems	175	—	160,000	47,300

Louisiana assets:
Cajun-Sibon NGL pipeline system	760	—	185,000	164,200
Ascension NGL pipeline (5)	35	—	50,000	21,300
Ohio River Valley (6)	210	—	25,650	18,900
Louisiana NGL, Crude Oil, and Condensate assets	1,005	—	260,650	204,400

Total NGL, Crude Oil, and Condensate Pipelines	1,695	—	749,150	383,700

____________________________


(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 Lobo gathering system includes only the Delaware Basin JV’s compression capacity and does not include gas compressed by third parties on our system.


(4)	Estimated capacity is comprised of 188,500 Bbls/d of pipeline capacity and 50,000 Bbls/d of trucking capacity. Our Permian Basin gathering crude and condensate assets include the ECP system, Greater Chickadee system, and Avenger system.


(5)	Includes gross mileage, capacity, and throughput for the Ascension JV, which is owned 50% by us.


(6)	Estimated capacity is comprised of trucking capacity only.

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		Year Ended
		December 31, 2019
Processing Facilities	Processing Capacity (MMcf/d)	Average Throughput (MMBtu/d)
Permian assets:
MEGA system processing facilities	458	467,400
Lobo processing facilities	375	304,000
Permian assets	833	771,400

North Texas assets:
Bridgeport processing facility	800	580,000
Silver Creek processing system (1)	480	170,500
North Texas assets	1,280	750,500

Oklahoma assets:
Central Oklahoma processing facilities	1,245	1,181,900
Northridge processing facility	200	94,800
Oklahoma assets	1,445	1,276,700

Louisiana assets:
Louisiana gas processing facilities (2)	1,778	400,200
Total Processing Facilities	5,336	3,198,800

____________________________


(1)	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.


(2)	The Blue Water, Eunice, and Sabine processing plants are not operational. These plants represent 193 MMcf/d, 350 MMcf/d, and 300 MMcf/d, respectively, of the total processing capacity of the Louisiana gas processing assets.

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		Year Ended
		December 31, 2019
Fractionation Facilities	Estimated NGL Fractionation Capacity (Bbls/d)	Average Throughput (Bbls/d)
Permian assets:
Mesquite terminal (1)	15,000	—

North Texas assets:
Bridgeport processing facility (2)	15,000	—

Louisiana assets:
Plaquemine fractionation facility (3)	125,000	79,200
Plaquemine processing plant	5,000	3,300
Eunice fractionation facility	70,000	58,700
Riverside fractionation facility (3)	—	33,600
Louisiana assets	200,000	174,800

Corporate assets:
Gulf Coast Fractionators (4)	56,000	47,600
Total Fractionation Facilities	286,000	222,400

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(1)	The Mesquite terminal fractionator is not operational.

(2)

Our Bridgeport processing plant in North Texas provides operational flexibility for the related processing plants but are not the primary fractionation facilities for the NGLs produced by the processing plants. Under our current contracts, we do not earn fractionation fees for operating these facilities, so throughput volumes through these facilities are not captured on a routine basis and are not significant to our gross operating margins.


(3)	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 125 MBbls/d.


(4)	Volumes shown reflect our 38.75% ownership in Gulf Coast Fractionators.



		Year Ended
		December 31, 2019
Storage Assets	Storage Type	Estimated Storage Capacity (1)
Permian assets:
Avenger storage	Crude	0.1
VEX storage	Crude	0.2

Oklahoma assets:
Central Oklahoma storage	Crude	0.2

Louisiana assets:
Belle Rose gas storage facility	Gas	11.9
Sorrento gas storage facility	Gas	7.3
Napoleonville NGL storage facility	NGL	6.0
ORV storage	Crude	0.7

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(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.

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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 are connected to our Permian Basin processing assets and 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.


•	Lobo gathering system. This rich natural gas gathering system consists of gathering pipeline and compression assets in the Delaware Basin in Texas and New Mexico. The Lobo gathering system is owned by the Delaware Basin JV.


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

•

Avenger. During 2018, we constructed a new crude oil gathering system in the northern Delaware Basin called Avenger. Avenger 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. We commenced initial operations on Avenger during the third quarter of 2018 and full-service operations during the second quarter of 2019.


•	Greater Chickadee Gathering System. Greater Chickadee was placed into service in March 2017 and delivers crude oil for customers to Enterprise Product Partners L.P.’s crude oil terminal in West Texas. Greater Chickadee also includes multiple central tank batteries with pump, truck injection, and storage stations to maximize shipping and delivery options for producers.

•

VEX. VEX includes a multi-grade crude oil pipeline with terminals in Cuero and the Port of Victoria and barge docks. The Cuero truck unloading terminal at the origin of the VEX system contains unloading bays and above-ground storage capacity for receipt from, and delivery to, the VEX pipeline. The VEX pipeline terminates at the Port of Victoria Terminal, which has an unloading dock and above-ground storage capacity. The Port of Victoria Terminal delivers to two barge loading docks at the Port of Victoria.


•	ECP System. The ECP System includes trucking and crude gathering pipelines in the Midland Basin.


•	Gas Processing Facilities. Our Permian Basin gas processing facilities include six gas processing plants and 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 160 MMcf/d, and the Riptide processing facility with a capacity of 165 MMcf/d.


•	Lobo processing facilities. Our Lobo natural gas processing facilities are located in Loving County, Texas and include Lobo I, Lobo II, and Lobo III, which account for 35 MMcf/d, 140 MMcf/d, and 200 MMcf/d of processing capacity, respectively. The Lobo processing facilities and the connected gathering system 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. We idled the Mesquite fractionator and only operate the condensate stabilizer in the Mesquite terminal, which has a capacity of 5,000 Bbls/d.

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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 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. Devon is the largest customer on the Bridgeport rich gas gathering system contributing substantially all of the natural gas gathered for the year ended December 31, 2019. As described above, we have extended our fixed-fee gathering agreement with Devon, which was effective after the GIP Transaction, and currently have approximately nine years remaining on a fixed-fee gathering agreement with Devon 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 is primarily attributable to Devon and is delivered to the Acacia transmission system and to intrastate pipelines without processing. As described above, we are party to a fixed-fee gathering and processing agreement with Devon that covers gathering services on the Bridgeport system.


•	Johnson County gathering system. 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 four 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 Energy Partners, Energy Transfer Partners, Enterprise Product Partners, and GDF Suez. Devon is the largest customer on the Acacia pipeline with approximately four years remaining on a fixed-fee transportation agreement that covers transmission services and includes annual rate escalators.


•	Gas Processing Facilities. Our gas processing facilities in North Texas include four gas processing plants and consist of the following:

•

Bridgeport processing facility. Our Bridgeport natural gas processing facility, located in Wise County, Texas, approximately 40 miles northwest of Fort Worth, Texas, is one of the largest processing plants in the U.S. with seven cryogenic turboexpander plants. Devon is the Bridgeport facility’s largest customer, providing substantially all of the natural gas processed for the year ended December 31, 2019. We have extended our fixed-fee processing agreement with Devon, which was effective after the GIP Transaction, and currently have approximately nine years remaining on our agreement with Devon pursuant to which we provide processing services for natural gas delivered by Devon 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, which account for 50 MMcf/d, 400 MMcf/d, and 30 MMcf/d of processing capacity, respectively. During 2018, we idled the Azle and Goforth plants due to decreased volumes. 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 gross operating margin.

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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 Oklahoma gas gathering systems consist of the following:


•	Central Oklahoma gathering system. The Central Oklahoma gathering system serves the STACK and CNOW plays. In addition, our contractual arrangement with Devon includes an MVC that will remain in effect until December 2020. For 2020, the MVC dictates that approximately 230 MMcf/d of natural gas will be delivered through the Chisholm gathering system.


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


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

•

Central Oklahoma processing facilities. The Central Oklahoma processing facilities include the Thunderbird Plant, the Chisholm plants, the Battle Ridge plant, and the Cana processing facilities (collectively, the “Central Oklahoma processing system”), which account for 200 MMcf/d, 560 MMcf/d, 85 MMcf/d, and 400 MMcf/d of processing capacity, respectively. The residue natural gas from the Cana processing facility is delivered to Enable Midstream Partners, LP and an affiliate of ONEOK, Inc. (“ONEOK”). The unprocessed NGLs from the Chisholm facilities are transported by ONEOK to NGL transmission lines, which then transport the NGLs to our fractionators in Louisiana. Devon is the primary customer of the Cana processing facilities. We have extended our fixed-fee processing agreement with Devon, which was effective after the GIP Transaction, and currently have approximately nine years remaining on a fixed-fee gathering and processing agreement with us pursuant to which we provide processing services for natural gas delivered by Devon to the Cana processing facility. Additionally, we have a contractual arrangement with Devon on the Chisholm plants that includes an MVC that will remain in effect until December 2020. For 2020, the MVC dictates that approximately 230 MMcf/d of natural gas will be delivered to the Chisholm plant processing facility.


•	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 Oklahoma crude and condensate assets 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.

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 Louisiana gas pipeline system 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.

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


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


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

•

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 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 Assumption Parish, Louisiana. This facility is designed for injecting pipeline quality gas into storage or withdrawing stored gas for delivery by pipeline.


•	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.


•	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. The plant is not expected 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 do not anticipate reopening the plant based on current market conditions.


•	NGL and Crude Oil Pipeline Systems. Our NGL and crude oil pipeline systems 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.

•

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 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

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include eight condensate stabilization and natural gas compression stations that are supported by long-term, fee-based contracts with multiple producers.


•	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.


•	Fractionation Facilities. There are four fractionation facilities located in Louisiana 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 125,000 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.

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. Phillips 66 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.


•	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.

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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 stronger 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 may result in a reduction in our customers’ liquidity and ability to make payments or perform on their obligations to us. Some of our customers have filed for bankruptcy protection, and their debts and payments to us are subject to laws governing bankruptcy.

The following customers individually represented greater than 10% of our consolidated revenues. These customers represent a significant percentage of revenues, and the loss of the customer would have a material adverse impact on our results of operations because the revenues and gross operating margin received from transactions with these customers is material to us. No other customers represented greater than 10% of our consolidated revenues.



	Year Ended December 31,
	2019		2018		2017
Devon	10.5	%	10.4	%	14.4	%
Dow Hydrocarbons and Resources LLC	10.0	%	11.1	%	11.2	%
Marathon Petroleum Corporation	13.8	%	11.5	%	(1)

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(1)	Consolidated revenues for Marathon Petroleum Corporation did not exceed 10% of our consolidated revenues for the year ended December 31, 2017.

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Regulation

Natural Gas Pipeline Regulation. We own an interstate natural gas pipeline that is subject to regulation as a natural gas company by the FERC under the Natural Gas Act (“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.

The cost-of-service rates charged by our FERC regulated natural gas pipeline may also be affected by FERC’s income tax allowance policy, although we do not currently expect to experience any impact to financial results as a result of this policy. In July 2016, the United States Court of Appeals for the District of Columbia Circuit issued its opinion in United Airlines, Inc., et al.v. FERC, finding that FERC had acted arbitrarily and capriciously when it failed to demonstrate that permitting SFPP, L.P., then an interstate petroleum products pipeline organized as a master limited partnership, to include an income tax allowance in the cost of service underlying its rates in addition to the discounted cash flow return on equity would not result in the pipeline double-recovering its investors’ income taxes. The court vacated FERC’s order and remanded to FERC. In March 2018, FERC issued an Order on Remand to SFPP, L.P. and simultaneously issued a revised policy statement disallowing master limited partnerships from recovering both an income tax allowance for the partners’ tax costs and a discounted cash flow return on equity in their cost-of-service rates. The revised policy statement further provides that FERC will address the application of this policy to partnerships and pass-through entities that are not organized as master limited partnerships in subsequent proceedings on a case-by-case basis as the issue arises. In July 2018, FERC dismissed the requests for rehearing of the revised policy statement and provided guidance that if a pipeline organized as a master limited partnership or other pass-through entity eliminates its income tax allowance from its cost of service, FERC anticipates that such pipeline will also remove accumulated deferred income taxes from its cost of service. FERC further required all interstate natural gas pipelines to file a one-time informational filing in 2018 on a new form in order to collect information to evaluate the impact of the 2017 Tax Cuts and Jobs Act and the revised policy statement on such pipelines.

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 amends the NGA and the Natural Gas Policy Act of 1978 (“NGPA”) to give 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 $1.3 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 NGPA (“Section 311”). Pipelines providing transportation service under Section 311 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.

In addition to Section 311 regulation, 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

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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. For the five-year period beginning on July 1, 2016, FERC established an annual index adjustment equal to the change in the producer price index for finished goods plus 1.23%. On October 20, 2016, however, FERC issued an Advance Notice of Proposed Rulemaking indicating that FERC is considering a new policy that would deny proposed index increases for pipelines under certain circumstances where revenues exceed cost-of-service by a certain percentage or where the proposed index increases exceed certain annual cost changes reported to FERC. Under current FERC regulations, liquids pipelines can request a rate increase that exceeds the rate obtained through application of the indexing methodology by using a cost-of-service approach, but only after the pipeline establishes that a substantial divergence exists between the actual costs experienced by the pipeline and the rates resulting from application of the indexing methodology. The cost-of-service rates charged by our interstate liquids pipelines may also be affected by FERC’s revised income tax allowance policy statement discussed above. In addition, FERC intends to incorporate its revised income tax allowance policy as well as the impact of the tax reduction from the Tax Cuts and Jobs Act of 2017 in its next five-year review of the oil pipeline index, which is scheduled to occur in 2020 to establish the index level for the July 1, 2021 to June 30, 2026 time period.

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. We own a number of natural gas pipelines that we believe meet the traditional tests FERC has used to establish that a pipeline is a gathering pipeline and therefore not subject to FERC jurisdiction. The distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of substantial, ongoing litigation, 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.

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Natural Gas Storage Regulation. In December 2016, the DOT’s Pipeline and Hazardous Materials Safety Administration (“PHMSA”) issued an interim final rule (“IFR”) that addresses safety issues related to downhole facilities located at both intrastate and interstate underground storage facilities. The IFR incorporates by reference two of the American Petroleum Institute’s Recommended Practice standards and mandates certain reporting requirements for operators of underground natural gas storage facilities. Under the IFR, all intrastate transportation related underground natural gas storage facilities will become subject to minimum federal safety standards and be inspected by PHMSA or by a state entity that has chosen to expand its authority to regulate these facilities under a certification filed with PHMSA. The IFR became effective on January 18, 2017, with a compliance deadline of January 18, 2018. PHMSA subsequently determined, however, that it will not issue enforcement citations to any operators for violations of provisions of the IFR that had previously been non-mandatory provisions of American Petroleum Institute Recommended Practices 1170 and 1171 until one year after PHMSA issues a final rule. On October 19, 2017, PHMSA formally reopened the comment period on the IFR in response to a petition for reconsideration. On January 13, 2020, PHMSA transmitted a final rule to the Office of the Federal Register for publication. This final rule has not yet been published or made available for public review. However, PHMSA has issued statements indicating that the final rule will be consistent with the December 2016 IFR. We are in compliance with this IFR.

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.

We also operate brine disposal wells that are regulated as Class II wells under the federal Safe Drinking Water Act (“SDWA”). The SDWA imposes requirements on owners and operators of Class II wells through the EPA’s Underground Injection Control program, including construction, operating, monitoring and testing, reporting, and closure requirements. Our brine disposal wells are also subject to comparable state laws and regulations. For more information, see “Environmental Matters” below.

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

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

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

On January 23, 2017, PHMSA published in the Federal Register amendments to the 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 adds 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.

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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.

In October 2019, PHMSA issued three new final rules. One rule 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 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.

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

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 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

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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, 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.

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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.

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. However, should the area fail to attain this standard by its marginal attainment date of August 2021, it risks reclassification to moderate, 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. This new standard is being challenged in a pending appeal before the U.S. Court of Appeals for the D.C. Circuit, but if the standard is implemented, it 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.

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 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 recently finalized new rules that took effect August 2, 2016 to regulate emissions of methane and VOCs from new and modified sources in the oil and gas sector under the NSPS. In October 2018, and pursuant to its reconsideration, the EPA proposed a rule that would amend certain requirements of the NSPS standard. In August 2019, EPA published a rule proposing to reconsider certain aspects of both the 2012 and 2016 rules. This proposed rule would remove sources in the transmission and storage segments from the regulated source category and would rescind the application of the NSPS and methane-specific requirements to these sources. The rule remains in effect pending reconsideration. Depending on the outcome of such proceedings, the rules may be further modified or rescinded, or the EPA may issue new rules. We cannot predict the costs of compliance with any modified or newly issued rules.

In 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 on November 15, 2016, to be effective on January 17, 2017, to reduce venting, flaring, and leaks during oil and natural gas production activities on onshore federal and Indian leases. Certain provisions of the BLM rule went into effect in January 2017, while the effective date of others was delayed until 2019 pending reconsideration. In September 2018, BLM published a final rule that rescinded several requirements

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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. The challenge is still pending. 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 Trump 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, 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. Due to the Paris Agreement’s protocol, the withdrawal will be effective in November 2020. There are no guarantees that the agreement will not be re-implemented in the U.S., or re-implemented in part by specific U.S. states or local governments. 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

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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 January 2020, EPA and USACE promulgated a new 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 October 2019 final rule to repeal the 2015 WOTUS definition are currently before multiple federal district courts and challenges to EPA’s January 2020 rule are anticipated. If the October 2019 final rule is vacated and the expanded scope of jurisdiction in the 2015 rule is ultimately implemented, or to the extent that any future rules expand the scope of the Clean Water Act's jurisdiction, 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 Elimination System (“NPDES”) permits and/or state permits authorizing these discharges. The Clean Water Act and analogous state laws assess administrative, civil, and criminal penalties for discharges of unauthorized pollutants into the water and impose substantial liability for the costs of removing spills from such waters. In addition, the Clean Water Act and analogous state laws require that individual permits or coverage under general permits be obtained by covered facilities for discharges of storm water runoff. We believe that we are in substantial compliance with Clean Water Act permitting requirements as well as the conditions imposed by our permits and that continued compliance with such existing permit conditions will not have a material effect on our financial condition, results of operations, or cash flows.

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 rules that took effect October 1, 2012. These rules set new, more stringent standards for the permitting and operating of brine disposal wells, including extensive review of geologic data and use of state-of-the-art technology. The Ohio Department of Natural Resources also imposes requirements on the transportation and disposal of brine. Compliance with current and future laws and regulations regarding our brine disposal wells may impose substantial costs and restrictions on our brine disposal operations, as well as adversely affect demand for our brine disposal services. State and federal regulatory agencies recently have focused on a possible connection between the operation of injection wells used for oil and gas waste waters and an observed increase in minor seismic activity and tremors. When caused by human activity, such events are called induced seismicity. In a few instances, operators of injection wells in the vicinity of minor seismic events have reduced injection volumes or suspended operations, often voluntarily. A 2012 report published by the National Academy of Sciences concluded that only a very small fraction of the tens of thousands of injection wells have been suspected to be, or have been, the likely cause of induced seismicity. However, some state regulatory agencies have modified their regulations to account for induced seismicity. For example, TRRC rules allow the TRRC to modify, suspend, or terminate a permit based on a determination that the permitted activity is likely to be contributing to seismic activity. In the state of Ohio, the Ohio Department of Natural Resources (“ODNR”) 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

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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. This rescission is subject to pending challenges in federal courts. 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 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 occupy approximately 157,600 square feet of space at our executive offices in Dallas, Texas under a lease expiring in February 2030. We also occupy office space of approximately 56,000 square feet in Midland, Texas, 32,000 square feet in Houston, Texas under long-term leases, and various other locations to support our operations.

Employees

As of December 31, 2019, we (through our subsidiaries) employed 1,355 full-time employees. Of these employees, 296 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.

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. 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.

Risks Inherent in our Business

We are dependent on Devon for a substantial portion of the natural gas that we gather, process, and transport. The expiration of a five-year MVC from Devon in December 2020 will result in a decline in our operating results and cash available for distribution because the volumes of natural gas that we gathered, processed, and transported for Devon during 2019 have been below the MVC levels under this contract.

We are dependent on Devon for a substantial portion of our natural gas supply. For the year ended December 31, 2019, Devon represented approximately 29.9% of our gross operating margin. In order to minimize volumetric exposure, we entered into an agreement providing a five-year MVC from Devon at the Chisholm processing facility and gathering system, which expires in December 2020. For the year ended December 31, 2019, we recognized $10.3 million in MVC shortfall revenue from Devon attributable to this MVC agreement because volumes were below the minimum level. In 2020, this expiring MVC agreement is projected to generate approximately $55-$65 million of shortfall revenue. In 2021, if volumes under the MVC agreement do not increase or we are unable to replace the shortfall revenue from other sources, our operating results and cash flows would be adversely affected.

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Because we are substantially dependent on Devon for a significant portion of our gross operating margin, any development that materially and adversely affects their operations, financial condition, or market reputation could have a material and adverse impact on us. Material adverse changes for Devon could restrict our access to capital, make it more expensive to access the capital markets, or increase the costs of our borrowings.

We expect to derive a significant portion of our gross operating margin from Devon 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. Accordingly, we are indirectly subject to the business risks of our significant customers, some of which are the following:


•	potential changes in the supply of and demand for oil, natural gas and NGLs. and related products and services;


•	risks relating to exploration and drilling programs, including potential environmental liabilities;


•	adverse effects of governmental and environmental regulation; and


•	general economic and financial market conditions.

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

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. In recent periods, we have seen suppressed drilling activity due to low commodity prices, which has resulted in lower volumes in some of the basins in which we operate. 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

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principal geographic areas for a prolonged period, as a result of unfavorable commodity prices or otherwise, likely would have a material adverse effect on our financial condition, results of operations, and cash flows.

Any 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;


•	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;


•	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 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.

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

GAAP requires us to test goodwill and intangible assets with indefinite useful lives for impairment on an annual basis or when events or circumstances occur indicating that goodwill might be impaired. Long-lived assets, including intangible assets with finite useful lives, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. For the investments we account for under the equity method, the impairment test considers whether the fair value of the unconsolidated affiliate investment as a whole, not the underlying net assets, has declined and whether that decline is other than temporary. If we determine that an impairment is indicated, we would be required to take an immediate non-cash charge to earnings with a correlative effect on equity and balance sheet leverage as measured by debt to total capitalization. We have recognized goodwill impairments and impairments on property and equipment in the past, including the $190.3 million of goodwill impairments taken during 2019. See “Item 8. Financial Statements and Supplementary Data—Note 3” for more information about impairment of goodwill and long-lived assets. Additional impairment of the value of our existing goodwill and long-lived assets could have a significant negative impact on our future operating results.

Our construction of new assets may be more expensive than anticipated, may not result in revenue increases, and may be subject to regulatory, environmental, political, legal, and economic risks that could adversely affect our financial condition, results of operations, or cash flows.

The construction of additions or modifications to our existing systems and the construction of new midstream assets involves numerous regulatory, environmental, political, and legal uncertainties beyond our control including potential protests or legal actions by interested third parties, and may require the expenditure of significant amounts of capital. Financing may not be available on economically acceptable terms or at all. If we undertake these projects, we may not be able to complete them on schedule, at the budgeted cost, or at all. Moreover, our revenues may not increase due to the successful construction of a particular project. For instance, if we expand a pipeline or construct a new pipeline, the construction may occur over an

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extended period of time, and we may not receive any material increases in revenues promptly following completion of a project or at all. Moreover, we may construct facilities to capture anticipated future production growth in a region in which such growth does not materialize. As a result, new facilities may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our financial condition, results of operations, or cash flows. In addition, the construction of additions to our existing gathering and processing assets will generally require us to obtain new rights-of-way and permits prior to constructing new pipelines or facilities. We may be unable to timely obtain such rights-of-way or permits to connect new product supplies to our existing gathering lines or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for us to obtain new rights-of-way or to expand or renew existing rights-of-way. If the cost of renewing or obtaining new rights-of-way increases, our cash flows could be adversely affected.

Construction of our major development projects subjects us to risks of construction delays, cost over-runs, limitations on our growth, and negative effects on our financial condition, results of operations, or cash flows.

We are engaged in the planning and construction of several major development projects, some of which will take a number of months before commercial operation. These projects are complex and subject to a number of factors beyond our control, including delays from vendors, suppliers, and third-party landowners, the permitting process, changes in laws, unavailability of materials, labor disruptions, environmental hazards, financing, accidents, weather, and other factors. Any delay in the completion of these projects could have a material adverse effect on our financial condition, results of operations, or cash flows. The construction of pipelines and gathering and processing and fractionation facilities requires the expenditure of significant amounts of capital, which may exceed our estimated costs. Estimating the timing and expenditures related to these development projects is very complex and subject to variables that can significantly increase expected costs. Should the actual costs of these projects exceed our estimates, our liquidity and capital position could be adversely affected. This level of development activity requires significant effort from our management and technical personnel and places additional requirements on our financial resources. We may not have the ability to attract and/or retain the necessary number of personnel with the skills required to bring complicated projects to successful conclusions.

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, 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.

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

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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 August 2019, EPA published a rule proposing to reconsider certain aspects of both the 2012 and 2016 rules. This proposed rule would remove sources in the transmission and storage segments from the regulated source category and would rescind the application of the NSPS and methane-specific requirements to these sources. However, the rule remains in effect pending reconsideration, along with the restriction on discharges to publicly owned wastewater treatment plants. The BLM also adopted new rules, effective on January 17, 2017, to reduce venting, flaring and leaks during oil and natural gas production activities on onshore federal and Indian leases. 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. The challenge is still pending.

In addition, certain candidates in the 2020 U.S. presidential campaign have declared that they 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. A new presidential 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 Agreement. Due to the Paris Agreement’s protocol, the withdrawal will be effective in November 2020. There are no guarantees that the agreement will not be re-implemented in the U.S. or re-implemented in part by specific U.S. states or local governments. 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.

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., including climate change related pledges made by certain candidates in the U.S. presidential campaign. These pledges 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. A new presidential administration could also pursue the imposition of more restrictive requirements for the establishment of pipeline infrastructure or the permitting of LNG export facilities.

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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 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.

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.

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

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

Any reductions in 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. Fitch Ratings, S&P, and Moody’s have currently assigned a BBB-, BB+, and Ba1 credit rating, respectively, to ENLK and ENLC. In August 2019, Fitch Ratings announced that it had revised its rating outlook for both ENLK and ENLC to negative from stable. 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.

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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.

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, 2019, approximately 7% of our total gross operating margin was generated under percent of liquids contracts and percent of proceeds contracts, with most of these contracts relating to our processing plants in the Permian Basin. Under percent of liquids contracts, we receive a fee in the form of a percentage of the liquids recovered, and the producer bears all the cost of the natural gas shrink. Accordingly, our revenues under percent of liquids contracts are directly impacted by the market price of NGLs. Gross operating margin under percent of proceeds contracts is impacted only by the value of the natural gas or liquids produced with margins higher during periods of higher natural gas and liquids prices.

We also realize gross operating margins under processing margin contracts. For the year ended December 31, 2019, less than 1% of our total gross operating margin was generated under processing margin contracts. We have a number of processing margin contracts for activities at our Plaquemine and Pelican processing plants. Under this type of contract, we pay the producer for the full amount of inlet gas to the plant, and we make a margin based on the difference between the value of liquids recovered from the processed natural gas as compared to the value of the natural gas volumes lost (“shrink”) and the cost of fuel used in processing. The shrink and fuel losses are referred to as plant thermal reduction (“PTR”). Our margins from these contracts can be greatly reduced or eliminated during periods of high natural gas prices relative to liquids prices.

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

Although the majority of our NGL fractionation business is under fee-based arrangements, a portion of our business is exposed to commodity price risk because we realize a margin due to product upgrades associated with our Louisiana fractionation business. For the year ended December 31, 2019, gross operating margin realized associated with product upgrades represented less than 1% of our gross operating margin.

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Commodity prices were volatile during 2019 and the prices for natural gas and natural gas products declined. Crude oil prices increased 31% while weighted average NGL prices and natural gas prices decreased 25% and 26%, respectively, from January 1, 2019 to December 31, 2019. In February 2020, natural gas prices reached a low of $1.77 per MMBtu, which was the lowest price since March 2016. We expect continued volatility in these commodity prices. For example, crude oil prices (based on the NYMEX futures daily close prices for the prompt month) in 2019 ranged from a high of $66.30 per Bbl in April 2019 to a low of $46.54 per Bbl in January 2019. Weighted average NGL prices in 2019 (based on the Oil Price Information Service (“OPIS”) Napoleonville daily average spot liquids prices) ranged from a high of $0.56 per gallon in February 2019 to a low of $0.25 per gallon in July 2019. Natural gas prices (based on Gas Daily Henry Hub closing prices) during 2019 ranged from a high of $3.59 per MMBtu in January 2019 to a low of $2.07 per MMBtu in August 2019.

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 coronavirus outbreak;


•	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 gross operating margin and cash flows to vary widely from period to period. Our hedging strategies may not be sufficient to offset price volatility risk and, in any event, do not cover all of our throughput volumes. Moreover, hedges are subject to inherent risks, which we describe in “Item 7A. Quantitative and Qualitative Disclosure about Market Risk.” Our use of derivative financial instruments does not eliminate our exposure to fluctuations in commodity prices and interest rates and has (in the past) resulted and could (in the future) result in financial losses or reductions in our income.

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

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

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

We continue to have the ability to incur debt, subject to limitations in the Consolidated Credit Facility and the Term Loan. 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 and future business opportunities 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 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.

The terms of the Consolidated Credit Facility, Term Loan, and indentures governing ENLC’s senior notes and our 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 Term Loan, and the indentures governing ENLC’s senior notes and our 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 and the Term Loan require ENLC to satisfy and maintain specified financial ratios. ENLC’s ability to meet these financial ratios can be affected by events beyond its control, and we cannot assure you that ENLC will continue to meet these ratios.

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

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 Term Loan currently bear interest at rates based on the London Interbank Offered Rate (“LIBOR”). Interest charged to ENLK for borrowings made through the related party debt arrangement are substantially the same as interest charged to ENLC on borrowings under the Consolidated Credit Facility and the Term Loan. On July 27, 2017, the Financial Conduct Authority in the United Kingdom announced that it would phase out

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LIBOR as a benchmark by the end of 2021. It is unclear whether new methods of calculating LIBOR will be established such that it continues to exist after 2021. The Consolidated Credit Facility and the Term Loan include a mechanism to amend the facilities to reflect the establishment of an alternative rate of interest upon the occurrence of certain events related to the phase-out of LIBOR. However, we have not yet pursued any technical amendment or other contractual alternative to address this matter and are currently evaluating the impact of the potential replacement of LIBOR. If no such amendment or other contractual alternative is established on or prior to the phase-out of LIBOR, interest under the Consolidated Credit Facility and Term Loan 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.

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

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


•	adverse weather conditions, including hurricanes and tropical storms;


•	delays or decreases in production, the availability of equipment, facilities, or services; and


•	changes in the regulatory environment.

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

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

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

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

In addition, we rely on the volumes of natural gas, crude oil, condensate, and NGLs gathered, processed, fractionated, and transported on our assets. These volumes are influenced by the production from the regions that supply our systems. Adverse weather conditions can cause direct or indirect disruptions to the operations of, and otherwise negatively affect, producers, suppliers, customers, and other third parties to which our assets are connected, even if our assets are not damaged. As a result, our financial condition, results of operations, and cash flows could be adversely affected.

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

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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.

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

If we expand our operations into new geographic areas, we expect to encounter significant competition for natural gas, condensate, NGLs, and crude oil supplies and markets. Competitors in these new markets will include companies larger than us, which have both lower cost of capital and greater geographic coverage, as well as smaller companies, which have lower total cost structures. As a result, we may not be able to successfully develop greenfield or acquire assets located in new geographic areas, and our results of operations could be adversely affected.

We do not own 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

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right-of-way contracts, leases, or otherwise, could cause us to cease operations on the affected land, increase costs related to continuing operations elsewhere, and reduce our revenue.

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

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

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

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

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

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

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

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

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


•	the inability to integrate the operations of recently acquired businesses or assets, especially if the assets acquired are in a new business segment or geographic area;


•	the diversion of management’s attention from other business concerns;


•	the failure to realize expected volumes, revenues, profitability, or growth;


•	the failure to realize any expected synergies and cost savings;


•	the coordination of geographically disparate organizations, systems, and facilities;


•	the assumption of unknown liabilities;


•	the loss of customers or key employees from the acquired businesses;


•	a significant increase in our indebtedness; and


•	potential environmental or regulatory liabilities and title problems.

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

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

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

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

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

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

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

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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 $1.3 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.

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.

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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 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 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.

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 $3.1 million, $1.8 million, and $2.3 million for the years ended December 31, 2019, 2018, and 2017, 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,

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including, for example, legislation relating to the control of greenhouse gas emissions, or changes in existing environmental laws or regulations might adversely affect our products and activities, including processing, storage, and transportation, as well as waste management and air emissions. Federal and state agencies could also impose additional safety requirements, any of which could affect our profitability. Changes in laws or regulations could also limit our production or the operation of our assets or adversely affect our ability to comply with applicable legal requirements or the demand for crude oil, brine disposal services, or natural gas, which could adversely affect our business and our profitability.

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

We are subject to stringent and complex regulation under the federal Clean Air Act, implementing regulations, and state and local equivalents, including regulations related to controls for oil and natural gas production, pipelines, and processing operations. For instance, the EPA finalized new rules, effective August 2, 2016, to regulate emissions of methane and volatile organic compounds from new and modified sources in the oil and gas sector. In August 2019, EPA published a rule proposing to reconsider certain aspects of the 2016 rule. This proposed rule would remove sources in the transmission and storage segments from the regulated source category and would rescind the application of the NSPS and methane-specific requirements to these sources. The rule remains in effect pending reconsideration. The 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 on November 15, 2016, effective January 17, 2017, to reduce venting, flaring, and leaks during oil and natural gas production activities on onshore federal and Indian leases. Certain provisions of the BLM rule went into effect in January 2017, while others were scheduled to go into effect in January 2018. In December 2017, BLM published a final rule delaying the 2018 provisions until 2019. In September 2018, BLM published a final rule to repeal certain requirements of the 2016 methane rule. The September 2018 rule was challenged in the U.S. District Court for the Northern District of California almost immediately after issuance. The challenge is still pending.

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.

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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.

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

Comprehensive financial reform legislation was signed into law by the President on July 21, 2010. The legislation calls for the Commodities Futures Trading Commission (“CFTC”) to regulate certain markets for derivative products, including over-the-counter (“OTC”) derivatives. The CFTC has issued several 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.

In particular, on October 18, 2011, the CFTC adopted final rules under the Dodd-Frank Act establishing position limits for certain energy commodity futures and options contracts and economically equivalent swaps, futures and options. The position limit levels set the maximum amount of covered contracts that a trader may own or control separately or in combination, net long or short. The final rules also contained limited exemptions from position limits which would be phased in over time for certain bona fide hedging transactions and positions. The CFTC’s original position limits rule was challenged in court by two industry associations and was vacated and remanded by a federal district court. The CFTC proposed new rules in January 2020 (withdrawing previously proposed rules from November 2013 and December 2016) that would place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. The CFTC sought comment on the position limits rules as reproposed and revised, but the new rules have not yet been issued in final form, and the impact of any final provisions on us is uncertain at this time.

The legislation and potential new regulations may also require counterparties to our derivative instruments to spin off 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.

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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 Term Loan 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, 2019, 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 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 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. Any failure of our computer systems, or those of our customers, suppliers, or others with whom we do business, could materially disrupt our ability to operate our business. Unknown entities or groups have mounted so-called “cyberattacks” on businesses to disable or disrupt computer systems, disrupt operations, and steal funds or data including through so-called “phishing” schemes. Cyberattacks could also result in the loss of confidential or proprietary data or security breaches of other information technology systems that could disrupt our operations and critical business functions. In addition, our assets may be targets of terrorist activities that could disrupt our ability to conduct our business and have a material adverse effect on our business and results of operations. Strategic targets, such as energy-related assets, may be at greater risk of future terrorist or cyberattacks than other targets in the United States. Our insurance may not protect us against such occurrences. Any such terrorist or cyberattack that affects us or our customers, suppliers, or others with whom we do business could have a material adverse effect on our business, cause us to incur a material financial loss, subject us to possible legal claims and liability, and/or damage our reputation.

Moreover, as 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. We cannot predict the potential impact to our business or the energy industry resulting from additional regulations.

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.

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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. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to the new employees, or the future availability and cost of contract labor may adversely affect our ability to manage and operate our business. If we are unable to successfully attract and retain an appropriately qualified workforce, our results of operations could be negatively affected.

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

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

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

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

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Risks Inherent in an Investment in the Partnership

GIP, through its control of ENLC, controls our general partner, which has sole responsibility for conducting our business and managing our operations. GIP may have conflicts of interest with us, has limited duties to us, and may favor GIP’s interests to the detriment of, our unitholders.

GIP, through its control of ENLC, controls our general partner and indirectly has the power to appoint all of the officers and directors of our general partner. Conflicts of interest may arise in the future among GIP and its affiliates, including our general partner, on the one hand, and our partnership and our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and those of its affiliates, including GIP and ENLC, over our interests. Subject to certain limitations, our partnership agreement limits our general partner’s liability and reduces its fiduciary duties, while also restricting the remedies available to our unitholders for actions that might, without these limitations, constitute breaches of fiduciary duty by our general partner.

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 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 partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner, its executive officers, or any of its affiliates, including GIP. 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 limited partner 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 distributable cash flow. This may create actual and potential conflicts of interest between us and affiliates of our general partner and result in less than favorable treatment of us and our unitholders.

GIP has pledged all of the equity interests that it owns in ENLC and ENLC’s 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 our general partner.

GIP has pledged all of the equity interests that it owns in ENLC and ENLC’s 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 our general partner and would allow the new owner of our general partner to replace the board of directors and officers of our general partner with its own designees and to control the decisions taken by the board of directors and officers. Moreover, any change of control of our general partner would permit the lenders under ENLC’s Consolidated Credit Facility and Term Loan 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 partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.

Unitholders’ voting rights are further restricted by the partnership agreement, which provides that, other than Enfield with respect to the Series B Preferred Units, any units held by a person that owns 20% or more of any class of units, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of the general partner, cannot vote on any matter.

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The control of our general partner may be transferred to a third party without unitholder consent.

Our general partner may transfer its general partner 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, there is no restriction in the partnership agreement on the ability of (i) ENLC to transfer all or a portion of its ownership interest in our general partner to a third party or (ii) GIP to transfer all or a portion of its ownership interest in ENLC and/or ENLC’s manager to a third party. The new owner of our general partner or ENLC’s manager, as the case may be, would then be in a position to replace the board of directors and officers of our general partner with its own choices and to control the decisions taken by the board of directors and officers.

Our partnership agreement replaces the fiduciary duties otherwise owed to our unitholders by our general partner with contractual standards governing its duties and restricts the remedies available to our unitholders for actions that might otherwise constitute a breach of fiduciary duty by our general partner.

Our partnership agreement contains provisions that eliminate and replace the fiduciary standards that our general partner would otherwise be held to by state fiduciary duty law. For example, our partnership agreement permits our general partner to make a number of decisions, in its individual capacity, as opposed to in its capacity as our general partner, or otherwise, free of fiduciary duties to our unitholders. This entitles our general partner 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, our unitholders. Examples of decisions that the general partner may make in its individual capacity include:


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


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


•	whether or not the general partner should elect to seek the approval of the unitholders in connection with any conflicted transaction.

The partnership agreement also restricts the remedies available to our unitholders for actions that would otherwise constitute breaches of our general partner’s fiduciary duties.

We may issue additional units, including units that are pari passu with our Series C Preferred Units, without the approval of the holders of the Series C Preferred Units.

We may issue an unlimited number of limited partner interests in parity with the Series C Preferred Units without any vote of the holders of the Series C Preferred Units (except where the cumulative distributions on the Series C Preferred Units or any parity securities are in arrears and in certain other circumstances).

Additionally, although holders of the Series C Preferred Units are entitled to limited voting rights, with respect to certain matters the Series C Preferred Units generally vote separately as a class along with all other series of our parity securities that we may issue with respect to which like voting rights have been conferred and are exercisable. As a result, the voting rights of holders of Series C Preferred Units may be significantly diluted, and the holders of such other series of parity securities that we may issue may be able to control or significantly influence the outcome of any vote. The issuance of additional units on parity with or senior to the Series C Preferred Units would dilute the interests of the holders of the Series C Preferred Units, and any issuance of equity securities of any class or series that ranks on parity with the Series C Preferred Units as to the payment of distributions and amounts payable upon a liquidation event or additional indebtedness could affect our ability to pay distributions on, redeem, or pay the liquidation preference on the Series C Preferred Units.

Future issuances and sales of parity securities, or the perception that such issuances and sales could occur, may cause prevailing market prices for the Series C Preferred Units to decline and may adversely affect our ability to raise additional capital in the financial markets at times and prices favorable to us.

Our outstanding equity and debt securities are not listed on the NYSE or any other national securities exchange and, as a result, we are not obligated to comply with any exchange listing requirements.

Our outstanding equity and debt securities are not listed on the NYSE or any other national securities exchange, which means that we are exempt from any exchange listing requirements.

For so long as we do not have securities listed on a national securities exchange, we will not be required to have a majority of independent directors, an independent audit committee, or nominating, corporate governance, or compensation committees.

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Accordingly, you may not have the same protections afforded to stockholders of companies that are subject to the corporate governance requirements of a national securities exchange.

Our unitholders may not have limited liability if a court finds that unitholder action constitutes control of our business.

Our unitholders could be held liable for our obligations to the same extent as a general partner if a court determined that the right or the exercise of the right by our unitholders to remove or replace our general partner, to approve amendments to our partnership agreement, or to take other action under our partnership agreement constituted participation in the “control” of our business, to the extent that a person who has transacted business with the Partnership reasonably believes, based on our unitholders’ conduct, that our unitholders are a general partner. Our general partner generally has unlimited liability for the obligations of our partnership, such as its debts and environmental liabilities, except for those contractual obligations of our partnership that are expressly made without recourse to our general partner. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business.

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 Section 17-607 of the Revised Uniform Limited Partnership Act (“the Delaware Act”), a limited partnership cannot make a distribution to its limited partners if, after the distribution, all liabilities, other than liabilities to unitholders on account of their limited partner interests and liabilities for which the recourse of creditors is limited to specific property of the limited partnership, would exceed the fair value of the assets of the limited partnership. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act 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 partnership only to the extent that the fair value of that property exceeds the non-recourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act will be liable to the limited partnership for the amount of the distribution for three years from the date of distribution.

Tax Risks to Our Unitholders

Our tax treatment and our being subject to entity level taxation by individual states depends on our status as a partnership for federal income tax purposes. If the IRS treats us as a corporation or we become subject to entity level taxation for state tax purposes, it would substantially reduce the amount of cash available for distribution.

The anticipated after-tax economic benefit of an investment in us depends largely on our being treated as a partnership for federal income tax purposes.

If we were treated as a corporation for federal income tax purposes, we would pay additional tax on our income at corporate rates of up to 21% for taxable years beginning on or after January 1, 2018 (under the law as of the date of this report), and 35% to the extent we were treated as a corporation in any taxable years ending prior to January 1, 2018, and we would probably pay state income taxes as well. In addition, distributions to unitholders would generally be taxed again as corporate distributions. Because a tax would be imposed upon us as a corporation, our cash available for distribution would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in our anticipated cash flow.

Moreover, changes in current state law may subject us to entity-level taxation by individual states. Because of widespread state budget deficits, several states are evaluating ways to subject partnerships to entity level taxation through the imposition of state income, franchise and other forms of taxation. For example, we are required to pay Texas franchise tax at a maximum effective rate of 0.75% of our taxable margin apportioned to Texas in the prior year. If additional state tax were to be imposed on us, the cash available for distribution could be reduced.

If the IRS makes audit adjustments to our income tax returns for tax years beginning after 2017, it may collect any resulting taxes (including any applicable penalties and interest) directly from us, in which case our cash available for distribution might be substantially reduced.

If the IRS makes audit adjustments to income tax returns for tax years beginning after 2017, it may assess and collect taxes (including any applicable penalties and interest) directly from us, unless we are eligible to (and choose to) elect to push out those audit adjustments to those persons who were our unitholders during the tax period subject to such audit adjustments. If we make payments of taxes, penalties and interest resulting from audit adjustments, our cash available for distribution might be

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substantially reduced. In addition, because payment would be due for the taxable year in which the audit is completed, unitholders during that taxable year would bear the expense of the adjustment even if they were not unitholders during that taxable year.

Treatment of distributions on our Series C Preferred Units as guaranteed payments for the use of capital is uncertain.

The tax treatment of distributions on our Series C Preferred Units is uncertain. We will treat the holders of Series C Preferred Units as partners for tax purposes and will treat distributions on the Series C Preferred Units as guaranteed payments for the use of capital that will generally be taxable to the holders of Series C Preferred Units as ordinary income. Although a holder of Series C Preferred Units could recognize taxable income from the accrual of such a guaranteed payment even in the absence of a contemporaneous distribution, we anticipate accruing and making the guaranteed payment distributions semi-annually on the 15th day of June and December through and including December 15, 2022 and, thereafter, quarterly on the 15th day of March, June, September and December of each year. Because the guaranteed payment for each unit must accrue as income to a holder during the taxable year of the accrual, the guaranteed payment attributable to the period beginning December 15 and ending December 31 will accrue as income to the holder of record of a Series C Preferred Unit on December 31 for such period, regardless of whether such holder continues to own the Series C Preferred Unit at the time the actual distribution is made. Otherwise, the holders of Series C Preferred Units are generally not anticipated to share in our items of income, gain, loss or deduction, nor will we allocate any share of our nonrecourse liabilities to the holders of Series C Preferred Units. If the Series C Preferred Units were treated as indebtedness for tax purposes, rather than as guaranteed payments for the use of capital, distributions likely would be treated as payments of interest by us to the holders of Series C Preferred Units.

Tax-exempt entities and non-U.S. persons face unique issues from owning our Series C Preferred Units which may result in adverse tax consequences to them.

Investment in the Series C Preferred Units by tax-exempt investors, such as employee benefit plans and individual retirement accounts (“IRAs”), and non-U.S. persons raises issues unique to them. Although the issue is not free from doubt, we will treat distributions to non-U.S. holders of Series C Preferred Units as “effectively connected income” subject to withholding taxes. If the amount of withholding exceeds the amount of U.S. federal income tax actually due, non-U.S. holders of Series C Preferred Units may be required to file U.S. federal income tax returns in order to seek a refund of such excess. The treatment of guaranteed payments for the use of capital to tax-exempt investors is not certain and such payments may be treated as unrelated business taxable income for federal income tax purposes. If you are a tax-exempt entity or a non-U.S. person, you should consult your tax advisor with respect to the consequences of owning our Series C Preferred Units.

The tax treatment of an investment in our Series C Preferred Units could be subject to potential legislative, judicial, or administrative changes and differing interpretations, possibly on a retroactive basis.

The present federal income tax treatment of an investment in our Series C Preferred Units may be modified by administrative, legislative or judicial interpretation at any time. For example, from time to time, the President and members of Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships, including elimination of partnership tax treatment for publicly traded partnerships. Any modification to the federal income tax laws and interpretations thereof may or may not be retroactively applied and could make it more difficult or impossible for us to meet the requirements that must be satisfied in order for us to be treated as a partnership for federal income tax purposes.

We are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes could negatively impact the value of an investment in our Series C Preferred Units.

Entity level taxes on income from our C corporation subsidiary will reduce cash available for distribution.

A portion of our taxable income is earned through a C corporation subsidiary. Such C corporation subsidiary is subject to federal income tax on its taxable income at the corporate tax rate, which is currently a maximum of 21%, and will likely pay state (and possibly local) income tax at varying rates, on its taxable income. Any such entity level taxes will reduce our cash available for distribution.

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Holders of Series C Preferred Units may be subject to state and local taxes and return filing or withholding requirements in jurisdictions where they do not live.

In addition to federal income taxes, holders of Series C Preferred Units may be subject to other taxes such as state and local income taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property. Holders of Series C Preferred Units also may be required to file state and local tax returns and pay state and local income taxes in some or all of the various jurisdictions in which we do business or own property and may be subject to penalties for failure to comply with those requirements. We own property or conduct business in a number of states, most of which currently impose a state income tax on individuals. Most of these states also impose an income tax on corporations and other entities. As we make acquisitions or expand our business, we may do business or own property in other states that impose an income tax. It is our unitholders’ responsibility to file all federal, state, local, and foreign tax returns. Under the tax laws of some states where we will conduct business, we may be required to withhold a percentage from amounts to be distributed to a unitholder who is not a resident of that state.

A unitholder whose Series C Preferred Units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units.

A holder of Series C Preferred Units whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of the loaned units and, thus, may recognize gain or loss from such disposition. Our counsel has not rendered an opinion regarding the treatment of a unitholder where Series C Preferred Units are loaned to a short seller to cover a short sale of Series C Preferred Units; therefore, unitholders desiring to avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

Compliance with and changes in tax law could adversely affect our performance.

We are subject to extensive tax laws and regulations, including federal and state income taxes and transactional taxes such as excise, sales/use, payroll, franchise and ad valorem taxes. New tax laws and regulations and changes in existing tax laws and regulations are continuously being enacted that could result in increased tax expenditures in the future. Many of these tax liabilities are subject to audits by the respective taxing authority. These audits may result in additional taxes as well as interest and penalties.

Item 1B. Unresolved Staff Comments

We do not have any unresolved staff comments.

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 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. Except as otherwise set forth herein, we do not

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believe that any pending or threatened claim or dispute is material to our financial condition, results of operations, or cash flows. We maintain insurance policies with insurers in amounts and with coverage and deductibles that our general partner believes are reasonable and prudent. However, we cannot assure you that this insurance will be adequate to protect us from all material expenses related to potential future claims for personal and property damage or that these levels of insurance will be available in the future at economical prices.

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

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 and Related Unitholder Matters.

Subsequent to the closing of the Merger, ENLC owns 100% of ENLK’s 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.”

We will distribute all of our available cash, as defined in our partnership agreement, to ENLC, as the holder of all of our common units. Our available cash consists generally of all cash on hand at the end of any fiscal quarter or other applicable period plus all cash on hand on the date of determination resulting from working capital borrowings made after the end of such applicable period, less reserves that our general partner determines are necessary to:


•	properly conduct our business;


•	comply with applicable law, our debt instruments, or other agreements; and


•	provide funds for distributions to the holders of the Series B Preferred Units and the Series C Preferred Units.

Our general partner has broad discretion to establish cash reserves that it determines are necessary or appropriate to properly conduct our business. These can include cash reserves for future capital and maintenance expenditures, reserves to stabilize distributions of cash to the unitholders and our general partner, reserves to reduce debt or, as necessary, reserves to comply with the terms of any of our agreements or obligations.

Item 6. Selected Financial Data

The following tables present our selected historical financial and operating data of ENLK for the periods indicated. Financial and operating data for the years ended December 31, 2019, 2018, 2017, 2016, and 2015 reflect acquisitions and dispositions for periods subsequent to the applicable transaction date. The selected historical financial data should be read together with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements and accompanying notes in “Item 8. Financial Statements and Supplementary Data.”

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	EnLink Midstream Partners, LP
	Year Ended December 31,
	2019			2018			2017			2016			2015
	(In millions, except per unit data)
Revenues:
Product sales	$	5,030.1		$	6,512.3		$	4,358.4		$	3,008.9		$	3,253.7
Product sales—related parties	—			41.0			144.9			134.3			119.4
Midstream services	1,008.4			763.3			552.3			467.2			451.0
Midstream services—related parties	—			377.2			688.2			653.1			618.6
Gain (loss) on derivative activity	14.4			5.2			(4.2		)	(11.1		)	9.4
Total revenues	6,052.9			7,699.0			5,739.6			4,252.4			4,452.1
Operating costs and expenses:
Cost of sales (1)	4,392.5			6,008.0			4,361.5			3,015.5			3,245.3
Operating expenses	467.1			453.4			418.7			398.5			419.9
General and administrative	139.2			130.2			123.5			119.3			132.4
(Gain) loss on disposition of assets	(1.9		)	0.4			—			13.2			1.2
Depreciation and amortization	617.0			577.3			545.3			503.9			387.3
Impairments	198.2			365.8			17.1			566.3			1,563.4
Loss on secured term loan receivable	52.9			—			—			—			—
Gain on litigation settlement	—			—			(26.0		)	—			—
Total operating costs and expenses	5,865.0			7,535.1			5,440.1			4,616.7			5,749.5
Operating income (loss)	187.9			163.9			299.5			(364.3		)	(1,297.4		)
Other income (expense):
Interest expense, net of interest income	(215.7		)	(178.3		)	(187.9		)	(188.1		)	(102.5		)
Gain on extinguishment of debt	—			—			9.0			—			—
Income (loss) from unconsolidated affiliates	(16.8		)	13.3			9.6			(19.9		)	20.4
Other income	0.9			0.6			0.6			0.3			0.8
Total other expense	(231.6		)	(164.4		)	(168.7		)	(207.7		)	(81.3		)
Income (loss) before non-controlling interest and income taxes	(43.7		)	(0.5		)	130.8			(572.0		)	(1,378.7		)
Income tax benefit (expense)	(2.5		)	2.1			24.0			(1.3		)	0.5
Net income (loss)	(46.2		)	1.6			154.8			(573.3		)	(1,378.2		)
Net income (loss) attributable to non-controlling interests	8.1			2.1			1.1			(2.6		)	(0.4		)
Net income (loss) attributable to ENLK	$	(54.3	)	$	(0.5	)	$	153.7		$	(570.7	)	$	(1,377.8	)
Distributions declared per limited partner unit	$	—		$	1.560		$	1.560		$	1.560		$	1.545

____________________________


(1)	Includes related party cost of sales of $21.7 million, $114.1 million, $211.0 million, $150.1 million, and $141.3 million for the years ended December 31, 2019, 2018, 2017, 2016, and 2015, respectively.



	EnLink Midstream Partners, LP
	December 31,
	2019		2018		2017		2016		2015
	(In millions)
Balance Sheet Data (end of period):
Property and equipment, net	$	7,081.3	$	6,846.7	$	6,587.0	$	6,256.7	$	5,666.8
Total assets	9,134.6		9,571.3		9,414.0		9,153.4		8,092.8
Long-term debt (including current maturities)	4,764.3		4,319.6		3,467.8		3,268.0		3,066.8
Partners' equity including non-controlling interest	3,564.9		4,284.1		4,805.5		4,640.4		4,434.5

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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. Discussions of the year ended December 31, 2017 and year-to-year comparisons of the year ended December 31, 2018 and the year ended December 31, 2017 can be found in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7 of ENLK’s Annual Report on Form 10-K for the year ended December 31, 2018.

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

Overview

We are a Delaware limited partnership formed on July 12, 2002. 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 12,000 miles of pipelines, 21 natural gas processing plants with approximately 5.3 Bcf/d of processing capacity, seven fractionators with approximately 290,000 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.


•	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 and our crude operations in South Texas;


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


•	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;


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

We have recast the segment information for the years ended December 31, 2018 and December 31, 2017 to conform to the current period presentation.

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We manage our operations by focusing on gross operating margin because our business is generally to gather, process, transport, or market natural gas, NGLs, crude oil, and condensate using our assets for a fee. We earn our fees through various fee-based contractual arrangements, which include stated fee-only contract arrangements or arrangements with fee-based components where we purchase and resell commodities in connection with providing the related service and earn a net margin as our fee. We earn our net margin under our purchase and resell contract arrangements primarily as a result of stated service-related fees that are deducted from the price of the commodity purchase. While our transactions vary in form, the essential element of 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. We define gross operating margin as operating revenue minus cost of sales. Gross operating margin is a non-GAAP financial measure and is explained in greater detail under “Non-GAAP Financial Measures” below. Approximately 90% of our gross operating margin was derived from fee-based contractual arrangements with minimal direct commodity price exposure for the year ended December 31, 2019. We reflect revenue as “Product sales” and “Midstream services” on the consolidated statements of operations.

Devon is one of our primary customers. For the years ended December 31, 2019 and 2018, approximately 29.9% and 36.4% of our gross operating margin, respectively, was attributable to commercial contracts with Devon. For additional information about our significant customers, refer to “Item 1. Business—Credit Risks and Significant Customers.”

Our revenues and gross operating margins are generated from volumes related to 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.

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 gross operating margins from product upgrades during periods with higher NGL prices.

We gather or transport crude oil and condensate owned by others by rail, truck, pipeline, and barge facilities under fee-only contract arrangements based on volumes gathered or transported. We also buy crude oil and condensate on our own gathering systems, third-party systems, and trucked from producers at a market index less a stated transportation deduction. We then transport and resell the crude oil and condensate through a process of basis and fixed price trades. We execute substantially all purchases and sales concurrently, thereby establishing the net margin we will receive for each crude oil and condensate transaction.

We realize gross operating margins from our gathering and processing services primarily through different contractual arrangements: processing margin (“margin”) contracts, POL contracts, POP contracts, fixed-fee component contracts, or a combination of these contractual arrangements. “See Item 7A. Quantitative and Qualitative Disclosures about Market Risk—

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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 gross operating margins are higher during periods of high NGL prices relative to natural gas prices. Gross operating margin results under POL contracts are impacted only by the value of the liquids produced with margins higher during periods of higher liquids prices. Gross operating 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 gross operating margins are driven by throughput volume.

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

Recent Developments

Organic Growth

Debt Issuances and Redemption

Issuance and Repayment of Senior Unsecured Notes. On April 9, 2019, ENLC issued $500.0 million in aggregate principal amount of ENLC’s 5.375% senior unsecured notes due June 1, 2029 (the “2029 Notes”) at a price to the public of 100% of their face value. Interest payments on the 2029 Notes are payable on June 1 and December 1 of each year. The 2029 Notes are fully and unconditionally guaranteed by ENLK. Net proceeds of approximately $496.5 million were used to repay outstanding

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borrowings under the Consolidated Credit Facility, including borrowings incurred on April 1, 2019 to repay at maturity all of the $400.0 million outstanding aggregate principal amount of ENLK’s 2.70% senior unsecured notes due 2019, and for general limited liability company purposes. See “Item 8. Financial Statements and Supplementary Data—Note 6” for more information regarding this transaction.

Consolidated Credit Facility. On December 11, 2018, ENLC entered into the Consolidated Credit Facility, which we were able to borrow under upon the closing of the Merger. ENLK is a guarantor of the Consolidated Credit Facility. See “Item 8. Financial Statements and Supplementary Data—Note 6” for more information regarding this transaction.

Term Loan. On December 11, 2018, ENLK entered into a three-year $850.0 million unsecured term loan. Upon closing of the Merger, ENLC assumed ENLK’s obligations under the term loan, and ENLK guaranteed ENLC’s obligations thereunder. See “Item 8. Financial Statements and Supplementary Data—Note 6” for more information regarding this transaction.

Related Party Debt. Related party debt includes borrowings under the Consolidated Credit Facility, the Term Loan, and ENLC’s 5.375% senior unsecured notes due 2029 to fund the operations and growth capital expenditures of ENLK through a related party arrangement with ENLC. See “Item 8. Financial Statements and Supplementary Data—Note 6” for more information regarding this arrangement.

GIP Transaction and Organic Growth in 2018


•	On July 18, 2018, subsidiaries of Devon closed a transaction to sell all of their equity interests in ENLK, ENLC, and the managing member of ENLC to GIP. See “Item 8. Financial Statements and Supplementary Data—Note 1” for more information regarding the GIP Transaction.

•

During the second quarter of 2018, we completed construction of an expansion to our Lobo II cryogenic gas processing plant, which brought total operational processing capacity at our Lobo facilities to 175 MMcf/d. We further expanded our natural gas processing capacity at our Lobo facilities through the construction of the Lobo III cryogenic gas processing plant, which was completed during the fourth quarter of 2018 and provided an additional 100 MMcf/d of operational capacity.


•	In late March 2018, we completed construction of Black Coyote. In addition, we further expanded our crude oil gathering operations in the STACK through the construction of Redbud, which is supported by a contract with Marathon Oil Company. We commenced initial operations on Redbud during the third quarter of 2018.

Non-GAAP Financial Measures

To assist management in assessing our business, we use the following non-GAAP financial measure: gross operating margin.

Gross Operating Margin

We define gross operating margin as revenues less cost of sales. We present gross operating margin by segment in “Results of Operations.” We disclose gross operating margin in addition to total revenue because it is the primary performance measure used by our management. We believe gross operating margin is an important measure because, in general, our business is to 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 operating performance of field operations. Direct labor and supervision, property insurance, property taxes, repair and maintenance, utilities, and contract services comprise the most significant portion of our operating expenses. We do not deduct operating expenses from total revenue in calculating gross operating margin because these expenses are largely independent of the volumes we transport or process and fluctuate depending on the activities performed during a specific period. The GAAP measure most directly comparable to gross operating margin is operating income (loss). Gross operating margin should not be considered an alternative to, or more meaningful than, operating income (loss) as determined in accordance with GAAP. Gross operating margin has important limitations because it excludes all operating costs that affect operating income (loss) except cost of sales. Our gross operating margin may not be comparable to similarly titled measures of other companies because other entities may not calculate these amounts in the same manner.

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The following table provides a reconciliation of operating income to gross operating margin (in millions):



	Year Ended December 31,
	2019			2018		2017
Operating income	$	187.9		$	163.9	$	299.5

Add:
Operating expenses	467.1			453.4		418.7
General and administrative	139.2			130.2		123.5
(Gain) loss on disposition of assets	(1.9		)	0.4		—
Depreciation and amortization	617.0			577.3		545.3
Impairments	198.2			365.8		17.1
Loss on secured term loan receivable	52.9			—		—
Gain on litigation settlement	—			—		(26.0		)
Gross operating margin	$	1,660.4		$	1,691.0	$	1,378.1

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Results of Operations

The table below sets forth certain financial and operating data for the periods indicated. We manage our operations by focusing on gross operating margin, which we define as revenue less cost of sales as reflected in the table below (in millions, except volumes):



	Year Ended December 31,
	2019			2018			2017
Permian Segment
Revenues	$	2,542.3		$	3,030.3		$	1,797.2
Cost of sales	(2,283.9		)	(2,808.3		)	(1,628.5		)
Total gross operating margin	$	258.4		$	222.0		$	168.7
North Texas Segment
Revenues	$	601.1		$	684.1		$	745.0
Cost of sales	(208.8		)	(199.2		)	(264.5		)
Total gross operating margin	$	392.3		$	484.9		$	480.5
Oklahoma Segment
Revenues	$	1,181.1		$	1,299.8		$	874.8
Cost of sales	(627.0		)	(743.6		)	(523.0		)
Total gross operating margin	$	554.1		$	556.2		$	351.8
Louisiana Segment
Revenues	$	2,622.8		$	3,788.4		$	3,182.2
Cost of sales	(2,181.6		)	(3,365.7		)	(2,800.9		)
Total gross operating margin	$	441.2		$	422.7		$	381.3
Corporate Segment
Revenues	$	(894.4	)	$	(1,103.6	)	$	(859.6	)
Cost of sales	908.8			1,108.8			855.4
Total gross operating margin	$	14.4		$	5.2		$	(4.2	)
Total
Revenues	$	6,052.9		$	7,699.0		$	5,739.6
Cost of sales	(4,392.5		)	(6,008.0		)	(4,361.5		)
Total gross operating margin	$	1,660.4		$	1,691.0		$	1,378.1

Midstream Volumes:
Permian Segment
Gathering and Transportation (MMBtu/d)	723,400			521,900			361,200
Processing (MMBtu/d)	771,400			531,700			385,000
Crude Oil Handling (Bbls/d)	132,000			124,300			91,800
North Texas Segment
Gathering and Transportation (MMBtu/d)	1,651,900			1,733,900			1,901,700
Processing (MMBtu/d)	750,500			747,400			799,400
Oklahoma Segment
Gathering and Transportation (MMBtu/d)	1,302,200			1,204,700			829,300
Processing (MMBtu/d)	1,276,700			1,195,300			810,300
Crude Oil Handling (Bbls/d)	47,300			15,700			—
Louisiana Segment
Gathering and Transportation (MMBtu/d)	2,050,000			2,196,200			1,995,800
Processing (MMBtu/d)	400,200			431,200			453,300
Crude Oil Handling (Bbls/d)	18,900			15,400			16,400
NGL Fractionation (Gals/d)	7,341,700			6,584,400			5,772,800
Brine Disposal (Bbls/d)	2,700			3,200			4,200

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Year Ended December 31, 2019 Compared to Year Ended December 31, 2018

Gross Operating Margin. Gross operating margin was $1,660.4 million for the year ended December 31, 2019 compared to $1,691.0 million for the year ended December 31, 2018, a decrease of $30.6 million, or 1.8%, due to the following:

•

Permian Segment. Gross operating margin in the Permian segment increased $36.4 million, which was primarily due to a $43.4 million increase in gross operating margin due to higher volumes on our Permian gas assets from continued development by our customers, including $26.7 million from our Delaware Basin assets, and $16.7 million from our Midland Basin assets. This increase was partially offset by a $7.0 million decrease in gross operating margin from our Permian crude assets, which was due to a $5.4 million decrease in gross operating margin from our South Texas assets due to an MVC expiration in July 2019 and a $4.5 million decrease in gross operating margin associated with our physical crude marketing arrangements partially offset by a $2.9 million increase in gross operating margin from our Midland and Delaware Basins crude assets. We manage our exposure to crude price fluctuations in our physical crude marketing arrangements through various derivative arrangements, which primarily relate to our Permian segment. The timing of our realization of the gains or losses from these crude derivative arrangements may not occur in the same period as the corresponding physical crude marketing transaction, and all associated gains and losses from the derivative arrangements are reflected in our Corporate segment.


•	North Texas Segment. Gross operating margin in the North Texas segment decreased $92.6 million, which was primarily due to the January 1, 2019 expiration of Devon’s obligations related to MVCs on our North Texas assets and normal volume declines due to limited new drilling in the region. Shortfall revenue from the Devon-related MVCs was $84.3 million for the year ended December 31, 2018.

•

Oklahoma Segment. Gross operating margin in the Oklahoma segment decreased $2.1 million. Gross operating margin from our Oklahoma assets increased $43.4 million, which was primarily due to higher volumes from continued development by our customers, with $20.4 million contributed by our Oklahoma gas assets and $23.0 million contributed by our Oklahoma crude assets. These increases in gross operating margin for the year ended December 31, 2019 derived from our Oklahoma assets were offset by the recognition of $45.5 million in revenue from a contract restructuring with White Star during the year ended December 31, 2018.

•

Louisiana Segment. Gross operating margin in the Louisiana segment increased $18.5 million. Gross operating margin from our NGL assets increased by $40.4 million primarily due to higher volumes with the completion of the Cajun-Sibon pipeline expansion in April 2019. Our ORV crude assets contributed an increase of $1.1 million primarily due to higher volumes. These increases were partially offset by a decrease of $23.0 million from our Louisiana gas business, primarily due to a $14.6 million decrease from a less favorable processing environment for our Louisiana gas plants and an $8.4 million decrease in our Louisiana gas transportation business due to the expiration of certain firm transportation contracts and decreased volumes during the same period.

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•	Corporate Segment. Gross operating margin in the Corporate segment increased $9.2 million, which was primarily due to the changes in fair value of our commodity swaps between the periods as summarized below (in millions):



	Year Ended December 31,
	2019			2018
Realized swaps:
Crude swaps	$	11.7		$	(0.3	)
NGL swaps	6.5			(3.2		)
Gas swaps	(3.7		)	(1.4		)
Realized gain (loss) on derivatives	14.5			(4.9		)

Unrealized swaps:
Crude swaps	(0.3		)	7.0
NGL swaps	(3.5		)	8.3
Gas swaps	3.7			(5.2		)
Change in fair value of derivatives	(0.1		)	10.1

Gain on derivative activity	$	14.4		$	5.2

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

Revenue recorded for the shortfall between actual product volumes and the MVCs were as follows (in millions):



	Permian		North Texas		Oklahoma		Total
Year Ended December 31, 2019
Midstream services	$	9.4	$	—	$	10.3	$	19.7
Total	$	9.4	$	—	$	10.3	$	19.7

Year Ended December 31, 2018
Midstream services (1)	$	5.2	$	41.0	$	53.4	$	99.6
Midstream services—related parties	6.3		43.3		1.2		50.8
Total	$	11.5	$	84.3	$	54.6	$	150.4

____________________________


(1)	We restructured a natural gas gathering and processing contract that contained MVCs. As a result, we recognized $45.5 million of midstream services revenue in the Oklahoma segment for the year ended December 31, 2018. For more information, see “Item 8. Financial Statements and Supplementary Data—Note 2.”

On January 1, 2019, certain MVCs related to gathering and processing agreements with Devon for operations in the North Texas and Oklahoma segments expired. These MVCs generated $85.5 million in shortfall revenue for the year ended December 31, 2018. On July 31, 2019, an MVC related to a transportation services agreement with Devon for operations in the Permian segment expired. This MVC generated $9.4 million and $11.5 million in shortfall revenue for the years ended December 31, 2019 and 2018, respectively. For the year ended December 31, 2019, our MVC revenue in the Oklahoma segment was generated from a gathering and processing arrangement with Devon which expires in 2030, with the MVC provision under the agreement expiring in December 2020. This MVC generated $10.3 million in shortfall revenue for the year ended December 31, 2019. In 2020, this expiring MVC agreement is projected to generate approximately $55-$65 million in shortfall revenue.

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Operating Expenses. Operating expenses were $467.1 million for the year ended December 31, 2019 compared to $453.4 million for the year ended December 31, 2018, an increase of $13.7 million, or 3.0%. The primary contributors to the total increase by segment were as follows (in millions):



	Year Ended December 31,				Change
	2019		2018		$			%
Permian Segment	$	112.9	$	96.1	$	16.8		17.5	%
North Texas Segment	102.9		112.7		(9.8		)	(8.7	)%
Oklahoma Segment	104.0		90.3		13.7			15.2	%
Louisiana Segment	147.3		154.3		(7.0		)	(4.5	)%
Total	$	467.1	$	453.4	$	13.7		3.0	%


•	Permian Segment. Operating expenses in the Permian segment increased $16.8 million primarily due to expanded operations and higher utilities expense, bulk purchases of materials and supplies, construction fees and services, and compressor rentals.


•	North Texas Segment. Operating expenses in the North Texas segment decreased $9.8 million primarily due to decreased compressor rentals, compressor overhauls, and labor and benefits costs.


•	Oklahoma Segment. Operating expenses in the Oklahoma segment increased $13.7 million primarily due to expanded operations with increases in utilities, equipment rentals, compression operations and maintenance, and labor and benefits costs.


•	Louisiana Segment. Operating expenses in the Louisiana segment decreased $7.0 million primarily due to reduced materials and supplies expenses, labor and benefits costs, and compression rentals partially offset by increased equipment rental and utility costs.

General and Administrative Expenses. General and administrative expenses were $139.2 million for the year ended December 31, 2019 compared to $130.2 million for the year ended December 31, 2018, an increase of $9.0 million, or 6.9%. The primary contributors to the increase were as follows:


•	Fees and services expense increased $4.6 million, which was primarily due to increased software consulting and legal fees.


•	Other office expense increased $2.9 million, which was primarily due to a reduction of expense allocation to ENLC as a result of the Merger, which closed during the first quarter of 2019.


•	Unit-based compensation expense increased $2.5 million, which was primarily due to increased bonus expense and accelerated vesting of units related to an executive departure in the third quarter of 2019. This increase was partially offset by accelerated vesting of units related to the GIP Transaction during 2018.

•

Labor and benefits costs decreased $0.7 million. Labor and benefit costs for the year ended December 31, 2019 included severance costs of $7.0 million, driven by an executive departure and a reduction in workforce, compared to $3.0 million in severance costs for the year ended December 31, 2018. The $4.0 million increase in severance costs between years was offset by a decrease in bonus expense of $5.5 million.


•	Transaction costs decreased $1.0 million, which was primarily due to costs incurred related to the Merger, which closed during the first quarter of 2019, compared to the costs of transactions related to the GIP Transaction, which closed during 2018.

Depreciation and Amortization. Depreciation and amortization expenses were $617.0 million for the year ended December 31, 2019 compared to $577.3 million for the year ended December 31, 2018, an increase of $39.7 million, or 6.9%. This increase was primarily due to increased depreciation of $32.5 million attributable to new assets placed into service in key growth areas, including the Thunderbird Plant, the expansion of the Lobo III cryogenic gas processing plant, the Cajun-Sibon NGL pipeline, Avenger, the Black Coyote crude oil gathering system, and well connections in Oklahoma. Additionally, depreciation increased by $18.3 million primarily due to retirements and reductions in our estimated useful lives of certain assets primarily located in the Texas and Louisiana segments. These increases were partially offset by a $11.1 million decrease

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in depreciation during 2019 resulting from an impairment of the carrying value of certain non-core crude pipeline assets during 2018.

Impairments. Impairment expense was $198.2 million for the year ended December 31, 2019, which was primarily related to $190.3 million of recognized goodwill impairment for our Oklahoma reporting unit. We also recorded a $7.9 million impairment on property and equipment related to certain decommissioned and removed non-core assets. For the year ended December 31, 2018, we recognized impairments on property and equipment related to the carrying values of certain non-core natural gas assets in the Louisiana segment of $24.6 million and $109.2 million related to non-core crude pipeline assets in the Permian segment. In addition, we recognized goodwill impairments for our North Texas and Permian reporting units of $202.7 million and $29.3 million, respectively. See “Item 8. Financial Statements and Supplementary Data—Note 3” for additional information about our goodwill impairments.

Loss on secured term loan receivable. We have recorded a $52.9 million loss in our consolidated statement of operations for the year ended December 31, 2019 related to the write-off of the White Star secured term loan receivable. For additional information regarding this transaction, refer to “Item 8. Financial Statements and Supplementary Data—Note 2.”

Interest Expense. Interest expense was $215.7 million for the year ended December 31, 2019 compared to $178.3 million for the year ended December 31, 2018, an increase of $37.4 million, or 21.0%. Net interest expense consisted of the following (in millions):



	Year Ended December 31,
	2019			2018
Senior notes	$	151.8		$	160.0
Related Party Debt	66.0			—
Term Loan	—			1.9
ENLK Credit Facility	0.3			22.3
Capitalized interest	(5.8		)	(7.0		)
Amortization of debt issuance costs and net discount	4.9			4.0
Other	(1.5		)	(2.9		)
Total interest expense, net of interest income	$	215.7		$	178.3

Income (loss) from Unconsolidated Affiliate Investments. Loss from unconsolidated affiliate investments was $16.8 million for the year ended December 31, 2019 compared to income of $13.3 million for the year ended December 31, 2018, a decrease in income of $30.1 million. The reduction in income was primarily due to a $31.4 million 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.

Year Ended December 31, 2018 Compared to Year Ended December 31, 2017

We have recast the segment information for the years ended December 31, 2018 and December 31, 2017 to conform to the current period presentation.

Gross Operating Margin. Gross operating margin was $1,691.0 million for the year ended December 31, 2018 compared to $1,378.1 million for the year ended December 31, 2017, an increase of $312.9 million, or 22.7%, due to the following:

•

Permian Segment. Gross operating margin in the Permian segment increased $53.3 million, which was primarily due to a $42.7 million increase from our Permian Basin processing assets as a result of higher volumes due to continued development by our customers. In addition, there was a $5.9 million increase from our Permian Basin crude business as a result of increased trucking volumes, higher trucking fees, higher volumes due to continued expansion of our customer base on the Greater Chickadee gathering system, and the start of initial operations of Avenger and $2.3 million due to higher volumes on VEX.


•	North Texas Segment. Gross operating margin in the North Texas segment increased $4.4 million, which was primarily due to an increase in processing, gathering, and transmission volumes associated with new development in the Barnett

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Shale. For the year ended December 31, 2018, the shortfall revenue from Devon-related MVCs was $84.3 million compared to $59.2 million for the year ended December 31, 2017.

•

Oklahoma Segment. Gross operating margin in the Oklahoma segment increased $204.4 million, which was primarily due to a $156.3 million increase from higher volumes as a result of continued development by our customers. In addition, during the year ended December 31, 2018, we restructured a contract with a customer, which resulted in the recognition of $45.5 million in revenue for the year ended December 31, 2018 (as discussed in “Item 8. Financial Statements and Supplementary Data—Note 2”). Additionally, gross operating margin increased $2.5 million from the start of initial operations of our Central Oklahoma crude oil gathering systems and trucking business. For the year ended December 31, 2018, the shortfall revenue from Devon-related MVCs was $1.2 million compared to $13.8 million for the year ended December 31, 2017.

•

Louisiana Segment. Gross operating margin in the Louisiana segment increased $41.4 million, which was primarily due to a $29.0 million increase in our NGL transmission and fractionation gross operating margin due to additional NGL volumes received from our Oklahoma and Permian Basin assets and fees earned from the start-up of our Ascension JV assets in April 2017. In addition, there was a $14.9 million increase from ORV due to higher condensate stabilization volumes and improved margins from contract renegotiations.

•

Corporate Segment. Gross operating margin in the Corporate segment increased $9.4 million, due to the changes in fair value of our commodity swaps between the periods. For the year ended December 31, 2018, there were realized losses of $4.9 million that were offset by unrealized gains of $10.1 million. For the year ended December 31, 2017, there were realized losses of $8.9 million that were partially offset by unrealized gains of $4.7 million.

Revenue recorded for the shortfall between actual product volumes and the MVCs were as follows (in millions):



	Permian		North Texas		Oklahoma		Total
Year Ended December 31, 2018
Midstream services (1)	$	5.2	$	41.0	$	53.4	$

EnLink Midstream Partners, LP 10-K