enlc_Current_Folio

10-K 1 c000-20161231x10k.htm 10-K enlc_Current_Folio_10K

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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, 2016

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number: 001-36336

ENLINK MIDSTREAM, LLC

(Exact name of registrant as specified in its charter)

Delaware
(State of organization)	46-4108528
	(I.R.S. Employer Identification No.)
2501 CEDAR SPRINGS
DALLAS, TEXAS	75201
(Address of principal executive offices)	(Zip Code)

(Registrant's telephone number, including area code)

(214) 953-9500

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

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

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: None.

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

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

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

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

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

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

Large accelerated filer ☒

Accelerated filer ☐

Non-accelerated filer ☐

(Do not check if a

smaller reporting company)

Smaller reporting company ☐

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

The aggregate market value of the common units representing limited liability company interests held by non-affiliates of the registrant was approximately $1.0 billion on June 30, 2016, based on $15.91 per unit, the closing price of the common units as reported on The New York Stock Exchange on such date.

At February 8, 2017, there were 180,075,376 common units outstanding.

DOCUMENTS INCORPORATED BY REFERENCE:

None.

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TABLE OF CONTENTS

Item	DESCRIPTION	Page
PART I
1.	BUSINESS	3
1A.	RISK FACTORS	31
1B.	UNRESOLVED STAFF COMMENTS	58
2.	PROPERTIES	58
3.	LEGAL PROCEEDINGS	58
4.	MINE SAFETY DISCLOSURES	59
PART II
5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	59
6.	SELECTED FINANCIAL DATA	62
7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	65
7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	96
8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	99
9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	154
9A.	CONTROLS AND PROCEDURES	154
9B.	OTHER INFORMATION	154
PART III
10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	155
11.	EXECUTIVE COMPENSATION	159
12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS	179
13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE	182
14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	186
PART IV
15.	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES	187

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ENLINK MIDSTREAM, LLC

PART I

Item 1. Business

General

EnLink Midstream, LLC (“ENLC”) is a Delaware limited liability company formed in October 2013. Effective as of March 7, 2014, EnLink Midstream, Inc. (“EMI”) merged with and into a subsidiary wholly owned by us, and Acacia Natural Gas Corp I, Inc. (“Acacia”), formerly a wholly-owned subsidiary of Devon Energy Corporation (“Devon”), merged with and into another subsidiary wholly owned by us (collectively, the “mergers”). Pursuant to the mergers, each of EMI and Acacia became our wholly-owned subsidiaries and we became publicly held. EMI owns common units representing an approximate 5.1% limited partner interest in EnLink Midstream Partners, LP (the “Partnership”) as of December 31, 2016 and also owns EnLink Midstream Partners GP, LLC, the general partner of the Partnership (the “General Partner”). At the conclusion of the mergers in March 2014, Acacia directly owned a 50% limited partner interest in a limited partnership, formerly wholly owned by Devon, that was renamed EnLink Midstream Holdings, LP (“Midstream Holdings”). As a result of the drop down transactions discussed below, Acacia owned approximately 17.2% of the limited partner interests in the Partnership as of December 31, 2016, bringing ENLC’s total ownership, through its wholly-owned subsidiaries, of limited partner interests in the Partnership to 22.3% as of December 31, 2016.

Concurrently with the consummation of the mergers, a wholly-owned subsidiary of the Partnership acquired the remaining 50% of the outstanding limited partner interest in Midstream Holdings and all of the outstanding equity interests in EnLink Midstream Holdings GP, LLC, the general partner of Midstream Holdings (together with the mergers, the “Business Combination”).

On February 17, 2015, Acacia contributed a 25% interest in Midstream Holdings (the “February 2015 Transferred Interests”) to the Partnership in a drop down transaction (the “February EMH Drop Down”) in exchange for 31.6 million units in the Partnership. On May 27, 2015, Acacia contributed the remaining 25% limited partner interest in Midstream Holdings (the “May 2015 Transferred Interests”) to the Partnership in a drop down transaction (the “May 2015 EMH Drop Down” and together with the February 2015 EMH Drop Down, the “EMH Drop Downs”) in exchange for 36.6 million units in the Partnership. After giving effect to the EMH Drop Downs, the Partnership owns 100% of Midstream Holdings.

Our common units are traded on the New York Stock Exchange (“NYSE”) under the symbol “ENLC.” Our executive offices are located at 2501 Cedar Springs Rd., Dallas, Texas 75201, and our telephone number is (214) 953-9500. Our Internet address is www.enlink.com. We post the following filings in the “Investors” section of our website as soon as reasonably practicable after they are electronically filed with or furnished to the Securities and Exchange Commission: 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.

On January 7, 2016, EnLink Oklahoma Gas Processing, LP (“EnLink Oklahoma T.O.”) completed its acquisition of 100% of the issued and outstanding membership interests of TOMPC LLC and TOM-STACK, LLC. EnLink Oklahoma T.O. is sometimes used herein to refer to EnLink Oklahoma Gas Processing, LP itself or Enlink Oklahoma Gas Processing, LP, together with its consolidated subsidiaries. As of February 12, 2016, (a) the Partnership indirectly owns an 84% limited partnership interest in EnLink Oklahoma T.O (b) we own a 16% limited partnership interest in EnLink Oklahoma T.O. and (c) EnLink Energy GP, LLC, the general partner of EnLink Oklahoma T.O. and an indirect subsidiary of the Partnership, owns the non-economic general partnership interest.

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

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ENLINK MIDSTREAM, LLC

Our assets consist of equity interests in the Partnership and EnLink Oklahoma T.O. The Partnership is a publicly traded limited partnership that primarily focuses on providing midstream energy services, including gathering, processing, transmission, fractionation, storage, condensate stabilization, brine services and marketing to producers of natural gas, NGLs, crude oil and condensate. EnLink Oklahoma T.O. is a partnership held by us and the Partnership engaged in the gathering, transmission and processing of natural gas and NGLs. As of December 31, 2016, our interests in the Partnership consist of the following:

88,528,451 common units representing an aggregate 22.3% limited partner interest in the Partnership;

100.0% ownership interest in the General Partner, which owns a 0.4% general partner interest and all of the incentive distribution rights in the Partnership; and

16% limited partner interest in EnLink Oklahoma T.O.

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

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

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

federal income taxes, which we are required to pay because we are taxed as a corporation;

the expenses of being a public company;

other general and administrative expenses;

capital calls for our interest in EnLink Oklahoma T.O. to the extent not covered by our borrowings;

capital contributions to the Partnership upon the issuance by it of additional partnership securities in order to maintain the General Partner’s then-current general partner interest, to the extent the board of directors of the General Partner (the “GP Board”) exercises its option to do so; and

cash reserves the board of directors of EnLink Midstream Manager, LLC, our managing member (the “Managing Member”), believes are prudent to maintain.

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

ENLINK MIDSTREAM PARTNERS, LP

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

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

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The following diagram depicts the organization and ownership of the Company and its subsidiaries as of December 31, 2016:

Definitions

The following terms as defined generally are used in the energy industry and in this document:

/d = per day

Bbls = barrels

Bboe = billion Boe

Bcf = billion cubic feet

Boe = six Mcf of gas per Bbl of oil

Btu = British thermal units

CO2= Carbon dioxide

CPI= Consumer Price Index

Gal=gallon

Mcf = thousand cubic feet

MMBtu = million British thermal units

MMcf = million cubic feet

NGL = natural gas liquid and natural gas liquids

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Capacity volumes at the Partnership’s 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 capacity of 100 MMcf generally correlates to volume capacity of 100,000 MMBtu. 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”).

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

Our Operations

The Partnership connects the wells of natural gas producers in its market areas to its gathering systems, processes natural gas for the removal of NGLs, fractionate NGLs into purity products and markets those products for a fee, transports natural gas and ultimately provides natural gas to a variety of markets. The Partnership purchases natural gas from natural gas producers and other supply sources and sells that natural gas to utilities, industrial consumers, other marketers and pipelines. The Partnership operates processing plants that process gas transported to the plants by major interstate pipelines or from its own gathering systems under a variety of fee-based arrangements. The Partnership provides a variety of crude oil and condensate services, which include crude oil and condensate gathering via pipelines, barges, rail and trucks, condensate stabilization and brine disposal. The Partnership’s gas gathering systems consist of networks of pipelines that collect natural gas from points near producing wells and transport it to larger pipelines for further transmission. The Partnership’s transmission pipelines primarily receive natural gas from its gathering systems and from third party gathering and transmission systems and deliver natural gas to industrial end-users, utilities and other pipelines. The Partnership also has transmission lines that transport NGLs from east Texas and from its south Louisiana processing plants to its fractionators in south Louisiana. Additionally, the Partnership owns an economic interest in an NGL fractionator located at Mont Belvieu, Texas that receives raw mix NGLs from customers, fractionates such raw mix and redelivers the finished products to the customers for a fee. Devon is one of the largest customers of this fractionator. The Partnership’s crude oil and condensate gathering and transmission systems consist of trucking facilities, pipelines, rail and barge facilities that, in exchange for a fee, transport oil from a producer site to end users or other pipelines. The Partnership’s processing plants remove NGLs and CO2 from a natural gas stream and its fractionators separate the NGLs into separate NGL products, including ethane, propane, iso-butane, normal butane and natural gasoline.

The Partnership’s assets are included in five primary segments:

Texas. The Partnership’s Texas assets consist of transmission pipelines with a capacity of approximately 920 MMcf/d, processing facilities with a total processing capacity of approximately 1.6 Bcf/d and gathering systems with total capacity of approximately 2.3 Bcf/d.

Oklahoma. The Partnership’s Oklahoma assets consist of processing facilities with a total processing capacity of approximately 795 MMcf/d and gathering systems with total capacity of approximately 810 MMcf/d.

Louisiana. The Partnership’s Louisiana assets consist of Louisiana Gas and Processing assets, which include transmission pipelines with a capacity of approximately 3.5 Bcf/d, processing facilities with a total processing

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capacity of approximately 1.9 Bcf/d and gathering systems with total capacity of approximately 510 MMcf/d. The Partnership’s Louisiana Liquids assets consists of 720 miles of liquids transport lines and four fractionation assets with total fractionation capacity of 175 MBbls/d.

Crude and Condensate. The Partnership’s Crude and Condensate assets consist of approximately 540 miles of crude oil and condensate pipelines. The assets also include 900,000 barrels of above ground storage and a trucking fleet of approximately 150 vehicles comprised of both semi and straight trucks with a current capacity of 85,350 Bbls/d. The current pipeline capacity is 116,100 Bbls/d. Additionally, the Partnership’s operations include eight condensate stabilization and natural gas compression stations with combined capacities of over 36,000 Bbls/d of condensate stabilization and 780 MMcf/d of natural gas compression.

Corporate. The Partnership’s Corporate assets consist of a contractual right to the benefits and burdens associated with Devon’s 38.75% ownership interest in Gulf Coast Fractionators (“GCF”), an approximate 31% ownership interest in Howard Energy Partners (“HEP”) and our approximate 30% ownership in Cedar Cove Midstream LLC (“Cedar Cove JV”).

About Devon

Devon (NYSE: DVN) is a leading independent energy company engaged primarily in the exploration, development and production of crude oil, natural gas and NGLs. Devon’s operations are concentrated in various onshore areas in the U.S. and Canada. Please see Devon’s Annual Report on Form 10-K for the year ended December 31, 2016 (the “Devon Annual Report”) for additional information concerning Devon’s business. The information contained in the Devon Annual Report is not incorporated by reference into this annual report on Form 10-K and should not be considered part of this or any other report that we file with or furnish to the SEC.

Our Business Strategies

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 having the Partnership execute the following strategies:

Maintain stable cash flows supported by long-term, fee-based contracts. The Partnership will seek to generate cash flows pursuant to long-term, firm contracts with creditworthy customers. The Partnership will continue to pursue opportunities to increase the fee-based and minimum volume commitment (“MVC”) components of its contract portfolio to minimize its direct commodity price exposure.

Maintain a strong financial position. The Partnership believes that maintaining a conservative and balanced capital structure, appropriate leverage and other key financial metrics will afford it better access to the capital markets at a competitive cost of capital. The Partnership also believes a strong financial position provides it the opportunity to grow its business in a prudent manner throughout the cycles in its industry.

Execute in our core growth areas. The Partnership believes its assets are positioned in some of the most economic basins in the U.S., as well as key demand centers with growing end-use customers. The Partnership expects to grow certain of its systems organically over time by meeting their customers’ midstream service needs that result from its drilling activity in the Partnership’s areas of operation. The Partnership continually evaluates whether to pursue economically attractive organic expansion opportunities in existing or new areas of operation that allow it to leverage its existing infrastructure, operating expertise and customer relationships by constructing and expanding systems to meet new or increased demand for its services.

Our Competitive Strengths

We believe that the Partnership is well-positioned to execute its strategies and to achieve its business objective due to the following competitive strengths:

Devon’s sponsorship. The Partnership expects its relationship with Devon will continue to provide it with significant business opportunities. Devon is one of the largest independent oil and gas producers in North America. Devon has a significant interest in promoting the success of the Partnership’s business, due to its 64.1% ownership interest in us and approximate 23.8% ownership interest in the Partnership as of December

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31, 2016. Approximately 50% of the Partnership’s gross operating margin was attributable to commercial contracts with Devon in 2016.

Strategically-located assets. The majority of the Partnership’s assets are strategically located in producing regions with the potential for increasing throughput volume and cash flow generation. The Partnership’s asset portfolio includes gathering, transmission, fractionation and processing systems that are located in the areas in which producer activity is focused on crude oil, condensate and NGLs as well as natural gas. The Partnership has established platforms in Texas, Oklahoma, Louisiana and Ohio, and are focused on growing our operations in central Oklahoma, the Permian Basin and southern Louisiana through organic development and acquisitions.

Stable cash flows. Approximately 97% of the Partnership’s gross operating margin were generated from fee-based services with no direct commodity exposure during 2016. The Partnership currently has approximately seven years remaining on fixed-fee gathering and processing agreements with a subsidiary of Devon pursuant to which the Partnership will provide gathering, treating, compression, dehydration, stabilization, processing and fractionation services, as applicable, for natural gas delivered by Devon to Partnership’s gathering and processing systems in the Barnett and Cana-Woodford Shales. These agreements provide the Partnership with dedication of all of the natural gas owned or controlled by Devon and produced from or attributable to existing and future wells located on certain oil, natural gas and mineral leases covering lands within the acreage dedications, excluding properties previously dedicated to other natural gas gathering systems not owned and operated by Devon. These agreements also include MVCs that will remain in effect for through January 1, 2019, as well as annual rate escalators. Additionally, the Partnership’s EnLink Oklahoma T.O. assets are supported by Devon with acreage dedications and MVCs for gathering and processing on Devon’s recently acquired Sooner Trend Anadarko Basin Canadian and Kingfisher Counties (“STACK”) acreage. For additional information please read “—Partnership’s Contractual Relationship with Devon.” The Partnership will continue to focus on contract structures that reduce volatility and support long-term stability of cash flows.

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

Experienced management team. The Partnership believes its management team has a proven track record of creating value through the development, acquisition, optimization and integration of midstream assets. The Partnership’s management team has an average of over 20 years of experience in the energy industry. The Partnership believes this team provides it with a strong foundation for evaluating growth opportunities and operating its assets in a safe, reliable and efficient manner.

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

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The Partnership’s Contractual Relationship with Devon

The following table includes the Partnership’s long-term, fixed-fee contracts with Devon:

Minimum

Year

Gathering

Processing

Volume

Contract

Volume

Commitment

Annual

Term

Entered

Commitment

Term

Rate

Contract

(Years)

Into

(MMcf/d)

(Years)

Escalators

Bridgeport gathering and processing contract (1)

2014

850

650

CPI

East Johnson County gathering contract

2014

125

—

CPI

Cana gathering and processing contract

2014

330

CPI

Chisholm gathering and processing contract (2)

2016

Varies

(2)

Varies

(2)

—

(1)

The Bridgeport gathering and processing contract includes volume commitments to the Bridgeport processing facility as well as the Bridgeport gathering systems.

(2)

The minimum gathering volume commitments and minimum processing volume commitments under this contract escalate on a quarterly basis over the life of the five-year commitment beginning with an average commitment of 37 MMcf/d during 2016 and ending with an average commitment of 230 MMcf/d during 2020.

In addition, the Partnership entered into to a five-year minimum transportation volume commitment with Devon related to its Victoria Express Pipeline (“VEX Pipeline”). The volume commitments under this contract escalates over the life of the contract, beginning with an average commitment of 25,000 Bbls/d during the first year and 30,000 Bbls/d in years two through five. The MVC was executed in June 2014 and the initial term expires in July 2019.

Recent Growth Developments

Acquisitions and Expansion

EnLink Oklahoma T.O. Acquisition and Expansion. On January 7, 2016, we and the Partnership acquired a 16% and 84% interest, respectively, in EnLink Oklahoma T.O. for approximately $1.4 billion. The first installment of $1.02 billion for the acquisition was paid at closing. The second installment of $250.0 million was paid on January 6, 2017, and the final installment of $250.0 million is due no later than January 7, 2018. The installment payables are valued net of discount within the total purchase price.

The first installment consisted of approximately $1.02 billion and was funded by (a) approximately $783.6 million in cash paid by the Partnership, the majority of which was derived from the proceeds from the issuance of Preferred Units (as defined under “Issuance of Preferred Units” below), and (b) 15,564,009 of our common units issued directly by us and approximately $22.2 million in cash paid by us.

The EnLink Oklahoma T.O. assets serve gathering and processing needs in the growing STACK and Central Northern Oklahoma Woodford (“CNOW”) plays in Oklahoma and are supported by long-term, fixed-fee contracts with acreage dedications that, at the time of acquisition, had a weighted-average term of approximately 15 years. The EnLink Oklahoma T.O. assets are strategically located in the core areas of the STACK and CNOW plays and include:

Chisholm Plant. The Chisholm Plant, which serves the STACK play, is a cryogenic gas processing plant with a capacity of 120 MMcf/d. The plant is connected to a 350-mile, low- and high-pressure gathering system with compression facilities, including gathering pipelines and compression facilities completed by us during 2016.

During 2016, we commenced construction on a new cryogenic gas processing plant, referred to as Chisholm II, that will provide an additional 200 MMcf/d of processing capacity and will be tied to new and existing pipelines in the STACK and South Central Oklahoma Oil Province (“SCOOP”) play. Chisholm II is scheduled to be completed during the first quarter of 2017. The new capacity is supported by long-term contracts.

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Additionally, we expect to commence construction on Chisholm III in April 2017. Chisholm III will provide an additional 200 MMcf/d of processing capacity and will be tied to new and existing pipelines in the STACK and SCOOP play. Construction is scheduled to be completed by the fourth quarter of 2017.

Battle Ridge Plant. The Battle Ridge Plant is a cryogenic gas processing plant located in the CNOW play with a current capacity of 75 MMcf/d. The plant is connected to a 250-mile, low and high-pressure gathering system with compression facilities.

Connecting Pipeline. A 42-mile, 16-inch high-pressure header pipeline with a total capacity of 150 MMcf/d was constructed to connect the Chisolm and Battle Ridge systems. The pipeline went into service in March 2016 and provides customers with additional operational flexibility.

Organic Growth

Greater Chickadee Crude Oil Gathering System. The Partnership has a new crude oil gathering system in Upton and Midland counties, Texas in the Permian Basin that we refer to as “Greater Chickadee.” Greater Chickadee includes approximately 185 miles of high- and low-pressure pipelines that will transport crude oil volumes to several major market outlets and other key hub centers in the Midland, Texas area. Greater Chickadee also includes the construction of 50,000 Bbls of crude oil storage and a truck injection station to maximize shipping and delivery options for the Partnership’s producer customers. The initial phase of the Greater Chickadee transportation service began in November 2016. Additional construction is ongoing, and the Partnership expect full service capabilities in the first quarter of 2017.

Cedar Cove Joint Venture. On November 9, 2016, the Partnership formed the Cedar Cove JV with Kinder Morgan, Inc., consisting of gathering and compression assets in Blaine County, Oklahoma, located in the heart of the STACK play. The gathering system has a capacity of 25 MMcf/d with over 50,000 gross acres of dedications and ties into the Partnership’s existing Oklahoma assets. All gas gathered by the Cedar Cove JV will be processed at the Partnership’s central Oklahoma processing system. The Partnership has a commitment to contribute $39.0 million in cash in exchange for 30% ownership of the Cedar Cove JV, including $28.8 million contributed as of December 31, 2016. Thereafter, the Partnership and Kinder Morgan, Inc. will contribute additional capital in proportion to their respective ownership interests to fund operations.

Delaware Basin Joint Venture. On August 1, 2016, the Partnership formed the Delaware Basin JV with NGP to operate and expand their natural gas, natural gas liquids and crude oil midstream assets in the liquids-rich Delaware Basin. The Delaware Basin JV is owned 50.1% by the Partnership and 49.9% by NGP. The Partnership contributed approximately $221.0 million of existing assets, net of depreciation, to the Delaware Basin JV and committed an additional $285.0 million in capital to fund potential future development projects and potential acquisitions. NGP committed an aggregate of approximately $400.0 million of capital, including an initial contribution of $114.3 million, which the Delaware Basin JV distributed to the Partnership at the formation of the joint venture to reimburse the Partnership for capital spent to the date of formation on existing assets and ongoing projects. In addition to the initial contributions, the Partnership and NGP contributed $30.2 million and $30.1 million, respectively, to the Delaware Basin JV for the year ended December 31, 2016. As part of this agreement, NGP granted the Partnership call rights beginning in 2021 to acquire increasing portions of NGP’s interest in the joint venture at a price based upon a predetermined valuation methodology.

Lobo II Natural Gas Gathering and Processing Facility. In October 2016, the Partnership completed construction of a new cryogenic gas processing plant located in the Delaware Basin (the “Lobo II plant”) with initial capacity of 60 MMcf/d. The Lobo II expansion also included the construction of a 75-mile gathering system located in Texas and New Mexico. Construction on the Texas portion of the gathering system was completed in October 2016 and the remaining New Mexico pipeline was completed in the first quarter of 2017. The Lobo II facilities are part of the Delaware Basin JV.

Riptide Processing Plant. In April 2016, the Partnership completed construction of the Riptide processing plant in the Permian Basin. The plant provides 100 MMcf/d of processing capacity and is tied to approximately 50 miles of new gathering pipeline, all of which is connected to the Partnership’s MEGA system (as defined below).

Ascension Joint Venture. The Partnership have formed a 50/50 joint venture named Ascension Pipeline Company, LLC (the “Ascension JV”) with a subsidiary of Marathon Petroleum Corporation (“Marathon Petroleum”) to build a new

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30-mile NGL pipeline connecting the Partnership’s existing Riverside fractionation and terminal complex to Marathon Petroleum’s Garyville refinery located on the Mississippi River. The Partnership commenced construction of the pipeline during 2016 and will operate the pipeline upon completion, which is currently estimated to be during the second quarter of 2017. This bolt-on project to the Partnership’s Cajun-Sibon NGL system is supported by long-term, fee-based contracts with Marathon Petroleum.

Sale of Non-Core Assets

In December 2016, the Partnership entered into an agreement to sell its ownership interest in HEP for approximately $193.1 million, subject to customary closing conditions, including regulatory approvals. We expect the transaction to close in the first quarter of 2017. For the year ended December 31, 2016, the Partnership recorded an impairment loss of $20.1 million to reduce the carrying value of its investment to the expected sales price.

In December 2016, the Partnership sold the North Texas Pipeline (the “NTPL”), a 140-mile natural gas transportation pipeline, for $84.6 million. The Partnership maintains capacity on the NTPL at competitive rates and at levels sufficient to support current and expected operations. The Partnership recorded a loss related to the sale of $13.4 million.

Acquisitions in 2014 and 2015

On November 1, 2014, the Partnership acquired, from affiliates of Chevron Corporation, Gulf Coast natural gas pipeline assets predominantly located in southern Louisiana, together with 100% of the voting interests in certain entities, for approximately $231.5 million.

In 2014, the Partnership completed the drop down of certain equity interests in EnLink Appalachian Compression, LLC (formerly, E2 Appalachian Compression, LLC) and E2 Energy Services, LLC from us.

On January 31, 2015, the Partnership acquired 100% of the voting equity interests of LPC Crude Oil Marketing LLC (“LPC”), which has crude oil gathering, transportation and marketing operations in the Permian Basin, for approximately $108.1 million.

On October 1, 2015, the Partnership acquired 100% of the voting equity interests in a subsidiary of Matador Resources Company (“Matador”), which has gathering and processing assets operations in the Delaware Basin, for approximately $141.3 million.

Prior to November 2015, the Partnership co-owned the Deadwood natural gas processing plant with a subsidiary of Apache Corporation (“Apache”). On November 16, 2015, the Partnership’s acquired Apache’s 50% ownership interest in the Deadwood natural gas processing facility for approximately $40.1 million. the Partnership’s now own 100% of the Deadwood processing plant.

During 2015, the Partnership completed the EMH Drop Downs and a drop down transaction to acquire VEX from Devon.

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Our Assets

The Partnership’s 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 the Partnership’s assets as of and for the year ended December 31, 2016:


				Year Ended
				December 31, 2016
	Approximate
	Length	Compression (1)	Estimated	Average
Gathering and Transmission Pipelines	(Miles)	(HP)	Capacity (2)	Throughput (3)
Gas Pipelines
Texas Assets:
North Texas Assets (4)	3,980	341,600	2,892	2,377,300
Permian Basin Assets (5)	520	73,760	348	245,100
Oklahoma Assets:
Central Oklahoma System	1,040	206,000	745	585,200
Northridge System	140	14,000	65	44,300
Louisiana Assets:
Louisiana Gas System	3,145	97,400	3,975	1,676,500
Total Gas Pipelines	8,825	732,760	8,025	4,928,400
NGL, Crude Oil and Condensate Pipelines
Louisiana Assets:
Louisiana Liquids Pipeline System	720	—	130,000	104,900
Crude and Condensate Assets:
Ohio River Valley (6)	210	—	25,650	19,900
Victoria Express Pipeline	60	—	90,000	14,500
Permian Gathering (7)	270	—	85,800	55,500
Total NGL, Crude Oil and Condensate Pipelines	1,260	—	331,450	194,800

(1)

Includes power generation units.

(2)

Estimated capacity for gas pipelines is MMcf/d. Estimated capacity for liquids and crude and condensate pipelines is Bbls/d.

(3)

Average throughput for gas pipelines is MMBtu/d. Average throughput for liquids and crude and condensate pipelines is Bbls/d.

(4)

Includes throughput volumes of 256,700 MMbtu/d for the North Texas Pipeline, which was sold in December 2016.

(5)

Includes gross mileage, compression, capacity and throughput for the Delaware Basin JV, which is owned 50.1% by us.

(6)

Estimated capacity is comprised of trucking capacity only.

(7)

Estimated capacity is comprised of 26,100 Bbls/d of pipeline capacity and 59,700 Bbls/d of trucking capacity.


		Year Ended
		December 31,
		2016
	Processing	Average
	Capacity	Throughput
Processing Facilities	(MMcf/d)	(MMBtu/d)
Texas Assets:
North Texas Assets	1,080	890,900
Permian Basin Assets	503	282,300
Oklahoma Assets:
Central Oklahoma System	595	522,700
Northridge System	200	54,900
Louisiana Assets:
Louisiana Gas System	1,903	490,400
Total	4,281	2,241,200

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		Year Ended
		December 31,
		2016
	Estimated NGL
	Fractionation	Average
	Capacity	Throughput
Fractionation Facilities	(MBbls/d)	(MBbls/d)
Louisiana Liquids System	175	124
Gulf Coast Fractionators (1)	56	38
Texas Assets	30	—	(2)
Total	261	162

(1)

Volumes shown reflect only the Partnership’s net contractual right to the burdens and benefits of a 38.75% economic interest in Gulf Coast Fractionators held by Devon.

(2)

The Partnership has two small fractionation facilities of 15 MBbls/d each. The Partnership’s Mesquite Terminal in the Permian Basin and its Bridgeport processing plant in North Texas provide operational flexibility for the related processing plants, but are not the primary fractionation facilities for the NGLs produced by the processing plants. Under the Partnership’s current contracts, it does not earn fractionation fees for operating these fractionation facilities so throughput volumes through these fractionation facilities are not captured on a routine basis and are not significant to its operating margins.

Texas Assets. The Partnership’s Texas assets include transmission pipelines with a capacity of approximately 920 MMcf/d, processing facilities with a total processing capacity of approximately 1.6 Bcf/d and gathering systems with a capacity of approximately 2.3 Bcf/d.

Transmission System. The Acacia transmission system is a 130-mile pipeline that connects production from the Barnett Shale to markets in north Texas accessed by Atmos Energy, Brazos Electric, Midcoast Energy Partners, Energy Transfer Partners, Enterprise Product Partners and GDF Suez. The Acacia transmission system has approximately 920 MMcf/d of capacity and 16,600 horsepower of compression and, for the year ended December 31, 2016, average throughput was approximately 615,100 MMBtu/d. Devon is the Acacia transmission system’s only customer with approximately seven years remaining on a fixed-fee transportation agreement that covers transmission services and includes annual rate escalators.

Processing and Fractionation Facilities. The Partnership’s processing facilities in Texas include 10 gas processing plants and the Partnership’s 38.75% interest in GCF and consist of the following:

North Texas Assets. The Partnership’s North Texas processing systems include the following:

Bridgeport processing facility. The Partnership’s 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 that have a total of 800 MMcf/d of processing capacity and 15 MBbls/d of NGL fractionation capacity. For the year ended December 31, 2016, throughput volumes at the Bridgeport processing facility averaged 662,000 MMBtu/d of natural gas. Devon is the Bridgeport facility’s largest customer with approximately 656,700 MMBtu/d of natural gas processed for the year ended December 31, 2016. The Partnership currently has approximately seven years remaining on a fixed-fee processing agreement with Devon pursuant to which the Partnership provides processing services for natural gas delivered by Devon to the Bridgeport processing facility. This contractual arrangement includes an MVC from Devon of 650 MMcf/d of natural gas delivered to the Bridgeport processing facility that will remain in effect through January 1, 2019 and also provides annual rate escalators.

Silver Creek processing complex. The Partnership’s Silver Creek processing complex, located in Weatherford, Azle and Fort Worth, Texas, includes three processing plants. The Partnership’s Silver Creek plants have a total of 280 MMcf/d of processing capacity, with the Azle Plant, Silver Creek Plant and Goforth Plant accounting for 50 MMcf/d, 200 MMcf/d and 30 MMcf/d of processing capacity, respectively. For the year ended December 31, 2016, throughput volumes at the Silver Creek processing facility averaged 228,900 MMBtu/d of natural gas.

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Permian Basin processing facilities. The Partnership’s Permian Basin processing facilities consist of the following:

MEGA system processing facilities. The Partnership’s Permian Basin processing plants are located in Midland, Martin, and Glasscock counties, 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 175 MMcf/d and the Riptide processing facility with a capacity of 100 MMcf/d (collectively, the “Midland Energy Gathering Area” or “MEGA system”). For the year ended December 31, 2016, throughput volumes at the MEGA system averaged 258,000 MMBtu/d of natural gas.

Lobo processing facility. The Partnership’s Lobo natural gas processing facility is located in Loving County, Texas and has a total capacity of 95 MMcf/d. For the year ended December 31, 2016, throughput volumes at the Lobo facility averaged 24,300 MMBtu/d of natural gas. The Lobo Processing facility was contributed to the Delaware Basin JV on August 1, 2016.

Gathering Systems. The Partnership’s gathering systems in Texas include approximately 4,400 miles of pipeline.

North Texas Assets. The Partnership’s North Texas gathering systems include the following:

Bridgeport rich gathering system. This rich natural gas gathering system consists of approximately 2,240 miles of pipeline segments with approximately 145,000 horsepower of compression. A substantial majority of the natural gas gathered on the system is delivered to the Bridgeport processing facility. For the year ended December 31, 2016, throughput volumes on the Bridgeport rich gathering system averaged 685,200 MMBtu/d of natural gas. Devon is the largest customer on the Bridgeport rich gathering system with approximately 659,300 MMBtu/d of natural gas gathered for the year ended December 31, 2016. As described above, the Partnership currently has approximately seven years remaining on a fixed-fee gathering agreement with Devon pursuant to which the Partnership provides gathering services on the Bridgeport system, and the agreement includes an MVC from Devon that will remain in effect through January 1, 2019, with a combined 850 MMcf/d of natural gas to be delivered for gathering into the Bridgeport rich and Bridgeport lean gathering systems.

Bridgeport lean gathering system. This lean natural gas gathering system consists of approximately 600 miles of pipeline segments with approximately 59,000 horsepower of compression. Natural gas gathered on this system is delivered to the Acacia transmission system and intrastate pipelines without processing. For the year ended December 31, 2016, throughput volumes on the Bridgeport lean gathering system averaged 216,600 MMBtu/d of natural gas, all of which were attributable to Devon. As described above, The Partnership is party to a fixed-fee gathering and processing agreement with Devon that covers gathering services on the Bridgeport system.

Johnson County gathering system. This natural gas gathering system consists of approximately 290 miles of pipeline segments with approximately 44,000 horsepower of compression. Natural gas gathered on this system is delivered to intrastate pipelines without processing. For the year ended December 31, 2016, throughput volumes on the Johnson County gathering system averaged 143,200 MMBtu/d of natural gas, which were primarily attributable to Devon. The Partnership currently has approximately seven years remaining on a fixed-fee gathering agreement pursuant to which the Partnership provides gathering services on the Johnson County gathering system. This contractual arrangement includes an MVC from Devon that will remain in effect through January 1, 2019, with 125 MMcf/d of natural gas to be delivered for gathering into the Johnson County gathering system and also provides annual rate escalators.

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Silver Creek gathering systems. The Partnership’s Silver Creek gathering system consists of approximately 720 miles of gathering lines with approximately 77,000 horsepower of compression and had an average throughput of approximately 460,500 MMBtu/d for the year ended December 31, 2016

Permian Basin assets. The Partnership’s Permian Basin gathering systems include the following:

MEGA System gathering facilities. The Partnership’s gathering system in the Permian Basin consists of the 140-mile Bearkat gathering system with 19,000 horsepower of compression, and the 300-mile Midland Basin gathering system with 52,000 horsepower of compression. For the year ended December 31, 2016 throughput averaged 220,900 MMBtu/d.

Lobo gathering system. The rich natural gas gathering system consists of 80 miles of gathering pipeline with approximately 2,760 horsepower of compression. For the year ended December 31, 2016, throughput volumes averaged 24,200 MMBtu/d. The Lobo gathering system was contributed to the Delaware Basin JV on August 1, 2016.

Oklahoma Assets. The Partnership’s Oklahoma assets consist of processing facilities with a total processing capacity of approximately 795 MMcf/d and gathering systems with total capacity of approximately 810 MMcf/d.

Oklahoma processing system. The Partnership’s processing facilities include the following:

Central Oklahoma processing system. The central Oklahoma plants include the 120 MMcf/d Chisholm plant, the 75 MMcf/d Battle Ridge plant and the 400 MMcf/d Cana processing facilities (collectively, the “central Oklahoma processing system”). The residue natural gas from the Cana processing facility is delivered to Enable Midstream Partners and ONEOK Partners. Devon is the primary customer of the Cana processing facilities and has approximately seven 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. Throughput for the central Oklahoma processing system for the year ended December 31, 2016 averaged 522,700 MMBtu/d. In addition, contractual arrangements related to the central Oklahoma processing system that contain an MVC include the following:

The Partnership’s contractual arrangement with Devon includes an MVC that will remain in effect until October 2020. For 2017, the MVC dictates that approximately 103 MMcf/d of natural gas will be delivered to the Chisholm plant processing facility. The MVC escalates quarterly, resulting in approximately 230 MMcf/d to be delivered in 2020. The contractual arrangement also provides annual rate escalators.

The Partnership has another contractual arrangement with Devon that includes an MVC that will remain in effect until January 1, 2019, with 330 MMcf/d of natural gas to be delivered to the Cana processing facility, and provides annual rate escalators.

Northridge processing plant. The Partnership’s Northridge processing plant has 200 MMcf/d of processing capacity. For the year ended December 31, 2016, throughput volumes at the Northridge processing facility averaged 54,900 MMBtu/d. The residue natural gas from the Northridge processing facility is delivered to Centerpoint, Enable Midstream Partners and MarkWest.

Oklahoma gathering system. The Partnership’s Oklahoma gathering systems include the following:

Central Oklahoma gathering system. The Partnership’s central Oklahoma gathering system consists of the 350-mile Chisholm gathering system with approximately 80,000 horsepower of compression, the 250-mile Battle Ridge gathering system with approximately 38,000 horsepower of compression and the 440-mile Cana gathering system with approximately 88,000 horsepower of compression (collectively, the “central Oklahoma gathering system”). The central Oklahoma gathering system serves the STACK and CNOW plays. For the year ended December 31, 2016, throughput averaged

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585,200 MMbtu/d. In addition, contractual arrangements related to the central Oklahoma gathering system that contain an MVC include the following:

The Partnership’s contractual arrangement with Devon includes an MVC that will remain in effect until October 2020. For 2017, the MVC dictates that approximately 103 MMcf/d of natural gas will be handled through the Chisholm gathering system. The MVC escalates quarterly, resulting in approximately 230 MMcf/d to be delivered in 2020. The contractual arrangement also provides annual rate escalators.

The Partnership has another contractual arrangement with Devon that includes an MVC that will remain in effect until January 1, 2019, with 330 MMcf/d of natural gas to be handled through the Cana gathering system, and provides annual rate escalators.

Northridge gathering system. The Partnership’s Northridge gathering system is located in the Arkoma-Woodford Shale in Southeastern Oklahoma and includes an approximately 140-mile gathering system with approximately 14,000 horsepower of compression. For the year ended December 31, 2016, the Northridge system gathered 44,300 MMBtu/d of gas.

Louisiana Assets. The Partnership’s Louisiana assets consist of transmission pipelines with a capacity of approximately 3.5 Bcf/d, processing facilities with a total processing capacity of approximately 1.9 Bcf/d and gathering systems with total capacity of approximately 510 MMcf/d.

Louisiana Gas Pipeline and Processing Systems. The Louisiana gas pipeline system includes gathering and transmission systems with a capacity of approximately 4.0 Bcf/d and processing facilities with total processing capacity of approximately 1.9 Bcf/d and underground gas storage of 19.2 Bcf/d

Gas Gathering and Transmission Systems. The Partnership’s gathering and transmission systems include 3,145 miles of gathering and transmission systems with a total capacity of 4.0 bcf/d. The systems have a combined 97,400 horsepower of compression. The systems have access to both rich and lean gas supplies from onshore production in south central and southeast Louisiana and a variety of transportation and industrial sale customers in south Louisiana, with the majority of its sales being made into the industrial Mississippi River corridor between Baton Rouge and New Orleans. This system also serves the natural gas fields south of Shreveport, Louisiana and extends into the Haynesville Shale plays in north Louisiana. For the year ended December 31, 2016, throughput volumes on the gathering system averaged 671,500 MMBtu/d of natural gas, and throughput volumes on the transmission system averaged 1,005,000 MMBtu/d of natural gas.

Gas Processing and Storage Facilities. The Partnership’s processing facilities in Louisiana include five gas processing plants, of which three are currently operational, with total processing throughput that averaged 490,400 MMBtu/d for the year ended December 31, 2016.

Plaquemine Processing Plant. The Plaquemine processing plant has 225 MMcf/d of processing capacity. For the year ended December 31, 2016, throughput volumes of the Plaquemine processing plant averaged 156,000 MMBtu/d of natural gas.

Gibson Processing Plant. The Gibson processing plant has 110 MMcf/d of processing capacity. For the year ended December 31, 2016, throughput volumes of the Gibson processing plant averaged 41,000 MMBtu/d of natural gas.

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. For the year ended December 31, 2016, the plant processed approximately 293,400 MMBtu/d of natural gas. The Pelican 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 the Partnership to process natural gas from this system at our Pelican plant when markets are favorable.

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Blue Water Gas Processing Plant. The Partnership operates and owns a 64.29% interest in the Blue Water gas processing plant. The Blue Water plant is located in Crowley, Louisiana and is connected to the Blue Water pipeline system. The Partnership’s share of the plant’s capacity is approximately 193 MMcf/d. The plant is not expected to operate in the future unless fractionation spreads are favorable and 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 475 MMcf/d of natural gas. In August 2013, the Partnership shut down the Eunice processing plant due to adverse economics driven by low NGL prices and low processing volumes, which the Partnership does not see improving in the near future based on forecasted prices.

Belle Rose Gas Storage Facility. The Belle Rose storage facility is located in Assumption Parish, Louisiana and has a total capacity of 11.9 Bcf. This facility was placed in service in May 2016 and is designed for injecting pipeline quality gas into storage or withdrawing stored gas for delivery by pipeline. The storage facility includes three compressors with a total of 9,637 horsepower.

Sorrento Gas Storage Facility. The storage facility is located in Assumption Parish, Louisiana and has a total capacity of 7.3 Bcf. This facility is designed for injecting pipeline quality gas into storage or withdrawing stored gas for delivery by pipeline. There are three compressors with a total of 6,600 horsepower.

Louisiana Liquids Pipeline System. The Partnership’s Louisiana liquids pipeline system includes approximately 720 miles of liquids transport lines, processing and fractionation assets and underground storage.

Cajun-Sibon Pipeline System. The Cajun-Sibon pipeline system consists of approximately 720 miles of raw make NGL pipelines with a current system capacity of approximately 130,000 Bbls/d. For the year ended December 31, 2016, average throughput was approximately 104,900 MMBtu/d. The pipelines transport unfractionated NGLs, referred to as “raw make,” from areas such as the Liberty, Texas interconnects near Mont Belvieu and from our Eunice and Pelican processing plants in south Louisiana to either the Riverside or Eunice fractionators or to third party fractionators when necessary.

Fractionation Facilities. There are four fractionation facilities located in Louisiana that averaged 123,700 Bbls/d for the year ended December 31, 2016.

Plaquemine Fractionation Facility. The Plaquemine fractionator is located at the Plaquemine gas processing plant complex and is connected to the Partnership’s Cajun-Sibon pipeline. The Plaquemine fractionation facility produces purity ethane and propane for sale by pipeline to long-term markets with the butane and heavier products sent to the Partnership’s Riverside facility for further processing. The Plaquemine fractionator collectively with the Riverside Fractionation Facility has an approximate capacity of 110,000 Bbls/d of raw-make NGL products. The Plaquemine facility fractionated 55,400 Bbls/d for the year ended December 31, 2016.

The Plaquemine Gas Processing Plant. The Plaquemine Gas Processing Plant has a fractionator with a capacity of 11,000 Bbls/d of raw-make NGL products, and total volume for fractionated liquids at Plaquemine averaged approximately 3,600 Bbls/d for the year ended December 31, 2016.

Eunice Fractionation Facility. The Eunice fractionation facility is located in south central Louisiana. The Eunice fractionation facility has a capacity of 55,000 Bbls/d of liquid products, including ethane, propane, iso-butane, normal butane and natural gasoline, and is directly connected to the southeast propane market and pipelines to the Anse La Butte storage facility. The plant fractionated 36,600 Bbls/d of liquids for the year ended December 31, 2016.

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Riverside Fractionation Facility. The Riverside fractionator and loading facility is located on the Mississippi River upriver from Geismar, Louisiana. The Riverside plant has a fractionation capacity of approximately 32,000 Bbls/d of liquids delivered by the Cajun-Sibon pipeline system from the Eunice and Pelican processing plants or by third-party truck and rail assets. The Riverside facility has above-ground storage capacity of approximately 278,300 Bbls. The loading/unloading facility has the capacity to transload 15,000 Bbls/d of crude oil and condensate from rail cars to barges. Total volumes for fractionated liquids at Riverside averaged 28,100 Bbls/d for the year ended December 31, 2016.

Napoleonville Storage Facility. The Napoleonville NGL storage facility is connected to the Riverside facility and has a total capacity of 3.2 million barrels of underground storage comprised of two existing caverns. The caverns are currently operated in butane service, and space is leased to customers for a fee.

Ohio River Valley. The Partnership’s Ohio River Valley (“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 and approximately 210 miles of crude oil and condensate pipelines in Ohio and West Virginia. The assets also include over 500,000 barrels of above ground storage and a trucking fleet of approximately 86 vehicles comprised of both semi and straight trucks, and trailers for hauling NGL volumes with a current capacity of 25,650 Bbls/d. Total crude oil and condensate handled averaged approximately 19,900 Bbls/d for the year ended December 31, 2016. The Partnership has eight existing brine disposal wells with an injection capacity of approximately 4,000 Bbls/d and an average disposal rate of 3,600 Bbls/d for the year ended December 31, 2016. Additionally, our ORV operations include eight condensate stabilization and natural gas compression stations with combined capacities of over 36,000 Bbls/d of condensate stabilization and 780 MMcf/d of natural gas compression. These stations are in service and are supported by long-term, fee-based contracts with multiple producers.

Permian Crude and Condensate. The Partnership’s Permian Crude and Condensate assets have crude oil gathering, transportation and marketing operations in the Permian Basin with a current capacity of approximately 85,800 Bbls/d. Their integrated logistics services are supported by 54 tractor trailers, 14 pipeline injection stations and 85 miles of crude oil gathering pipeline. Total crude oil and condensate handled averaged approximately 54,500 Bbls/d for the year ended December 31, 2016.

Additionally the Partnership is constructing a new crude oil gathering system in Upton and Midland counties, Texas in the Permian Basin referred to as “Greater Chickadee.” Greater Chickadee includes approximately 185 miles of high- and low-pressure pipelines that will transport crude oil volumes to several major market outlets and other key hub centers in the Midland, Texas area. Greater Chickadee also includes the construction of multiple central tank batteries and pump, truck injection, and storage stations to maximize shipping and delivery options for the Partnership’s producer customers. The initial phase of our Greater Chickadee transportation service began in November 2016. For the year ended December 31, 2016, throughput volumes averaged 1,000 Bbls/d. For the period of commencement of service to December 31, 2016, throughput volumes averaged 6,200 Bbls/d. Additional construction is ongoing, and the Partnership expects the gathering system to reach full service in the first quarter of 2017.

Victoria Express Pipeline. The VEX pipeline is a 60-mile, multi-grade crude oil pipeline with a current capacity of approximately 90,000 Bbls/d. Other VEX assets include the Cuero Terminal and Port of Victoria Terminal and Barge Docks. The Cuero truck unloading terminal at the origin of the VEX system contains 8 unloading bays and 200,000 bbls of above-ground storage capacity for receipt from and delivery to the VEX pipeline. The VEX pipeline terminates at the Port of Victoria Terminal that also has an 8-bay truck unloading dock and 200,000 bbls of above-ground storage capacity. The Port of Victoria Terminal

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delivers to two barge loading docks at the Port of Victoria. Total crude oil and condensate handled averaged approximately 14,500 Bbls/d for the year ended December 31, 2016. The Partnership has an agreement with Devon, which includes an MVC of 30,000 Bbls/d, that will remain in effect until July 2019.

Corporate. The Partnership’s Corporate assets primarily consist of a contractual right to the benefits and burdens associated with Devon’s 38.75% ownership interest in GCF, an approximate 31% ownership interest in HEP, and a 30% ownership interest in the Cedar Cove Joint Venture.

Gulf Coast Fractionators. The Partnership is entitled to receive the economic benefits and burdens of the 38.75% interest in GCF held by Devon, with the remaining interests owned 22.5% by Phillips 66 and 38.75% by Targa Resources Partners. 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 the customers for a fee. The facility has a capacity of approximately 145 MBbls/d. The plant fractionated approximately 38,000 Bbls/d of liquids for the year ended December 31, 2016.

Howard Energy Partners As of December 31, 2016, the Partnership owned an approximate 31% interest in HEP and accounted for this investment under the equity method of accounting. In December 2016, the Partnership entered into an agreement to sell its ownership in HEP to Alberta Investment Corp for approximately $193.1 million. The transaction is expected to close during the first quarter of 2017.

Cedar Cove Joint Venture. On November 9, 2016 the Partnership formed a joint venture with Kinder Morgan, Inc. consisting of gathering and compression assets in Blaine County, Oklahoma. The gathering system has a capacity of 25 MMcf/d and ties into the Partnerships existing Oklahoma assets. All gas gathered by Cedar Cove will be processed at the Partnerships central Oklahoma plants.

Industry Overview

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

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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 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

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disposal location, water is processed and filtered to remove impurities and injection wells place fluids underground for storage and disposal.

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 the Partnership purchases natural gas, crude oil and condensate, we establish a margin normally by selling it for physical delivery to third-party users. The Partnership 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 its natural gas purchases. Through these transactions, the Partnership seeks to maintain a position that is balanced between (1) purchases and (2) sales or future delivery obligations. The Partnership’s policy is not to acquire and hold natural gas 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. The Partnership faces strong competition in obtaining natural gas, NGLs, crude oil and condensate supplies and in the marketing and transportation of natural gas, NGLs, crude oil and condensate. The Partnership’s competitors include major integrated and independent exploration and production companies, natural gas producers, interstate and intrastate pipelines, other natural gas, NGLs, 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. As a result of certain of the Partnership’s contractual relationships with Devon, the Partnership will not compete for the portion of Devon’s existing operations subject to existing acreage dedication for the terms of such contracts. For areas where acreage is not dedicated to us, we will compete with similar enterprises in providing additional gathering and processing services in its respective areas of operation, which may offer more services or have strong 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 the Partnership has 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 its marketing operations.

The Partnership faces 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. The Partnership’s competitors may have greater financial resources than it possesses or may be willing to accept lower returns or greater risks. Competition differs by region and by the nature of the business or the project involved.

Natural Gas, NGL, Crude Oil and Condensate Supply

The Partnership’s gathering and transmission pipelines have connections with major intrastate and interstate pipelines, which it believes have ample natural gas and NGL supplies in excess of the volumes required for the operation of these systems. The Partnership evaluates 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 its gathering systems and assets to determine the availability of natural gas, NGLs, crude oil and condensate supply for its systems and assets and/or obtain an MVC from the producer that results in a rate of return on investment. The Partnership does not routinely obtain independent evaluations of reserves dedicated to its systems and assets due to the cost and relatively limited

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benefit of such evaluations. Accordingly, the Partnership does not have estimates of total reserves dedicated to its systems and assets or the anticipated life of such producing reserves.

Credit Risk and Significant Customers

The Partnership is subject to risk of loss resulting from nonpayment or nonperformance by its customers and other counterparties, such as its lenders and hedging counterparties. The Partnership diligently attempts to ensure that it issues credit to only credit-worthy customers. However, the Partnership’s purchase and resale of crude oil, condensate, NGLs and natural gas exposes it 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 the Partnership’s overall profitability. Some of the Partnership’s customers have filed for bankruptcy protection, and their debts and payments to it are subject to laws governing bankruptcy. Moreover, the combination of a reduction of cash flow resulting 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 the Partnership’s customers’ liquidity and ability to make payment or perform on their obligations to the Partnership. Furthermore, some of the Partnership’s 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 the Partnership. A substantial portion of the Partnership’s throughput volumes come from producers that have investment-grade ratings; however, many of its customers’ equity values have substantially declined and some of these customers, including Devon, have had their credit ratings downgraded by major credit ratings agencies.

For the years ended December 31, 2016, 2015 and 2014, Devon represented 18.5%, 16.6% and 30.6%, respectively, of the Partnership’s consolidated revenues and Dow Hydrocarbons & Resources LLC (“Dow Hydrocarbons”) represented 10.8%, 11.7% and 11.0%, respectively, of the Partnership’s consolidated revenues. No other customer represented greater than 10.0% of the Partnership’s revenue. The Partnership’s operations are dependent on the volume of natural gas that Devon provides to us under commercial agreements, which constitutes a substantial portion of the Partnership’s natural gas supply. The loss of Devon or Dow Hydrocarbons as a customer could have a material impact on the Partnership’s results of operations if it were not able to gather, transport or process Devon’s gas or sell Dow Hydrocarbons’ products to another customer with similar margins because the gross operating margins received from transactions with Devon and Dow Hydrocarbons are material to the Partnership’s total gross operating margin.

Regulation

Interstate Natural Gas Pipeline Regulation. The Partnership owns interstate natural gas pipelines that are subject to regulation as natural gas companies by the Federal Energy Regulatory Commission (“FERC”) under the Natural Gas Act (“NGA”). These assets include the Partnership’s Acacia transmission system and its Louisiana gas pipeline system. FERC regulates the rates and terms and conditions of service on interstate natural gas pipelines, as well as the certification, construction, extension and abandonment of facilities.

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

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

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considering whether, and if so, to what extent, pipelines owned by pass-through entities such as MLPs may include income tax allowance in rates to compensate for the income tax liability of investors.

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. 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 make any statement necessary to make the statements made not misleading; or (3) engage in any act or practice that operates 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 and will continue to be adjusted periodically for inflation. Should the Partnership fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, the Partnership could be subject to substantial penalties and fines.

The Partnership’s 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 intrastate transportation services must be “fair and equitable.” Such rates are generally subject to review every five years by FERC or by an appropriate state agency.

Interstate Liquids Pipeline Regulation. The Partnership owns 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. These assets include the Partnership’s ORV, VEX, Chickadee and Cajun-Sibon NGL pipelines.

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 rates charged by the Partnership’s interstate liquids pipelines may also be affected by the ongoing uncertainty regarding FERC’s current income tax allowance policy discussed above.

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 the Partnership’s ability to set rates based on its costs or could order the Partnership to reduce its 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 the Partnership’s terms and conditions of service if it determines that they are unjust and unreasonable or unduly discriminatory or preferential.

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As the Partnership acquires, constructs and operates new liquids assets and expands its liquids transportation business, the classification and regulation of its liquids transportation services are subject to ongoing assessment and change based on the services the Partnership provides and determinations by FERC and the courts. Such changes may subject additional services the Partnership provides to regulation by FERC.

Intrastate Natural Gas Pipeline Regulation. In addition to the Section 311 regulation discussed above, the Partnership’s intrastate natural gas pipeline operations are subject to regulation by various state agencies. Most state agencies possess the authority to review and authorize natural gas transportation transactions and the construction, acquisition, abandonment and interconnection of physical facilities. State agencies also may regulate transportation rates, service terms and conditions and contract pricing.

Intrastate Liquids Pipeline Regulation. 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. The Partnership owns a number of natural gas pipelines that it believes 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 the Partnership’s gathering facilities are subject to change. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation.

In addition, the Partnership is 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.

Intrastate Natural Gas Storage Regulation. The storage field injection and withdrawal wells used in association with the Partnership’s Acacia system, along with water disposal wells located at the Partnership’s Bridgeport processing facility, are subject to the jurisdiction of the Railroad Commission of Texas (“TRRC”). TRRC regulations require that the Partnership 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, the Partnership’s 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.

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

Employee Safety. The Partnership is 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. The Partnership believes that its 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. The Partnership’s pipelines are subject to regulation by the DOT’s Pipeline and Hazardous Materials Safety Administration (“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

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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.

The Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 increased penalties for safety violations, established additional safety requirements for newly constructed pipelines and required studies of certain safety issues that could result in the adoption of new regulatory requirements for existing pipelines. In April 2016, PHMSA published a notice of proposed rulemaking, or NPRM, addressing natural gas transmission and gathering lines. The proposed rule would, among other things, change existing integrity management requirements, expand assessment and repair requirements to pipelines in “moderate-consequence areas,” including areas of medium population density and increase requirements for monitoring and inspection of pipeline segments located outside of HCAs. Further, this NPRM would require that records or other data relied on to determine operating pressures must be traceable, verifiable and complete. Locating such records and, in the absence of any such records, verifying maximum pressures through physical testing or modifying or replacing facilities, could significantly increase the Partnership’s costs. Additionally, failure to locate such records or verify maximum pressures could result in the reduction of allowable operating pressures, which would reduce available capacity on the Partnership’s pipelines.

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. Pursuant to the PIPES Act, on December 14, 2016, PHMSA issued an interim final rule (“IFR”) that addresses safety issues related to downhole 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. Along with other operators of natural gas storage facilities, the Partnership will have one year from January 18, 2017, the effective date of the IFR to implement this first set of PHMSA regulations governing underground storage fields.

In addition, on January 13, 2017, PHMSA finalized new hazardous liquid pipeline safety regulations extending certain regulatory reporting requirements to all hazardous liquid gathering (including oil) pipelines. The final rule requires additional event-driven and periodic inspections, requires the use of leak detection systems on all hazardous liquid pipelines, modifies repair criteria, and requires certain pipelines to eventually accommodate in-line inspection tools. The effective date of this final rule is currently uncertain due to a regulatory freeze implemented by the Trump administration on January 20, 2017.

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, renews existing special permits, and incorporates certain standards for in-line inspections and stress corrosion cracking assessments. The effective date of the final rule would have been March 24, 2017; however, the rule is subject to a regulatory freeze pending review by the Trump administration, unless exempted by PHMSA and OMB due to health and safety considerations.

At the state level, several states have passed legislation or promulgated rulemaking dealing with pipeline safety. The Partnership believes that its 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 the Partnership’s financial condition, results of operations or cash flows.

On November 2, 2015, PHMSA issued a Notice of Probable Violation and Proposed Compliance Order (the “NOPV”) asserting that the Partnership has probable violations of 49 CFR Part 195 due to the misclassification of a transmission line as a gathering line. Transmission lines are subject to more fulsome pipeline safety regulations than gathering lines. The NOPV proposed a compliance order requiring us to satisfy the Part 195 requirements applicable to transmission lines but did not propose a penalty. The Partnership disagrees with the assertion of PHMSA that the pipeline meets the definition of a transmission rather than gathering line. Accordingly, on December 30, 2015, the Partnership objected to the NOPV and requested a hearing. The hearing took place on July 27, 2016, and the Partnership is awaiting a decision from PHMSA regarding the arguments presented at the hearing. We cannot predict the outcome of the Partnership’s challenge. In the event the pipeline in question is ultimately treated as a transmission line rather than a

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gathering line, the Partnership estimates that it would incur costs of approximately $2.1 million over a two-year period to develop and implement a Part 195-compliant integrity management program, including hydrostatic testing and a leak detection and repair program.

Environmental Matters

General. The Partnership’s operations involve processing and pipeline services for delivery of hydrocarbons (natural gas, NGLs, crude oil and condensates) from point-of-origin at oil and gas wellheads operated by its suppliers to the Partnership’s end-use market customers. The Partnership’s 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 the Partnership’s industrial sector, the Partnership’s operations are subject to stringent and complex federal, state and local laws and regulations relating to 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 the Partnership’s 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, 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 the Partnership’s operations, it 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 the Partnership currently anticipates. Moreover, risks of process upsets, accidental releases or spills are associated with possible future operations, and the Partnership cannot assure you that we will not incur significant costs and liabilities, including those relating to claims for damage to property and persons as a result of any such upsets, releases or spills. The Partnership may be unable to pass on current or future environmental costs to its 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 the Partnership to substantial expenses, 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. The Partnership attempts to anticipate future regulatory requirements that might be imposed and plan accordingly to comply with changing environmental laws and regulations and to minimize costs with respect to more stringent future laws and regulations or more rigorous enforcement of existing laws and regulations.

Hazardous Substances and Solid Waste. Environmental laws and regulations that relate to the release of hazardous substances or solid wastes into soils, sediments, groundwater and surface water and/or include measures to prevent and control pollution may pose the highest potential cost 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 persons 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, the Partnership may generate wastes that may fall within the

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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, the Partnership 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. The Partnership has not received any notification that it may be potentially responsible for cleanup costs under CERCLA or any analogous federal, state, or local law.

The Partnership also generates, 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 the Partnership 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 the Partnership’s capital expenditures or plant operating expenses or otherwise impose limits or restrictions on our production and operations.

The Partnership currently owns or leases, has 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 the Partnership 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 the Partnership had no control. These properties and wastes disposed thereon may be subject to the Safe Drinking Water Act, CERCLA, RCRA, TSCA and analogous state laws. Under these laws, the Partnership 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. The Partnership’s 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 the Partnership’s facilities, and impose various control, monitoring and reporting requirements. Pursuant to these laws and regulations, the Partnership 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. The Partnership 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 the Partnership’s financial condition, results of operations, or cash flows, and the requirements are not expected to be more burdensome to the Partnership than to any similarly situated company.

In addition, the EPA included Wise County, the location of the Partnership’s Bridgeport facility, in its January 2012 revision to the Dallas-Ft. Worth ozone nonattainment area for the 2008 revised ozone national ambient air quality standard (“NAAQS”). As a result of this designation, new major sources in Wise County, meaning sources that emit greater than 100 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 40 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 1.15 to 1 ratio. On October 26, 2016, the EPA finalized its 2015 revised ozone NAAQS that, if implemented, will further restrict ozone within the Dallas-Ft. Worth nonattainment area. The 2015 ozone NAAQS are being challenged in the U.S. Court of Appeals for the D.C. Circuit. The appeal remains pending.

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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 and has indicated that it may reconsider other aspects of the rules. Depending on the outcome of such proceedings, the rules may be further modified or rescinded or the EPA may issue new rules. We cannot predict the costs of compliance with any modified or newly issued rules.

In partial response to the issues raised regarding the 2012 rulemaking, the EPA recently finalized new rules that took effect August 2, 2016 to regulate emissions of methane and VOCs from new and modified sources in the oil and gas sector. 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, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting processes and requirements across the oil and gas industry. On November 10, 2016, the EPA issued a final Information Collection Request (“ICR”) that requires numerous oil and gas companies to provide information regarding methane emissions from existing oil and gas facilities, a step used to provide a basis for future rulemaking. The Partnership has received numerous EPA ICR requests and is meeting with the EPA to discuss simplifying the requests. The EPA has delayed the Partnership’s ICR response deadline until these issues are resolved. The Obama Administration also indicated that other federal agencies, including the Bureau of Land Management (“BLM”), the Pipeline and Hazardous Materials Safety Administration (“PHMSA”), and the Department of Energy would be imposing 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. 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 new Trump Administration is 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.

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 the Partnership 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 the Partnership’s litigation risk for such claims. In addition, in 2015, the United States participated in the United

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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. The status of the United States’ commitment to Paris Agreement under the Trump Administration remains to be determined. 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 the Partnership.

Federal or state legislative or regulatory initiatives that regulate or restrict emissions of greenhouse gases in areas in which the Partnership conducts business could adversely affect the availability of, or demand for, the products the Partnership stores, transports and processes, and, depending on the particular program adopted, could increase the costs of the Partnership’s operations, including costs to operate and maintain its facilities, install new emission controls on its facilities, acquire allowances to authorize its greenhouse gas emissions, pay any taxes related to its greenhouse gas emissions and/or administer and manage a greenhouse gas emissions program. The Partnership may be unable to recover any such lost revenues or increased costs in the rates the Partnership charges its customers, and any such recovery may depend on events beyond the Partnership’s 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 the Partnership’s revenues or increases in its expenses as a result of climate control initiatives could have adverse effects on the Partnership’s business, financial condition, results of operations and cash flows.

Due to its location, the Partnership’s 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. The Partnership’s insurance may not cover all associated losses. The Partnership is 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 its 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 finalized a rule intended to clarify the meaning of the term “waters of the United States,” which establishes the scope of regulated waters under the Clean Water Act. The rule has been challenged and was stayed by federal courts. Absent Congressional action, the rule will become applicable if the courts do not continue the stay of the rule during the litigation; if upheld, the rule is expected to expand federal jurisdiction under the Clean Water Act. 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. The Partnership believes that it is in substantial compliance with Clean Water Act permitting requirements as well as the conditions imposed by their permits and that continued compliance with such existing permit conditions will not have a material effect on the Partnership’s financial condition, results of operations and cash flows.

The Partnership operates 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. The Partnership’s brine disposal wells are also subject to comparable state laws and regulations, which in some cases are more stringent than requirements under the federal 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 the Partnership’s brine disposal operations, as well as adversely affect demand for the Partnership’s 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

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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 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. 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 the Partnership’s brine disposal operations.

It is common for the Partnership’s 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 the Partnership’s customers and suppliers. There are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices. On December 13, 2016, the EPA released a study of the potential adverse effects that hydraulic fracturing may have on water quality and public health, concluding that there is scientific evidence that hydraulic fracturing activities potentially can impact drinking water resources in the United States under some circumstances. This study or similar studies could spur initiatives to further regulate hydraulic fracturing. In June 2016, the EPA finalized rules prohibiting discharges of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. The EPA has also issued an advance notice of proposed rulemaking under the Toxic Substances Control Act to gather information regarding the potential regulation of chemical substances and mixtures used in oil and gas exploration and production. Also, effective June 24, 2015, BLM adopted rules regarding well stimulation, chemical disclosures, water management, and other requirements for hydraulic fracturing on federal and Indian lands; however, a federal district court invalidated these BLM rules in June 2016 and an appeal is pending. Additional regulatory burdens in the future, whether federal, state or local, could increase the cost of or restrict the ability of the Partnership’s 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 the Partnership’s customers move through our gathering systems which would materially adversely affect the Partnership’s revenues and 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 Endangered Species Act can also make it more difficult to secure a federal permit for a new pipeline.

Office Facilities

The Partnership occupies approximately 109,400 square feet of space at our executive offices in Dallas, Texas under a lease expiring in August 2019. In November 2014, the Partnership entered into a new agreement to lease approximately 157,600 square feet of space for its executive offices in Dallas, Texas with a lease term commencing in August 2016 and expiring in February 2030.

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Employees

As of December 31, 2016, the Partnership (through its subsidiaries) employed approximately 1,472 full-time employees. Approximately 336 of the Partnership’s employees were general and administrative, engineering, accounting and commercial personnel and the remainder were operational employees. The Partnership is not party to any collective bargaining agreements and it has not had any significant labor disputes in the past. The Partnership believes that it has good relations with its 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, cash flows (including our ability to make distributions to our noteholders) could be affected materially and adversely. In that case, we may be unable to make distributions to our unitholders and the trading price of our common units could decline. Because EnLink Oklahoma T.O. and its subsidiaries are controlled by the Partnership and have similar operations to the Partnership, references to the “Partnership” in this report should also be read to include EnLink Oklahoma T.O. when applicable, including general references to the Partnership’s business in the following risk factors. These risk factors should be read in conjunction with the other detailed information concerning us 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 an Investment in EnLink Midstream

Devon owns approximately 64.1% of our outstanding common units as of February 8, 2017 and controls the Managing Member, which has sole responsibility for conducting our business and managing our operations. Our manager and its affiliates, including Devon, have conflicts of interest with us and limited duties to us and may favor their own interests to your detriment.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Devon may compete with us.

Devon may compete with us, including by developing or acquiring additional gathering and processing assets. Pursuant to the terms of our operating agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to the Managing Member or any of its affiliates, including Devon and its executive officers and directors. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any of our members for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of the Managing Member and result in less than favorable treatment of us and our unitholders.

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

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

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

Our operating agreement contains provisions that eliminate and replace the fiduciary standards that the Managing Member would otherwise be held to by state fiduciary duty law. For example, our operating agreement permits the Managing Member to make a number of decisions, in its individual capacity, as opposed to in its capacity as the

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Managing Member, or otherwise, free of fiduciary duties to us and our unitholders. This entitles the Managing Member to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our members. Examples of decisions that the Managing Member may make in its individual capacity include:

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

whether to exercise its call right;

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

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

whether or not the manager should elect to seek the approval of the conflicts committee or the unitholders, or neither, of any conflicted transaction.

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

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

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

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

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

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

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

brought in a derivative manner on our behalf;

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

asserting a claim arising pursuant to any provision of the DLLCA; or

asserting a claim governed by the internal affairs doctrine;

must be exclusively brought in the Court of Chancery of the State of Delaware (or, if such court does not have subject matter jurisdiction thereof, any other court located in the State of Delaware with subject matter jurisdiction), regardless of whether such claims, suits, actions or proceedings sound in contract, tort, fraud or otherwise, are based on common law, statutory, equitable, legal or other grounds, or are derivative or direct

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claims. By purchasing our common units, a member is irrevocably consenting to these limitations and provisions regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of the Court of Chancery of the State of Delaware (or such other Delaware courts) in connection with any such claims, suits, actions or proceedings;

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

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

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

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

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

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

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

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

Our unitholders are unable to remove the Managing Member without its consent because the Managing Member and its affiliates own sufficient units to be able to prevent its removal. The vote of the holders of at least 66 2/3% of all outstanding common units voting together as a single class is required to remove the managing member. As of February 8, 2017, the Managing Member and its affiliates owned approximately 64.1% of the outstanding ENLC Common Units.

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

Unitholders’ voting rights are further restricted by our operating agreement, which provides that any units held by a person that owns 20% or more of any class of units, other than the Managing Member, its affiliates, their transferees and

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persons who acquired such units with the prior approval of the board of directors of the Managing Member, cannot vote on any matter.

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

Our manager may transfer its managing member interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of our unitholders. Furthermore, our operating agreement does not restrict the ability of Devon to transfer all or a portion of the ownership interest in the Managing Member to a third party. If the managing member interest were transferred, the new owner of the Managing Member would then be in a position to replace the board of directors and officers of the Managing Member with its own choices and thereby exert significant control over the decisions made by such board of directors and officers. This effectively permits a “change of control” of the Managing Member without the vote or consent of the unitholders.

We may issue additional units, including units that are senior to our common units, without your approval, which would dilute your existing ownership interests.

Our operating agreement does not limit the number of additional membership interests that we may issue at any time without the approval of our unitholders. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

each unitholder’s proportionate ownership interest in us will decrease;

the amount of cash available for distribution on each unit may decrease;

the relative voting strength of each previously outstanding unit may be diminished; and

the market price of our common units may decline.

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

As of February 8, 2017, Devon held 115,495,669 common units. Additionally, we have agreed to provide Devon with certain registration rights with respect to the common units held by it. The sale of these units could have an adverse impact on the price of the our common units or on any trading market that may develop.

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

If at any time the Managing Member and its affiliates own more than 90% of our common units, the Managing Member will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of our common units held by unaffiliated persons at a price equal to the greater of (1) the average of the daily closing price of our common units over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed and (2) the highest per-unit price paid by the Managing Member or any of its affiliates for our common units during the 90-day period preceding the date such notice is first mailed. As a result, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return or a negative return on their investment. Unitholders may also incur a tax liability upon a sale of their units. Our manager is not obligated to obtain a fairness opinion regarding the value of our common units to be repurchased by it upon exercise of the call right. There is no restriction in our operating agreement that prevents the Managing Member from issuing additional common units and exercising its call right. If the Managing Member exercised its call right, the effect would be to take us private. As of February 8, 2017, Devon owned an aggregate of approximately 64.1% of our common units.

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

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under the DLLCA, a limited liability company may not make a distribution to a member if, after the distribution, all liabilities of the limited liability company, other than liabilities to members on account of their membership interests and liabilities for which the recourse of creditors is limited to specific property of the company, would exceed the fair value of the assets of the limited liability company. For the purpose of determining the fair value of the assets of a limited liability company, the DLLCA provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited liability company only to the extent that the fair value of that

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property exceeds the non-recourse liability. The DLLCA provides that a member who receives a distribution and knew at the time of the distribution that the distribution was in violation of the DLLCA will be liable to the limited liability company for the amount of the distribution for three years.

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

As of February 8, 2017, only approximately 35.9% of our common units are held by public unitholders. The lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of our common units and limit the number of investors who are able to buy our common units. The market price of our common units may be influenced by many factors, some of which are beyond our control, including:

the quarterly distributions paid by us with respect to our common units;

our quarterly or annual earnings, or those of other companies in our industry;

the loss of Devon as a customer;

events affecting Devon;

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

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

general economic conditions;

the failure of securities analysts to cover our common units or changes in financial estimates by analysts;

future sales of our common units; and

other factors described in these “Risk Factors.”

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

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

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

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

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

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

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

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

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Our cash flow consists almost exclusively of distributions from the Partnership.

Currently, our only cash-generating assets are our partnership interests in the Partnership and our 16% limited partner interest in EnLink Oklahoma T.O. Although EnLink Oklahoma T.O. generates positive cash flows from operating activities, our capital contributions exceeded distributions received during 2016, and estimated capital contributions during 2017 will exceed its cash flows from operating activities. We have a credit facility in place to fund our share of capital expenditures to the extent not funded by EnLink Oklahoma T.O.’s operating cash flows. See “Item 8. Financial Statements and Supplementary Data—Note 6” for further discussion. If our borrowing capacity under this facility is not sufficient to fund our share of EnLink Oklahoma T.O.’s capital expenditures, we may have to use our cash flow from Partnership distributions to fund such costs. Our cash flow is therefore completely dependent upon the ability of the Partnership to make distributions to its partners. Accordingly, you should read and consider the risk factors described under the caption “Risks Inherent in the Partnership’s Business.”

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

the amount of natural gas transported in its gathering and transmission pipelines;

the level of the Partnership’s processing operations;

the fees the Partnership charges and the margins it realizes for its services;

the prices of, levels of production of and demand for crude oil, condensate, NGLs and natural gas;

the volume of natural gas the Partnership gathers, compresses, processes, transports and sells, the volume of NGLs the Partnership processes or fractionates and sells, the volume of crude oil the Partnership handles at its crude terminals, the volume of crude oil and condensate the Partnership gathers, transports, purchases and sells, the volumes of condensate stabilized and the volumes of brine the Partnership disposes;

the relationship between natural gas and NGL prices; and

the Partnership’s level of operating costs.

In addition, the actual amount of cash the Partnership will have available for distribution will depend on other factors, some of which are beyond its control, including:

the level of capital expenditures the Partnership makes;

the cost of acquisitions, if any;

the Partnership’s debt service requirements;

fluctuations in its working capital needs;

the Partnership’s ability to make working capital borrowings under its bank credit facility to pay distributions;

prevailing economic conditions; and

the amount of cash reserves established by its respective general partners in its sole discretion for the proper conduct of business.

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

Although we control the Partnership, the General Partner owes fiduciary duties to the Partnership and the unitholders.

Conflicts of interest exist and may arise in the future as a result of the relationship between us and our affiliates, including the General Partner, on the one hand, and the Partnership and its limited partners, on the other hand. The directors and officers of EnLink Midstream GP, LLC have fiduciary duties to manage the General Partner in a manner beneficial to us, its owner. At the same time, the General Partner has a fiduciary duty to manage the Partnership in a

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manner beneficial to the Partnership and its limited partners. The board of directors of EnLink Midstream GP, LLC will resolve any such conflict and has broad latitude to consider the interests of all parties to the conflict. The resolution of these conflicts may not always be in our best interest or that of our unitholders.

For example, conflicts of interest may arise in the following situations:

the allocation of shared overhead expenses to the Partnership and us;

the interpretation and enforcement of contractual obligations between us and our affiliates, on the one hand, and the Partnership, on the other hand;

the determination of the amount of cash to be distributed to the Partnership’s partners and the amount of cash to be reserved for the future conduct of the Partnership’s business;

the determination whether to make borrowings under the Partnership’s credit facility to pay distributions to partners; and

any decision we make in the future to engage in activities in competition with the Partnership.

If the General Partner is not fully reimbursed or indemnified for obligations and liabilities it incurs in managing the business and affairs of the Partnership, its value, and therefore the value of our common units, could decline.

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

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

If we cease to manage and control the Partnership and are deemed to be an investment company under the Investment Company Act of 1940, we would either have to register as an investment company under the Investment Company Act of 1940, obtain exemptive relief from the SEC or modify our organizational structure or our contractual rights so as to fall outside the definition of an investment company. Registering as an investment company could, among other things, materially limit our ability to engage in transactions with affiliates, including the purchase and sale of certain securities or other property to or from our affiliates, restrict our ability to borrow funds or engage in other transactions involving leverage and require us to add additional directors who are independent of us and our affiliates, and adversely affect the price of our common units.

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

We are treated as a corporation for tax purposes that is required to pay federal and state income tax on our taxable income at corporate rates. Historically, we have had net operating losses that eliminated substantially all of our taxable income and, thus, we historically have not had to pay material amounts of income taxes. We anticipate generating net operating losses for tax purposes during 2017, and as a result, do not expect to incur material amounts of federal and state income tax liabilities. In the event we do generate taxable income, federal and state income tax liabilities will reduce the cash available for distribution to our unitholders.

The terms of our credit facility may restrict our current and future operations, particularly our ability to respond to changes in business or to take certain actions.

Our credit agreement contains, and any future indebtedness we incur will likely contain, 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. In addition, our credit facility requires us to satisfy and maintain specified financial ratios and other financial condition tests. Our ability to meet those financial ratios and tests can be affected by events beyond our control, and we cannot assure you that we will meet those ratios and tests.

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

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

Under the terms of our credit facility, certain events of default under the Partnership’s credit facility could constitute an event of default under our credit facility. Additionally, certain events of default under our credit facility relate specifically to events relating to the Partnership, including certain bankruptcy events affecting the Partnership or any event that causes us to no longer indirectly control the Partnership. Additionally, any default by the Partnership under the terms of its credit facility could limit its ability to make distributions to us.

Risks Inherent in the Partnership’s Business

The Partnership is dependent on Devon for a substantial portion of the natural gas that it gathers, processes and transports. The expiration of five-year MVCs from Devon at the end of 2018 and in April 2020, could result in a material decline in the Partnership’s operating results and cash available for distribution because the volumes of natural gas that the Partnership gathered, processed and transported for Devon during 2016 have been below the MVC levels under certain of their contracts .

The Partnership is dependent on Devon for a substantial portion of its natural gas supply. For the year ended December 31, 2016, Devon represented approximately 50% of the Partnership’s gross operating margin. In order to minimize volumetric exposure, in March 2014, the Partnership obtained five-year MVCs from Devon at the Bridgeport processing facility, Bridgeport and East Johnson County gathering systems and the central Oklahoma gathering system, which expire on January 1, 2019. The Partnership also has a five-year MVC from Devon attributable to the VEX pipeline which expires on April 1, 2020. If the volumes of natural gas and crude oil that the Partnership gathers and transports on its systems are below the MVC levels after the contracts expire, the Partnership could experience a material decline in its combined gross operating margin and cash flow. For the years ended December 31, 2016, the Partnership recognized $26.4 million, $10.8 million, and $9.0 million under MVCs from Devon attributable to its Texas, Oklahoma and Crude and Condensate segments, respectively, because volumes have been below the minimum level. For the years ended December 31, 2015, the Partnership recognized $3.8 million, $20.1 million, and $0.5 million under MVCs from Devon attributable to their Texas, Oklahoma and Crude and Condensate segments, respectively.

Because the Partnership is substantially dependent on Devon as its primary customer and through Devon’s control of us and our control of the General Partner, any development that materially and adversely affects Devon’s operations, financial condition or market reputation could have a material and adverse impact on the Partnership and us. Material adverse changes at Devon could restrict our access to capital, make it more expensive to access the capital markets or increase the costs of our or the Partnership’s borrowings.

The Partnership is substantially dependent on Devon as its primary customer and through Devon’s control of us and our control of the General Partner, and we expect the Partnership to derive a majority of its gross operating margin from Devon for the foreseeable future. As a result, any event, whether in the Partnership’s area of operations or otherwise, that adversely affects Devon’s production, financial condition, leverage, market reputation, liquidity, results of operations or cash flows may adversely affect the Partnership’s revenues and cash available for distribution. Accordingly, we are indirectly subject to the business risks of Devon, some of which are the following:

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

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risks relating to Devon’s exploration and drilling programs, including potential environmental liabilities;

adverse effects of governmental and environmental regulation; and

general economic and financial market conditions.

Further, the Partnership is subject to the risk of non-payment or non-performance by Devon, including with respect to the Partnership’s 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 the Partnership’s gathering and processing agreements. Additionally, due to our relationship with Devon, our or the Partnership’s 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. In February 2016, S&P Global Ratings(“S&P”), and Moody’s Investors Services (“Moody’s”) each downgraded Devon to a BBB and Ba2 credit rating, respectively. Any material limitations on our or the Partnership’s 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. Similarly, material adverse changes at Devon could negatively impact our or the Partnership’s unit price, limiting our ability to raise capital through equity issuances or debt financing or our ability to engage in, expand or pursue our business activities and could also prevent us from engaging in certain transactions that might otherwise be considered beneficial to us.

Please see “Item 1A. Risk Factors” in Devon’s Annual Report on Form 10-K for the year ended December 31, 2016 for a full discussion of the risks associated with Devon’s business.

Adverse developments in the Partnership’s gathering, transmission, processing, crude oil, condensate, natural gas and NGL services businesses would reduce its ability to make distributions to its unitholders.

The Partnership relies exclusively on the revenues generated from its gathering, transmission, processing, fractionation, crude oil, natural gas, condensate and NGL services businesses and as a result its 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 the Partnership’s financial condition and its ability to make distributions to its unitholders.

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

The Partnership’s revenue-producing operations are geographically concentrated in the Barnett Shale, causing it to be disproportionally exposed to risks associated with regional factors. Specifically, the Partnership’s operations in the Barnett Shale accounted for approximately 17.5% of its consolidated revenues and approximately 40.2% of its consolidated gross operating margin for the year ended December 31, 2016. The concentration of the Partnership’s operations in this region also increases exposure to unexpected events that may occur in this region such as natural disasters or labor difficulties. Any one of these events has the potential to have a relatively significant impact on the Partnership’s operations and growth plans, decrease cash flows, increase operating and capital costs and prevent development within originally anticipated time frames. Any of these risks could have a material adverse effect on the Partnership’s financial condition, results of operations or cash flows.

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

In order to maintain or increase throughput levels in the Partnership’s gathering systems and asset utilization rates at its processing plants and fractionators, the Partnership must continually contract for new product supplies. The Partnership may not be able to obtain additional contracts for crude oil, condensate, natural gas and NGL supplies. The primary factors affecting the Partnership’s ability to connect new wells to its gathering facilities include the Partnership’s success in contracting for existing supplies that are not committed to other systems and the level of drilling activity near its gathering systems. If the Partnership is unable to maintain or increase the volumes on its systems by accessing new supplies to offset the natural decline in reserves, the Partnership’s business and financial results could be

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materially, adversely affected. In addition, the Partnership’s future growth will depend in part upon whether it can contract for additional supplies at a greater rate than the rate of natural decline in its current supplies.

Fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new crude oil, condensate and natural gas reserves. During 2016, the Partnership saw lower drilling activity due to low commodity prices. Although drilling activity improved during 2016 in some of the most economic basins, including the STACK, SCOOP and CNOW basins in Oklahoma and the Permian basin in Texas, we could see downward pressure on future drilling activity in these basins if commodity prices decline below current levels, which may result in lower volumes. Tax policy changes or additional regulatory restrictions on development could also have a negative impact on drilling activity, reducing supplies of product available to the Partnership’s systems and assets. Additional governmental regulation of, or delays in issuance of permits for, the offshore exploration and production industry may negatively impact current and future volumes from offshore pipelines supplying the Partnership’s processing plants. The Partnership has no control over producers and depends 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 the Partnership’s principal geographic areas for a prolonged period, as a result of continued depressed commodity prices or otherwise, likely would have a material adverse effect on the Partnership’s financial condition, results of operations and cash flow.

Any decrease in the volumes that the Partnership gathers, processes, fractionates or transports would adversely affect its financial condition, results of operations and cash flows.

The Partnership’s financial performance depends to a large extent on the volumes of natural gas, crude oil, condensate and NGLs gathered, processed, fractionated and transported on its assets. Decreases in the volumes of natural gas, crude oil, condensate and NGLs we gather, process, fractionate or transport would directly and adversely affect the Partnership’s financial condition. These volumes can be influenced by factors beyond the Partnership’s control, including:

environmental or other governmental regulations;

weather conditions;

increases in storage levels of natural gas, NGLs, crude oil and condensate;

increased use of alternative energy sources;

decreased demand for natural gas, NGLs, crude oil and condensate;

continued fluctuation in commodity prices, including the prices of natural gas, NGLs, crude oil and condensate;

economic conditions;

supply disruptions;

availability of supply connected to the Partnership’s systems; and

availability and adequacy of infrastructure to gather and process supply into and out of the Partnership’s systems.

The volumes of natural gas, crude oil, condensate and NGLs gathered, processed, fractionated and transported on the Partnership’s assets also depend on the production from the regions that supply its 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 the Partnership’s systems, the Partnership must obtain new sources of natural gas, crude oil, condensate and NGLs. The primary factors affecting the Partnership’s 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 the Partnership’s areas of operation, (ii) the Partnership’s ability to compete for volumes from new wells and (iii) the Partnership’s ability to compete successfully for volumes from sources connected to other pipelines. The Partnership has no control over the level of drilling activity in its areas of operation, the amount of reserves associated with wells connected to its systems or the rate at which production from a well declines. In addition, the Partnership has no control over producers or its 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

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intangible assets with finite useful lives, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. For the investments we account for under the equity method, the impairment test considers whether the fair value of the unconsolidated affiliate investment as a whole, not the underlying net assets, has declined and whether that decline is other than temporary. If we determine that an impairment is indicated, we would be required to take an immediate non-cash charge to earnings with a correlative effect on equity and balance sheet leverage as measured by debt to total capitalization. For the year ended December 31, 2015, the Partnership recognized a $12.1 million impairment on property, plant and equipment, primarily related to costs associated with the cancellation of various capital projects in their Texas, Louisiana, and Crude and Condensate segments. In addition, for the year ended December 31, 2015, the Partnership recognized a $223.1 million impairment of intangible assets in our Crude and Condensate segment and a goodwill impairment totaling $1,328.2 million in their Texas, Louisiana and Crude and Condensate segments. During February 2016, we determined that continued further weakness in the overall energy sector, driven by low commodity prices together with further declines in our unit price and the Partnership unit price subsequent to year-end, caused a change in circumstances warranting an interim impairment test. Based on these triggering events, we performed a goodwill impairment analysis in the first quarter of 2016 on all reporting units. Based on this analysis, a goodwill impairment loss for the Texas, Crude and Condensate, and Corporate reporting units in the amount of $873.3 million was recognized in the first quarter of 2016 and is included as an impairment loss in the consolidated statement of operations for the year ended December 31, 2016. Additional impairment of the value of our and the Partnership’s existing goodwill and intangible assets could have a significant negative impact on our future operating results.

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

The construction of additions or modifications to the Partnership’s existing systems and the construction of new midstream assets involves numerous regulatory, environmental, political and legal uncertainties beyond its 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 the Partnership undertakes these projects, it may not be able to complete them on schedule, at the budgeted cost or at all. Moreover, the Partnership’s revenues may not increase due to the successful construction of a particular project. For instance, if the Partnership expands a pipeline or constructs a new pipeline, the construction may occur over an extended period of time, and it may not receive any material increases in revenues promptly following completion of a project or at all. Moreover, the Partnership 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 its expected investment return, which could adversely affect the Partnership’s financial condition, results of operations or cash flows. In addition, the construction of additions to the Partnership’s existing gathering and processing assets will generally require it to obtain new rights-of-way and permits prior to constructing new pipelines or facilities. The Partnership may be unable to timely obtain such rights-of-way or permits to connect new product supplies to its existing gathering lines or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for the Partnership 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, the Partnership’s cash flows could be adversely affected.

Construction of the Partnership’s major development projects subjects it to risks of construction delays, cost over-runs, limitations on its growth and negative effects on its financial condition, results of operations or cash flows.

The Partnership is 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 the Partnership’s control, including delays from third-party landowners, the permitting process, complying with 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 the Partnership’s 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 the Partnership’s 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 the Partnership’s estimates, its liquidity and capital position could be adversely affected. This level of development activity requires significant effort from the Partnership’s management and technical personnel and places additional

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requirements on its financial. The Partnership 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.

The Partnership conducts a portion of its operations through joint ventures, which subjects it to additional risks that could have a material adverse effect on the success of these operations, its financial position, results of operations or cash flows.

The Partnership participates in several joint ventures, and it may enter into other joint venture arrangements in the future. The nature of a joint venture requires it to share control with unaffiliated third parties. If the Partnership’s 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 the Partnership may be required to increase its level of commitment. If the Partnership does not timely meet its financial commitments or otherwise comply with our joint venture agreements, its 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 the Partnership 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 the Partnership’s credit ratings could increase its financing costs, the cost of maintaining certain contractual relationships and reduce the Partnership’s cash available for distribution.

The Partnership cannot assure you that its 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. In February 2016, S&P and Moody’s downgraded us to a BBB- and Ba2 credit rating, respectively. Any future downgrade could increase the cost of borrowings under the Partnership’s credit facility. Any downgrade could also lead to higher borrowing costs and, if below investment grade, could require:

additional or more restrictive covenants that impose operating and financial restrictions on the Partnership and its subsidiaries;

the Partnership’s subsidiaries to guarantee such debt and certain existing debt, including its senior notes;

the Partnership and its subsidiaries to provide collateral to secure such debt; and

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

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

The Partnership typically does not obtain independent evaluations of hydrocarbon reserves; therefore, volumes the Partnership service in the future could be less than anticipated.

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

The Partnership may not be successful in balancing its purchases and sales.

The Partnership is a party to certain long-term gas, NGL and condensate sales commitments that it satisfies through supplies purchased under long-term gas, NGL and condensate purchase agreements. When the Partnership enters into

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those arrangements, its sales obligations generally match its purchase obligations. However, over time the supplies that the Partnership has under contract may decline due to reduced drilling or other causes and the Partnership 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 the Partnership’s purchases and sales not to be balanced. If the Partnership’s purchases and sales are not balanced, it will face increased exposure to commodity price risks and could have increased volatility in its operating income.

The Partnership 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 the Partnership’s margins or even result in losses. For example, the Partnership is a party to one contract associated with it’s north Texas operations with a term to 2019 to supply approximately 150,000 MMBtu/d of gas. The Partnership buys gas for this contract on several different production-area indices and sell the gas into a different market area index. The Partnership realizes a loss on the delivery of gas under this contract each month based on current prices. The balance sheet as of December 31, 2016 reflects a liability of $44.8 million related to this performance obligation based on forecasted discounted cash obligations in excess of market under this gas delivery contract. Reduced supplies and narrower basis spreads in recent periods have increased the losses on this contract, and greater losses on this contract could occur in future periods if these conditions persist or become worse.

The Partnership’s profitability is dependent upon prices and market demand for crude oil, condensate, natural gas and NGLs that are beyond its control and have been volatile. The current depressed commodity price environment, if it continues, could result in financial losses and reduce the Partnership’s cash available for distribution.

The Partnership is subject to significant risks due to fluctuations in commodity prices. The Partnership is directly exposed to these risks primarily in the gas processing and NGL fractionation components of its business. For the year ended December 31, 2016, approximately 3.0% of the Partnership’s total gross operating margin was generated under percent of liquids contracts and percent of proceeds contracts, with most of these contracts relating to our Permian processing plants. Under percent of liquids contracts the Partnership receives 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, the Partnership’s revenues under percent of liquids contracts are directly impacted by the market price of NGLs. Gross operating margin results under percent of proceeds contracts are impacted only by the value of the natural gas or liquids produced with margins higher during periods of higher natural gas and liquids prices.

The Partnership also realizes processing gross operating margins under processing margin contracts. For the year ended December 31, 2016, approximately 0.9% of the Partnership’s total gross operating margin was generated under processing margin contracts. The Partnership has a number of processing margin contracts for activities at its Plaquemine and Pelican processing plants. Under this type of contract, the Partnership pays the producer for the full amount of inlet gas to the plant, and it makes 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”). The Partnership’s margins from these contracts can be greatly reduced or eliminated during periods of high natural gas prices relative to liquids prices.

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

Although the majority of the Partnership’s NGL fractionation business is under fee-based arrangements, a portion of its business is exposed to commodity price risk because it realizes a margin due to product upgrades associated with its Cajun-Sibon fractionation business. For the year ended December 31, 2016, margins realized associated with product upgrades represented less than 1% of the Partnership’s gross operating margin.

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The prices of crude oil, condensate, natural gas and NGLs were extremely volatile during 2016. Crude oil, weighted average NGL, and natural gas prices increased 46%, 53% and 60%, respectively from January 1, 2016 to December 31, 2016. We expect this volatility to continue. For example, crude oil prices (based on the NYMEX futures daily close prices for the prompt month) in 2016 ranged from a high of $54.06 per Bbl in December 2016 to a low of $26.21 per Bbl in February 2016. Weighted average NGL prices in 2016 (based on the Oil Price Information Service (“OPIS”) Napoleonville daily average spot liquids prices) ranged from a high of $0.66 per gallon in December 2016 to a low of $0.31 per gallon in January 2016. Natural gas prices (based on Gas Daily Henry Hub closing prices) during 2016 ranged from a high of $3.93 per MMBtu in December 2016 to a low of $1.64 per MMBtu in March 2016.

The markets and prices for crude oil, condensate, natural gas and NGLs depend upon factors beyond the Partnership’s 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 demand for crude oil and natural gas;

the level of domestic crude oil, condensate and natural gas production;

technology, including improved production techniques (particularly with respect to shale development);

the level of domestic industrial and manufacturing activity;

the availability of imported crude oil, natural gas and NGLs;

international demand for crude oil and NGLs;

actions taken by foreign crude oil and gas producing nations;

the continued threat of terrorism and the impact of military action and civil unrest;

the availability of local, intrastate and interstate transportation systems;

the availability of downstream NGL fractionation facilities;

the availability and marketing of competitive fuels;

the impact of energy conservation efforts; and

the extent of governmental regulation and taxation, including the regulation of hydraulic fracturing and “greenhouse gases.”

Changes in commodity prices also indirectly impact our profitability by influencing drilling activity and well operations, and thus the volume of gas, crude oil and condensate we gather and process and NGLs we fractionate. The volatility in commodity prices may cause the Partnership’s gross operating margin and cash flows to vary widely from period to period. The Partnership’s hedging strategies may not be sufficient to offset price volatility risk and, in any event, do not cover all of the Partnership’s throughput volumes. Moreover, hedges are subject to inherent risks, which we describe in “Item 7A. Quantitative and Qualitative Disclosure about Market Risk.” The Partnership’s use of derivative financial instruments does not eliminate the Partnership’s 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.

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 the Partnership connects, the Partnership’s gross operating margin and cash flow could be adversely affected.

The Partnership’s gathering, processing and transportation assets connect to other pipelines or facilities owned and operated by unaffiliated third parties. The continuing operation of, and the Partnership’s continuing access to, such third-party pipelines, processing facilities and other midstream facilities is not within the Partnership’s 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. In addition, if the Partnership’s costs to access and transport on these third-party pipelines significantly increase, the Partnership’s 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 the Partnership gathers or transports do not meet the product quality requirements of such pipelines or facilities, the Partnership’s operating margin and cash flow could be adversely affected.

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The Partnership’s debt levels could limit our flexibility and adversely affect its financial health or limit its flexibility to obtain financing and to pursue other business opportunities.

The Partnership continues to have the ability to incur debt, subject to limitations in its credit facility. The Partnership’s level of indebtedness could have important consequences to it, including the following:

the Partnership’s 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;

the Partnership’s funds available for operations, future business opportunities and distributions to unitholders will be reduced by that portion of the Partnership’s cash flows required to make interest payments on its debt;

the Partnership’s debt level will make it more vulnerable to general adverse economic and industry conditions;

limit the Partnership’s flexibility in planning for, or reacting to, changes in its business and the industry in which it operates; and

increase the risk that we may default on our debt obligations.

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

The terms of the Partnership’s credit facility and indentures may restrict its current and future operations, particularly its ability to respond to changes in business or to take certain actions.

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

incur subsidiary indebtedness;

engage in transactions with its affiliates;

consolidate, merge or sell substantially all of its assets;

incur liens;

enter into sale and lease back transactions; and

change business activities it conducts.

In addition, the Partnership’s credit facility requires it to satisfy and maintain a specified financial ratio. The Partnership’s ability to meet that financial ratio can be affected by events beyond its control, and the Partnership cannot assure you that it will continue to meet that ratio.

The Partnership’s ability to comply with the covenants and restrictions contained in its credit facility and indentures may be affected by events beyond its control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, the Partnership’s ability to comply with these covenants may be impaired. A breach of any of these covenants could result in an event of default under its credit facility and indentures. Upon the occurrence of such an event of default, all amounts outstanding under the applicable debt agreements could be declared to be immediately due and payable and all applicable commitments to extend further credit could be terminated. If indebtedness under the Partnership’s credit facility or indentures is accelerated, there can be no assurance that it 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 the Partnership’s ability to finance future operations or capital needs or to engage in other business activities.

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

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

The Partnership is vulnerable to operational, regulatory and other risks due to its significant assets in south Louisiana and the Gulf of Mexico, including the effects of adverse weather conditions such as hurricanes.

The Partnership’s operations and revenues will be significantly impacted by conditions in south Louisiana and the Gulf of Mexico because the Partnership significant assets located in these two areas. The Partnership’s concentration of activity in Louisiana and the Gulf of Mexico makes the Partnership more vulnerable than many of its 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 the Partnership’s operations could experience the same condition at the same time, these conditions could have a relatively greater impact on the Partnership’s results of operations than they might have on other midstream companies that have operations in more diversified geographic areas.

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

The NGL products the Partnership produces has 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 the Partnership handles or reduce the fees the Partnership charges for its services. The Partnership’s 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,” which the Partnership has experienced in greater volumes, 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 the Partnership’s 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

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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 the Partnership provides as well as NGL prices, which would negatively impact our financial condition, results of operations or cash flows.

The Partnership expects to encounter significant competition in any new geographic areas into which it seeks to expand, and the Partnership’s ability to enter such markets may be limited.

If the Partnership expands its operations into new geographic areas, the Partnership expects 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 the Partnership, 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, the Partnership may not be able to successfully develop greenfield or acquire assets located in new geographic areas and its results of operations could be adversely affected.

The Partnership does not own most of the land on which its pipelines, compression and plant facilities are located, which could disrupt its operations.

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

The Partnership offers pipeline, truck, rail and barge services. Significant delays, inclement weather or increased costs affecting these transportation methods could materially affect the Partnership’s results of operations.

The Partnership offers pipeline, truck, rail and barge services. The costs of conducting these services could be negatively affected by factors outside of the Partnership’s 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 the Partnership’s 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.

The Partnership could experience increased severity or frequency of trucking accidents and other claims, which could materially affect the Partnership’s 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 the Partnership’s results of operations. In the event that accidents occur, the Partnership may be unable to obtain desired contractual indemnities, and its 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.

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Changes in trucking regulations may increase the Partnership’s costs and negatively impact its results of operations.

The Partnership’s 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 the Partnership’s 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 the Partnership’s 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 the Partnership does not make acquisitions on economically acceptable terms or efficiently and effectively integrate the acquired assets with its asset base, its future growth will be limited.

The Partnership’s ability to grow depends, in part, on its ability to make acquisitions that result in an increase in cash generated from operations on a per unit basis. If the Partnership is unable to make accretive acquisitions either because it is (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 its future growth and ability to increase distributions will be limited.

From time to time, the Partnership may evaluate and seek to acquire assets or businesses that it believes complement its existing business and related assets. The Partnership may acquire assets or businesses that it plans to use in a manner materially different from its 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 the Partnership’s indebtedness; and

potential environmental or regulatory liabilities and title problems.

Management’s assessment of these risks is inexact and may not reveal or resolve all existing or potential problems associated with an acquisition. Realization of any of these risks could adversely affect the Partnership’s operations and cash flows. If the Partnership consummates any future acquisition, its 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 the Partnership will consider in determining the application of these funds and other resources.

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

The renewal or replacement of existing contracts with the Partnership customers at rates sufficient to maintain current revenues and cash flows depends on a number of factors beyond the Partnership’s control, including competition from other midstream service providers, and the price of, and demand for, crude oil, condensate, NGLs and natural gas in the markets it serves. The inability of the Partnership’s management to renew or replace the Partnership’s current contracts as they expire and to respond appropriately to changing market conditions could have a negative effect on the Partnership’s profitability.

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In particular, the Partnership’s ability to renew or replace its existing contracts with industrial end-users and utilities impacts our profitability. For the year ended December 31, 2016, approximately 50.1% of the Partnership’s sales of gas transported using the Partnership’s physical facilities were to industrial end-users and utilities. As a consequence of the increase in competition in the industry and volatility of natural gas prices, industrial end-users and utilities may be reluctant to enter into long-term purchase contracts. Many industrial end-users purchase natural gas from more than one natural gas company and have the ability to change providers at any time. Some of these industrial end-users also have the ability to switch between gas and alternate fuels in response to relative price fluctuations in the market. Because there are numerous companies of greatly varying size and financial capacity that compete with the Partnership in marketing natural gas, the Partnership often competes in the industrial end-user and utilities markets primarily on the basis of price.

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

Risks of nonpayment and nonperformance by the Partnership’s customers are a major concern in its business. The Partnership is subject to risks of loss resulting from nonpayment or nonperformance by its customers and other counterparties, such as its lenders and hedging counterparties. Any increase in the nonpayment and nonperformance by the Partnership’s customers could adversely affect its results of operations and reduce its ability to make distributions to us. Additionally, equity values for many of our customers continue to be low. The combination of a reduction of cash flow resulting 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 the Partnership’s customers’ liquidity and ability to make payment or perform on its obligations to the Partnership. Furthermore, some of the Partnership’s 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 the Partnership.

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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 the Partnership’s customers, which could adversely impact its revenues.

A portion of the Partnership’s 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. The EPA and the BLM have also issued rules, conducted studies and made proposals that, if implemented, could either restrict the practice of hydraulic fracturing or subject the process to further regulation. For instance, the EPA has issued final regulations under the federal Clean Air Act establishing performance standards, including standards for the capture of air emissions released during hydraulic fracturing and adopted rules prohibiting the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. The 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. 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. As regulatory agencies continue to study induced seismicity, additional legislative and regulatory initiatives could affect the Partnership’s customers injection well operations as well as its brine disposal operations.

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

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

The rates, terms and conditions of service under which the Partnership transports natural gas in the Partnership’s pipeline systems in interstate commerce are subject to regulation of 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 the Partnership’s ability to establish reasonable rates that cover operating costs and allow for a reasonable return. An adverse determination in any future rate proceeding brought by or against us could have a material adverse effect on the Partnership’s business, financial condition, results of operations, and cash available for distribution. Under the NGPA, the Partnership is required to justify its rates for interstate transportation service on a cost-of-service basis every five years. The Partnership’s 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 the Partnership’s rates for Section 311 transportation service or intrastate transportation service should be lowered, the Partnership’s business could be adversely affected.

The rates charged by the Partnership’s natural gas pipelines may also be affected by the ongoing uncertainty regarding FERC’s current income tax allowance policy. There is not likely to be a definitive resolution of these income tax allowance issues for some time, and the ultimate outcome of this proceeding is not certain and could result in changes going forward to FERC’s treatment of income tax allowances in the cost of service or to the discounted cash flow return on equity. Depending upon the resolution of these issues, the cost of service rates of the Partnership’s interstate natural gas pipelines could be affected to the extent it proposes new rates or changes to its existing rates or if its rates are subject to compliance or challenged by FERC.

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The Partnership’s 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 the Partnership’s 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. The Partnership’s 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 the Partnership’s operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

If the Partnership fails to comply with all the applicable FERC-administered statutes, rules, regulations and orders, it 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 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 the Partnership’s business. The Partnership is subject to some ratable take and common purchaser statutes in the states where it operates. 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 the Partnership’s right as an owner of gathering facilities to decide with whom the Partnership contracts 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 the Partnership operates have adopted complaint-based or other limited economic regulation of natural gas gathering activities. States in which the Partnership operates 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 the Partnership’s liquids pipelines is subject to federal and state rate and service regulation, which could limit the revenues the Partnership collects from its customers and adversely affect the cash available for distribution to us.

The Partnership’s 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 the 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. Under certain circumstances, FERC could limit the Partnership’s recovery of costs or could require the Partnership to reduce its rates and the payment of reparations to complaining shippers for up to two years prior to the date of the complaint. In particular, ongoing uncertainty surrounding FERC’s current income tax allowance policy could affect the Partnership’s rates going forward. FERC also has the authority to change the Partnership’s terms and conditions of service if it determines that they are unjust and unreasonable or unduly discriminatory or preferential.

Changes to FERC’s annual indexing methodology, including 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 could have a material impact on the Partnership’s business. Such changes, if accepted, could decrease the Partnership’s rates and adversely affect its business.

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subject additional services the Partnership provides to regulation by FERC, which could increase the Partnership’s operating costs, decrease the Partnership’s rates and adversely affect the Partnership’s business.

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

The pipelines the Partnership owns and operates 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. PHMSA also recently proposed rulemaking that would expand existing integrity management requirements to natural gas transmission and gathering lines in areas with medium population densities. Additional action by PHMSA with respect to pipeline integrity management requirements may occur in the future. At this time, the Partnership 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. The Partnership’s costs relating to compliance with the required testing under the TRRC regulations were approximately $3.3 million, $3.3 million, and $2.5 million for the years ended December 31, 2016, 2015 and 2014, respectively. If the Partnership’s pipelines fail to meet the safety standards mandated by the TRRC or the DOT regulations, then the Partnership may be required to repair or replace sections of such pipelines or operate the pipelines at a reduced maximum allowable operating pressure, the cost of which 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 the Partnership’s results of operations or financial positions. Because certain of the Partnership’s operations are located around urban or more populated areas, such as the Barnett Shale, the Partnership may incur additional expenses to mitigate noise, odor and light that may be emitted in the Partnership’s operations and expenses related to the appearance of the Partnership’s facilities. Municipal and other local or state regulations are imposing various obligations including, among other things, regulating the location of the Partnership’s facilities, imposing limitations on the noise levels of the Partnership’s facilities and requiring certain other improvements that increase the cost of the Partnership’s facilities. The Partnership is also subject to claims by neighboring landowners for nuisance related to the construction and operation of the Partnership’s facilities, which could subject the Partnership to damages for declines in neighboring property values due to the Partnership’s construction and operation of facilities.

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 the Partnership to incur significant costs and liabilities.

Many of the operations and activities of the Partnership’s 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 the Partnership’s 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 the Partnership or locations to which it has 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 the Partnership’s facilities or upon or through which its 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.

The Partnership’s business may be adversely affected by increased costs due to stricter pollution control requirements or liabilities resulting from non-compliance with required operating or other regulatory permits. New environmental laws or regulations, including, for example, legislation relating to the control of greenhouse gas

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emissions, or changes in existing environmental laws or regulations might adversely affect the Partnership’s 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 the Partnership’s profitability. Changes in laws or regulations could also limit its production or the operation of its assets or adversely affect its ability to comply with applicable legal requirements or the demand for crude oil, brine disposal services or natural gas, which could adversely affect its business and its profitability.

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

The Partnership is 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. 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, thereby triggering more stringent air permitting processes and requirements across the oil and gas industry. In addition, on November 10, 2016, the EPA issued a final Information Collection Request (“ICR”) that requires numerous oil and gas companies to provide information regarding methane emissions from existing oil and gas facilities, a step used to provide a basis for future rulemaking. The 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.

Additional regulation of GHG emissions from the oil and gas industry remains a possibility. These regulations could require a number of modifications to the Partnership’s operations, and its 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 the Partnership suppliers and customers could result in reduced production by those suppliers and customers and thus translate into reduced demand for its services. Responding to rule challenges, the EPA has since revised certain aspects of its April 2012 rules and has indicated that it may reconsider other aspects of the rules.

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

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 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. At the federal regulatory level, both the EPA and the BLM have adopted regulations for the control of methane emissions, which also include leak detection and repair requirements, from the oil and gas industry.

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

Although it is not possible at this time to predict whether future legislation or new regulations may be adopted to address greenhouse gas emissions or how such measures would impact the Partnership’s business, the adoption of legislation or regulations imposing reporting or permitting obligations on, or limiting emissions of GHGs from, its equipment and operations could require the Partnership to incur additional costs to reduce emissions of GHGs associated with our operations, could adversely affect its performance of operations in the absence of any permits that may be

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required to regulate emission of GHGs or could adversely affect demand for the natural gas the Partnership gathers, processes or otherwise handles in connection with its services.

The Endangered Species Act and Migratory Bird Treaty Act 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, the Partnership may be obligated to develop and implement plans to avoid potential adverse impacts to protected species, and it may be prohibited from conducting operations in certain locations or during certain seasons, such as breeding and nesting seasons, when its 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 the Partnership’s 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.

The Partnership’s 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 the Partnership’s operations and financial condition.

The Partnership’s 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, related equipment and surrounding properties caused by hurricanes, floods, fires and other natural disasters and acts of terrorism;

inadvertent damage from construction and farm equipment;

leaks of natural gas, NGLs, crude oil, condensate and other hydrocarbons;

induced seismicity;

rail accidents, barge accidents and truck accidents; 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 the Partnership’s related operations. The Partnership is not fully insured against all risks incident to its business. In accordance with typical industry practice, the Partnership has appropriate levels of business interruption and property insurance on its underground pipeline systems. The Partnership is 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 the Partnership’s 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 the Partnership’s business.

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

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options. The position limit levels set the maximum amount of covered contracts that a trader may own or control separately or in combination, net long or short. The final rules also contained limited exemptions from position limits which would be phased in over time for certain bona fide hedging transactions and positions. The CFTC’s original position limits rule was challenged in court by two industry associations and was vacated and remanded by a federal district court. However, in November 2013, the CFTC proposed new rules that would place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. The CFTC has sought comment on the position limits rule as reproposed, but these new position limit rules are not yet final and the impact of those provisions on the Partnership is uncertain at this time. The CFTC has withdrawn its appeal of the court order vacating the original position limits rule.

The legislation and new regulations may also require counterparties to our derivative instruments to spin off some of its derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. The new legislation and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks the Partnership encounters, reduce the Partnership’s ability to monetize or restructure the Partnership’s existing derivative contracts, and increase the Partnership’s exposure to less creditworthy counterparties. If the Partnership reduces its use of derivatives as a result of the legislation and regulations, the Partnership’s results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect the Partnership’s ability to plan for and fund capital expenditures and to generate sufficient cash flow to pay quarterly distributions at current levels or at all. The Partnership’s 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 the Partnership, its financial condition and its results of operations.

The Partnership’s use of derivative financial instruments does not eliminate its 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 its income.

The Partnership’s operations expose us to fluctuations in commodity prices, and the Partnership’s credit facility exposes it to fluctuations in interest rates. The Partnership uses over-the-counter price and basis swaps with other natural gas merchants and financial institutions. Use of these instruments is intended to reduce the Partnership’s exposure to short-term volatility in commodity prices. As of December 31, 2016, the Partnership had hedged only portions of its expected exposures to commodity price risk. In addition, to the extent the Partnership hedges its commodity price risk using swap instruments, the Partnership will forego the benefits of favorable changes in commodity prices. Although the Partnership does not currently have any financial instruments to eliminate its exposure to interest rate fluctuations, we may use financial instruments in the future to offset its exposure to interest rate fluctuations.

Even though monitored by management, the Partnership’s hedging activities may fail to protect it and could reduce its earnings and cash flow. The Partnership’s hedging activity may be ineffective or adversely affect cash flow and earnings because, among other factors:

hedging can be expensive, particularly during periods of volatile prices;

the Partnership’s counterparty in the hedging transaction may default on its obligation to pay or otherwise fail to perform; and

available hedges may not correspond directly with the risks against which the Partnership seeks protection. For example:

the duration of a hedge may not match the duration of the risk against which the Partnership seeks protection;

variations in the index the Partnership uses to price a commodity hedge may not adequately correlate with variations in the index the Partnership uses to sell the physical commodity (known as basis risk); and

the Partnership may not produce or process sufficient volumes to cover swap arrangements the Partnership enters into for a given period. If the Partnership’s actual volumes are lower than the volumes the Partnership estimated when entering into a swap for the period, it might be forced to satisfy all or a portion of its derivative obligation without the benefit of cash flow from the sale or purchase of the underlying physical commodity, which could adversely affect the Partnership’s liquidity.

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

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

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

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

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

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

Gathering and compression services require laborers skilled in multiple disciplines, such as equipment operators, mechanics and engineers, among others. The Partnership’s business is dependent on its 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. The Partnership’s 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 the Partnership’s ability to manage and operate its business. If the Partnership is unable to successfully attract and retain an appropriately qualified workforce, its results of operations could be negatively affected.

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

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

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The Partnership’s assets were constructed over many decades using varying construction and coating techniques, which may cause its 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 the Partnership’s pipelines that could have a material adverse effect on its financial condition, results of operations or cash flows.

The Partnership’s 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 the Partnership’s financial condition, results of operations or cash flows, as well as its ability to make cash distributions to its unitholders.

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 the Partnership’s 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. The Partnership has 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 the Partnership’s pipelines were built was purchased in fee. The Partnership’s processing plants are located on land that the Partnership leases or owns in fee.

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

Item 3. Legal Proceedings

Our operations and those of the Partnership are subject to a variety of risks and disputes normally incident to our business. As a result, at any given time we or the Partnership 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. Additionally, the Partnership 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 believe that any pending or threatened claim or dispute is material to our financial results on our operations or cash flows. We and the Partnership maintain insurance policies with insurers in amounts and with coverage and deductibles as our Managing Member and the General Partner believe are reasonable and prudent. However, we cannot assure you that this insurance will be adequate to protect us and the Partnership 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, the Partnership’s subsidiaries acquire pipeline easements and other property rights by exercising rights of eminent domain and common carrier. As a result, from time to time the Partnership (or its subsidiaries) is party to lawsuits under which a court will determine the value of pipeline easements or other property interests obtained by the Partnership’s 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

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outcomes of these matters, the Partnership does not expect that awards in these matters will have a material adverse impact on its consolidated results of operations, financial condition, or cash flows.

The Partnership (or its subsidiaries) is defending lawsuits filed by owners of property located near processing facilities or compression facilities constructed by the Partnership as part of its 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.

In July 2013, the Board of Commissioners for the Southeast Louisiana Flood Protection Authority for New Orleans and surrounding areas filed a lawsuit against approximately 100 energy companies, seeking, among other relief, restoration of wetlands allegedly lost due to historic industry operations in those areas. The suit was filed in Louisiana state court in New Orleans, but was removed to the United States District Court for the Eastern District of Louisiana. The amount of damages is unspecified. The Partnership’s subsidiary, EnLink LIG, LLC, is one of the named defendants as the owner of pipelines in the area. On February 13, 2015, the court granted defendants’ joint motion to dismiss and dismissed the plaintiff’s claims with prejudice. Plaintiffs have appealed the matter to the United States Court of Appeals for the Fifth Circuit. The Partnership intends to continue vigorously defending the case. The success of the plaintiffs’ appeal as well as the Partnership’s costs and legal exposure, if any, related to the lawsuit are not currently determinable.

The Partnership owns and operates a high-pressure pipeline and underground natural gas and NGL storage reservoirs and associated facilities near Bayou Corne, Louisiana. In August 2012, a large sinkhole formed in the vicinity of this pipeline and underground storage reservoirs. The Partnership is seeking to recover its losses from responsible parties. The Partnership has sued Texas Brine Company, the operator of a failed cavern in the area and its insurers, seeking recovery for these losses in in the 23rd Judicial Court, Assumption Parish, Louisiana. The Partnership has also sued Occidental Chemical Company and Legacy Vulcan Corp. f/k/a Vulcan Materials Company, two Chlor-Alkali plant operators that participated in Texas Brine’s operational decisions regarding mining the failed cavern. The Partnership also filed a claim with its insurers, which the Partnership’s insurers denied. The Partnership has filed a claim for defense and indemnity with their insurers. In August 2014, the Partnership received a partial settlement from Texas Brine’s insurers with respect to the Texas Brine claims in the amount of $6.1 million, but additional claims remain outstanding. The Partnership cannot give assurance that the Partnership will be able to fully recover its losses through insurance recovery or claims against responsible parties.

In June 2014, a group of landowners in Assumption Parish, Louisiana added a subsidiary of the Partnership, EnLink Processing Services, LLC, as a defendant in a pending lawsuit they had filed against Texas Brine, Occidental Chemical Corporation, and Vulcan Materials Company relating to claims arising from the Bayou Corne sinkhole. The suit is pending in the 23rd Judicial Court, Assumption Parish, Louisiana. Although plaintiffs’ claims against the other defendants had been pending since October 2012, plaintiffs alleged in June 2014 and continue to allege that EnLink Processing Services, LLC’s negligence also contributed to the formation of the sinkhole. The amount of damages is unspecified. The validity of the causes of action, as well as the Partnership’s costs and legal exposure, if any, related to the lawsuit are not currently determinable. The Partnership intends to vigorously defend the case. The Partnership has also filed a claim for defense and indemnity with its insurers.

Item 4. Mine Safety Disclosures

Not applicable.

PART II

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

Our common units are listed on the NYSE under the symbol “ENLC.” On February 8, 2017, there were approximately 19,348 record holders and beneficial owners (held in street name) of our common units. For equity compensation plan information, see discussion under “Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters—Equity Compensation Plan Information.”

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The following table shows the high and low sales prices per common unit, as reported by the NYSE and cash distributions declared per common unit for the periods indicated:


	Range				Cash Distribution
	High		Low		Declared Per Unit
2016:
Quarter Ended December 31,	$	19.25	$	14.85	$	0.255
Quarter Ended September 30,		17.70		14.81		0.255
Quarter Ended June 30,		16.73		10.00		0.255
Quarter Ended March 31,		15.38		7.13		0.255

2015:
Quarter Ended December 31,	$	23.21	$	12.15	$	0.255
Quarter Ended September 30,		31.03		17.32		0.255
Quarter Ended June 30,		35.32		31.09		0.250
Quarter Ended March 31,		36.48		30.80		0.245

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

federal income taxes, which we are required to pay because we are taxed as a corporation;

the expenses of being a public company;

other general and administrative expenses;

capital calls for our interest in EnLink Oklahoma T.O. to the extent not covered by our borrowings; and

cash reserves the Managing Member believes are prudent to maintain.

During 2016, the Partnership paid quarterly distributions to its common unitholders in May, August and November of $0.390 related to the first, second and third quarters of 2016, respectively. The Partnership paid a quarterly distribution of $0.390 in February 2017 related to the fourth quarter of 2016. Our share of the distributions with respect to our limited and general partner interests in the Partnership totaled $197.0 million for the year ended December 31, 2016.

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Performance Graph

The following graph sets forth the cumulative total stockholder return for our common units, the Standard & Poor’s 500 Stock Index and a peer group of publicly traded partners of publicly traded limited partnerships in the Midstream natural gas, natural gas liquids, propane, and pipeline industries for the year ended December 31, 2016. The chart assumes that $100 was invested on March 10, 2014, with distributions reinvested. The peer group includes MarkWest Energy Partners, L.P., Energy Transfer Equity, L.P., Targa Resources, Inc. and Western Gas Equity Partners, L.P.

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Item 6. Selected Financial Data

The historical financial statements included in this report reflect (1) for periods prior to March 7, 2014, the assets, liabilities and operations of EnLink Midstream Holdings, LP Predecessor (the “Predecessor”), the predecessor to EnLink Midstream Holdings, LP (“Midstream Holdings”), which is our historical predecessor and (2) for periods on or after March 7, 2014, the results of our operations after giving effect to the Business Combination discussed under “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Devon Energy Transaction and EMH Drop Downs.” The Predecessor was comprised of all of the U.S. midstream assets and operations of Devon Energy Corporation (“Devon”) prior to the Business Combination, including its 38.75% interest in Gulf Coast Fractionators (“GCF”). However, in connection with the Business Combination, only the Predecessor’s systems serving the Barnett, Cana-Woodford and Arkoma-Woodford Shales in Texas and Oklahoma, as well as the economic burdens and benefits of the 38.75% interest in GCF, were contributed to Midstream Holdings, effective as of March 7, 2014.

The following table presents the selected historical financial and operating data of EnLink Midstream LLC and the Predecessor for the periods indicated. Financial and operating data for the years ended December 31, 2016, 2015 and 2014 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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	Year Ended December 31,
	2016		2015		2014 (4)		2013 (4)		2012 (4)
	(In millions, except per unit data)
Statement of Operations Data:
Revenues:
Product sales	$	3,008.9	$	3,253.7	$	2,159.3	$	179.4	$	153.9
Product sales - related parties		134.3		119.4		505.6		2,116.5		1,753.9
Midstream services		467.2		451.0		253.4		—		—
Midstream services - related parties		653.1		618.6		567.4		—		—
Gain (loss) on derivatives		(11.1)		9.4		22.1		—		—
Total revenue		4,252.4		4,452.1		3,507.8		2,295.9		1,907.8
Operating costs and expenses:
Cost of sales (1)		3,015.5		3,245.3		2,494.5		1,736.3		1,428.1
Operating expenses (2)		398.5		419.9		283.6		156.2		149.9
General and administrative (3)		122.5		136.9		97.3		45.1		41.7
(Gain) loss on disposition of assets		13.2		1.2		(0.1)		—		—
Depreciation and amortization		503.9		387.3		284.3		187.0		145.4
Impairments		873.3		1,563.4		—		—		16.4
Gain on litigation settlement		—		—		(6.1)		—		—
Total operating costs and expenses		4,926.9		5,754.0		3,153.5		2,124.6		1,781.5
Operating income (loss)		(674.5)		(1,301.9)		354.3		171.3		126.3
Other income (expense):
Interest expense, net of interest income		(189.5)		(103.3)		(49.8)		—		—
Income (loss) from unconsolidated affiliates		(19.9)		20.4		18.9		14.8		2.0
Gain on extinguishment of debt		—		—		3.2		—		—
Other income (expense)		0.3		0.8		(0.5)		—		—
Total other income (expense)		(209.1)		(82.1)		(28.2)		14.8		2.0
Income (loss) from continuing operations before non-controlling interest and income taxes		(883.6)		(1,384.0)		326.1		186.1		128.3
Income tax (provision) benefit		(4.6)		(25.7)		(76.4)		(67.0)		(46.2)
Net income (loss) from continuing operations		(888.2)		(1,409.7)		249.7		119.1		82.1
Discontinued operations:
Income (loss) from discontinued operations, net of tax		—		—		1.0		(2.3)		(5.2)
Income from discontinued operations attributable to non-controlling interest, net of tax		—		—		—		(1.3)		(1.1)
Discontinued operations, net of tax		—		—		1.0		(3.6)		(6.3)
Net income (loss)		(888.2)		(1,409.7)		250.7		115.5		75.8
Less: Net income (loss) from continuing operations attributable to the non-controlling interest		(428.2)		(1,054.5)		126.7		—		—
Net income (loss) attributable to EnLink Midstream, LLC	$	(460.0)	$	(355.2)	$	124.0	$	115.5	$	75.8
Predecessor interest in net income	$	—	$	—	$	35.5	$	—	$	—
Devon investment interest in net income (loss)	$	—	$	1.8	$	(2.0)	$	—	$	—
EnLink Midstream LLC interest in net income (loss)	$	(460.0)	$	(357.0)	$	90.5	$	—	$	—
Net income (loss) attributable to EnLink Midstream, LLC per unit:
Basic and diluted common unit	$	(2.56)	$	(2.17)	$	0.55	$	—	$	—
Distributions declared per common unit	$	1.02	$	1.01	$	0.87	$	0.52	$	0.48

(1)

Includes related party cost of sales of $150.1 million, $141.3 million, $354.3 million, $1,588.2 million and $1,310.3 million for the years ended December 31, 2016, 2015, 2014, 2013 and 2012, respectively.

(2)

Includes related party operating expense of $0.5 million, $0.5 million, $5.9 million, $36.2 million and $33.8 million for the years ended December 31, 2016, 2015, 2014, 2013 and 2012, respectively.

(3)

Includes related party general and administrative expenses of $0.0 million, $0.2 million, $11.6 million, $45.1 million and $41.7 million for the years ended December 31, 2016, 2015, 2014, 2013 and 2012, respectively.

(4)

Prior to March 7, 2014, the financial results only included the assets, liabilities and operations of the Predecessor. Beginning on March 7, 2014, our financial results also consolidate the assets, liabilities and operations of the legacy business of the Partnership prior to giving effect to the Business Combination. In connection with the Business Combination, the Partnership entered into new agreements with Devon that were effective on March 1, 2014 pursuant to which the Partnership provides services to Devon under fixed-fee arrangements in which the Partnership does not take title to the natural gas gathered or processed or the NGLs the Partnership fractionates. Prior to the effectiveness of these agreements, the Predecessor provided services to Devon under a percent-of-proceeds arrangement in which it took title to the natural gas it gathered and processed and the NGLs it fractionated.

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	Year Ended December 31,
	2016		2015		2014		2013		2012
	(In millions, except per unit data)
Balance Sheet Data (end of period):
Property and equipment, net	$	6,256.7	$	5,666.8	$	5,042.8	$	1,768.1	$	1,739.4
Total assets	$	10,275.9	$	9,541.3	$	10,206.7	$	2,309.8	$	2,535.2
Long-term debt (including current maturities)	$	3,295.3	$	3,066.0	$	2,022.5	$	—	$	—
Members' equity including non-controlling interest	$	5,265.6	$	5,424.9	$	7,074.8	$	—	$	2,002.0

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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. For more detailed information regarding the basis of presentation for the following information, please read the notes to the financial statements included in this report.

The historical financial statements included in this report reflect (1) for periods prior to March 7, 2014, the assets, liabilities and operations of EnLink Midstream Holdings, LP Predecessor (the “Predecessor”), the predecessor to EnLink Midstream Holdings, LP (“Midstream Holdings”), which is the historical predecessor of EnLink Midstream, LLC and (2) for periods on or after March 7, 2014, the results of operations of EnLink Midstream, LLC, after giving effect to the Business Combination discussed under “Devon Energy Transaction” below. The Predecessor was comprised of all of the U.S. midstream assets and operations of Devon Energy Corporation (“Devon”) prior to the Business Combination, including its 38.75% interest in Gulf Coast Fractionators (“GCF”). However, in connection with the Business Combination, only the Predecessor’s systems serving the Barnett, Cana-Woodford and Arkoma-Woodford Shales in Texas and Oklahoma, as well as the economic burdens and benefits of the 38.75% interest in GCF, were contributed to Midstream Holdings, effective as of March 7, 2014.

All references in this section to the “Company”, as well as the terms “our,” “we,” “us” and “its” (1) for periods prior to March 7, 2014 refer to the Predecessor and (2) for periods on or after March 7, 2014 refer to EnLink Midstream, LLC, together with its consolidated subsidiaries including the Partnership. All references in this section to the “Partnership” (1) for periods prior to March 7, 2014 refer to the Predecessor and (2) for periods on or after March 7, 2014 refer to EnLink Midstream Partners, LP, together with its consolidated subsidiaries including EnLink Midstream Operating, LP (the “Operating Partnership”) and EnLink Oklahoma Gas Processing, LP (“EnLink Oklahoma T.O.”). EnLink Oklahoma T.O. is sometimes used herein to refer to EnLink Oklahoma Gas Processing, LP itself or Enlink Oklahoma Gas Processing, LP, together with its consolidated subsidiaries. Finally, because EnLink Oklahoma T.O. and its subsidiaries are controlled by the Partnership and have similar operations to the Partnership, references to the “Partnership” in this report should also be read to include EnLink Oklahoma T.O. when applicable, including general references to the Partnership’s business in the risk factors and otherwise.

Overview

We are a Delaware limited liability company formed in October 2013. Our assets consist of equity interests in EnLink Midstream Partners, LP and EnLink Oklahoma T.O. EnLink Midstream Partners, LP is a publicly traded limited partnership engaged in the gathering, transmission, processing and marketing of natural gas and natural gas liquids, or NGLs, condensate and crude oil, as well as providing crude oil, condensate and brine services to producers. EnLink Oklahoma T.O., a partnership owned by the Partnership and us, is engaged in the gathering and processing of natural gas. Our interests in EnLink Midstream Partners, LP and EnLink Oklahoma T.O. consist of the following as of December 31, 2016:

88,528,451 common units representing an aggregate 22.3% limited partner interest in the Partnership;

100.0% ownership interest in EnLink Midstream Partners GP, LLC, the general partner of the Partnership ( the “General Partner” ), which owns a 0.4% general partner interest and all of the incentive distribution rights in the Partnership; and

16% limited partner interest in EnLink Oklahoma T.O.

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In January 2016, we adopted Accounting Standards Updates (“ASU”) 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis. This ASU provides additional guidance to reporting entities in evaluating whether certain legal entities, such as limited partnerships, limited liability corporations and securitization structures, should be consolidated. Due to ENLC’s ownership of the General Partner, the Partnership is considered a variable interest entity as the limited partners lack the ability to exercise kick-out rights over the General Partner and do not have substantive participating rights. Further, ENLC is considered the primary beneficiary as it has the power to direct the activities that most significantly impact the Partnership’s economic performance. The adoption of this standard has no impact on our consolidated financial statements as we will continue to consolidate the Partnership. Accordingly, the discussion of our financial position and results of operations in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” primarily reflects the operating activities and results of operations of the Partnership and EnLink Oklahoma T.O.

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

The Partnership is a Delaware limited partnership formed on July 12, 2002. The Partnership primarily focus on providing midstream energy services, including gathering, processing, transmission, fractionation, storage, condensate stabilization, brine services and marketing to producers of natural gas, NGLs, crude oil and condensate. The Partnership’s midstream energy asset network includes approximately 11,000 miles of pipelines, 20 natural gas processing plants, 7 fractionators, barge and rail terminals, product storage facilities, purchasing and marketing capabilities, brine disposal wells, a crude oil trucking fleet, and equity investments in certain private midstream companies. The Partnership manages and reports its activities primarily according to the nature of activity and geography. The Partnership has five reportable segments, which include the:

Texas Segment. The Texas segment includes the Partnership’s natural gas gathering, processing and transmission activities in north Texas and the Permian Basin in west Texas;

Oklahoma Segment. The Oklahoma segment includes the Partnership’s natural gas gathering, processing and transmission activities in Cana-Woodford, Arkoma-Woodford, Northern Oklahoma Woodford, Sooner Trend Anadarko Basin Canadian and Kingfisher Counties (“STACK”), South Central Oklahoma Oil Province (“SCOOP”) and Central Northern Oklahoma Woodford (“CNOW”) Shale areas;

Louisiana Segment. The Louisiana segment includes the Partnership’s natural gas pipelines, natural gas processing plants, storage facilities and NGL assets located in Louisiana;

Crude and Condensate Segment. The Crude and Condensate segment includes the Partnership’s Ohio River Valley (“ORV”) crude oil, condensate and brine disposal activities in the Utica and Marcellus Shales, its condensate stabilization and natural gas compression stations in the Utica and Marcellus Shales, its crude oil operations in the Permian Basin and our crude oil activities associated with the Victoria Express Pipeline and related truck terminal and storage assets (“VEX”) located in the Eagle Ford Shale; and

Corporate Segment. The Corporate segment includes the Partnership’s unconsolidated affiliate investments in Howard Energy Partners (“HEP”), its ownership in the Cedar Cove JV in Oklahoma and its contractual right to the economic burdens and benefits associated with Devon’s ownership interest in GCF in south Texas and its general partnership property and expenses.

The Partnership manages its operations by focusing on gross operating margin because the Partnership’s business is generally to gather, process, transport or market natural gas, NGLs, crude oil and condensate using its assets for a fee. The Partnership earns its fees through various contractual arrangements, which include stated fixed-fee contract arrangements or arrangements where the Partnership purchases and resells commodities in connection with providing the

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related service and earns a net margin as its fees. While the Partnership’s transactions vary in form, the essential element of each transaction is the use of its assets to transport a product or provide a processed product to an end-user at the tailgate of the plant, barge terminal or pipeline. The Partnership defines 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 97% of the Partnership’s gross operating margin was derived from fee-based services with no direct commodity exposure for the year ended December 31, 2016. The Partnership reflects revenue as “Product sales” and “Midstream services” on the consolidated statements of operations.

The Partnership’s gross operating margins are determined primarily by the volumes of:

•natural gas gathered, transported, purchased and sold through our pipeline systems;

•natural gas processed at our processing facilities;

•NGLs handled at our fractionation facilities;

•crude oil and condensate handled at our crude terminals;

•crude oil and condensate gathered, transported, purchased and sold;

•brine disposed; and

•condensate stabilized.

The Partnership generates revenues from eight primary sources:

•gathering and transporting natural gas and NGLs 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 gathering, transportation and terminal services;

•providing condensate stabilization services;

•providing brine disposal services; and

•providing gas, crude, and NGL storage.

The Partnership typically gathers or transports gas owned by others through its facilities for a fee. The Partnership also buys natural gas from a producer, plant or shipper at either a fixed discount to a market index or a percentage of the market index, then transports and resells the natural gas at the same market index. The fixed discount difference to a market index represents the fee for using the Partnership’s assets. The Partnership attempts to execute substantially all purchases and sales concurrently, or it enters into a future delivery obligation, thereby establishing the basis for the fee it will receive for each natural gas transaction. The Partnership’s gathering and transportation fee related to a percentage of the index price can be adversely affected by declines in the price of natural gas. The Partnership is also party to certain long-term gas sales commitments that it satisfies through supplies purchased under long-term gas purchase agreements. When the Partnership enters into those arrangements, its sales obligations generally match its purchase obligations. However, over time, the supplies that it has under contract may decline due to reduced drilling or other causes, and the Partnership 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 the Partnership’s purchase/sale transactions, the resale price is generally based on the same index at which the gas was purchased.

On occasion the Partnership has entered into certain purchase/sale transactions in which the purchase price is based on a production-area index and the sales price is based on a market-area index, and it captures the difference in the indices (also referred to as “basis spread”), less the transportation expenses from the two areas, as its fee. Changes in the basis spread can increase or decrease its margins or potentially result in losses. For example, the Partnership is a party to one contract associated with its north Texas operations with a term to 2019 to supply approximately 150,000 MMBtu/d of gas. The Partnership buys gas for this contract on several different production-area indices and sells the gas into a different market area index. The Partnership realizes a cash loss on the delivery of gas under this contract each month based on current prices. The fair value of this performance obligation was recorded based on forecasted discounted cash obligations in excess of market prices under this gas delivery contract. As of December 31, 2016, the balance sheet reflects a liability of $44.8 million related to this performance obligation. Narrower basis spreads in recent periods have increased the losses on this contract, and greater losses on this contract could occur in future periods if these conditions persist or become worse.

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The Partnership typically transports and fractionates or stores NGLs owned by others for a fee based on the volume of NGLs transported and fractionated or stored. The Partnership also buys mixed NGLs from its suppliers at a fixed discount to market indices for the component NGLs with a deduction for its fractionation fee. The Partnership subsequently sells the fractionated NGL products based on the same index-based prices. The operating results of the Partnership’s NGL fractionation business are dependent upon the volume of mixed NGLs fractionated and the level of fractionation fees charged. With the Partnership’s fractionation business, it also has the opportunity for product upgrades for each of the discrete NGL products. The fees the Partnership earns on the product upgrade from this fractionation business are higher during periods with higher liquids prices.

The Partnership generally gathers or transports crude oil and condensate owned by others by rail, truck, pipeline and barge facilities for a fee. The Partnership also buys crude oil and condensate from a producer at a fixed discount to a market index and then transports and resells the crude oil and condensate at the same market index. The Partnership executes substantially all purchases and sales concurrently, thereby establishing the fee it will receive for each crude oil and condensate transaction.

The Partnership realizes gross operating margins from its processing services primarily through different contractual arrangements: processing margins (“margin”), percentage of liquids (“POL”), percentage of proceeds (“POP”) or fixed-fee based. Under margin contract arrangements the Partnership’s gross operating margins are higher during periods of high liquid 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 the Partnership’s gross operating margins are driven by throughput volume. See “Item 7A. Quantitative and Qualitative Disclosures about Market Risk — Commodity Price Risk.”

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 the asset.

General and administrative expenses are dictated by the terms of the partnership agreement. These expenses include the costs of employee, officer and director compensation and benefits properly allocable to the Partnership, fees, services and other transaction costs related to acquisitions, and all other expenses necessary or appropriate to the conduct of business and allocable to the Partnership. The partnership agreement provides that we determine the expenses that are allocable to the Partnership in any reasonable manner determined by the us at its sole discretion.

Recent Growth Developments

Acquisitions and Expansion

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The EnLink Oklahoma T.O. assets serve gathering and processing needs in the growing STACK and CNOW plays in Oklahoma and are supported by long-term, fixed-fee contracts with acreage dedications that, at the time of acquisition, had a weighted-average term of approximately 15 years. The EnLink Oklahoma T.O. assets are strategically located in the core areas of the STACK and CNOW plays and include:

During 2016, we commenced construction on a new cryogenic gas processing plant, referred to as Chisholm II, that will provide an additional 200 MMcf/d of processing capacity and will be tied to new and existing pipelines in the STACK and SCOOP play. Chisholm II is scheduled to be completed during the first quarter of 2017. The new capacity is supported by long-term contracts.

Organic Growth

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Ascension Joint Venture. The Partnership has formed a 50/50 joint venture named Ascension Pipeline Company, LLC (the “Ascension JV”) with a subsidiary of Marathon Petroleum Corporation (“Marathon Petroleum”) to build a new 30-mile NGL pipeline connecting the Partnership’s existing Riverside fractionation and terminal complex to Marathon Petroleum’s Garyville refinery located on the Mississippi River. The Partnership commenced construction of the pipeline during 2016 and will operate the pipeline upon completion, which is currently estimated to be during the second quarter of 2017. This bolt-on project to the Partnership’s Cajun-Sibon NGL system is supported by long-term, fee-based contracts with Marathon Petroleum.

Sale of Non-Core Assets

Issuance of Senior Notes

On July 14, 2016, the Partnership issued $500.0 million in aggregate principal amount of its 4.850% senior notes due 2026 (the “2026 Notes”) at a price to the public of 99.859% of their face value. The 2026 Notes mature on July 15, 2026. Interest payments on the 2026 Notes are payable on January 15 and July 15 of each year, beginning January 15, 2017. Net proceeds of approximately $495.7 million were used to repay outstanding borrowings under the Partnership’s revolving credit facility and for general partnership purposes.

Issuance of the Partnership’s Common Units

Equity Distribution Agreement. In November 2014, the Partnership entered into an equity distribution agreement (the “BMO EDA”) with BMO Capital Markets Corp. and certain other sales agents to sell up to $350.0 million in aggregate gross sales of the Partnership’s common units from time to time through an “at the market” equity offering program. The Partnership may also sell common units to any sales agent as principal for the sales agent’s own account at a price agreed upon at the time of sale. The Partnership has no obligation to sell any of the common units under the BMO EDA and may at any time suspend solicitation and offers under the BMO EDA.

For the year ended December 31, 2016 the Partnership sold an aggregate of 10.0 million common units under the BMO EDA, generating proceeds of approximately $167.5 million (net of approximately $1.7 million of commissions). The Partnership used the net proceeds for general partnership purposes. As of December 31, 2016, approximately $147.8 million remains available to be issued under the BMO EDA.

Issuance of the Partnership’s Preferred Units

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On January 7, 2016, the Partnership issued an aggregate of 50,000,000 Series B Cumulative Convertible Preferred Units (the “Preferred Units”) representing the Partnership’s limited partner interests to Enfield Holdings, L.P. (“Enfield”) in a private placement (the “Private Placement”) for a cash purchase price of $15.00 per Preferred Unit (the “Issue Price”), resulting in net proceeds of approximately $724.1 million after fees and deductions. Proceeds from the Private Placement were used to fund the EnLink Oklahoma T.O. acquisition.

The Preferred Units are convertible into the Partnership’s common units on a one-for-one basis, subject to certain adjustments, at any time after the record date for the quarter ending June 30, 2017 (a) in full, at the Partnership’s option, if the volume weighted average price of a common unit over the 30-trading day period ending two trading days prior to the conversion date (the “Conversion VWAP”) is greater than 150% of the Issue Price or (b) in full or in part, at Enfield’s option. In addition, upon certain events involving a change of control of the general partner or the managing member of ENLC, all of the Preferred Units will automatically convert into a number of common units equal to the greater of (i) the number of common units into which the Preferred Units would then convert and (ii) the number of Preferred Units to be converted multiplied by an amount equal to (x) 140% of the Issue Price divided by (y) the Conversion VWAP.

Enfield receives quarterly distributions, subject to certain adjustments, equal to (x) during the quarter ending March 31, 2016 through the quarter ending June 30, 2017, an annual rate of 8.5% on the Issue Price payable in-kind in the form of additional Preferred Units and (y) thereafter, at an annual rate of 7.5% on the Issue Price payable in cash (the “Cash Distribution Component”) plus an in-kind distribution equal to the greater of (A) an annual rate of 1.0% of the Issue Price and (B) an amount equal to (i) the excess, if any, of the distribution that would have been payable had the Preferred Units converted into common units over the Cash Distribution Component, divided by (ii) the Issue Price. Distributions on the Preferred Units for the three months ended March 31, 2016, June 30, 2016 and September 30,2016, were paid-in kind through the issuance of 992,445, 1,083,589, and 1,106,616 Preferred Units on May 12, 2016, August 11, 2016, and November 10, 2016 respectively. A distribution on the Preferred Units was declared for the three months ended December 31, 2016, which will result in the issuance of 1,130,131 additional Preferred Units on February 13, 2016. Income was allocated to the Preferred Units in an amount equal to the quarterly distribution with respect to the period earned. For the year ended December 31, 2016, $69.9 million of income was allocated to the Partnership Preferred Units.

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Acquisitions in 2014 and 2015

In 2014, the Partnership completed the drop down of certain equity interests in EnLink Appalachian Compression, LLC (formerly, E2 Appalachian Compression, LLC) and E2 Energy Services, LLC (collectively, “E2”) from us.

During 2015, the Partnership completed the EMH Drop Downs and a drop down transaction to acquire VEX from Devon.

Devon Energy Transaction and EMH Drop Downs

On March 7, 2014, we and the Partnership consummated the transactions contemplated by the Contribution Agreement, dated as of October 21, 2013, among us, the Operating Partnership, Devon, Devon Gas Corporation, Devon Gas Services, L.P. (“Gas Services”) and Southwestern Gas Pipeline, Inc. (“Southwestern Gas” and, together with Gas Services, the “Contributors”) pursuant to which the Contributors contributed (the “Contribution”) to the Operating Partnership a 50% limited partner interest in Midstream Holdings and all of the outstanding equity interests in EnLink Midstream Holdings GP, LLC, the general partner of Midstream Holdings (“Midstream Holdings GP”), in exchange for the issuance by the Partnership of 120,542,441 units representing limited partnership interests in the Partnership.

Also on March 7, 2014, EnLink Midstream, Inc. (“EMI”) and Devon consummated the transactions contemplated by the Merger Agreement, dated as of October 21, 2013, among the EMI, Devon, ENLC, Acacia Natural Gas Corp I, Inc., formerly a wholly-owned subsidiary of Devon, and certain other wholly-owned subsidiaries of Devon pursuant to which EMI and Acacia each became wholly-owned subsidiaries of ENLC (collectively, the “Mergers” and together with the Contribution, the “Business Combination”). Upon completion of the merger with Acacia, ENLC indirectly owned the remaining 50% limited partner interest in Midstream Holdings.

On February 17, 2015, Acacia contributed a 25% interest in Midstream Holdings (the “February 2015 Transferred Interests”) to the Partnership in a drop down transaction (the “February EMH Drop Down”) in exchange for 31.6 million Class D Common Units in the Partnership. On May 27, 2015, Acacia contributed the remaining 25% limited partner interest in Midstream Holdings (the “May 2015 Transferred Interests”) to the Partnership in a drop down transaction (the “May 2015 EMH Drop Down” and together with the February 2015 EMH Drop Down, the “EMH Drop Downs”) in exchange for 36.6 million Class E Common Units in the Partnership. After giving effect to the EMH Drop Downs, the Partnership owns 100% of Midstream Holdings. In addition, on April 1, 2015, the Partnership acquired the Victoria Express Pipeline and related truck terminal and storage assets from Devon (the “VEX Interests”).

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As of December 31, 2016, Devon held approximately 23.8% of the Partnership’s outstanding limited partner interests. Public common unitholders and preferred unitholders held approximately 40.1% and 13.4% of the outstanding limited partner interests, respectively. We indirectly held approximately 22.3% of the outstanding limited partner interests and an approximate 0.4% general partner interest as of December 31, 2016.

Non-GAAP Financial Measures

Cash Available for Distribution

We calculate cash available for distribution as distributions due to us from the Partnership and our interest in EnLink Oklahoma T.O. adjusted EBITDA (as defined herein), plus our share of EnLink Oklahoma T.O.’s growth capital expenditures, less our share of maintenance capital attributable to our interest in EnLink Oklahoma T.O., our specific general and administrative costs as a separate public reporting entity, the interest costs associated with our debt and current taxes attributable to our earnings. We also calculate cash available for distribution as net income (loss) of ENLC less the net income (loss) of ENLK, which is consolidated into ENLC's net income (loss), plus ENLC's (i) share of distributions from ENLK, (ii) share of EnLink Oklahoma Gas Processing, LP (together with its subsidiaries, "EnLink Oklahoma T.O.”) depreciation expense, (iii) deferred income tax expense, (iv) interest in the adjusted EBITDA of Midstream Holdings prior to the EMH drop downs, (v) corporate goodwill impairment, (vi) acquisition transaction costs attributable to its share of the EnLink Oklahoma T.O. acquisition, and less ENLC’s interest in maintenance capital expenditures of Midstream Holdings prior to the EMH drop downs. ENLC’s share of EnLink Oklahoma T.O. growth capital expenditures are funded by borrowings under ENLC’s credit facility and not considered in determining ENLC’s cash flow available for distribution. During 2016, we generated federal net operating loss carryforwards to offset future taxable income generated during 2016. We have $170.1 million of federal net operating loss carryforwards remaining as of December 31, 2016. Historically, we have had net operating losses that eliminated substantially all of our taxable income and thus we have not historically paid significant amounts of income taxes. We anticipate generating net operating losses for tax purposes during 2017, and as a result, do not expect to incur material amounts of federal and state income tax liabilities. In the event we do generate taxable income, federal and state income tax liabilities will reduce the cash available for distribution to our unitholders. Cash available for distribution is a supplemental liquidity metric used by us and by external users of our financial statements, such as investors, commercial banks, research analysts and others to compare basic cash flows generated by us to the cash distributions we expect to pay our unitholders. Using this metric, management and external users of our financial statements can quickly compute the coverage ratio of estimated cash flows to planned cash distributions. Cash available for distribution is also an important financial measure for our unitholders since it serves as an indicator of our success in providing a cash return on investment.

Growth capital expenditures generally include capital expenditures made for acquisitions or capital improvements that we expect will increase our asset base, operating income or operating capacity over the long-term. Examples of growth capital expenditures include the acquisition of assets and the construction or development of additional pipeline, storage, gathering or processing assets, in each case, to the extent such capital expenditures are expected to expand the Partnership’s asset base, operating capacity or our operating income. Maintenance capital expenditures include capital expenditures made to replace partially or fully depreciated assets in order to maintain the existing operating capacity of the assets and to extend their useful lives. Examples of maintenance capital expenditures are expenditures to refurbish and replace pipelines and other gathering, well connection, compression and processing assets up to their original operating capacity, to maintain equipment reliability, integrity and safety and to address environmental laws and regulations.

The GAAP measure most directly comparable to cash available for distribution is net income (loss). Cash available for distribution should not be considered as an alternative to GAAP net income (loss). Cash available for distribution is not a presentation made in accordance with GAAP and has important limitations as an analytical tool. Investors should not consider cash available for distribution in isolation or as a substitute for analysis of our results as reported under GAAP. Because cash available for distribution excludes some items that affect net income (loss) and is defined differently by different companies in our industry, our definition of cash available for distribution may not be comparable to similarly-titled measures of other companies, thereby diminishing its utility.

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The following is a calculation of our cash available for distribution (in millions):


	Year Ended December 31,
	2016		2015		2014
Distribution declared by ENLK associated with (1):
General partner interest	$	2.1	$	2.4	$	2.2
Incentive distribution rights		56.8		47.5		22.6
ENLK common units owned		138.1		104.5		24.8
Total share of ENLK distributions declared	$	197.0	$	154.4	$	49.6
Transferred interest EBITDA (2)		—		53.7		187.9
Adjusted EBITDA of EnLink Oklahoma T.O. (3)		9.0		—		—
Transaction costs (4)		0.6		—		—
Total cash available	$	206.6	$	208.1	$	237.5
Uses of cash:
General and administrative expenses		(2.8)		(4.1)		(3.2)
Current income taxes (5)		(0.6)		0.1		(3.5)
Interest expense		(1.4)		(0.8)		(2.2)
Maintenance capital expenditures (6)		(0.1)		(4.0)		(11.0)
Total cash used	$	(4.9)	$	(8.8)	$	(19.9)
ENLC cash available for distribution	$	201.7	$	199.3	$	217.6

(1)

Represents distributions to be paid to us on February 13, 2017 and distributions paid on November 11, 2016, August 11, 2016, May 12, 2016, February 11, 2016, November 12, 2015, August 14, 2015 and May 14, 2015.

(2)

Represents our interest in Midstream Holdings adjusted EBITDA, which was disbursed to ENLC by Midstream Holdings on a monthly basis prior to the transfer of all interests in Midstream Holdings to the Partnership in the EMH Drop Downs. Midstream Holdings’ adjusted EBITDA is defined as net income (loss) plus interest expense, provision for income taxes, depreciation and amortization expense, impairment expense, unit-based compensation, (gain) loss on non-cash derivatives, (gain) loss on disposition of assets, successful transaction costs, accretion expense associated with asset retirement obligations, reimbursed employee costs, non-cash rent, and distributions from unconsolidated affiliate investments, less payments under onerous performance obligations, non-controlling interest, and income (loss) from unconsolidated affiliate investments.

(3)

Represents our interest in EnLink Oklahoma T.O. adjusted EBITDA, which is disbursed to ENLC by EnLink Oklahoma T.O. on a monthly basis. EnLink Oklahoma T.O. adjusted EBITDA is defined as net income (loss) plus depreciation and amortization and provision for income taxes.

(4)

Represents acquisition transaction costs attributable to the Company’s 16% interest in EnLink Oklahoma T.O, which are considered growth capital expenditures as part of the cost of the assets acquired.

(5)

Represents our stand-alone current tax expense.

(6)

Represents our share of EnLink Oklahoma T.O.’s maintenance capital expenditures for the year ended December 31, 2016 and our interest in Midstream Holdings’ maintenance capital expenditures prior to the 2015 EMH Drop Downs for the years ended December 31, 2015 and 2014.

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The following table provides a reconciliation our net income from continuing operations to our cash available for distribution (in millions):


	Year Ended December 31,
	2016		2015		2014
Net income (loss) of ENLC	$	(888.2)	$	(1,409.7)	$	249.7
Less: Net income (loss) attributable to ENLK		(565.2)		(1,377.8)		310.5
Net loss of ENLC excluding ENLK	$	(323.0)	$	(31.9)	$	(60.8)
ENLC's share of distributions from ENLK (1)		197.0		154.4		49.6
ENLC's interest in EnLink Oklahoma T.O. depreciation		14.3		—		—
ENLC's deferred income tax expense (2)		2.8		26.2		52.1
Maintenance capital expenditures (3)		(0.1)		(4.0)		(11.0)
Transferred interest EBITDA (4)		—		53.7		187.9
ENLC corporate goodwill impairment		307.0		—		—
Other items (5)		3.7		0.9		(0.2)
ENLC cash available for distribution	$	201.7	$	199.3	$	217.6

(1)

Represents distributions declared by ENLK and to be paid to ENLC on February 13, 2017 and distributions paid by ENLK to ENLC on November 11, 2016, August 11, 2016, May 12, 2016, February 11, 2016, November 12, 2015, August 14, 2015 and May 14, 2015.

(2)

Represents our stand-alone deferred taxes.

(3)

For the year ended December 31, 2016 this amount represents our share of EnLink Oklahoma T.O.’s maintenance capital expenditures. For the years ended December 31, 2015 and 2014, these amount represent ENLC’s interest in maintenance capital expenditures of Midstream Holdings prior to the EMH Drop Downs.

(4)

(5)

Represents transaction costs attributable to our share of the acquisition of EnLink Oklahoma T.O., E2's adjusted EBITDA with respect to 2014 and other non-cash items not included in cash available for distributions.

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 purchase and resell natural gas, NGLs, condensate and crude oil for a margin or to gather, process, transport or market natural gas, NGLs, condensate and crude oil for a fee. Operating expense is a separate measure used by 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 gross operating margin in the same manner.

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


	Year Ended December 31,
	2016		2015		2014
Operating income (loss)	$	(674.5)	$	(1,301.9)	$	354.3

Add (deduct):
Operating expenses		398.5		419.9		283.6
General and administrative expenses		122.5		136.9		97.3
Depreciation and amortization		503.9		387.3		284.3
(Gain) loss on disposition of assets		13.2		1.2		(0.1)
Impairments		873.3		1,563.4		—
Gain on litigation settlement		—		—		(6.1)
Total gross operating margin	$	1,236.9	$	1,206.8	$	1,013.3

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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 operating revenue less cost of sales as reflected in the table below (in millions, except volumes):


	Year Ended December 31,
	2016		2015		2014
Texas Segment
Revenues	$	1,068.3	$	1,000.2	$	1,032.4
Cost of sales		(483.4)		(412.2)		(456.9)
Total gross operating margin	$	584.9	$	588.0	$	575.5
Louisiana Segment
Revenues	$	2,001.5	$	1,840.3	$	1,837.4
Cost of sales		(1,729.0)		(1,567.6)		(1,674.2)
Total gross operating margin	$	272.5	$	272.7	$	163.2
Oklahoma Segment
Revenues	$	437.0	$	187.0	$	318.8
Cost of sales		(184.9)		(17.9)		(142.6)
Total gross operating margin	$	252.1	$	169.1	$	176.2
Crude and Condensate Segment
Revenues	$	1,176.5	$	1,498.2	$	367.2
Cost of sales		(1,038.0)		(1,330.6)		(290.9)
Total gross operating margin	$	138.5	$	167.6	$	76.3
Corporate
Revenues	$	(430.9)	$	(73.6)	$	(48.0)
Cost of sales		419.8		83.0		70.1
Total gross operating margin	$	(11.1)	$	9.4	$	22.1
Total
Revenues	$	4,252.4	$	4,452.1	$	3,507.8
Cost of sales		(3,015.5)		(3,245.3)		(2,494.5)
Total gross operating margin	$	1,236.9	$	1,206.8	$	1,013.3

Midstream Volumes:
Texas (1)
Gathering and Transportation (MMBtu/d)		2,622,600		2,849,600		2,958,000
Processing (MMBtu/d)		1,173,100		1,222,700		1,146,000
Louisiana (2)
Gathering and Transportation (MMBtu/d)		1,676,600		1,468,300		615,200
Processing (MMBtu/d)		490,300		506,100		547,000
NGL Fractionation (Gals/d)		5,197,100		5,771,500		3,804,300
Oklahoma (3)
Gathering and Transportation (MMBtu/d)		626,300		428,600		471,000
Processing (MMBtu/d)		574,900		359,600		442,000
Crude and Condensate (2)
Crude Oil Handling (Bbls/d)		94,000		131,500		26,300
Brine Disposal (Bbls/d)		3,600		3,900		4,700

(1)

Volumes include volumes per day based on 365-day period for the years ended December 31, 2016, 2015 and 2014 for Midstream Holdings operations. Volumes include volumes per day based on the 300-day period from March 7 to December 31, 2014 for the year ended December 31, 2014 for our legacy operations in Texas.

(2)

Volumes include volumes per day based on the 300-day period from March 7 to December 31, 2014 for the year ended December 31, 2014 for our legacy operations. Midstream Holdings does not have any operations in Louisiana or Ohio.

(3)

Volumes include volumes per day based on 365-day period for the years ended December 31, 2016, 2015 and 2014 respectively, for Midstream Holdings operations. We did not have any legacy operations in Oklahoma.

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Year ended December 31, 2016 Compared to Year ended December 31, 2015

Gross Operating Margin. Gross operating margin was $1,236.9 million for the year ended December 31, 2016 compared to $1,206.8 million for the year ended December 31, 2015, an increase of $30.1 million, or 2.5%, due to the following:

Texas Segment. Gross operating margin in the Texas segment decreased $3.1 million for the year ended December 31, 2016 compared to the year ended December 31, 2015. The Texas segment decrease was attributable to a decrease of $34.1 million in gross operating margin due to volume declines and expirations of certain higher margin contracts from our north Texas processing, gathering, and transportation assets. The gross operating margin decline due to volumes includes minimum volume commitment (“MVC”) revenue from Partnership contracts with Devon of $26.4 million for the year ended December 31, 2016 as compared to $3.8 million for the year ended December 31, 2015. This decrease from the Partnership’s north Texas assets was partially offset by gross operating margin contributions totaling $20.5 million from 2015 acquisitions on the MEGA system. In addition, volume growth in the Mega System resulted in an additional increase in gross operating margin of $10.7 million between periods.

Louisiana Segment. Gross operating margin in the Louisiana segment decreased $0.2 million for the year ended December 31, 2016 compared to the year ended December 31, 2015. The Louisiana segment realized a 1% decrease in gross operating margin from its NGL business as a result of declines in pipeline throughput and fractionation volumes, substantially offset by an increase in gross operating margin from the Louisiana gas business.

Oklahoma Segment. Gross operating margin in the Oklahoma segment increased $83.1 million for the year ended December 31, 2016 compared to the year ended December 31, 2015. This increase was driven by a gross operating margin contribution of $82.0 million from the EnLink Oklahoma T.O. assets acquired in January 2016. In addition, the Partnership’s gross operating margin from its Cana gathering and processing assets increased by $5.8 million between periods primarily due to increased volumes from Devon, including MVC revenue from Devon of $10,8 million for the year ended December 31, 2016 as compared to $20.1 million for the year ended December 31, 2015. This increase was partially offset by a decline in gross operating margin of $5.4 million at the Partnership’s Northridge gathering and processing assets as a result of a decline in volumes and a rate reduction on a third-party contract.

Crude and Condensate Segment. Gross operating margin in the Crude and Condensate segment decreased $29.1 million for the year ended December 31, 2016 compared to the year ended December 31, 2015. A decrease of $24.7 million resulted from the termination of a customer contract during the second quarter of 2015 and included a $10.3 million early termination payment from the customer in 2015. The remaining decrease was primarily the result of volume declines throughout the Crude and Condensate segment.

Corporate Segment. The Corporate segment included a loss from derivative activity of $11.1 million for the year ended December 31, 2016 compared to a gain of $9.4 million for the year ended December 31, 2015 related to the changes in fair value of our commodity swaps between periods. For the year ended December 31, 2016, there were realized gains of $9.0 million offset by $20.1 million in unrealized losses. For the year ended December 31, 2015, there were realized gains of $17.1 million partially offset by unrealized losses of $7.7 million.

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Operating Expenses. Operating expenses were $398.5 million for the year ended December 31, 2016 compared to $419.9 million for the year ended December 31, 2015, a decrease of $21.4 million, or 5.1%. The primary contributors to the total decrease by segment were as follows (in millions):


	Year Ended
	December 31,				Change
	2016		2015		$		%
Texas Segment	$	168.5	$	181.8	$	(13.3)	(7.3)	%
Louisiana Segment		96.6		105.9		(9.3)	(8.8)	%
Oklahoma Segment		52.1		30.3		21.8	71.9	%
Crude and Condensate Segment		81.3		101.9		(20.6)	(20.2)	%
Total	$	398.5	$	419.9	$	(21.4)	(5.1)	%

Texas Segment. Operating expenses in the Texas segment decreased $13.3 million for the year ended December 31, 2016 compared to the year ended December 31, 2015. The decrease was primarily attributable to lower operating costs of $18.3 million resulting from overall cost reduction measures and lower rental expense on compressors. These decreases were partially offset by a $8.0 million increase in operating expenses attributable to the acquisitions in the MEGA system.

Louisiana Segment. Operating expenses in the Louisiana segment decreased $9.3 million for the year ended December 31, 2016 compared to the year ended December 31, 2015 due to overall cost reduction measures, including cost savings from materials and supplies, construction fees and services and labor. In addition, rental expense decreased $1.0 million due to rental equipment that was returned in the first quarter of 2016.

Oklahoma Segment. Operating expenses in the Oklahoma segment increased $21.8 million for the year ended December 31, 2016 compared to the year ended December 31, 2015. This increase was primarily attributable to the EnLink Oklahoma T.O. acquisition in January 2016.

Crude and Condensate Segment. Operating expenses in the Crude and Condensate segment decreased $20.6 million for the year ended December 31, 2016 compared to the year ended December 31, 2015. This decrease was due primarily to decreased trucking volumes, which decreased labor, fuel and contractor costs, in addition to overall cost reduction measures.

General and Administrative Expenses. General and administrative expenses were $122.5 million for the year ended December 31, 2016 compared to $136.9 million for the year ended December 31, 2015, a decrease of $14.4 million, or 10.5%. The primary contributors to the decrease are as follows:

unit-based compensation expense decreased $7.3 million due primarily to bonuses being paid in the form of units that immediately vested in March 2015;

wages and salaries decreased $2.9 million due to a decrease in bonus expense;

software consulting fees decreased $2.0 million due to completed implementation of new software;

bad debt expense decreased $2.1 million;

transition service fees related to acquisitions decreased $1.0 million;

transaction costs related to acquisitions decreased $1.3 million;

travel and training expense decreased $1.0 million; and

rent expense increased $4.9 million related to new office leases that commenced during 2016.

Loss on Disposition of Assets. Loss on disposition of assets was $13.2 million for the year ended December 31, 2016 compared to a loss on disposition of assets of $1.2 million for the year ended December 31, 2015. The loss on disposition of assets for the year ended December 31, 2016 was primarily attributable to a $13.4 million loss on sale of the NTPL. The loss on disposition of assets for the year ended December 31, 2015 related to the retirement of a compressor due to fire damage.

Depreciation and Amortization. Depreciation and amortization expenses were $503.9 million for the year ended December 31, 2016 compared to $387.3 million for the year ended December 31, 2015, an increase of $116.6 million, or 30.1%. Of this increase, $88.6 million was attributable to the acquisition of the EnLink Oklahoma T.O. assets; $11.5 million was attributable to additional assets on the MEGA system; and $7.4 million was attributable to the Lobo plants.

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These increases were partially offset by a $14.4 million decrease in amortization attributable to the impairment of ORV intangible assets in the third quarter of 2015. The remaining increase in depreciation and amortization expense was primarily attributable to assets placed in service.

Impairments. Impairment expense was $873.3 million for the year ended December 31, 2016 compared to impairment expense of $1,563.4 million for the year ended December 31, 2015, a decrease of $690.1 million, or 44.1%. In the first quarter of 2016, we recognized an impairment of goodwill of $566.3 million related to the Partnership’s Texas and Crude and Condensate segments, as well as $307.0 million related to our Corporate segment. For the year ended December 31, 2015, the Partnership recognized an impairment on goodwill of $1,328.2 million related to its Louisiana, Texas, and Crude and Condensate segments and an impairment on intangible assets of $223.1 million in its Crude and Condensate segment. For the year ended December 31, 2015, the Partnership also recognized an impairment on property, plant and equipment of $12.1 million primarily related to costs associated with the cancellation of various projects. For more information, see the “Critical Accounting Policies” section below.

Interest Expense. Interest expense was $189.5 million for the year ended December 31, 2015 compared to $103.3 million for the year ended December 31, 2015, an increase of $86.2 million, or 83.4%. Net interest expense consisted of the following (in millions):


	Year Ended
	December 31,
	2016		2015
Partnership senior notes	$	131.1	$	106.0
Partnership credit facility		11.7		7.9
Credit facility		1.1		0.6
Capitalized interest		(7.2)		(7.7)
Amortization of debt issue costs and net discount (premium)		53.4		0.4
Cash settlements on interest rate swaps		(0.4)		(3.6)
Redeemable non-controlling interest		0.3		(1.8)
Other		(0.5)		1.5
Total	$	189.5	$	103.3

The increase in interest expense of $86.2 million was primarily due to an increase of $52.3 million attributable to the non-cash amortization of the discount related to the EnLink Oklahoma T.O. acquisition installment payments in 2016 and an increase of $25.1 million attributable to the issuance of $900.0 million aggregate principal amount of unsecured senior notes in May 2015 and the issuance of $500.0 million in aggregate principal amount of unsecured senior notes in July 2016.

Income (loss) from Unconsolidated Affiliate Investments. Loss from unconsolidated affiliate investments was $19.9 million for the year ended December 31, 2016 compared to income of $20.4 million for the year ended December 31, 2015, a decrease of $40.3 million. This decrease was primarily due to a $20.1 million impairment on the Partnership’s investment in HEP for the year ended December 31, 2016. In December 2016, we entered into an agreement to sell our ownership interest in HEP for approximately $193.1 million, and the transaction is expected to close in the first quarter of 2017. As a result, the Partnership reduced the carrying value of its investment to the expected sales price. In addition, the decrease in income from unconsolidated affiliate investments resulted from a $10.6 million decrease in income from the Partnership’s investment in HEP. Income from the Partnership’s investment in GCF also declined $9.2 million due to lower revenues as a result of lower pipeline and fractionator feed volumes, together with increased operating costs for major scheduled fractionator maintenance during the first quarter of 2016.

Income Tax Expense. Income tax expense was $4.6 million for the year ended December 31, 2016 compared to income tax expense of $25.7 million for the year ended December 31, 2015, a decrease of $21.1 million. The decrease in income tax expense was due to a decrease in taxable income between periods. Although we realized losses from continuing operations before income taxes for the years ended December 31, 2016 and 2015, we did not realize tax benefits associated with these losses because substantially all of the losses were the result of goodwill impairments, which are treated as permanent differences for tax. See “Item 8. Financial Statements and Supplementary Data—Note 7” for further details.

Net Income (Loss) Attributable to Non-controlling Interest. Net loss attributable to non-controlling interest was $428.2 million for the year ended December 31, 2016 compared to a net loss of $1,054.5 million for the year ended

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December 31, 2015, a decrease of $626.3 million. The decrease in net loss attributable to non-controlling interests is primarily due to narrowing net losses in 2016 and 2015 at the Partnership driven by lower impairment expense.

Year ended December 31, 2015 Compared to Year ended December 31, 2014

Gross Operating Margin. Gross operating margin was $1,206.8 million for the year ended December 31, 2015 compared to $1,013.3 million for the year ended December 31, 2014, an increase of $193.5 million, or 19.1%. Of this increase in gross operating margin:

$85.9 million was attributable to the legacy Partnership assets for a full year of gross operating margin during 2015 as compared to ten months during 2014;

$100.3 million was attributable to the LPC, Coronado, Chevron, and Matador acquisitions;

$13.0 million was attributable to the VEX pipeline, which commenced operations in July 2014;

$21.6 million was attributable to the commercial start-up of five compression and condensate stabilization stations in the ORV since the fourth quarter of 2014; and

$51.5 million was attributable to the completion of the Cajun-Sibon expansion in September 2014.

This increase is partially offset by a:

$57.4 million decrease in gross operating margin related to a decline in volumes on the Partnership’s Texas assets;

$11.9 million decrease in gross operating margin related primarily to volume declines in the Partnership’s Louisiana gas business; and

$6.7 million decrease in gross operating margin related to Midstream Holdings, which is the result of the new fixed-fee arrangements with Devon entered into in connection with the Business Combination.

Operating Expenses. Operating expenses were $419.9 million for the year ended December 31, 2015 compared to $283.6 million for the year ended December 31, 2014, an increase of $136.3 million, or 48.1%. Of this increase in operating expenses:

$43.2 million was attributable to legacy Partnership assets for a full year of operating expense during 2015 as compared to ten months during 2014;

$59.0 million was attributable to direct operating costs of the LPC, Coronado, Matador and Chevron acquisitions during 2014 and 2015;

$7.9 million was due to our Cajun-Sibon expansion completed in September 2014;

$10.7 million was attributable to ORV compression and stabilization facilities that have been placed in service since the fourth quarter of 2014;

$6.7 million was attributable to our Bearkat natural gas processing plant and rich gas gathering system, which commenced operations in September 2014; and

$5.2 million was attributable to an increase in Midstream Holdings’ operating costs.

General and Administrative Expenses. General and administrative expenses were $136.9 million for the year ended December 31, 2015 compared to $97.3 million for the year ended December 31, 2014, an increase of $39.6 million, or 40.7%. The primary contributors to the increase were as follows:

$18.8 million was attributable to the legacy Partnership assets for a full year of expenses during 2015 as compared to ten months during 2014;

$6.0 million was attributable to certain bonuses paid in March 2015 in the form of unit awards that immediately vested;

$5.4 million in transaction costs related to the EnLink Oklahoma T.O., Matador, LPC, and Coronado acquisitions, as well as the VEX dropdown;

$3.2 million in increased unit-based compensation expense;

$2.3 million in increased bad debt expense; and

$5.9 million in increased salaries and wages due to an increase in headcount related to acquisitions during the year.

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These increases were partially offset by a $2.4 million decrease attributable to Midstream Holdings. Prior to March 7, 2014, general and administrative expenses were allocated to Midstream Holdings by Devon.

Loss on Disposition of Assets. Loss on disposition of assets was $1.2 million for the year ended December 31, 2015 compared to a gain on disposition of assets of $0.1 million for the year ended December 31, 2014, an increase of $1.3 million. The loss on disposition of assets for the year ended December 31, 2015 related to the retirement of a compressor due to fire damage.

Depreciation and Amortization. Depreciation and amortization expenses were $387.3 million for the year ended December 31, 2015 compared to $284.3 million for the year ended December 31, 2014, an increase of $103.0 million, or 36.2%. Of this increase in depreciation and amortization expenses, $21.8 million was attributable to the legacy Partnership assets acquired in March 2014; $12.0 million was attributable to the Chevron acquisition in November 2014; $6.8 million was attributable to the LPC asset acquisition in January 2015; $25.6 million was attributable to the Coronado asset acquisition in March 2015 and $1.7 million was attributable to the Matador asset acquisition in October 2015. The remaining increase in depreciation and amortization expense of $35.1 million was primarily attributable to new assets placed in service.

Impairments. Impairment expense was $1,563.4 million for the year ended December 31, 2015. The Partnership recognized an impairment on goodwill of $1,328.2 million related to its Louisiana, Texas, and Crude and Condensate segments and an impairment on intangible assets of $223.1 million in its Crude and Condensate segment for the year ended December 31, 2015. The Partnership also recognized an impairment on property, plant and equipment of $12.1 million for the year ended December 31, 2015 primarily related to costs associated with the cancellation of various capital projects. For more information, see “Critical Accounting Policies—Impairment of Goodwill” below.

Gain on Litigation Settlement. The Partnership recognized a gain on the settlement of a lawsuit of $6.1 million for the year ended December 31, 2014 due to a partial settlement of its claims against Texas Brine and its insurers. Additional claims related to this matter remain outstanding.

Interest Expense. Interest expense was $103.3 million for the year ended December 31, 2015 compared to $49.8 million for the year ended December 31, 2014, an increase of $53.5 million, or 107.4%. Of the increase in interest expense, $16.2 million was attributable to the number of days debt was outstanding in 2015 compared to 2014 because Midstream Holdings did not have any borrowings prior to March 7, 2014. Interest expense for the year ended December 31, 2015 also included interest expense for 365 days as compared to 300 days for the year ended December 31, 2014 (days from March 7, 2014 through December 31, 2014). In addition, average debt outstanding increased in 2015 as compared to 2014, which increased interest expense by $41.6 million but was partially offset by $5.2 million due to a decrease in average interest rates primarily related to our credit facility. Net interest expense consists of the following (in millions):


	Year Ended
	December 31,
	2015		2014
Partnership senior notes	$	106.0	$	55.6
Partnership credit facility		7.9		5.8
Credit facility		0.6		2.2
Capitalized interest		(7.7)		(11.5)
Amortization of debt issue costs and net discount (premium)		0.4		(1.0)
Cash settlements on interest rate swaps		(3.6)		(3.6)
Redeemable non-controlling interest		(1.8)		—
Other		1.5		2.3
Total	$	103.3	$	49.8

Income from Unconsolidated Affiliate Investments. Income from unconsolidated affiliate investments was $20.4 million for the year ended December 31, 2015 compared to $18.9 million for the year ended December 31, 2014, an increase of $1.5 million. This increase was primarily due to a $5.6 million increase attributable to the Partnership's investment in HEP as a result of acquisition activity that occurred in 2015. This increase was partially offset by a

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decrease in the Partnership's investment in GCF of $4.1 million due to lower throughput volume and decreased product price spreads.

Income Tax Expense. Income tax expense was $25.7 million for the year ended December 31, 2015 compared to income tax expense of $76.4 million for the year ended December 31, 2014, a decrease of $50.7 million. The decrease in income tax expense was primarily attributable to a decrease in taxable income between periods. Although we realized a loss from continuing operations before income taxes for the year ended December 31, 2015, we did not realize a tax benefit associated with this loss because substantially all of the loss was the result of a goodwill impairment which was treated as a permanent difference for tax.

Net Income (Loss) Attributable to Non-Controlling Interest. Net loss attributable to non-controlling interest was $1,054.5 million for the year ended December 31, 2015 compared to net income of $126.7 million for the year ended December 31, 2014, a decrease of $1,181.2 million. Net income (loss) attributable to non-controlling interests decreased due to a net loss in 2015 at the Partnership primarily driven by impairment expense offset by higher incentive right distributions received.

Critical Accounting Policies

The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as the accounting rules have developed. Accounting rules generally do not involve a selection among alternatives, but involve an implementation and interpretation of existing rules, and the use of judgment to the specific set of circumstances existing in our business. Compliance with the rules necessarily involves reducing a number of very subjective judgments to a quantifiable accounting entry or valuation. We make every effort to properly comply with all applicable rules on or before their adoption, and we believe the proper implementation and consistent application of the accounting rules is critical.

Our critical accounting policies are discussed below. See “Item 8. Financial Statements and Supplementary Data— Note 2” for further details on our accounting policies.

Revenue Recognition and Commodity Risk Management. We recognize revenue for sales or services at the time the natural gas, NGL, condensate or crude oil is delivered or at the time the service is performed. We generally accrue one month of sales and the related gas, NGL, condensate or crude oil purchases and reverse these accruals when the sales and purchases are actually invoiced and recorded in the subsequent months. Actual results could differ from the accrual estimates.

We utilize extensive estimation procedures to determine the sales and cost of gas, NGL, condensate or crude oil purchase accruals for each accounting cycle. Accruals are based on estimates of volumes flowing each month from a variety of sources. We use actual measurement data, if it is available, and will use such data as producer/shipper nominations, prior month average daily flows, estimated flow for new production and estimated end-user requirements (all adjusted for the estimated impact of weather patterns) when actual measurement data is not available. Throughout the month following production, actual measured sales and transportation volumes are received and invoiced and used in a process referred to as “actualization.” Through the actualization process, any estimation differences recorded through the accrual are reflected in the subsequent month’s accounting cycle when the accrual is reversed and actual amounts are recorded. Actual volumes purchased, processed or sold may differ from the estimates due to a variety of factors including, but not limited to: actual wellhead production or customer requirements being higher or lower than the amount nominated at the beginning of the month; liquids recoveries being higher or lower than estimated because gas processed through the plants was richer or leaner than estimated; NGL composition of purchases, sales and inventory being different than estimated; the estimated impact of weather patterns being different from the actual impact on sales and purchases; and pipeline maintenance or allocation causing actual deliveries of gas to be different than estimated. We believe that our accrual process for sales and purchases provides a reasonable estimate of such sales and purchases.

We engage in price risk management activities in order to minimize the risk from market fluctuations in the price of natural gas, NGLs, crude oil and condensate. We also manage our price risk related to future physical purchase or sale commitments by entering into either corresponding physical delivery contracts or financial instruments with an objective to balance our future commitments and significantly reduce our risk to the movement in natural gas, NGL and crude oil prices.

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We use derivatives to hedge against changes in cash flows related to product prices, as opposed to their use for trading purposes. ASC 815, Derivatives and Hedging, requires that all derivatives and hedging instruments are recognized as assets or liabilities at fair value. We manage our price risk related to future physical purchase or sale commitments for physical quantities of natural gas, NGLs and crude oil by entering into either corresponding physical delivery contracts or financial instruments with an objective to balance future commitments and significantly reduce risk related to the movement in natural gas, NGL and crude oil prices. However, we are subject to counter-party risk for both the physical and financial contracts. Our hedging contracts qualify as derivatives and we use mark-to-market accounting for both physical and financial contracts of the energy trading business. Accordingly, any gain or loss associated with changes in the fair value of derivatives and physical delivery contracts relating to our hedging activities are recognized currently in earnings as gain on derivatives.

Impairment of Long-Lived Assets. In accordance with ASC 360, Property, Plant and Equipment, the Partnership evaluates long-lived assets, including related intangibles, of identifiable business activities for impairment when events or changes in circumstances indicate, in management’s judgment, that the carrying value of such assets may not be recoverable. The determination of whether impairment has occurred is based on management’s estimate of undiscounted future cash flows attributable to the assets as compared to the carrying value of the assets. If impairment has occurred, the amount of the impairment recognized is determined by estimating the fair value for the assets and recording a provision for loss if the carrying value is greater than fair value.

When determining whether impairment of one of the Partnership’s long-lived assets has occurred, the Partnership must estimate the undiscounted cash flows attributable to the asset. The Partnership’s estimate of cash flows is based on assumptions regarding:

the future fee-based rate of new business or contract renewals;

the purchase and resale margins on natural gas; NGLs, crude oil and condensate;

the volume of gas, NGLs crude oil and condensate available to the asset;

markets available to the asset;

operating expenses; and

future natural gas, NGL product, crude oil and condensate prices.

The amount of availability of gas, NGLs, crude oil and condensate to an asset is sometimes based on assumptions regarding future drilling activity, which may be dependent in part on natural gas, NGL, crude oil and condensate prices. Projections of gas, NGL, crude oil and condensate volumes and future commodity prices are inherently subjective and contingent upon a number of variable factors, including but not limited to:

changes in general economic conditions in regions in which the Partnership markets are located;

the availability and prices of natural gas, NGLs, crude oil and condensate supply;

the Partnership’s ability to negotiate favorable sales agreements;

the risks that natural gas, NGLs, crude oil and condensate exploration and production activities will not occur or be successful;

the Partnership’s dependence on certain significant customers, producers and transporters of natural gas, NGLs, crude oil and condensate; and

competition from other midstream companies, including major energy companies.

Any significant variance in any of the above assumptions or factors could materially affect the Partnership’s cash flows, which could require it to record an impairment of an asset.

During 2016 and 2015, the Partnership reviewed its various assets groups for impairment due to the triggering events described in the goodwill impairment analysis below. During 2015, the undiscounted cash flows related to one of the Partnership’s assets groups in the Crude and Condensate segment were not in excess of its related carrying value. The Partnership estimated the fair value of this reporting unit and determined the fair of the intangible assets was not in excess of their carrying value. This resulted in a $223.1 million impairment of intangible assets in the Partnership’s Crude and Condensate segment, and this non-cash impairment charge is included as an impairment loss on the consolidated statements of operations for the year ended December 31, 2015. The Partnership utilized Level 3 fair value measurements in its impairment analysis of this definite-lived intangible asset, which included discounted cash flow assumptions by management consistent with those utilized in its goodwill impairment analysis.

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Additionally, the Partnership recognized a $12.1 million impairment on property, plant and equipment, primarily related to costs associated with the cancellation of various capital projects in its Texas, Louisiana and Crude and Condensate segments for the year ended December 31, 2015. For the year ended December 31, 2016 we did not identify any triggering events that would indicate impairment on our property, plant and equipment.

Impairment of Goodwill. We conduct our annual goodwill impairment test in the fourth quarter each year. Goodwill is the cost of an acquisition less the fair value of the net identifiable assets of the acquired business. We evaluate goodwill for impairment annually as of October 31, and whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount. We first assess qualitative factors to evaluate whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as the basis for determining whether it is necessary to perform the two-step goodwill impairment test. We may elect to perform the two-step goodwill impairment test without completing a qualitative assessment. If a two-step goodwill impairment test is elected or required, the first step involves comparing the fair value of the reporting unit to its carrying amount. If the carrying amount of a reporting unit exceeds its fair value, the second step of the process involves comparing the implied fair value to the carrying value of the goodwill for that reporting unit. If the carrying value of the goodwill of a reporting unit exceeds the implied fair value of that goodwill, the excess of the carrying value over the implied fair value is recognized as an impairment loss.

We and the Partnership perform our goodwill assessments at the reporting unit level for all reporting units. The Partnership uses a discounted cash flow analysis to perform the assessments. Key assumptions in the analysis include the use of an appropriate discount rate, terminal year multiples, and estimated future cash flows, including volume and price forecasts and estimated operating expense and general and administrative costs. In estimating cash flows, the Partnership incorporates current and historical market and financial information, among other factors. As of December 31, 2016, we also have $1,119.9 million of goodwill related to our investment in the Partnership that is included in our Corporate segment. We utilize the publicly traded market value of our common units, adjusted for our estimated control premium, in our Corporate level goodwill assessment.

During the third quarter of 2015, we determined that sustained weakness in the overall energy sector, driven by low commodity prices together with a decline in our unit price, caused a change in circumstances warranting an interim impairment test. We also performed our annual impairment analysis during the fourth quarter of 2015. Although our established annual effective date for this goodwill analysis is October 31, we updated the effective date for this impairment analysis for the 2015 annual period to December 31, 2015 due to continued declines in commodity prices and our unit price during the fourth quarter of 2015.

Using the fair value approaches described above, in step one of the goodwill impairment test, we and the Partnership determined that the estimated fair values of the Partnership’s Louisiana, Texas and Crude and Condensate reporting unit were less than their carrying amounts, primarily related to commodity prices, volume forecasts and discount rates. The second step of the goodwill impairment test at the Partnership measures the amount of impairment loss and allocates the estimated fair value of the reporting unit among all of the assets and liabilities of the reporting unit as if the reporting unit had been acquired in a business combination. Based on this analysis, a goodwill impairment loss for our Louisiana, Texas, and Crude and Condensate reporting units in the amount of $1,328.2 million was recognized for the year ended December 31, 2015 and is included as an impairment loss in the consolidated statements of operations.

During February 2016, we determined that continued further weakness in the overall energy sector, driven by low commodity prices together with further declines in our unit price and the Partnership unit price subsequent to year-end, caused a change in circumstances warranting an interim impairment test. Based on these triggering events, we performed a goodwill impairment analysis in the first quarter of 2016 on all reporting units. Based on this analysis, a goodwill impairment loss for the Texas, Crude and Condensate, and Corporate reporting units in the amount of $873.3 million was recognized in the first quarter of 2016 and is included as an impairment loss in the consolidated statement of operations for the year ended December 31, 2016.

The Partnership concluded that the fair value of its Oklahoma reporting unit exceeded its carrying value, and the amount of goodwill disclosed on the consolidated balance sheet associated with this reporting unit is recoverable for each of the impairment testing periods during 2015 and 2016. Therefore, no other goodwill impairment was identified or recorded for this reporting unit as a result of the Partnership’s goodwill impairment analyses.

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During our annual impairment test for 2016 performed as of October 31, 2016, we determined that no further impairments were required for the year ended December 31, 2016. The estimated fair value of our reporting units may be impacted in the future by a further decline in our unit price or a continuing prolonged period of lower commodity prices which may adversely affect our estimate of future cash flows, both of which could result in future goodwill impairment charges for our reporting units.

Our and the Partnership’s respective impairment determinations involved significant assumptions and judgments, as discussed above. Differing assumptions regarding any of these inputs could have a significant effect on the various valuations. If actual results are not consistent with our and the Partnership’s assumptions and estimates, or our assumptions and estimates change due to new information, we and the Partnership may be exposed to additional goodwill impairment charges, which would be recognized in the period in which the carrying value exceeds fair value.

Depreciation Expense and Cost Capitalization. Our and the Partnership’s assets consist primarily of natural gas, NGL, condensate and crude oil gathering pipelines, processing plants, condensate stabilization facilities, transmission pipelines and trucks. We and the Partnership capitalize all construction-related direct labor and material costs, as well as indirect construction costs. Indirect construction costs include general engineering and the costs of funds used in construction. Capitalized interest represents the cost of funds used to finance the construction of new facilities and is expensed over the life of the constructed assets through the recording of depreciation expense. We and the Partnership capitalize the costs of renewals and betterments that extend the useful life while we expense the costs of repairs, replacements and maintenance projects as incurred.

We generally calculate depreciation using the straight-line method over the estimated useful life of the assets. Certain assets such as land, NGL line pack, natural gas line pack and crude oil line pack are non-depreciable. The computation of depreciation expense requires judgment regarding the estimated useful lives and salvage value of assets. As circumstances warrant, we may review depreciation estimates to determine if any changes are needed. Such changes could involve an increase or decrease in estimated useful lives or salvage values, which would impact future depreciation expense.

Commodity Price Risk

The Partnership is subject to significant risks due to fluctuation in commodity prices. The Partnership’s exposure to these risks is primarily in the gas processing component of its business. Processing margin, POL and POP contracts are three types of contracts under which we process gas and are exposed to commodity price risk. For the year ended December 31, 2016, approximately 3.0% of the Partnership’s contracts, based on gross operating margin, were processed under POL and POP contracts. A portion of the volume of inlet gas at the Partnership’s south Louisiana and north Texas processing plants is settled under POL agreements. Under these contracts the Partnership receives a fee in the form of a percentage of the liquids recovered, and the producer bears all the costs of the natural gas volumes lost (“shrink”). All of the natural gas processed by the Partnership’s Midmar plants in the Permian Basin are POP-based contracts. Under these contracts, the Partnership receives a fee as a portion of the proceeds of the sale of natural gas and liquids. Accordingly, the Partnership’s revenues under these contracts are directly impacted by the market price of natural gas and NGLs.

The Partnership also realizes gross operating margin under processing margin contracts. For the year ended December 31, 2016, approximately 0.9% of the Partnership’s contracts, based on gross operating margin, were processed under processing margin contracts. The Partnership has a number of processing margin contracts on its Plaquemine and Pelican processing plants. Under this type of contract, the Partnership pays the producer for the full amount of inlet gas to the plant, and it makes 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 shrink and the cost of fuel used in processing. The shrink and fuel losses are referred to as “plant thermal reduction” or “PTR.”

The prices of crude oil, condensate, natural gas and NGLs were extremely volatile during 2016. Crude oil, weighted average NGL, and natural gas prices increased 46%, 53% and 60%, respectively from January 1, 2016 to December 31, 2016. The Partnership expects this volatility to continue. For example, crude oil prices (based on the NYMEX futures daily close prices for the prompt month) in 2016 ranged from a high of $54.06 per Bbl in December 2016 to a low of $26.21 per Bbl in February 2016. Weighted average NGL prices in 2016 (based on the Oil Price Information Service (“OPIS”) Napoleonville daily average spot liquids prices) ranged from a high of $0.66 per gallon in December 2016 to a

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low of $0.31 per gallon in January 2016. Natural gas prices (based on Gas Daily Henry Hub closing prices) during 2016 ranged from a high of $3.93 per MMBtu in December 2016 to a low of $1.64 per MMBtu in March 2016.

Changes in commodity prices may also indirectly impact the Partnership’s profitability by influencing drilling activity and well operations, and thus the volume of gas, NGLs, crude oil and condensate connected to or near the Partnership’s assets and on its fees earned for transportation between certain market centers. Low prices for these products could reduce the demand for the Partnership’s services and volumes in its systems. The volatility in commodity prices may cause the Partnership’s gross operating margin and cash flows to vary widely from period to period. The Partnership’s hedging strategies may not be sufficient to offset price volatility risk and, in any event, do not cover all of its throughput volumes. For a discussion of the Partnership’s risk management activities, please read “Item 7A. Quantitative and Qualitative Disclosures about Market Risk.”

Liquidity and Capital Resources

Cash Flows from Operating Activities. Net cash provided by operating activities was $666.4 million, $628.4 million and $458.9 million for the years ended December 31, 2016, 2015 and 2014, respectively. Operating cash flows and changes in working capital for 2016, 2015, and 2014 were as follows (in millions):


	Year Ended December 31,
	2016		2015		2014
Operating cash flows before working capital	$	633.5	$	609.0	$	582.9
Changes in working capital		32.9		19.4		(124.0)
Total	$	666.4	$	628.4	$	458.9

Operating cash flows before changes in working capital increased of $24.5 million for the year ended December 31, 2016 compared to the year ended December 31, 2015 due primarily to an increase in gross operating margin in the Partnership’s Oklahoma segment from the acquisition of the EnLink Oklahoma T.O. assets, which was offset partially by a decrease in gross operating margin in the Partnership’s Crude and Condensate segment due to lower volumes and the termination of a customer contract during the second quarter of 2015. The changes in working capital for the year ended December 31, 2016 were due primarily to fluctuations in trade receivable and payable balances due to timing of collection and payments and changes in inventory balances attributable to normal operating fluctuations.

Cash Flows from Investing Activities. Net cash used in investing activities was $1,380.3 million, $1,097.3 million and $1,148.6 million for the years ended December 31, 2016, 2015 and 2014, respectively. Our primary sources and uses of cash related to investing activities for the years ended December 31, 2016, 2015 and 2014 were as follows (in millions):


	Year Ended December 31,
	2016		2015		2014
Growth capital expenditures	$	632.5	$	530.0	$	758.9
Maintenance capital expenditures		30.5		42.3		37.1
Acquisition of business		791.5		524.2		357.9
Proceeds from sale of property		(93.1)		(1.0)		(0.1)
Proceeds from insurance settlement		(0.3)		(2.9)		—
Investment in unconsolidated affiliate investments		73.8		25.8		5.7
Distribution from unconsolidated affiliate investments in excess of earnings		(54.6)		(21.1)		(10.9)
Total	$	1,380.3	$	1,097.3	$	1,148.6

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

Maintenance capital expenditures include capital expenditures made to replace partially or fully depreciated assets in order to maintain the existing operating capacity of the assets and to extend their useful lives. Examples of

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maintenance capital expenditures are expenditures to refurbish and replace pipelines, gathering assets, well connections, compression assets and processing assets up to their original operating capacity, or to maintain pipeline and equipment reliability, integrity and safety and to address environmental laws and regulations.

Growth capital expenditures increased $102.5 million for the year ended December 31, 2016 compared to the year ended December 31, 2015. The increase in growth capital expenditures was primarily attributable to gas processing and gathering expansion projects for EnLink Oklahoma T.O and the construction of the Lobo II plant and gathering pipeline, which is owned by the Delaware Basin JV. Growth capital expenditures decreased $228.9 million for the year ended December 31, 2015 as compared to the year ended December 31, 2014. The decrease was primarily attributable to a decrease in growth capital expenditures of $281.2 million related to the Cajun Sibon expansion project, which went into service in September 2014. This decrease is partially offset by an increase in capital expenditures of $46.7 million related to the Partnership’s ORV assets.

Maintenance capital expenditures decreased $11.8 million for the year ended December 31, 2016 compared to the year ended December 31, 2015. The decrease was primarily attributable to decreases in compressor overhauls in the Partnership’s Texas segment, and other repairs in its Oklahoma and Louisiana segments. Maintenance capital expenditures increased $5.2 million for the year ended December 31, 2015 compared to the year ended December 31, 2014. The increase was primarily attributable to compressor overhauls and repairs in the Partnership’s Texas and Oklahoma segments.

Acquisition expenditures increased $267.3 million for the year ended December 31, 2016 compared to the year ended December 31, 2015. Acquisitions for the year ended December 31, 2016 included the acquisition of the EnLink Oklahoma T.O. assets. Acquisition expenditures increased $166.3 million for the year ended December 31, 2015 compared to the year ended December 31, 2014. Acquisitions of businesses for the year ended December 31, 2015 included LPC, Coronado, Matador and Deadwood. Acquisition of businesses for the year ended December 31, 2014 included the Chevron, E2 and VEX Interests.

Proceeds from sale of property increased $92.1 million for the year ended December 31, 2016 compared to the year ended December 31, 2015. The increase was due primarily to the sale of the Partnership’s NTPL in December 2016 for $84.6 million.

Investment in unconsolidated affiliate investments increased $48.0 million for the year ended December 31, 2016 compared to the year ended December 31, 2015. Investments in unconsolidated affiliate investments for the year ended December 31, 2016 included $45.0 million in contributions to the Partnership’s investment in HEP, including $32.7 million of contributions to HEP for preferred units, which were subsequently redeemed during the third quarter of 2016 and classified as a distribution from unconsolidated affiliate investments in excess of earnings. In addition, investments in unconsolidated affiliate investments for the year ended December 31, 2016 included a $28.8 million contribution to the Cedar Cove JV. Investments in unconsolidated affiliate investments for the years ended December 31, 2015 and 2014 consisted of the Partnership’s contributions to HEP.

Cash Flows from Financing Activities. Net cash provided by financing activities was $707.6 million, $418.5 million and $758.1 million for the years ended December 31, 2016, 2015 and 2014, respectively. Our primary financing activities consisted of the following (in millions):


	Year Ended December 31,
	2016		2015		2014
Net borrowings (repayments) on the Partnership's credit facility	$	(294.2)	$	176.8	$	(140.0)
Net borrowings (repayments) on the Company's credit facility		27.8		—		(75.1)
Net repayments on E2 credit facility		—		—		(13.8)
Partnership's unsecured senior notes borrowings		499.3		893.3		1,600.7
Redemption of the Partnership's 2018 notes		—		—		(760.3)
Partial redemption of the Partnership's 2022 notes		—		—		(36.4)
Debt financing costs		(4.7)		(9.6)		(19.7)
Proceeds from issuance of the Partnership's common units		167.5		24.4		412.0
Proceeds from issuance of the Partnership's Preferred Units		724.1		—		—
Contributions by non-controlling interest		167.9		16.4		6.3
Contributions from Devon		1.5		27.8		105.7

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For the year ended December 31, 2016, contributions by non-controlling partners included $144.4 million in contributions from NGP to the Delaware Basin JV, which consisted of an initial contribution of $114.3 million that the Delaware Basin JV distributed to us at the formation of the joint venture to reimburse us for capital spent to the date of formation on existing assets, as well as $30.1 million for NGP’s share of ongoing projects.

Distributions to unitholders, Devon and non-controlling partners in the Partnership also represent a primary uses of cash in financing activities. Total unitholder cash distributions made during the years ended December 31, 2016, 2015 and 2014 were as follows (in millions):


	Year Ended December 31,
	2016		2015		2014
Distributions to members	$	185.4	$	162.8	$	89.0
Distributions to non-controlling partners		384.2		359.5		204.3
Distributions to Devon for net assets acquired (1)		—		166.7		—

(1)

Represents distributions to Devon relating to the VEX assets.

In order to reduce our interest costs, we do not borrow money to fund outstanding checks until they are presented to the bank. Fluctuations in drafts payable are caused by timing of disbursements, cash receipts and draws on our credit facility. The Partnership borrows money under the Partnership’s credit facility to fund checks as they are presented. Changes in drafts payable were as follows (in millions):


	Year Ended December 31,
	2016		2015		2014
Decrease in drafts payable	$	—	$	(12.7)	$	10.2

Uncertainties. The Partnership owns and operates a high-pressure pipeline and underground natural gas and NGL storage reservoirs and associated facilities near Bayou Corne, Louisiana. In August 2012, a large sinkhole formed in the vicinity of this pipeline and underground storage reservoirs, resulting in damage to certain of the Partnership’s facilities. The Partnership is seeking to recover our losses from responsible parties. The Partnership has sued Texas Brine Company, LLC (“Texas Brine”), the operator of a failed cavern in the area, and its insurers seeking recovery for these losses. The Partnership has also sued Occidental Chemical Company and Legacy Vulcan Corp. f/k/a Vulcan Materials Company, two Chlor-Alkali plant operators that participated in Texas Brine’s operational decisions regarding mining the failed cavern. The Partnership has also filed a claim with its insurers, which its insurers denied. The Partnership has disputed the denial and have also sued its insurers. In August 2014, the Partnership received a partial settlement with respect to the Texas Brine claims in the amount of $6.1 million, but additional claims remain outstanding. The Partnership cannot give assurance that it will be able to fully recover our losses through insurance recovery or claims against responsible parties.

In June 2014, a group of landowners in Assumption Parish, Louisiana added the Partnership’s subsidiary, EnLink Processing Services, LLC, as a defendant in a pending lawsuit they had filed against Texas Brine, Occidental Chemical Corporation and Vulcan Materials Company relating to claims arising from the Bayou Corne sinkhole. The suit is pending in the 23rd Judicial Court, Assumption Parish, Louisiana. Although plaintiffs’ claims against the other defendants have been pending since October 2012, plaintiffs are now alleging that EnLink Processing Services, LLC’s negligence also contributed to the formation of the sinkhole. The amount of damages is unspecified. The validity of the causes of action, as well as the Partnership’s costs and legal exposure, if any, related to the lawsuit are not currently determinable. The Partnership intends to vigorously defend the case. The Partnership has also filed a claim for defense and indemnity with its insurers.

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Capital Requirements. The Partnership expects its 2017 capital expenditures, including capital contributions to its unconsolidated affiliate investments, to be as follows (in millions):


	2017
Growth capital expenditures
Texas segment	$	110 - 140
Louisiana segment		88 - 102
Oklahoma segment (1) (2)		360 - 460
Crude and Condensate segment		35 - 45
Corporate segment		17 - 23
Total growth capital expenditures	$	610 - 770
Less: Growth capital expenditures funded by joint venture partners (3)		(25 - 35)
Growth capital expenditures, less that funded by joint venture partners		585 - 735

Maintenance capital expenditures	$	38 - 48

(1)

Projected growth capital expenditure range for 2017 excludes the $250 million installment payable related to the acquisition of EnLink Oklahoma T.O. in January 2016.

(2)

Includes projected growth capital contributions related to our non-controlling interest share of the Cedar Cove JV.

(3)

Includes growth capital expenditures that will be contributed by other entities and relate to the non-controlling interest share of our consolidated entities. These contributions include contributions by NGP to the Delaware Basin JV and contributions by Marathon to the Ascension JV.

Our primary capital projects for 2017 include the construction of the Chisholm II and III plant expansions, the development of additional gathering and compression assets in the Oklahoma segment and the Midland Basin and contributions to the Delaware JV, Cedar Cove JV, and Ascension JV.

We expect to fund the growth capital expenditures from the proceeds of planned and completed asset sales, at-the-market equity issuances and borrowings under its credit facility, as well as contributions by joint venture partners that relate to the non-controlling interest share of our consolidated entities. The Partnership expects to fund its 2017 maintenance capital expenditures from operating cash flows. In 2017, it is possible that not all of the planned projects will be commenced or completed. The Partnership’s ability to pay distributions to its unitholders, and to fund planned capital expenditures and to make acquisitions will depend upon its future operating performance, which will be affected by prevailing economic conditions in the industry and financial, business and other factors, some of which are beyond its control.

Off-Balance Sheet Arrangements. We had no off-balance sheet arrangements as of December 31, 2016, 2015 and 2014.

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Total Contractual Cash Obligations . A summary of our total contractual cash obligations as of December 31, 2016 is as follows (in millions):


	Payments Due by Period
	Total		2017		2018		2019		2020		2021		Thereafter
Long-term debt obligations	$	3,162.5	$	—	$	—	$	400.0	$	—	$	—	$	2,762.5
Partnership's credit facility		120.0		—		—		—		120.0		—		—
Company credit facility		27.8		—		—		27.8		—				—
Installment payable obligations (1)		500.0		250.0		250.0		—		—		—		—
Interest payable on fixed long-term debt obligations		1,966.0		144.3		144.3		138.9		133.5		133.5		1,271.5
Capital lease obligations		7.5		2.0		2.2		1.6		1.7		—		—
Operating lease obligations		123.8		16.2		15.4		10.9		8.6		8.7		64.0
Purchase obligations		13.4		13.4		—		—		—		—		—
Delivery contract obligation		44.8		17.9		17.9		9.0		—		—		—
Pipeline capacity and deficiency agreements (2)		95.2		13.7		15.3		11.6		8.1		8.1		38.4
Inactive easement commitment (3)		10.0		—		—		—		—		—		10.0
Total contractual obligations	$	6,071.0	$	457.5	$	445.1	$	599.8	$	271.9	$	150.3	$	4,146.4

(1)

Amounts relate to the Partnership’s partial consideration of the acquisition of the EnLink Oklahoma T.O. assets with balances paid on January 7, 2017 and due on January 7, 2018.

(2)

Consists of pipeline capacity payments for firm transportation and deficiency agreements.

(3)

Amounts related to inactive easements paid as utilized by the Partnership with balance due at end of 10 years if not utilized.

In January 2017, the Partnership paid the $250.0 million installment payable obligation, related to the EnLink Oklahoma T.O. acquisition, which was due on January 7, 2017. The Partnership funded this installment payment using various sources, including $84.6 million in proceeds received from the sale of NTPL, proceeds from equity issuances through its ATM and borrowings under its credit facility. The Partnership’s remaining contractual cash obligations for 2017 are expected to be funded from cash flows from its operations.

The above table does not include any physical or financial contract purchase commitments for natural gas due to the nature of both the price and volume components of such purchases, which vary on a daily or monthly basis. Additionally, we do not have contractual commitments for fixed price and/or fixed quantities of any material amount.

The interest payable under the Partnership’s credit facility and the Company’s credit facility is not reflected in the above table because such amounts depend on outstanding balances and interest rates, which will vary from time to time. However, given the same borrowing amount and rates in effect at December 31, 2016, the Partnership’s and Company’s cash obligation for interest expense on its credit facilities would be approximately $2.8 million and $0.9 million per year, respectively.

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Indebtedness

As of December 31, 2016 and 2015, long-term debt consisted of the following (in millions):


	December 31, 2016						December 31, 2015
		Outstanding Principal		Premium (Discount)		Long-Term Debt		Outstanding Principal		Premium (Discount)		Long-Term Debt
Partnership credit facility, due 2020 (1)	$	120.0	$	—	$	120.0	$	414.0	$	—	$	414.0
Company credit facility, due 2019 (2)		27.8		—		27.8		—		—		—
2.70% Senior unsecured notes due 2019		400.0		(0.3)		399.7		400.0		(0.4)		399.6
7.125% Senior unsecured notes due 2022		162.5		16.0		178.5		162.5		18.9		181.4
4.40% Senior unsecured notes due 2024		550.0		2.5		552.5		550.0		2.9		552.9
4.15% Senior unsecured notes due 2025		750.0		(1.1)		748.9		750.0		(1.2)		748.8
4.85% Senior unsecured notes due 2026		500.0		(0.7)		499.3		—		—		—
5.60% Senior unsecured notes due 2044		350.0		(0.2)		349.8		350.0		(0.2)		349.8
5.05% Senior unsecured notes due 2045		450.0		(6.6)		443.4		450.0		(6.9)		443.1
Other debt		—		—		—		0.2		—		0.2
Debt classified as long-term	$	3,310.3	$	9.6	$	3,319.9	$	3,076.7	$	13.1	$	3,089.8
Debt issuance cost (3)						(24.6)						(23.8)
Long-term debt, net of unamortized issuance cost					$	3,295.3					$	3,066.0

(1)

Bears interest based on Prime and/or LIBOR plus an applicable margin. The effective interest rate was 2.3% and 1.8% at December 31, 2016 and 2015, respectively.

(2)

Bears interest based on Prime and/or LIBOR plus an applicable margin. The effective interest rate was 3.4% at December 31, 2016.

(3)

Net of amortization of $9.0 million at December 31, 2016 and $5.1 million at December 31, 2015.

Credit Facility

We have a $250.0 million revolving credit facility, including a $125.0 million letter of credit subfacility (the “credit facility”) that matures on March 7, 2019. Our obligations under the credit facility are guaranteed by two of our wholly-owned subsidiaries and secured by first priority liens on (i) 88,528,451 Partnership common units and the 100% membership interest in the General Partner indirectly held by us, (ii) the 100% equity interest in each of our wholly-owned subsidiaries held by us and any additional equity interests subsequently pledged as collateral under the credit facility.

The credit facility contains certain financial, operational and legal covenants. The financial covenants are tested on a quarterly basis, based on the rolling four-quarter period that ends on the last day of each fiscal quarter, and include (i) maintaining a maximum consolidated leverage ratio (as defined in the credit facility, but generally computed as the ratio of consolidated funded indebtedness to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges) of 4.00 to 1.00, provided that the maximum consolidated leverage ratio is 4.50 to 1.00 during an acquisition period (as defined in the credit facility) and (ii) maintaining a minimum consolidated interest coverage ratio (as defined in the credit facility, but generally computed as the ratio of consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges to consolidated interest charges) of 2.50 to 1.00 at all times unless an investment grade event (as defined in the credit facility) occurs.

Borrowings under our credit facility bear interest at our option at the Eurodollar Rate (the LIBOR Rate) plus an applicable margin (ranging from 1.00% to 1.75%) or the Base Rate (the highest of the Federal Funds Rate plus 0.50%, the 30-day Eurodollar Rate plus 1.0% or the administrative agent’s prime rate) plus an applicable margin (ranging from zero percent to 0.75%). The applicable margins vary depending on our leverage ratio. Upon breach by us of certain covenants governing the credit facility, amounts outstanding under the credit facility, if any, may become due and payable immediately and the liens securing the credit facility could be foreclosed upon. At December 31, 2016, the Company was in compliance and expects to be in compliance with the covenants in the existing credit facility for at least the next twelve months.

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As of December 31, 2016, there were no outstanding letters of credit and $27.8 million in outstanding borrowings under our credit facility, leaving approximately $222.2 million available for future borrowing based on the borrowing capacity of $250.0 million.

Partnership Credit Facility

The Partnership has a $1.5 billion unsecured revolving credit facility, including a $500.0 million letter of credit subfacility that matures on March 6, 2020. Under its credit facility, the Partnership is permitted to (1) subject to certain conditions and the receipt of additional commitments by one or more lenders, increase the aggregate commitments under the Partnership credit facility by an additional amount not to exceed $500.0 million and (2) subject to certain conditions and the consent of the requisite lenders, on two separate occasions extend the maturity date of the Partnership credit facility by one year on each occasion. The Partnership’s credit facility contains certain financial, operational and legal covenants. Among other things, these covenants include maintaining a ratio of consolidated indebtedness to consolidated EBITDA (which is defined in the its credit facility and includes projected EBITDA from certain capital expansion projects) of no more than 5.0 to 1.0. If the Partnership consummates one or more acquisitions in which the aggregate purchase price is $50.0 million or more, the Partnership can elect to increase the maximum allowed ratio of consolidated indebtedness to consolidated EBITDA to 5.5 to 1.0 for the quarter of the acquisition and the three following quarters.

Borrowings under the Partnership’s credit facility bear interest at the Partnership’s option at the Eurodollar Rate (the LIBOR Rate) plus an applicable margin based on our credit rating or the Base Rate (the highest of the Federal Funds Rate plus 0.50%, the 30-day Eurodollar Rate plus 1.0% or the administrative agent’s prime rate) plus an applicable margin.

If the Partnership breaches certain covenants governing its credit facility, amounts outstanding under its credit facility, if any, may become due and payable immediately. The Partnership expects to be compliance with the covenants in the Partnership credit facility for at least the next twelve months.

As of December 31, 2016, there were $11.5 million in outstanding letters of credit and $120.0 million in outstanding borrowings under the Partnership’s credit facility, leaving approximately $1.4 billion available for future borrowing based on the borrowing capacity of $1.5 billion.

Senior Unsecured Notes

On March 7, 2014, the Partnership recorded $196.5 million in aggregate principal amount of 7.125% senior unsecured notes (the “2022 Notes”) due on June 1, 2022 in the Business Combination. The interest payments on the 2022 Notes are due semi-annually in arrears in June and December. As a result of the Business Combination, the 2022 Notes were recorded at fair value in accordance with acquisition accounting at an amount of $226.0 million, including a premium of $29.5 million. On July 20, 2014, the Partnership redeemed $18.5 million aggregate principal amount of the 2022 Notes for $20.0 million, including accrued interest. On September 20, 2014, the Partnership redeemed an additional $15.5 million aggregate principal amount of the 2022 Notes for $17.0 million, including accrued interest. The Partnership recorded a gain on extinguishment of debt related to the redemption of the 2022 Notes of $2.4 million for the year ended December 31, 2014.

On March 19, 2014, the Partnership issued $1.2 billion aggregate principal amount of unsecured senior notes, consisting of $400.0 million aggregate principal amount of its 2.700% senior notes due 2019 (the “2019 Notes”), $450.0 million aggregate principal amount of its 4.400% senior notes due 2024 (the “2024 Notes”) and $350.0 million aggregate principal amount of its 5.600% senior notes due 2044 (the “2044 Notes”), at prices to the public of 99.850%, 99.830% and 99.925%, respectively, of their face value. The 2019 Notes mature on April 1, 2019; the 2024 Notes mature on April 1, 2024; and the 2044 Notes mature on April 1, 2044. The interest payments on the 2019 Notes, 2024 Notes and 2044 Notes are due semi-annually in arrears in April and October.

On November 12, 2014, the Partnership issued an additional $100.0 million aggregate principal amount of 2024 Notes and $300.0 million aggregate principal amount of its 5.050% senior notes due 2045 (the “2045 Notes”), at prices to the public of 104.007% and 99.452%, respectively, of their face value. The new 2024 Notes were offered as an additional issue of the Partnership’s outstanding 4.400% Senior Notes due 2024, issued in an aggregate principal amount of $450.0 million on March 19, 2014. The 2024 Notes issued on March 19, 2014 and November 12, 2014 are treated as a

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single class of debt securities and have identical terms, other than the issue date. The 2045 Notes mature on April 1, 2045, and interest payments on the 2045 Notes are due semi-annually in arrears in April and October.

On May 12, 2015, the Partnership issued $900.0 million aggregate principal amount of unsecured senior notes, consisting of $750.0 million aggregate principal amount of its 4.150% senior notes due 2025 (the “2025 Notes”) and an additional $150.0 million aggregate principal amount of 2045 Notes at prices to the public of 99.827% and 96.381%, respectively, of their face value. The 2025 Notes mature on June 1, 2025. Interest payments on the 2025 Notes are due semi-annually in arrears in June and December. The new 2045 Notes were offered as an additional issue of the Partnership’s outstanding 5.050% Senior Notes due 2045, issued in an aggregate principal amount of $300.0 million on November 12, 2014. The 2045 Notes issued on November 12, 2014 and May 12, 2015 are treated as a single class of debt securities and have identical terms, other than the issue date.

On July 14, 2016, the Partnership issued $500.0 million in aggregate principal amount of the Partnership’s 4.850% senior notes due 2026 (the “2026 Notes”) at a price to the public of 99.859% of their face value. The 2026 Notes mature on July 15, 2026. Interest payments on the 2026 Notes are due semi-annually in arrears in January and July. Net proceeds of approximately $495.7 million were used to repay outstanding borrowings under the Partnership’s revolving credit facility and for general partnership purposes.

For additional information on outstanding long-term debt issuances, redemption characteristics and criteria, and related debt covenants and indentures, see “Item 8. Financial Statements and Supplementary Data—Note 6.”

Credit Risk

Inflation

Inflation in the United States has been relatively low in recent years in the economy as a whole. The midstream natural gas industry’s labor and material costs remained relatively unchanged in 2014, 2015 and 2016. Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy and may increase the cost to acquire or replace property, plant and equipment and may increase the costs of labor and supplies. To the extent permitted by competition, regulation and the Partnership’s existing agreements, the Partnership has and will continue to pass along increased costs to its customers in the form of higher fees.

Environmental

The Partnership’s operations are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which these operations are conducted. The Partnership believes it is in material compliance with all applicable laws and regulations. For a more complete discussion of the environmental laws and regulations that impact the Partnership, see “Item 1. Business—Environmental Matters.”

Contingencies

The Partnership is involved in various litigation and administrative proceedings arising in the normal course of business. In the opinion of management, any liabilities that may result from these claims would not individually or in the aggregate have a material adverse effect on its financial position, results of operations or cash flows.

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could result in damage awards in excess of the amounts anticipated. Although it is not possible to predict the ultimate outcomes of these matters, the Partnership does not expect that awards in these matters will have a material adverse impact on its consolidated results of operations, financial condition, or cash flows.

The Partnership owns and operates a high-pressure pipeline and underground natural gas and NGL storage reservoirs and associated facilities near Bayou Corne, Louisiana. In August 2012, a large sinkhole formed in the vicinity of this pipeline and underground storage reservoirs. The Partnership is seeking to recover its losses from responsible parties. The Partnership has sued Texas Brine Company, the operator of a failed cavern in the area, and its insurers seeking recovery for these losses in the 23rd Judicial Court, Assumption Parish, Louisiana. The Partnership has also sued Occidental Chemical Company and Legacy Vulcan Corp. f/k/a Vulcan Materials Company, two Chlor-Alkali plant operators that participated in Texas Brine’s operational decisions regarding mining the failed cavern. The Partnership also filed a claim with its insurers, which the Partnership’s insurers denied. The Partnership has filed a claim for defense and indemnity with its insurers. In August 2014, the Partnership received a partial settlement from Texas Brine’s insurers with respect to the Texas Brine claims in the amount of $6.1 million, but additional claims remain outstanding. The Partnership cannot give assurance that the Partnership will be able to fully recover its losses through insurance recovery or claims against responsible parties.

Recent Accounting Pronouncements

See “Item 8. Financial Statements and Supplementary Data—Note 2.”

Disclosure Regarding Forward-Looking Statements

This Annual Report on Form 10-K (“Annual Report”) contains forward-looking statements that are based on information currently available to management as well as management’s assumptions and beliefs. All statements, other than statements of historical fact, included in this Annual Report constitute forward-looking statements, including but not limited to statements identified by the words “forecast,” “may,” “believe,” “will,” “should,” “plan,” “predict,” “anticipate,” “intend,” “estimate” and “expect” and similar expressions. Such statements reflect our current views with respect to future events, based on what we believe are reasonable assumptions; however, such statements are subject to certain risks and uncertainties. In addition to the specific uncertainties discussed elsewhere in this Annual Report, the

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risk factors set forth in “Item 1A. Risk Factors” may affect our performance and results of operations. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may differ materially from those in the forward-looking statements. We disclaim any intention or obligation to update or review any forward-looking statements or information, whether as a result of new information, future events or otherwise.

Item 7A . Quantitative and Qualitative Disclosures about Market Risk

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

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

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

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

Commodity Price Risk

We are subject to significant risks due to fluctuations in commodity prices. Our exposure to these risks is primarily in the gas processing component of our business. We currently process gas under four main types of contractual arrangements as summarized below. Approximately 88% of our processing margins are from fixed-fee based contracts for the year ended December 31, 2016.

Processing margin contracts: Under this type of contract, the Partnership pays the producer for the full amount of inlet gas to the plant, and makes a margin based on the difference between the value of liquids recovered from the processed natural gas as compared to the value of the natural gas volumes lost and the cost of fuel used in processing. The shrink and fuel losses are referred to as plant thermal reduction, or “PTR.” The Partnership’s margins from these contracts are high during periods of high liquids prices relative to natural gas prices, and can be negative during periods of high natural gas prices relative to liquids prices. However, the Partnership

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mitigates its risk of processing natural gas when margins are negative primarily through its ability to bypass processing when it is not profitable for the Partnership, or by contracts that revert to a minimum fee for processing if the natural gas must be processed to meet pipeline quality specifications.

Percent of liquids contracts: Under these contracts, the Partnership receives a fee in the form of a percentage of the liquids recovered, and the producer bears all the cost of the natural gas shrink. Therefore, the Partnership’s margins from these contracts are greater during periods of high liquids prices. The Partnership’s margins from processing cannot become negative under percent of liquids contracts, but they do decline during periods of low NGL prices.

Percent of proceeds contracts: Under these contracts, the Partnership receives a fee as a portion of the proceeds of the sale of natural gas and liquids. Therefore, the Partnership’s margins from these contracts are greater during periods of high natural gas and liquids prices. The Partnership’s margins from processing cannot become negative under percent of proceeds contracts, but they do decline during periods of low natural gas and NGL prices.

Fixed-fee based contracts: Under these contracts we have no direct commodity price exposure and are paid a fixed fee per unit of volume that is processed.

The Partnership’s primary commodity risk management objective is to reduce volatility in its cash flows. The Partnership maintains a risk management committee, including members of senior management, which oversees all hedging activity. The Partnership enters into hedges for natural gas and NGLs using over-the-counter derivative financial instruments with only certain well-capitalized counterparties which have been approved by its risk management committee.

The Partnership has hedged its exposure to fluctuations in prices for natural gas and NGL volumes produced for its account. The Partnership hedges its exposure based on volumes it considers hedgeable (volumes committed under contracts that are long term in nature) versus total volumes that include volumes that may fluctuate due to contractual terms, such as contracts with month to month processing options. Further, the Partnership has tailored its hedges to generally match the NGL product composition and the NGL and natural gas delivery points to those of its physical equity volumes. The NGL hedges cover specific NGL products based upon the Partnership’s expected equity NGL composition.

The following table sets forth certain information related to derivative instruments outstanding at December 31, 2016 mitigating the risks associated with the gas processing and fractionation components of the Partnership’s business. The relevant payment index price for liquids is the monthly average of the daily closing price for deliveries of commodities into Mont Belvieu, Texas as reported by OPIS. The relevant index price for Natural Gas is Henry Hub Gas Daily is as defined by the pricing dates in the swap contracts.


					Fair Value
					Asset/(Liability)
Period	Underlying	Notional Volume	We Pay	We Receive (1)	(In millions)
January 2017 - December 2017	Ethane	167 (MBbls)	$0.2642/gal (1)	Index	$	0.2
January 2017 - December 2017	Propane	434 (MBbls)	Index	$0.5461/gal		(2.3)
January 2017 - December 2017	Normal Butane	161 (MBbls)	Index	$0.7048/gal		(1.0)
January 2017 - December 2017	Natural Gasoline	95 (MBbls)	Index	$1.0691/gal		(0.5)
January 2017 - December 2017	Natural Gas	21,685 (MMBtu/d)	Index	$3.1422/MMBtu		(2.7)
					$	(6.3)

(1) weighted average

Another price risk the Partnership faces is the risk of mismatching volumes of gas bought or sold on a monthly price versus volumes bought or sold on a daily price. The Partnership enters each month with a balanced book of natural gas bought and sold on the same basis. However, it is normal to experience fluctuations in the volumes of natural gas bought or sold under either basis, which leaves the Partnership with short or long positions that must be covered. The Partnership uses financial swaps to mitigate the exposure at the time it is created to maintain a balanced position.

The use of financial instruments may expose the Partnership to the risk of financial loss in certain circumstances, including instances when (1) sales volumes are less than expected requiring market purchases to meet commitments or

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(2) counterparties fail to purchase the contracted quantities of natural gas or otherwise fail to perform. To the extent that the Partnership engages in hedging activities, it may be prevented from realizing the benefits of favorable price changes in the physical market. However, the Partnership is similarly insulated against unfavorable changes in such prices.

As of December 31, 2016, outstanding natural gas swap agreements, NGL swap agreements, swing swap agreements, storage swap agreements and other derivative instruments were a net fair value liability of $6.3 million. The aggregate effect of a hypothetical 10% change, increase or decrease, in gas and NGL prices would result in a change of approximately $3.1 million in the net fair value of these contracts as of December 31, 2016.

Interest Rate Risk

We are exposed to interest rate risk on our variable rate bank credit facility. At December 31, 2016, we had $27.8 million in outstanding borrowings under our credit facility. A 1% increase or decrease in interest rates on our credit facility would change our annual interest expense by approximately $0.3 million.

In addition, the Partnership is exposed to interest rate risk on its variable rate bank credit facility. At December 31, 2016, the Partnership’s credit facility had $120.0 million in outstanding borrowings under this facility. A 1% increase or decrease in interest rates on the Partnership’s credit facility would change its annual interest expense by approximately $1.2 million.

The Partnership is not exposed to changes in interest rates with respect to its senior unsecured notes due in 2019, 2022, 2024, 2025, 2026, 2044, or 2045 as these are fixed-rate obligations. The estimated fair value of the Partnership’s senior unsecured notes was approximately $3,105.7 million as of December 31, 2016, based on market prices of similar debt at December 31, 2016. Market risk is estimated as the potential decrease in fair value of the Partnership’s long-term debt resulting from a hypothetical increase of 1% in interest rates. Such an increase in interest rates would result in an approximately $229.7 million decrease in fair value of the Partnership’s senior unsecured notes at December 31, 2016.

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Item 8. Financial Statements and Supplementary Data

INDEX TO FINANCIAL STATEMENTS

EnLink Midstream, LLC Financial Statements:

Management’s Report on Internal Control Over Financial Reporting	100

Reports of Independent Registered Public Accounting Firm	101

Consolidated Balance Sheets as of December 31, 2016 and 2015	103

Consolidated Statements of Operations for the years ended December 31, 2016, 2015 and 2014	104

Consolidated Statements of Changes in Members’ Equity for the years ended December 31, 2016, 2015 and 2014	105

Consolidated Statements of Cash Flows for the years ended December 31, 2016, 2015 and 2014	106

Notes to Consolidated Financial Statements	107

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MANAGEMENT’S REPORT ON

INTERNAL CONTROL OVER FINANCIAL REPORTING

Management of EnLink Midstream, LLC is responsible for establishing and maintaining adequate internal control over financial reporting and for the assessment of the effectiveness of internal control over financial reporting for EnLink Midstream, LLC (the “Company”). As defined by the Securities and Exchange Commission (Rule 13a-15(f) under the Securities Exchange Act of 1934, as amended), internal control over financial reporting is a process designed by, or under the supervision of EnLink Midstream, LLC’s principal executive and principal financial officers and effected by its Board of Directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the consolidated financial statements in accordance with U.S. generally accepted accounting principles.

The Company’s internal control over financial reporting is supported by written policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the Company’s transactions and dispositions of the Company’s assets; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of the consolidated financial statements in accordance with U.S. generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorization of the EnLink Midstream, LLC’s management and directors; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the consolidated financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In connection with the preparation of the Company’s annual consolidated financial statements, management has undertaken an assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO Framework). Management’s assessment included an evaluation of the design of the Company’s internal control over financial reporting and testing of the operational effectiveness of those controls.

Based on this assessment, management has concluded that as of December 31, 2016, the Company’s internal control over financial reporting was effective to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. generally accepted accounting principles.

KPMG LLP, the independent registered public accounting firm that audited the Company’s consolidated financial statements included in this report, has issued an attestation report on the Company’s internal control over financial reporting, a copy of which appears on the following page of this Annual Report on Form 10-K.

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Report of Independent Registered Public Accounting Firm

To the Members

EnLink Midstream, LLC:

We have audited the accompanying consolidated balance sheets of EnLink Midstream, LLC (a Delaware limited liability corporation) and subsidiaries as of December 31, 2016 and 2015, and the related consolidated statements of operations, changes in members’ equity, and cash flows for each of the years in the three-year period ended December 31, 2016. In connection with our audits of the consolidated financial statements, we also have audited financial statement schedule 1. We also have audited EnLink Midstream, LLC’s internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). EnLink Midstream, LLC’s management is responsible for these consolidated financial statements and for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the consolidated financial statements and schedule and an opinion on the Company’s internal control over financial reporting based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the consolidated financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of EnLink Midstream, LLC and subsidiaries as of December 31, 2016 and 2015, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2016, in conformity with U.S. generally accepted accounting principles. Also in our opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein. Also in our opinion, EnLink Midstream, LLC maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016 based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

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As discussed in Note 2(h) to the financial statements, effective March 7, 2014, the Partnership has elected to change its method of accounting for computing depreciation under the units-of-production method for certain assets. That change is a change in accounting estimate effected by and inseparable from the change in accounting principle.

/s/ KPMG LLP

Dallas, Texas

February 15, 2017

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ENLINK MIDSTREAM, LLC

Consolidated Balance Sheets


	December 31,
	2016		2015
	(In millions, except unit data)
ASSETS
Current assets:
Cash and cash equivalents	$	11.7	$	18.0
Accounts receivable:
Trade, net of allowance for bad debt of $0.1 and $0.3, respectively		63.9		37.5
Accrued revenue and other		369.6		268.8
Related party		100.2		110.8
Fair value of derivative assets		1.3		16.8
Natural gas and NGLs inventory, prepaid expenses and other		33.5		41.8
Investment in unconsolidated affiliate - current		193.1		—
Total current assets		773.3		493.7
Property and equipment, net of accumulated depreciation of $2,124.1 and $1,757.6, respectively		6,256.7		5,666.8
Intangible assets, net of accumulated amortization of $171.6 and $54.6, respectively		1,624.2		689.9
Goodwill		1,542.2		2,413.9
Investment in unconsolidated affiliates - noncurrent		77.3		274.3
Other assets, net		2.2		2.7
Total assets	$	10,275.9	$	9,541.3
LIABILITIES AND MEMBERS’ EQUITY
Current liabilities:
Accounts payable and drafts payable	$	69.2	$	33.2
Accounts payable to related party		10.4		14.8
Accrued gas, NGLs, condensate and crude oil purchases		333.3		206.7
Fair value of derivative liabilities		7.6		2.9
Installment payable, net of discount of $0.5		249.5		—
Other current liabilities		217.5		174.8
Total current liabilities		887.5		432.4
Long-term debt		3,295.3		3,066.0
Fair value of derivative liabilities		—		0.1
Asset retirement obligations		13.5		12.9
Other long-term liabilities		42.5		65.9
Installment payable, net of discount of $26.3		223.7		—
Deferred tax liability		542.6		532.1

Redeemable non-controlling interest		5.2		7.0

Members’ equity:
Members’ equity (180,049,316 and 164,242,160 units issued and outstanding at December 31, 2016 and December 31, 2015, respectively)		1,880.9		2,285.7
Non-controlling interest		3,384.7		3,139.2
Total members’ equity		5,265.6		5,424.9
Commitments and contingencies (Note 15)
Total liabilities and members’ equity	$	10,275.9	$	9,541.3

See accompanying notes to consolidated financial statements.

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ENLINK MIDSTREAM, LLC

Consolidated Statements of Operations


	Year Ended December 31,
	2016		2015		2014
	(In millions, except per unit data)
Revenues:
Product sales	$	3,008.9	$	3,253.7	$	2,159.3
Product sales - related parties		134.3		119.4		505.6
Midstream services		467.2		451.0		253.4
Midstream services - related parties		653.1		618.6		567.4
Gain (loss) on derivative activity		(11.1)		9.4		22.1
Total revenues		4,252.4		4,452.1		3,507.8
Operating costs and expenses:
Cost of sales (1)		3,015.5		3,245.3		2,494.5
Operating expenses (2)		398.5		419.9		283.6
General and administrative (3)		122.5		136.9		97.3
(Gain) loss on disposition of assets		13.2		1.2		(0.1)
Depreciation and amortization		503.9		387.3		284.3
Impairments		873.3		1,563.4		—
Gain on litigation settlement		—		—		(6.1)
Total operating costs and expenses		4,926.9		5,754.0		3,153.5
Operating income (loss)		(674.5)		(1,301.9)		354.3
Other income (expense):
Interest expense, net of interest income		(189.5)		(103.3)		(49.8)
Income from unconsolidated affiliate investments		(19.9)		20.4		18.9
Gain on extinguishment of debt		—		—		3.2
Other income (expense)		0.3		0.8		(0.5)
Total other income (expense)		(209.1)		(82.1)		(28.2)
Income (loss) from continuing operations before non-controlling interest and income taxes		(883.6)		(1,384.0)		326.1
Income tax provision		(4.6)		(25.7)		(76.4)
Net income (loss) from continuing operations		(888.2)		(1,409.7)		249.7
Income (loss) from discontinued operations, net of tax		—		—		1.0
Net income (loss)		(888.2)		(1,409.7)		250.7
Net income (loss) attributable to the non-controlling interest		(428.2)		(1,054.5)		126.7
Net income (loss) attributable to EnLink Midstream, LLC	$	(460.0)	$	(355.2)	$	124.0
Predecessor interest in net income (4)	$	—	$	—	$	35.5
Devon investment interest in net income (loss)	$	—	$	1.8	$	(2.0)
EnLink Midstream LLC interest in net income (loss)	$	(460.0)	$	(357.0)	$	90.5
Net income (loss) attributable to EnLink Midstream, LLC per unit:
Basic common unit	$	(2.56)	$	(2.17)	$	0.55
Diluted common unit	$	(2.56)	$	(2.17)	$	0.55

(1)

Includes related party cost of sales of $150.1 million, $141.3 million and $354.3 million for the years ended December 31, 2016, 2015 and 2014, respectively.

(2)

Includes related party operating expenses of $0.5 million, $0.5 million and $5.9 million for the years ended December 31, 2016, 2015 and 2014, respectively.

(3)

Includes related party general and administrative expenses of $0.0 million, $0.2 million and $11.6 million for the years ended December 31, 2016, 2015 and 2014, respectively.

(4)

Represents net income attributable to the Predecessor for the period prior to March 7, 2014.

See accompanying notes to consolidated financial statements.

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ENLINK MIDSTREAM, LLC

Consolidated Statements of Changes in Members’ Equity


												Redeemable
												Non-
												controlling
								Non-				Interest
				Net Devon		Predecessor		Controlling				(Temporary
	Common Units			Investment		Equity		Interest				Equity)
	$		Units	$		$		$		Total		$
Balance, December 31, 2013	$	—	—	$	—	$	1,783.7	$	—	$	1,783.7		—
Distributions to the Predecessor		—	—		—		(71.9)		—		(71.9)		—
Issuance of units for reorganization of predecessor equity		941.7	115.5		—		(1,747.3)		805.6		—		—
Issuance of common units for acquisition of Company		1,822.6	48.5		—		—		2,847.7		4,670.3		—
Elimination of deferred taxes attributable to non-controlling interest in predecessor equity		—	—		—		—		204.9		204.9		—
Issuance of units by the Partnership		—	—		—		—		412.0		412.0		—
Change in equity due to issuance of units by the Partnership		(1.1)	—		—		—		1.8		0.7		—
Conversion of restricted units for common units, net of units withheld for taxes		(1.2)	0.1		—		—		0.1		(1.1)		—
Non-controlling partner's impact on conversion of restricted units and options		—	—		—		—		(0.3)		(0.3)		—
Unit-based compensation		10.6	—		—		—		9.0		19.6		—
Distributions to members		(89.0)	—		—		—		—		(89.0)		—
Distributions to non-controlling interest		—	—		—		—		(204.3)		(204.3)		—
Purchase of non-controlling interest		0.2	—		—		—		(12.7)		(12.5)		—
Non-controlling interest contributions		—	—		—		—		6.3		6.3		—
Acquisition of VEX Interest		—	—		105.7		—		—		105.7		—
Net income (loss)		90.5	—		(2.0)		35.5		126.7		250.7		—
Balance, December 31, 2014	$	2,774.3	164.1	$	103.7	$	—	$	4,196.8	$	7,074.8	$	—
Issuance of common units by the Partnership		—	—		—		—		384.4		384.4		—
Conversion of restricted units for common, net of units withheld for taxes		(2.9)	0.1		—		—		—		(2.9)		—
Non-controlling partner's impact of conversion of restricted units		—	—		—		—		(2.5)		(2.5)		—
Unit-based compensation		18.5	—		—		—		17.6		36.1		—
Change in equity due to issuance of units by the Partnership		8.5	—		—		—		(13.7)		(5.2)		—
Non-controlling interest distributions		—	—		—		—		(359.5)		(359.5)		—
Non-controlling interest contribution		—	—		—		—		16.4		16.4		—
Distributions to members		(162.8)	—		—		—		—		(162.8)		—
Adjustment related to mandatory redemption of E2 non-controlling interest		—	—		—		—		(5.4)		(5.4)		—
Redeemable non-controlling interest		—	—		—		—		(7.0)		(7.0)		7.0
Contribution from Devon to the Company		7.1	—		—		—		—		7.1		—
Contribution from Devon to the Partnership		—	—		25.6		—		2.2		27.8		—
Distribution attributable to VEX interests transferred (Note 3)		—	—		(131.1)		—		(35.6)		(166.7)		—
Net income (loss)		(357.0)	—		1.8		—		(1,054.5)		(1,409.7)		—
Balance, December 31, 2015	$	2,285.7	164.2	$	—	$	—	$	3,139.2	$	5,424.9	$	7.0
Issuance of common units by the Partnership		—	—		—		—		167.5		167.5		—
Issuance of Preferred Units by the Partnership		—	—		—		—		724.1		724.1		—
Issuance of common units		214.9	15.6		—		—		—		214.9		—
Conversion of restricted units for common, net of units withheld for taxes		(1.2)	0.2		—		—		—		(1.2)		—
Non-controlling partner's impact of conversion of restricted units		—	—		—		—		(1.2)		(1.2)		—
Unit-based compensation		15.1	—		—		—		15.2		30.3		—
Change in equity due to issuance of units by the Partnership		11.8	—		—		—		(18.9)		(7.1)		—
Non-controlling interest distributions		—	—		—		—		(382.4)		(382.4)		—
Non-controlling interest contribution		—	—		—		—		167.9		167.9		—
Distributions to members		(185.4)	—		—		—		—		(185.4)		—
Distributions to redeemable non-controlling interest		—	—		—		—		—		—		(1.8)
Contribution from Devon to the Company		—	—		—		—		1.5		1.5		—
Net loss		(460.0)	—		—		—		(428.2)		(888.2)		—
Balance, December 31, 2016	$	1,880.9	180.0	$	—	$	—	$	3,384.7	$	5,265.6	$	5.2

See accompanying notes to consolidated financial statements.

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ENLINK MIDSTREAM, LLC

Consolidated Statements of Cash Flows


	Year Ended December 31,
	2016		2015		2014
	(In millions)
Cash flows from operating activities:
Net income (loss)	$	(888.2)	$	(1,409.7)	$	249.7
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization		503.9		387.3		284.3
Impairments		873.3		1,563.4		—
Accretion expense		0.6		0.6		0.5
(Gain) loss on disposition of assets		13.2		1.2		(0.1)
Gain on extinguishment of debt		—		—		(3.2)
Deferred tax expense		2.1		22.6		67.4
Non-cash unit-based compensation		30.3		36.1		19.6
(Gain) loss on derivatives recognized in net income (loss)		11.1		(9.4)		(22.1)
Cash settlements on derivatives		10.5		17.1		(0.3)
Amortization of debt issue costs		3.9		3.3		1.9
Amortization of net (premium) discount on notes		49.5		(2.9)		(2.9)
Redeemable non-controlling interest expense		0.3		(1.8)		—
Distribution of earnings from unconsolidated affiliates		3.1		21.6		7.0
(Income) loss from unconsolidated affiliates		19.9		(20.4)		(18.9)
Changes in assets and liabilities net of assets acquired and liabilities assumed:
Accounts receivable, accrued revenue and other		(118.1)		197.5		(98.9)
Natural gas and NGLs inventory, prepaid expenses and other		18.7		(6.7)		(8.2)
Accounts payable, accrued gas and crude oil purchases and other accrued liabilities		132.3		(171.4)		(16.9)
Net cash provided by operating activities		666.4		628.4		458.9
Cash flows from investing activities, net of assets acquired and liabilities assumed:
Additions to property and equipment		(663.0)		(572.3)		(796.0)
Acquisition of business, net of cash acquired		(791.5)		(524.2)		(357.9)
Proceeds from insurance settlement		0.3		2.9		—
Proceeds from sale of property		93.1		1.0		0.1
Investment in unconsolidated affiliates		(73.8)		(25.8)		(5.7)
Distribution from unconsolidated affiliates in excess of earnings		54.6		21.1		10.9
Net cash used in investing activities		(1,380.3)		(1,097.3)		(1,148.6)
Cash flows from financing activities:
Proceeds from borrowings		2,150.4		3,204.4		3,367.8
Payments on borrowings		(1,917.5)		(2,134.3)		(2,792.7)
Payments on capital lease obligations		(6.6)		(3.6)		(3.0)
Increase (decrease) in drafts payable		—		(12.7)		10.2
Debt financing costs		(4.7)		(9.6)		(19.7)
Redeemable non-controlling interest		(3.0)		—		—
Conversion of restricted units, net of units withheld for taxes		(1.2)		(2.9)		(1.1)
Conversion of Partnership's restricted units, net of units withheld for taxes		(1.2)		(2.5)		(0.7)
Proceeds from issuance of Partnership's common units		167.5		24.4		412.0
Distributions to non-controlling partners		(384.2)		(359.5)		(204.3)
Distribution to members		(185.4)		(162.8)		(89.0)
Distributions to Predecessor		—		—		(21.3)
Contribution from Devon		1.5		27.8		105.7
Proceeds from exercise of Partnership unit options		—		0.1		0.4
Proceeds from issuance of Partnership Preferred Units		724.1		—		—
Purchase of non-controlling interest		—		—		(12.5)
Distribution to Devon for VEX interests transferred (Note 3)		—		(166.7)		—
Contributions by non-controlling interest		167.9		16.4		6.3
Net cash provided by financing activities		707.6		418.5		758.1
Cash flow from discontinued operations:
Net cash provided by operating activities		—		—		5.0
Net cash used in investing activities		—		—		(0.6)
Net cash used in financing activities, net distributions to Devon and non-controlling interests		—		—		(4.4)
Net cash provided by discontinued operations		—		—		—
Net increase (decrease) in cash and cash equivalents		(6.3)		(50.4)		68.4
Cash and cash equivalents, beginning of period		18.0		68.4		—
Cash and cash equivalents, end of period	$	11.7	$	18.0	$	68.4
Cash paid for interest	$	133.7	$	110.0	$	55.8
Cash paid (refund) for income taxes	$	(7.0)	$	13.7	$	7.5

See accompanying notes to consolidated financial statements.

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ENLINK MIDSTREAM, LLC

Notes to Consolidated Financial Statements

December 31, 2016 and 2015

(1) Organization and Summary of Significant Agreements

(a) Organization of Business and Nature of Business

EnLink Midstream, LLC (“ENLC”) is a publicly traded Delaware limited liability company formed in 2013. Effective as of March 7, 2014, EnLink Midstream, Inc. (“EMI”) merged with and into a wholly-owned subsidiary of the Company and Acacia Natural Gas Corp I, Inc. (“Acacia”), formerly a wholly-owned subsidiary of Devon Energy Corporation (“Devon”), merged with and into a wholly-owned subsidiary of the Company (collectively, the “mergers”). Pursuant to the mergers, each of EMI and New Acacia became wholly-owned subsidiaries of the Company and the Company became publicly held. EMI owns common units representing an approximate 5.9% limited partner interest in EnLink Midstream LP ( the “Partnership”) as of December 31, 2016 and also owns EnLink Midstream Partners GP, LLC (the “General Partner”). Acacia directly owned a 50% limited partner interest in Midstream Holdings, which was formerly a wholly-owned subsidiary of Devon. Upon closing of the Business Combination (as defined below), ENLC issued 115,495,669 units to a wholly-owned subsidiary of Devon, represent approximately 64% of the outstanding limited liability company interests in ENLC as of December 31, 2016. Concurrently with the consummation of the mergers, a wholly-owned subsidiary of the Partnership acquired the remaining 50% of the outstanding limited partner interest in Midstream Holdings and all of the outstanding equity interests in EnLink Midstream Holdings GP, LLC, the general partner of Midstream Holdings (together with the mergers, the “Business Combination”). The Company’s common units are traded on the New York Stock Exchange under the symbol “ENLC.”

On February 17, 2015, Acacia contributed a 25% interest in Midstream Holdings (the “February 2015 Transferred Interests”) to the Partnership in a drop down transaction (the “February EMH Drop Down”) in exchange for 31,618,311 Class D Common Units in the Partnership. On May 27, 2015, Acacia contributed the remaining 25% limited partner interest in Midstream Holdings (the “May 2015 Transferred Interests”) to the Partnership in a drop down transaction (the “May 2015 EMH Drop Down” and together with the February 2015 EMH Drop Down, the “EMH Drop Downs”) in exchange for 36,629,888 Class E Common Units in the Partnership. After giving effect to the EMH Drop Downs, the Partnership owns 100% of Midstream Holdings. In addition, on April 1, 2015, the Partnership acquired the Victoria Express Pipeline and related truck terminal and storage assets from Devon (the “VEX Interests”).

On January 7, 2016, the Operating Partnership acquired 84% of the outstanding equity interests in EnLink Oklahoma T.O., and ENLC acquired the remaining 16% equity interests in EnLink Oklahoma T.O. Since we control EnLink Oklahoma T.O., we reflect our ownership in EnLink Oklahoma T.O. on a consolidated basis in the consolidated financial statements and related disclosures. See “Note 3—Acquisitions” for further discussion.

On August 1, 2016, the Partnership formed a joint venture (the “Delaware Basin JV”) with an affiliate of NGP Natural Resources XI, L.P. (“NGP”) to operate and expand the Partnership’s natural gas, natural gas liquids (“NGLs”) and crude oil midstream assets in the liquids-rich Delaware Basin. The Delaware Basin JV is owned 50.1% by the Partnership and 49.9% by NGP. Since the Partnership controls the Delaware Basin JV, the Partnership reflects its ownership in the Delaware Basin JV on a consolidated basis, and NGP’s ownership is reflected as a non-controlling interest in the respective consolidated financial statements and related disclosures. See “Note 3—Acquisitions” for further discussion.

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Our assets consist of equity interests in the Partnership and EnLink Oklahoma T.O. The Partnership is a publicly traded limited partnership engaged in the gathering, transmission, processing and marketing of natural gas and natural gas liquids, or NGLs, condensate and crude oil, as well as providing crude oil, condensate and brine services to producers. EnLink Oklahoma T.O. is a partnership held by us and the Partnership, and is engaged in the gathering and processing of natural gas. As of December 31, 2016, our interests in the Partnership consist of the following:

88,528,451 common units representing an aggregate 22.3% limited partner interest in the Partnership;

100.0% ownership interest in EnLink Midstream Partners GP, LLC, the general partner of the Partnership (the “General Partner”), which owns a 0.4% general partner interest and all of the incentive distribution rights in the Partnership; and

16% limited partner interest in EnLink Oklahoma T.O.

(b) Nature of Business

The Partnership primarily focuses on providing midstream energy services, including gathering, transmission, processing, fractionation, storage, condensate stabilization, brine services and marketing to producers of natural gas, NGLs, crude oil and condensate. The Partnership connects the wells of producers in its market areas to its gathering systems, processes natural gas to remove NGLs, fractionates NGLs into purity products and markets those products for a fee, transports natural gas and ultimately provides natural gas to a variety of markets. The Partnership purchases natural gas from natural gas producers and other supply sources and sells that natural gas to utilities, industrial consumers, other marketers and pipelines. The Partnership operates processing plants that process gas transported to the plants by major interstate pipelines or from its own gathering systems under a variety of fee-based arrangements. The Partnership provides a variety of crude oil and condensate services, which include crude oil and condensate gathering and transmission via pipelines, barges, rail and trucks, condensate stabilization and brine disposal. The Partnership also has crude oil and condensate terminal facilities that provide access for crude oil and condensate producers to premium markets. The Partnership’s gas gathering systems consist of networks of pipelines that collect natural gas from points near producing wells and transport it to larger pipelines for further transmission. The Partnership’s transmission pipelines primarily receive natural gas from its gathering systems and from third party gathering and transmission systems and deliver natural gas to industrial end-users, utilities and other pipelines. The Partnership also has transmission lines that transport NGLs from east Texas and from our south Louisiana processing plants to its fractionators in south Louisiana. The Partnership’s crude oil and condensate gathering and transmission systems consist of trucking facilities, pipelines, rail and barge facilities that, in exchange for a fee, transport crude oil from a producer site to end users and other pipelines. The Partnership’s processing plants remove NGLs and CO₂ from a natural gas stream and its fractionators separate the NGLs into separate NGL products, including ethane, propane, iso-butane, normal butane and natural gasoline.

(2) Significant Accounting Policies

(a) Basis of Presentation

The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“US GAAP”). Further, the consolidated financial statements give effect to the Business Combination under the acquisition method of accounting and are treated as a reverse acquisition. Under the acquisition method of accounting, Midstream Holdings was the accounting acquirer in the transactions because its parent company, Devon, obtained control of ENLC through the indirect control of the general partner as a result of the Business Combination. Consequently, Midstream Holdings’ assets and liabilities retained their carrying values. All financial results prior to March 7, 2014 reflect the historical operations of Midstream Holdings and its majority-owned subsidiaries and are reflected as “Predecessor interest in net income” on the statement of operations for the year ended December 31, 2014. Additionally, EMI’s assets acquired and liabilities assumed by ENLC, as well as ENLC’s non-controlling interests in the Partnership, were recorded at their fair values measured as of the acquisition date, March 7, 2014. The excess of the purchase price over the estimated fair values of EMI’s net assets acquired was recorded as goodwill. Financial results subsequent to March 7, 2014 reflect the combined operations of Midstream Holdings and EMI, which give effect to new contracts entered into with Devon and include the legacy Partnership assets.

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All significant intercompany transactions and balances have been eliminated. Certain assets were not contributed to Midstream Holdings from the Predecessor and the operations of such non-contributed assets have been presented as discontinued operations. In conjunction with the Business Combination, Midstream Holdings became a non-taxable entity which was treated as a reorganization under common control with the removal of historical deferred taxes reflected through equity.

During the fourth quarter of 2014 and the first half of 2015, the Partnership acquired assets from Devon and us through drop down transactions. Due to our ownership and control of the general partner and Devon’s control of us through its ownership of the managing member of ENLC, each acquisition from ENLC and Devon was considered a transfer of net assets between entities under common control. As such, we were required to recast our historical financial statements to include the activities of such assets from the date that these entities were under common control. The consolidated financial statements for periods prior to the Partnership’s acquisition of the assets from Devon and us have been prepared from Devon’s and our historical cost-basis accounts for the acquired assets and may not necessarily be indicative of the actual results of operations that would have occurred if the Partnership had owned the acquired assets during the periods reported. Net income attributable to the assets acquired from Devon and us for periods prior to the Partnership’s acquisition is allocated to the general partner.

In January 2016, we adopted Accounting Standards Updates (“ASU”) 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis. This ASU provides additional guidance to reporting entities in evaluating whether certain legal entities, such as limited partnerships, limited liability corporations and securitization structures, should be consolidated. Due to ENLC’s ownership of the General Partner, the Partnership is considered a variable interest entity as the limited partners lack the ability to exercise kick-out rights over the General Partner and do not have substantive participating rights. Further, ENLC, including the consideration of the Incentive Distribution Rights, is considered the primary beneficiary as it has the power to direct the activities that most significantly impact the Partnership’s economic performance. The adoption of this standard has no impact on our consolidated financial statements as we will continue to consolidate the Partnership

(b) Management’s Use of Estimates

The preparation of financial statements in accordance with US GAAP requires our management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the period. Actual results could differ from these estimates.

The Partnership generates the majority of its revenues from midstream energy services, including gathering, transmission, processing, fractionation, storage, condensate stabilization, brine services and marketing, through various contractual arrangements, which include fee based contract arrangements or arrangements where it purchases and resells commodities in connection with providing the related service and earns a net margin for its fee. While the transactions vary in form, the essential element of each transaction is the use of the Partnership’s assets to transport a product or provide a processed product to an end-user at the tailgate of the plant, barge terminal or pipeline. The Partnership reflects revenue as Product sales and Midstream services revenue on the consolidated statements of operations as follows:

Product sales - Product sales represent the sale of natural gas, NGLs, crude oil and condensate where the product is purchased and resold in connection with providing its midstream services as outlined above.

Midstream services - Midstream services represents all other revenue generated as a result of performing the Partnership’s midstream services outlined above.

The Partnership recognizes revenue for sales or services at the time the natural gas, NGLs, crude oil or condensate are delivered or at the time the service is performed at a fixed or determinable price. The Partnership generally accrues one month of sales and the related natural gas, NGL, condensate and crude oil purchases and reverses these accruals when the sales and purchases are actually invoiced and recorded in the subsequent month. Actual results could differ from the accrual estimates. Except for fixed-fee based arrangements, the Partnership acts as the principal in these

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purchase and sale transactions, bearing the risk and reward of ownership as evidenced by title transfer, scheduling the transportation of products and assuming credit risk. The Partnership accounts for taxes collected from customers attributable to revenue transactions and remitted to government authorities on a net basis (excluded from revenues).

Certain gathering and processing agreements in the Partnership’s Texas, Oklahoma and Crude and Condensate segments provide for a quarterly or annual minimum volume commitment ("MVC"). Under these agreements, the Partnership’s customers agree to ship and/or process a minimum volume of production on its systems over an agreed time period. If a customer under such an agreement fails to meet its MVC for a specified period, the customer is obligated to pay a contractually-determined fee based upon the shortfall between actual production volumes and the MVC for that period. Some of these agreements also contain make-up right provisions that allow a customer to utilize gathering or processing fees in excess of the MVC in subsequent periods to offset shortfall amounts in previous periods. We record revenue under MVC contracts during periods of shortfall when it is known that the customer can not, or will not, make up the deficiency in the specific period.

Revenue recorded for the shortfall between actual production volumes and the MVC are as follows (in millions):


	Texas		Oklahoma		Crude and Condensate		Total

Year Ended December 31, 2016
Midstream services	$	1.9	$	9.5	$	—	$	11.4
Midstream services - related parties		26.4		10.8		9.0		46.2
Total	$	28.3	$	20.3	$	9.0	$	57.6

Year Ended December 31, 2015
Midstream services	$	0.5	$	—	$	—	$	0.5
Midstream services - related parties		3.8		20.1		0.5		24.4
Total	$	4.3	$	20.1	$	0.5	$	24.9

(d) Gas Imbalance Accounting

Quantities of natural gas and NGLs over-delivered or under-delivered related to imbalance agreements are recorded monthly as receivables or payables using weighted average prices at the time of the imbalance. These imbalances are typically settled with deliveries of natural gas or NGLs. The Partnership had imbalance payables of $7.1 million and $2.6 million at December 31, 2016 and 2015, respectively, which approximate the fair value of these imbalances. The Partnership had imbalance receivables of $3.9 million and $3.6 million at December 31, 2016 and 2015, respectively, which are carried at the lower of cost or market value. Imbalance receivables and imbalance payables are included in the line items “Accrued revenue and other” and “Accrued gas, NGLs, condensate and crude oil purchases,” respectively, on the consolidated balance sheets.

(e) Cash and Cash Equivalents

The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents.

(f) Income Taxes

We account for deferred income taxes related to the federal and state jurisdictions using the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases. Deferred tax assets are also recognized for the future tax benefits attributable to the expected utilization of existing tax net operating loss carryforwards and other types of carryforwards. If the future utilization of some portion of carryforwards is determined to be unlikely, a valuation allowance is provided to reduce the recorded tax benefits from such assets. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect

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on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. In the event interest or penalties are incurred with respect to income tax matters, our policy will be to include such items in income tax expense.

(g) Natural Gas, Natural Gas Liquids, Crude Oil and Condensate Inventory

The Partnership’s inventories of products consist of natural gas, NGLs, crude oil and condensate. The Partnership reports these assets at the lower of cost or market value which is determined by using the first-in, first-out method.

(h) Property, Plant, and Equipment

Property, plant and equipment are stated at historical cost less accumulated depreciation. Assets acquired in a business combination are recorded at fair value, including the Partnership’s assets acquired by the Predecessor in the Business Combination. Repairs and maintenance are charged against income when incurred. Renewals and betterments, which extend the useful life of the properties, are capitalized. Subsequent to a business combination, interest costs for material projects are capitalized to property, plant and equipment during the period the assets are undergoing preparation for intended use.

The components of property, plant and equipment are as follows (in millions):


	Year Ended December 31,
	2016		2015
Transmission assets	$	1,191.7	$	1,285.1
Gathering systems		3,530.9		2,999.2
Gas processing plants		3,163.0		2,673.7
Other property and equipment		149.5		135.9
Construction in process		345.7		330.5
Property, plant and equipment		8,380.8		7,424.4
Accumulated depreciation		(2,124.1)		(1,757.6)
Property, plant and equipment, net	$	6,256.7	$	5,666.8

Change in Depreciation Method. Historically, Midstream Holdings depreciated certain property, plant, and equipment using the units-of-production method. As a result of the Business Combination, the Company is operated as an independent midstream company and thus no longer have access to Devon’s proprietary reserve and production data historically used to compute depreciation under the units-of-production method. Additionally, the existing contracts with Devon were revised to a fee-based arrangement with MVCs. Effective March 7, 2014, the Company changed its method of computing depreciation for these assets to the straight-line method, consistent with the depreciation method applied to its acquired assets. In accordance with ASC 250, Accounting Changes and Error Corrections, the Company determined that the change in depreciation method was a change in accounting estimate effected by a change in accounting principle, and accordingly, the straight-line method was applied on a prospective basis. This change is considered preferable because the straight-line method will more accurately reflect the pattern of usage and the expected benefits of such assets. The effect of this change in estimate resulted in a decrease in depreciation expense of approximately $29.4 million, or $0.18 per unit for the year ended December 31, 2014.

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


		Useful Lives
Transmission assets		20 - 25 years
Gathering systems		20 - 25 years
Gas processing plants		20 - 25 years
Other property and equipment		3 - 15 years

Depreciation expense of $386.9 million, $331.3 million and $247.8 million was recorded for the years ended December 31, 2016, 2015 and 2014, respectively.

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Gain or Loss on Disposition. Upon the disposition or retirement of property, plant and equipment related to continuing operations, any gain or loss is recognized in operating income in the statement of operations. When a disposition or retirement occurs which qualifies as discontinued operations, any gain or loss is recognized as income or loss from discontinued operations in the statement of operations. For the year ended December 31, 2016, we retired or sold net property, plant and equipment of $106.6 million, which was offset by $0.3 million of nonrefundable cash proceeds collected from our insurance carrier and $93.1 million of proceeds from the sale of property. This resulted in a loss on disposition of assets of $13.2 million, which primarily relates to the sale of the North Texas Pipeline System (“NPTL”), a 140-mile natural gas transportation pipeline. We received net proceeds of $84.6 million and recorded a loss on sale of $13.4 million.

For the year ended December 31, 2015, we retired net property, plant and equipment of $5.1 million, which was offset by $2.9 million of nonrefundable cash proceeds collected from our insurance carrier and $1.0 million of proceeds from the sale of property. This resulted in a loss on disposition of assets of $1.2 million, which primarily relates to the retirement of a compressor due to fire damage. Additionally, we collected $2.4 million of business interruption proceeds from our insurance carrier that was presented in the Midstream services revenue line item in the consolidated statement of operations for the year ended December 31, 2015.

Impairment Review. We evaluate our property, plant and equipment for potential impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. The carrying amount of a long-lived asset is not recoverable when it exceeds the undiscounted sum of the future cash flows expected to result from the use and eventual disposition of the asset. Estimates of expected future cash flows represent management’s best estimate based on reasonable and supportable assumptions. When the carrying amount of a long-lived asset is not recoverable, an impairment loss is recognized equal to the excess of the asset’s carrying value over its fair value. The fair values of long-lived assets are generally determined from estimated discounted future net cash flows. Our estimate of cash flows is based on assumptions, which include: (1) the future fee-based rate of new business or contract renewals; (2) the purchase and resale margins on natural gas, NGLs, condensate and crude oil; (3) the volume of natural gas, NGL, condensate and crude oil available to the asset; (4) markets available to the asset, (5) operating expenses; and (6) future natural gas, crude oil, condensate and NGL product prices. The volume of available natural gas, condensate, NGLs and crude oil to an asset is sometimes based on assumptions regarding future drilling activity, which may be dependent in part on natural gas, NGL, condensate and crude oil prices. Projections of volumes and future commodity prices are inherently subjective and contingent upon a number of variable factors. Any significant variance in any of the above assumptions or factors could materially affect our cash flows, which could require us to record an impairment of an asset. During the year ended December 31, 2015, the Partnership recognized a $12.1 million impairment on property, plant and equipment, primarily related to costs associated with the cancellation of various capital projects in its Texas, Louisiana, and Crude and Condensate segments.

(i) Equity Method of Accounting

The Partnership accounts for investments where it does not control the investment but has the ability to exercise significant influence using the equity method of accounting. Under this method, unconsolidated affiliate investments are initially carried at the acquisition cost, increased by our proportionate share of the investee’s net income and by contributions made, and decreased by our proportionate share of the investee’s net losses and by distributions received.

The Partnership evaluates our unconsolidated affiliate investments for potential impairment whenever events or changes in circumstances indicate that the carrying amount of the investments may not be recoverable. The Partnership recognizes impairments of our investments as a loss from unconsolidated affiliates on our consolidated statements of operations. For additional information, see “Note 11—Investments in Unconsolidated Affiliates.”

(j) Goodwill

Goodwill is the cost of an acquisition less the fair value of the net identifiable assets of the acquired business. The Company evaluates goodwill for impairment annually as of October 31, and whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount. The Company first assesses qualitative factors to evaluate whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as the basis for determining whether it is necessary to perform the two-step

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goodwill impairment test. The Company may elect to perform the two-step goodwill impairment test without completing a qualitative assessment. If a two-step goodwill impairment test is elected or required, the first step involves comparing the fair value of the reporting unit with its carrying amount. If the carrying amount of a reporting unit exceeds its fair value, the second step of the process involves comparing the implied fair value of goodwill to the carrying value of the goodwill for that reporting unit. If the carrying value of the goodwill of a reporting unit exceeds the implied fair value of that goodwill, the excess of the carrying value over the implied fair value is recognized as an impairment loss. During the year ended December 31, 2016, the Company recognized a goodwill impairment loss totaling $873.3 million for our Texas, Crude and Condensate and Corporate segments. During the year ended December 31, 2015, the Company recognized a goodwill impairment of $1,328.2 million related to our Louisiana, Texas and Crude and Condensate segments. See “Note 4—Goodwill and Intangible Assets for further discussion regarding the goodwill impairments.

(k) Intangible Assets

Intangible assets associated with customer relationships are amortized on a straight-line basis over the expected period of benefits of the customer relationships, which range from ten to twenty years.

(l) Asset Retirement Obligations

The Partnership recognizes liabilities for retirement obligations associated with its pipelines and processing and fractionation facilities. Such liabilities are recognized when there is a legal obligation associated with the retirement of the assets and the amount can be reasonably estimated. The initial measurement of an asset retirement obligation is recorded as a liability at its fair value, with an offsetting asset retirement cost recorded as an increase to the associated property, plant and equipment. If the fair value of a recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the asset retirement cost. The Partnership’s retirement obligations include estimated environmental remediation costs that arise from normal operations and are associated with the retirement of the long-lived assets. The asset retirement cost is depreciated using the straight-line depreciation method similar to that used for the associated property, plant and equipment.

(m) Other Long-Term Liabilities

Other current and long-term liabilities include a liability related to an onerous performance obligation assumed in the Business Combination of $44.8 million and $62.8 million as of December 31, 2016 and 2015, respectively. The Company has one delivery contract that requires us to deliver a specified volume of gas each month at an indexed base price with a term to 2019. The Company realizes a loss on the delivery of gas under this contract each month based on current prices. The fair value of this onerous performance obligation was recorded as a result of the March 7, 2014 Business Combination and was based on forecasted discounted cash obligations in excess of market under this gas delivery contract. The liability is reduced each month as delivery is made over the remaining life of the contract with an offsetting reduction in purchased gas costs.

(n) Derivatives

The Company uses derivative instruments to hedge against changes in cash flows related to product price only. The Company generally determines the fair value of swap contracts based on the difference between the derivative’s fixed contract price and the underlying market price at the determination date. The asset or liability related to the derivative instruments is recorded on the balance sheet as fair value of derivative assets or liabilities in accordance with ASC 815, Derivatives and Hedging (“ASC 815”). Changes in fair value of derivative instruments are recorded in gain or loss on derivative activity in the period of change.

Realized gains and losses on commodity related derivatives are recorded as gain or loss on derivative activity within revenues in the consolidated statements of operations in the period incurred. Settlements of derivatives are included in cash flows from operating activities.

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(o) Concentrations of Credit Risk

Financial instruments, which potentially subject the Company to concentrations of credit risk, consist primarily of trade accounts receivable and commodity financial instruments. Management believes the risk is limited, other than our exposure to Devon discussed below, since the Company’s customers represent a broad and diverse group of energy marketers and end users. In addition, the Company continually monitors and reviews credit exposure of its marketing counter-parties and letters of credit or other appropriate security are obtained when considered necessary to limit the risk of loss. The Company records reserves for uncollectible accounts on a specific identification basis since there is not a large volume of late paying customers. The Company had a reserve for uncollectible receivables of $0.1 million and $0.3 million as of December 31, 2016 and 2015, respectively.

During the years ended December 31, 2016, 2015 and 2014, we had only one customer, other than the transactions with Devon, that individually represented greater than 10.0% of our midstream revenues. The customer is located in the Louisiana segment and represented 10.8%, 11.7% and 11.0% of the consolidated revenues for years ended December 31, 2016, 2015 and 2014, respectively. The affiliate transactions with Devon represented 18.5%, 16.6% and 30.6% of the consolidated midstream revenues for the years ended December 31, 2016, 2015 and 2014, respectively. Devon and our Louisiana customer represent a significant percentage of revenues and the loss of either as a customer would have a material adverse impact on our results of operations because the gross operating margin received from transactions with these customers are material to us.

(p) Environmental Costs

Environmental expenditures are expensed or capitalized depending on the nature of the expenditures and the future economic benefit. Expenditures that relate to an existing condition caused by past operations that do not contribute to current or future revenue generation are expensed. Liabilities for these expenditures are recorded on an undiscounted basis (or a discounted basis when the obligation can be settled at fixed and determinable amounts) when environmental assessments or clean-ups are probable and the costs can be reasonably estimated. Environmental expenditures were $3.5 million for the year ended December 31, 2015. For the years ended December 31, 2016 and 2014, such expenditures were not material.

(q) Unit-Based Awards

Prior to the Business Combination, Devon granted certain share-based awards to members of its board of directors and selected employees. The Predecessor did not grant share-based awards because it previously participated in Devon’s share-based award plans since the Predecessor comprised Devon’s U.S. midstream assets. The awards granted under Devon’s plans were measured at fair value on the date of grant and were recognized as expense over the applicable requisite service periods.

The Company recognizes compensation cost related to all unit-based awards in its consolidated financial statements in accordance with ASC 718, Compensation—Stock Compensation (“ASC 718”). The Company and the Partnership each have similar unit-based payment plans for employees. Unit-based compensation associated with ENLC’s unit-based compensation plans awarded to directors, officers and employees of the general partner of the Partnership are recorded by the Partnership since the Company has no substantial or managed operating activities other than its interests in the Partnership and EnLink Oklahoma T.O.

(r) Commitments and Contingencies

Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated.

(s) Discontinued Operations

The Company classifies as discontinued operations its assets that have clearly distinguishable cash flows and are in the process of being sold or have been sold. The Company also include as discontinued operations Predecessor assets that were not contributed in the Business Combination.

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(t) Debt Issuance Costs

Costs incurred in connection with the issuance of long-term debt are deferred and recorded as interest expense over the term of the related debt. Gains or losses on debt repurchases, redemptions and debt extinguishments include any associated unamortized debt issue costs. Unamortized debt issuance costs totaling $24.6 million and $23.8 million as of December 31, 2016 and 2015, respectively, are included in “Long-term debt” on the consolidated balance sheets as a direct reduction from the carrying amount of long-term debt. Debt issuance costs are amortized into interest expense using the straight-line method over the term of the related debt issuance.

(u) Legal Costs Expected to be Incurred in Connection with a Loss Contingency

Legal costs incurred in connection with a loss contingency are expensed as incurred.

(v) Redeemable Non-Controlling Interest

Non-controlling interests that contain an option for the non-controlling interest holder to require the Partnership to buy out such interests for cash are considered to be redeemable non-controlling interests because the redemption feature is not deemed to be a freestanding financial instrument and because the redemption is not solely within the control of the Partnership. Redeemable non-controlling interest is not considered to be a component of partners’ equity and is reported as temporary equity in the mezzanine section on the consolidated balance sheets. The amount recorded as redeemable non-controlling interest at each balance sheet date is the greater of the redemption value and the carrying value of the redeemable non-controlling interest (the initial carrying value increased or decreased for the non-controlling interest holder’s share of net income or loss and distributions).

(w) Adopted Accounting Standards

In January 2016, we adopted ASU 2015-03, Interest - Imputation of Interest (Topic 835): Simplifying the Presentation of Debt Issuance Costs. The update requires debt issuance costs related to a recognized debt liability to be presented on the balance sheet as a direct deduction from the carrying amount of that debt liability and requires retrospective application. The retrospective application of this new accounting guidance resulted in the reclassification of $23.8 million of debt issuance costs from “Other assets, net” to “Long-term debt” in our consolidated balance sheet as of December 31, 2015.

In January 2016, we adopted ASU 2015-17, Balance Sheet Classification of Deferred Taxes on a prospective basis. This new standard required that deferred tax assets and liabilities be classified as noncurrent in our consolidated balance sheet.

In January 2016, we adopted ASU 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments, which eliminates the requirement for an acquirer to retrospectively adjust the financial statements for measurement-period adjustments that occur in periods after a business combination is consummated. The adoption had no impact on our consolidated financial statements or related disclosures.

In January 2016, we adopted ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis. The update provides additional guidance to reporting entities in evaluating whether certain legal entities, such as limited partnerships, limited liability corporations and securitization structures, should be consolidated. The update is considered to be an improvement on current accounting requirements as it reduces the number of existing consolidation models. The adoption had no impact on our consolidated financial statements or related disclosures.

In August 2016, the Financial Accounting Standards Board (“FASB”) issued ASU 2016-15, Statement of Cash Flows (Topic 230) — Classification of Certain Cash Receipts and Cash Payments (“ASU 2016-15”). ASU 2016-15 addresses the classification and presentation of certain cash receipts and cash payments related to debt prepayment or debt extinguishment costs, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, distributions received from equity method investees, and other specific cash flow issues. ASU 2016-15 is effective for annual reporting periods beginning after December 15, 2017, including interim periods

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within those annual periods, and should be applied using a retrospective transition method to each period presented. Early application is permitted, including adoption in an interim period. In September 2016, we elected to early adopt ASU 2016-15 effective January 1, 2016. The adoption had no impact on our consolidated financial statements or related disclosures.

(x) Accounting Standards to be Adopted in Future Periods

In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting, which amends ASC Topic 718, Compensation – Stock Compensation (“ASU 2016-09”). First, ASU 2016-09 will require all of the tax effects related to share-based payments at settlement (or expiration) to be recorded through the income statement, and is required to be applied prospectively. Second, ASU 2016-09 allows entities to withhold taxes of an amount up to the employees’ maximum individual tax rate in the relevant jurisdiction without resulting in liability classification of the award, and is required to be adopted using a modified retrospective approach. Third, under ASU 2016-09, forfeitures can be estimated, as currently required, or recognized when they occur. If elected, the change to recognize forfeitures when they occur must be adopted using a modified retrospective approach. ASU 2016-09 is effective for annual reporting periods beginning after December 15, 2016 including interim periods within those annual periods. Early adoption is permitted. We do not expect this standard to materially impact our consolidated financial statements or related disclosures.

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) - Amendments to the FASB Accounting Standards Codification (“ASU 2016-02”). Lessees will need to recognize virtually all of their leases on the balance sheet, by recording a right-of-use asset and lease liability. Lessor accounting is similar to the current model, but updated to align with certain changes to the lessee model and the new revenue recognition standard. Existing sale-leaseback guidance is replaced with a new model applicable to both lessees and lessors. Additional revisions have been made to embedded leases, reassessment requirements, and lease term assessments including variable lease payment, discount rate, and lease incentives. ASU 2016-02 is effective for annual reporting periods beginning after December 15, 2018 including interim periods within those annual periods. Early adoption is permitted, and is required to be adopted using a modified retrospective transition. We are currently evaluating the impact this standard will have on our consolidated financial statements and related disclosures.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”), which established Accounting Standards Codification Topic 606, Revenue from Contracts with Customers (“ASC 606). ASC 606 will replace existing revenue recognition requirements in GAAP and will require entities to recognize revenue at an amount that reflects the consideration to which the Partnership expects to be entitled in exchange for transferring goods or services to a customer. ASC 606 will also require significantly expanded disclosures regarding the qualitative and quantitative information of the Partnership’s nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. In May 2016, the FASB issued ASU 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients (“ASU 2016-12”), which updated ASU 2014-09. ASU 2016-12 clarifies certain core recognition principles including collectability, sales tax presentation, noncash consideration, contract modifications and completed contracts at transition and disclosures no longer required if the full retrospective transition method is adopted. ASU 2014-09 and ASU 2016-12 are effective for annual reporting periods beginning after December 15, 2017, including interim periods within those annual periods, and are to be applied using either the modified retrospective or full retrospective transition methods, with early application permitted for annual reporting periods beginning after December 15, 2016. We plan to use the modified retrospective transition method and do not plan to early adopt ASC 606. We have aggregated and reviewed our contracts that are within the scope of ASC 606. Based on our evaluation to-date, we do not anticipate this standard will have a material impact on our consolidated financial statements. We continue to evaluate the impacts ASC 606 will have on our disclosures.

(3) Acquisitions

Chevron Acquisition

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entities, for approximately $231.5 million in cash. The natural gas assets include natural gas pipelines spanning from Beaumont, Texas to the Mississippi River corridor and working natural gas storage capacity in southern Louisiana. The transaction was accounted for using the acquisition method, which requires, among other things, that assets acquired and liabilities assumed be recognized at their fair values as of the acquisition date.

The following table presents the fair value of the identified assets received and liabilities assumed at the acquisition date (in millions):


Purchase Price Allocation:
Assets acquired:
Property, plant and equipment	$	225.3
Intangibles		13.0
Liabilities assumed:
Current liabilities		(6.8)
Total identifiable net assets	$	231.5

The Partnership recognized intangible assets related to customer relationships. The acquired intangible assets will be amortized on a straight-line basis over the estimated customer life of approximately 20 years.

The Partnership incurred $0.6 million of direct transaction costs for the year ended December 31, 2015. These costs are included in general and administrative costs in the accompanying Consolidated Statements of Operations.

LPC Acquisition

The following table presents the fair value of the identified assets received and liabilities assumed at the acquisition date (in millions):


Purchase Price Allocation:
Assets acquired:
Current assets (including $21.1 million in cash)	$	107.4
Property, plant and equipment		29.8
Intangibles		43.2
Goodwill		29.6
Liabilities assumed:
Current liabilities		(97.9)
Deferred tax liability		(4.0)
Total identifiable net assets	$	108.1

The Partnership recognized intangible assets related to customer relationships and trade name. The acquired intangible assets related to customer relationships are amortized on a straight-line basis over the estimated customer life of approximately 10 years.

Goodwill recognized from the acquisition primarily relates to the value created from additional growth opportunities and greater operating leverage in the Permian Basin. All such goodwill is allocated to our Crude and Condensate segment.

The Partnership incurred $0.3 million of direct transaction costs for the year ended December 31, 2015. These costs are included in general and administrative costs in the accompanying consolidated statements of operations.

For the period from January 31, 2015 to December 31, 2015, the Partnership recognized $1.1 billion of revenues and $0.9 million of net income related to the assets acquired.

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Coronado Acquisition

On March 16, 2015, the Partnership acquired 100% of the voting equity interests in Coronado Midstream Holdings LLC (“Coronado”), which owns natural gas gathering and processing facilities in the Permian Basin, for approximately $600.3 million. The purchase price consisted of $240.3 million in cash, 6,704,285 common units and 6,704,285 Class C Common Units, both in the Partnership.

The following table presents the fair value of the identified assets received and liabilities assumed at the acquisition date (in millions):


Purchase Price Allocation:
Assets acquired:
Current assets (including $1.4 million in cash)	$	20.8
Property, plant and equipment		302.1
Intangibles		281.0
Goodwill		18.7
Liabilities assumed:
Current liabilities		(22.3)
Total identifiable net assets	$	600.3

The Partnership recognized intangible assets related to customer relationships. The acquired intangible assets are amortized on a straight-line basis over the estimated customer life of approximately 10 years. Goodwill recognized from the acquisition primarily relates to the value created from additional growth opportunities and greater operating leverage in the Permian Basin. All such goodwill is allocated to the Partnership’s Texas segment.

The Partnership incurred $3.1 million of direct transaction costs for the year ended December 31, 2015. These costs are included in general and administrative costs in the accompanying consolidated statements of operations.

For the period from March 16, 2015 to December 31, 2015, the Partnership recognized $182.0 million of revenues and $14.2 million of net loss related to the assets acquired.

Matador Acquisition

The following table presents the fair value of the identified assets received and liabilities assumed at the acquisition date (in millions):


Purchase Price Allocation:
Assets acquired:
Current assets	$	1.1
Property, plant and equipment		35.5
Intangibles		98.8
Goodwill		10.7
Liabilities assumed:
Current liabilities		(4.8)
Total identifiable net assets	$	141.3

The Partnership recognized intangible assets related to customer relationships. The acquired intangible assets are amortized on a straight-line basis over the estimated customer life of approximately 15 years. Goodwill recognized from the acquisition primarily relates to the value created from additional growth opportunities and greater operating leverage in the Permian Basin. All such goodwill is allocated to the Partnership’s Texas segment.

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The Partnership incurred $0.1 million of direct transaction costs for the year ended December 31, 2015. These costs are included in general and administrative costs in the accompanying consolidated statements of operations.

For the period from October 1, 2015 to December 31, 2015, the Partnership recognized $5.6 million of revenues and $0.7 million of net loss related to the assets acquired.

Deadwood Acquisition

Prior to November 2015, the Partnership co-owned the Deadwood natural gas processing plant with a subsidiary of Apache Corporation (“Apache”). On November 16, 2015, the Partnership acquired Apache’s 50% ownership interest in the Deadwood natural gas processing facility for approximately $40.1 million, all of which is considered property, plant and equipment. The transaction was accounted for using the acquisition method. Direct transaction costs attributable to this acquisition were less than $0.1 million.

For the period from November 16, 2015 to December 31, 2015, the Partnership recognized $3.5 million of revenues and $1.3 million of net income related to the assets acquired.

VEX Pipeline Drop Down

On April 1, 2015, the Partnership acquired the Victoria Express Pipeline and related truck terminal and storage assets located in the Eagle Ford Shale in south Texas, together with 100% of the voting equity interests (the “VEX Interests”) in certain entities, from Devon in a drop down transaction (the “VEX Drop Down”). The aggregate consideration paid by the Partnership consisted of $166.7 million in cash, 338,159 common units representing limited partner interests in the Partnership with an aggregate value of approximately $9.0 million and the Partnership’s assumption of up to $40.0 million in certain construction costs related to VEX. The VEX pipeline is a multi-grade crude oil pipeline located in the Eagle Ford Shale. Other VEX assets at the destination of the pipeline include a truck unloading terminal, above-ground storage and rights to barge loading docks. The acquisition has been accounted for as an acquisition under common control under ASC 805, resulting in the retrospective adjustment of our prior results. As such, the VEX Interests were recorded on the Partnership’s books at historical cost on the date of transfer of $131.0 million. The difference between the historical cost of the net assets and consideration given was $35.7 million and is recognized as a distribution to Devon. Construction costs paid by Devon during the first quarter of 2015 totaling $25.6 million are reflected as contributions from Devon to the Partnership in our consolidated statements of changes in partners’ equity and consolidated statements of cash flows for the year ended December 31, 2015. The period of common control for VEX began on February 28, 2014, the effective date of the acquisition of the VEX Interests by Devon.

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Pro Forma of Acquisitions for the Years Ended 2015 and 2014

The following unaudited pro forma condensed financial information (in millions, except for per unit data) for the year ended December 31, 2015 and 2014 gives effect to the Business Combination, November 2014 Chevron acquisition, January 2015 LPC acquisition, March 2015 Coronado acquisition, October 2015 Matador acquisition, EMH Drop Downs, VEX Drop Down and E2 Drop Down as if they had occurred on January 1, 2014. The unaudited pro forma condensed financial information has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the transactions taken place on the dates indicated and is not intended to be a projection of future results.


	Year Ended December 31,
	2015		2014
Pro forma total revenues (1)	$	4,585.5	$	5,679.3
Pro forma net income (loss)	$	(1,413.0)	$	220.2
Pro forma net income (loss) attributable to EnLink Midstream, LLC	$	(355.5)	$	64.8
Pro forma net income (loss) per common unit:
Basic	$	(2.18)	$	0.41
Diluted	$	(2.18)	$	0.41

(1)

“On January 1, 2014, Midstream Holdings entered into gathering and processing agreements with Devon, which are described in “Note 5—Related Party Transactions.”

EnLink Oklahoma T.O. Acquisition

On January 7, 2016, we and the Partnership acquired a 16% and 84% voting interest, respectively, in EnLink Oklahoma T.O. for approximately $1.4 billion. The first installment of $1.02 billion for the acquisition was paid at closing. The second installment of $250.0 million was paid on January 6, 2017, and the final installment of $250.0 million is due no later than January 7, 2018. The Partnership’s installment payables are valued net of discount within the total purchase price.

The first installment consisted of approximately $1.02 billion and was funded by (a) approximately $783.6 million in cash paid by the Partnership, the majority of which was derived from the proceeds from the issuance of Preferred Units, and (b) 15,564,009 common units representing limited liability company interests in ENLC issued directly by us and approximately $22.2 million in cash paid by us. The transaction was accounted for using the acquisition method.

The following table presents the considerations we and the Partnership paid and the fair value of the identified assets received and liabilities assumed at the acquisition date (in millions):


Consideration:
Cash	$	805.8
Issuance of common units		214.9
The Partnership's total installment payable, net of discount of $79.1 million assuming payments are made on January 7, 2017 and 2018		420.9
Total consideration	$	1,441.6

Purchase Price Allocation:
Assets acquired:
Current assets (including $12.8 million in cash)	$	23.0
Property, plant and equipment		406.1
Intangibles		1,051.3
Liabilities assumed:
Current liabilities		(38.8)
Total identifiable net assets	$	1,441.6

The fair value of assets acquired and liabilities assumed are based on inputs that are not observable in the market and thus represent Level 3 inputs. The Partnership recognized intangible assets related to customer relationships and

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determined their fair value using the income approach. The acquired intangible assets are amortized on a straight-line basis over the estimated customer life of approximately 15 years.

The Partnership incurred $4.4 million and $0.4 million of direct transaction costs for the year ended December 31, 2016 and December 31, 2015, respectively. These costs are incurred in general and administrative costs in the accompanying consolidated statements of operations.

For the period from January 7, 2016 to December 31, 2016, the Partnership recognized $246.1 million of revenues and $34.1 million of net loss related to the assets acquired.

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Pro Forma of the EnLink Oklahoma T.O. Acquisition

The following unaudited pro forma condensed financial information (in millions, except for per unit data) for the year ended December 31, 2016 and 2015 gives effect to the January 2016 EnLink Oklahoma T.O. acquisition as if it had occurred on January 1, 2015. The unaudited pro forma condensed financial information has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the transaction taken place on the dates indicated and is not intended to be a projection of future results.


	Year Ended December 31,
	2016		2015
Pro forma total revenues	$	4,254.4	$	4,647.8
Pro forma net loss	$	(879.9)	$	(1,471.8)
Pro forma net loss attributable to EnLink Midstream, LLC	$	(451.3)	$	(368.4)
Pro forma net loss per common unit:
Basic	$	(2.51)	$	(2.05)
Diluted	$	(2.51)	$	(2.05)

(4) Goodwill and Intangible Assets

Goodwill

Goodwill is the cost of an acquisition less the fair value of the net identifiable assets of the acquired business. The fair value of goodwill is based on inputs that are not observable in the market and thus represent Level 3 inputs. We evaluate goodwill for impairment annually as of October 31, and whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount. We first assess qualitative factors to evaluate whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as the basis for determining whether it is necessary to perform the two-step goodwill impairment test. We may elect to perform the two-step goodwill impairment test without completing a qualitative assessment. If a two-step goodwill impairment test is elected or required, the first step involves comparing the fair value of the reporting unit to its carrying amount. If the carrying amount of a reporting unit exceeds its fair value, the second step of the process involves comparing the implied fair value of goodwill to the carrying value of the goodwill for that reporting unit. If the carrying value of the goodwill of a reporting unit exceeds the implied fair value of that goodwill, the excess of the carrying value over the implied fair value is recognized as an impairment loss.

We perform our goodwill assessments at the reporting unit level for all reporting units. The Partnership uses a discounted cash flow analysis to perform the assessments. Key assumptions in the analysis include the use of an appropriate discount rate, terminal year multiples, and estimated future cash flows including volume and price forecasts and estimated operating and general and administrative costs. In estimating cash flows, the Partnership incorporates current and historical market and financial information, among other factors. We also have goodwill related to our investment in the Partnership that is included in our Corporate segment. We utilize the publicly traded market value of our common units, adjusted for our estimated control premium, in our Corporate level goodwill assessment.

Our impairment determinations involved significant assumptions and judgments, as discussed above. Differing assumptions regarding any of these inputs could have a significant effect on the various valuations. If actual results are not consistent with our assumptions and estimates, or assumptions and estimates change due to new information, we may be exposed to additional goodwill impairment charges, which would be recognized in the period in which the carrying value exceeds fair value.

Impairment Analysis for the Year Ended December 31, 2015

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established annual effective date for this goodwill analysis is October 31, we updated the effective date for this impairment analysis for the 2015 annual period to December 31, 2015 due to continued declines in commodity prices and our unit price during the fourth quarter of 2015.

Using the fair value approaches described above, in step one of the goodwill impairment test, the Partnership determined that the estimated fair values of its Louisiana, Texas and Crude and Condensate reporting unit were less than their carrying amounts, primarily related to commodity prices, volume forecasts and discount rates. The second step of the goodwill impairment test measures the amount of impairment loss and allocated the estimated fair value of the reporting unit among all of the assets and liabilities of the reporting unit as if the reporting unit had been acquired in a business combination. Based on this analysis, a goodwill impairment loss for its Louisiana, Texas, and Crude and Condensate reporting units in the amount of $1,328.2 million was recognized for the year ended December 31, 2015 and is included as an impairment loss in the consolidated statements of operations.

The Partnership concluded that the fair value of goodwill for its Oklahoma reporting unit exceeded its carrying value, and the amount of goodwill disclosed on the consolidated balance sheet associated with this remaining reporting unit was recoverable. Therefore, no other goodwill impairment was identified or recorded for this reporting unit as a result of our annual goodwill assessment.

Impairment Analysis for the Year Ended December 31, 2016

During February 2016, we determined that continued further weakness in the overall energy sector, driven by low commodity prices together with a further declines in our unit price and the Partnership unit price subsequent to year-end, caused a change in circumstances warranting an interim impairment test. Based on these triggering events, we performed a goodwill impairment analysis in the first quarter of 2016 on all reporting units. Based on this analysis, a goodwill impairment loss for the Texas, Crude and Condensate, and Corporate reporting units in the amount of $873.3 million was recognized in the first quarter of 2016 and is included as an impairment loss in the consolidated statement of operations for the year ended December 31, 2016.

The Partnership concluded that the fair value of its Oklahoma reporting unit exceeded its carrying value, and the amount of goodwill disclosed on the consolidated balance sheet associated with this reporting unit is recoverable. Therefore, no other goodwill impairment was identified or recorded for this reporting unit as a result of their goodwill impairment analysis.

During our annual impairment test for 2016 performed as of October 31, 2016, it determined that no further impairments were required for the year ended December 31, 2016. The estimated fair value of our reporting units may be impacted in the future by a further decline in our unit price or a continuing prolonged period of lower commodity prices which may adversely affect its estimate of future cash flows, both of which could result in future goodwill impairment charges for its reporting units.

The table below provides a summary of our change in carrying amount of goodwill (in millions), by assigned reporting unit:


							Crude and
	Texas		Louisiana		Oklahoma		Condensate		Corporate		Totals
Year Ended December 31, 2016
Balance, beginning of period	$	703.5	$	—	$	190.3	$	93.2	$	1,426.9	$	2,413.9
Impairment		(473.1)		—		—		(93.2)		(307.0)		(873.3)
Acquisition adjustment		1.6		—		—		—		—		1.6
Balance, end of period	$	232.0	$	—	$	190.3	$	—	$	1,119.9	$	1,542.2

Year Ended December 31, 2015
Balance, beginning of period	$	1,168.2	$	786.8	$	190.3	$	112.5	$	1,427	$	3,684.7
Acquisitions (1)		27.8		—		—		29.6		—		57.4
Impairment		(492.5)		(786.8)		—		(48.9)		—		(1,328.2)
Balance, end of period	$	703.5	$	—	$	190.3	$	93.2	$	1,426.9	$	2,413.9

(1)

See “Note 3—Acquisitions” for further discussion.

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Intangible Assets

Intangible assets associated with customer relationships are amortized on a straight-line basis over the expected period of benefits of the customer relationships, which range from 10 to 20 years.

During 2016 and 2015, we reviewed our various assets groups for impairment due to the triggering events described in the goodwill impairment analysis above. During 2015, the undiscounted cash flows related to one of its assets groups in the Crude and Condensate segment were not in excess of its related carrying value. The Partnership estimated the fair value of this reporting unit and determined the fair of the intangible assets was not in excess of its carrying value. This resulted in a $223.1 million impairment of intangible assets in its Crude and Condensate segment, and this non-cash impairment charge is included as an impairment loss on the consolidated statements of operations for the year ended December 31, 2015. During 2016, the undiscounted cash flows of the Partnership’s assets exceeded its carrying values, and no impairment was recorded. The Partnership utilized Level 3 fair value measurements in its impairment analysis of this definite-lived intangible asset, which included discounted cash flow assumptions by management consistent with those utilized in its goodwill impairment analysis.

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


	Gross				Net
	Carrying		Accumulated		Carrying
	Amount		Amortization		Amount
Year Ended December 31, 2016
Customer relationships, beginning of period	$	744.5	$	(54.6)	$	689.9
Acquisitions		1,051.3		—		1,051.3
Amortization expense		—		(117.0)		(117.0)
Customer relationships, end of period	$	1,795.8	$	(171.6)	$	1,624.2

Year Ended December 31, 2015
Customer relationships, beginning of period	$	569.5	$	(36.5)	$	533.0
Acquisitions		436.0		—		436.0
Amortization expense		—		(56.0)		(56.0)
Impairment		(261.0)		37.9		(223.1)
Customer relationships, end of period	$	744.5	$	(54.6)	$	689.9

The weighted average amortization period for intangible assets is 13.7 years. Amortization expense for intangibles was approximately $117.0 million, $56.0 million, and $36.5 million for the years ended December 31, 2016, 2015 and 2014, respectively.

The following table summarizes the Partnership’s estimated aggregate amortization expense for the next five years (in millions):


2017	$	117.9
2018		117.9
2019		117.9
2020		117.9
2021		117.9
Thereafter		1,034.7
Total	$	1,624.2

(5) Related Party Transactions

The Partnership engages in various transactions with Devon and other related parties. For the years ended December 31, 2016, 2015 and 2014, Devon was a significant customer to the Partnership. Devon accounted for 18.5%,

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16.6% and 30.6% of the Partnership’s revenues for the years ended December 31, 2016, 2015 and 2014, respectively. The Partnership had an accounts receivable balance related to transactions with Devon of $100.2 million and $110.8 million as of December 31, 2016 and 2015, respectively. Additionally, the Partnership had an accounts payable balance related to transactions with Devon of $10.4 million and $14.8 million as of December 31, 2016 and 2015, respectively. Management believes these transactions are executed on terms that are fair and reasonable and are consistent with terms for transactions with unrelated third parties. The amounts related to related party transactions are specified in the accompanying financial statements.

Gathering, Processing and Transportation Agreements Associated with Our Business Combination with Devon

As described in “Note 1—Organization and Summary of Significant Agreements,” Midstream Holdings was previously a wholly-owned subsidiary of Devon, and all of its assets were contributed to it by Devon. On January 1, 2014, in connection with the consummation of the Business Combination, EnLink Midstream Services, LLC, a wholly-owned subsidiary of Midstream Holdings (“EnLink Midstream Services”), entered into 10-year gathering and processing agreements with Devon pursuant to which EnLink Midstream Services provides gathering, treating, compression, dehydration, stabilization, processing and fractionation services, as applicable, for natural gas delivered by Devon Gas Services, L.P., a subsidiary of Devon (“Gas Services”), to Midstream Holdings’ gathering and processing systems in the Barnett, Cana-Woodford and Arkoma-Woodford Shales. On January 1, 2014, SWG Pipeline, L.L.C. (“SWG Pipeline”), another wholly-owned subsidiary of Midstream Holdings, entered into a 10-year gathering agreement with Devon pursuant to which SWG Pipeline provides gathering, treating, compression, dehydration and redelivery services, as applicable, for natural gas delivered by Gas Services to another of the Partnership’s gathering systems in the Barnett Shale.

These agreements provide Midstream Holdings with dedication of all of the natural gas owned or controlled by Devon and produced from or attributable to existing and future wells located on certain oil, natural gas and mineral leases covering land within the acreage dedications, excluding properties previously dedicated to other natural gas gathering systems not owned and operated by Devon. Pursuant to the gathering and processing agreements entered into on January 1, 2014, Devon has committed to deliver specified average minimum daily volumes, referred to as MVCs, of natural gas to Midstream Holdings’ gathering systems in the Barnett, Cana-Woodford and Arkoma-Woodford Shales during each calendar quarter for a five-year period that expires on January 1, 2019. The Partnership recognized revenue from MVCs attributable to Devon of $46.2 million and $24.4 million for the years ended December 31, 2016 and 2015, respectively. Devon is entitled to firm service, meaning that if capacity on a system is curtailed or reduced, or capacity is otherwise insufficient, Midstream Holdings will take delivery of as much Devon natural gas as is permitted in accordance with applicable law.

The gathering and processing agreements are fee-based, and Midstream Holdings is paid a specified fee per MMBtu for natural gas gathered on Midstream Holdings’ gathering systems and a specified fee per MMBtu for natural gas processed. The particular fees, all of which are subject to an automatic annual inflation escalator at the beginning of each year, differ from one system to another and do not contain a fee redetermination clause.

In connection with the closing of the Business Combination, Midstream Holdings entered into an agreement with a wholly-owned subsidiary of Devon pursuant to which Midstream Holdings provides transportation services to Devon on its Acacia pipeline.

EnLink Oklahoma T.O. Gathering and Processing Agreement with Devon

In January 2016, in connection with the acquisition of EnLink Oklahoma T.O., the Partnership acquired a Gas Gathering and Processing Agreement with Devon Energy Production Company, L.P. (“DEPC”) pursuant to which EnLink Oklahoma T.O. provides gathering, treating, compression, dehydration, stabilization, processing and fractionation services, as applicable, for natural gas delivered by DEPC. The agreement has an MVC that will remain in place during each calendar quarter for five years and an overall term of approximately 15 years. Additionally, the agreement provides EnLink Oklahoma T.O. with dedication of all of the natural gas owned or controlled by DEPC and produced from or attributable to existing and future wells located on certain oil, natural gas and mineral leases covering land within the acreage dedications, excluding properties previously dedicated to other natural gas gathering systems not owned and operated by DEPC. DEPC is entitled to firm service, meaning a level of gathering and processing service in

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which DEPC’s reserved capacity may not be interrupted, except due to force majeure, and may not be displaced by another customer or class of service.

Cedar Cove Joint Venture

On November 9, 2016, the Partnership formed a joint venture (the “Cedar Cove JV”) with Kinder Morgan, Inc. consisting of gathering and compression assets in Blaine County, Oklahoma. Under a fifteen year, fixed-fee agreement, all gas gathered by the Cedar Cove JV will be processed at our central Oklahoma processing system. For the period from November 9, 2016 through December 31, 2016, revenue generated from processing gas from the Cedar Cove JV was classified as “Midstream services – related parties” on the consolidated statements of operations and was immaterial to our overall financial results.

Other Commercial Relationships with Devon

As noted above, the Partnership continues to maintain a customer relationship with Devon originally established prior to the Business Combination pursuant to which the Partnership provides gathering, transportation, processing and gas lift services to Devon in exchange for fee-based compensation under several agreements with Devon. The terms of these agreements vary, but the agreements began to expire in January 2016 and continue to expire through July 2021, renewing automatically for month-to-month or year-to-year periods unless canceled by Devon prior to expiration. In addition, the Partnership has agreements with Devon pursuant to which the Partnership purchases and sells NGLs, gas and crude oil and pays or receives, as applicable, a margin-based fee. These NGL, gas and crude oil purchase and sale agreements have month-to-month terms.

VEX Transportation Agreement

In connection with the VEX acquisition, the Operating Partnership became party to a five year transportation services agreement with Devon pursuant to which the Operating Partnership provides transportation services to Devon on the VEX pipeline. This agreement includes a five-year MVC with Devon. The MVC was executed in June 2014, and the initial term expires July 2019.

Transition Services Agreement with Devon

In connection with the consummation of the Business Combination, the Partnership entered into a transition services agreement with Devon pursuant to which Devon provides certain services to the Partnership with respect to the business and operations of Midstream Holdings and the Partnership provides certain services to Devon. General and administrative expenses related to the transition service agreement were $0.3 million, $0.2 million and $3.0 million for years ended December 31, 2016, 2015 and 2014, respectively. The Partnership received $0.3 million from Devon under the transition services agreement for the years ended December 31, 2016, 2015 and 2014.

Drop Down Transactions

During the fourth quarter of 2014 and the first half of 2015, the Partnership acquired assets from Devon and us through drop down transactions. See “Note 3—Acquisitions” for further discussion.”

Predecessor Affiliate Transactions

Prior to March 7, 2014, affiliate transactions relate to Predecessor transactions consisting of sales to and from affiliates, services provided by affiliates, cost allocations from affiliates and centralized cash management activities performed by affiliates.

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The following presents financial information for the Predecessor’s affiliate transactions and other transactions with Devon, all of which are settled through an adjustment to equity prior to March 7, 2014 (in millions):


	Year Ended
	December 31,
	2014
Continuing Operations:
Operating revenues - related parties	$	(436.4)
Operating expenses - related parties		340.0
Net related party transactions		(96.4)
Capital expenditures		16.2
Other third-party transactions, net		58.9
Net third-party transactions		75.1
Net cash distributions to Devon - continuing operations		(21.3)
Non-cash distribution of net assets to Devon		(6.3)
Total net distributions per equity	$	(27.6)

Discontinued operations:
Operating revenues - related parties	$	(10.4)
Operating expenses - related parties		5.0
Net related party transactions		(5.4)
Capital expenditures		0.6
Other third-party transactions, net		0.4
Net third-party transactions		1.0
Net distributions to Devon and non-controlling interests - discontinued operations		(4.4)
Non-cash distribution of net assets to Devon		(39.9)
Total net distributions per equity	$	(44.3)
Total distributions - continuing and discontinued operations	$	(71.9)

Share-based compensation costs included in the management services fee charged to Midstream Holdings by Devon were approximately $2.8 million for the year ended December 31, 2014. Pension, postretirement and employee savings plan costs included in the management services fee charged to the Partnership by Devon were approximately $1.6 million for the year ended December 31, 2014. These amounts are included in general and administrative expenses in the accompanying statements of operations.

Transactions with ENLK

We paid the Partnership $2.3 million, $2.1 million and $1.2 million as reimbursement during the years ended December 31, 2016, 2015, and 2014, respectively, to cover our portion of administrative and compensation costs for officers and employees that perform services for us. This reimbursement is evaluated on an annual basis. Officers and employees that perform services for us provide an estimate of the portion of their time devoted to such services. A portion of their annual compensation (including bonuses, payroll taxes and other benefit costs) is allocated to us for reimbursement based on these estimates. In addition, an administrative burden is added to such costs to reimburse the Partnership for additional support costs, including, but not limited to, consideration for rent, office support and information service support.

On October 29, 2015, the Partnership issued 2,849,100 common units at an offering price of $17.55 per common unit to a subsidiary of ours for aggregate consideration of approximately $50.0 million in a private placement transaction.

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(6) Long-Term Debt

As of December 31, 2016 and 2015, long-term debt consisted of the following (in millions):


	December 31, 2016						December 31, 2015
		Outstanding Principal		Premium (Discount)		Long-Term Debt		Outstanding Principal		Premium (Discount)		Long-Term Debt
Partnership credit facility, due 2020 (1)	$	120.0	$	—	$	120.0	$	414.0	$	—	$	414.0
Company credit facility, due 2019 (2)		27.8		—		27.8		—		—		—
2.70% Senior unsecured notes due 2019		400.0		(0.3)		399.7		400.0		(0.4)		399.6
7.125% Senior unsecured notes due 2022		162.5		16.0		178.5		162.5		18.9		181.4
4.40% Senior unsecured notes due 2024		550.0		2.5		552.5		550.0		2.9		552.9
4.15% Senior unsecured notes due 2025		750.0		(1.1)		748.9		750.0		(1.2)		748.8
4.85% Senior unsecured notes due 2026		500.0		(0.7)		499.3		—		—		—
5.60% Senior unsecured notes due 2044		350.0		(0.2)		349.8		350.0		(0.2)		349.8
5.05% Senior unsecured notes due 2045		450.0		(6.6)		443.4		450.0		(6.9)		443.1
Other debt		—		—		—		0.2		—		0.2
Debt classified as long-term	$	3,310.3	$	9.6	$	3,319.9	$	3,076.7	$	13.1	$	3,089.8
Debt issuance cost (3)						(24.6)						(23.8)
Long-term debt, net of unamortized issuance cost					$	3,295.3					$	3,066.0

(1)

Bears interest based on Prime and/or LIBOR plus an applicable margin. The effective interest rate was 2.3% and 1.8% at December 31, 2016 and 2015, respectively.

(2)

Bears interest based on Prime and/or LIBOR plus an applicable margin. The effective interest rate was 3.4% at December 31, 2016.

(3)

Net of amortization of $9.0 million and $5.1 million at December 31, 2016 and 2015, respectively.

Maturities

Maturities for the long-term debt as of December 31, 2016 are as follows (in millions):


2017	$	—
2018		—
2019		427.8
2020		120.0
2021		—
Thereafter		2,762.5
Subtotal		3,310.3
Add: net premium		9.6
Less: debt issuance cost		(24.6)
Long-term debt, net of unamortized issuance cost	$	3,295.3

Company Credit Facility

We have a $250.0 million revolving credit facility, which includes a $125.0 million letter of credit subfacility (the “credit facility”) that matures on March 7, 2019. Our obligations under the credit facility are guaranteed by two of our wholly-owned subsidiaries and secured by first priority liens on (i) 88,528,451 Partnership common units and the 100% membership interest in the General Partner indirectly held by us, (ii) the 100% equity interest in each of our wholly-owned subsidiaries held by us and any additional equity interests subsequently pledged as collateral under the credit facility.

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ratio of consolidated funded indebtedness to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges) of 4.00 to 1.00, provided that the maximum consolidated leverage ratio is 4.50 to 1.00 during an acquisition period (as defined in the credit facility) and (ii) maintaining a minimum consolidated interest coverage ratio (as defined in the credit facility, but generally computed as the ratio of consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges to consolidated interest charges) of 2.50 to 1.00 at all times unless an investment grade event (as defined in the credit facility) occurs.

Partnership Credit Facility

The Partnership has a $1.5 billion unsecured revolving credit facility, which includes a $500.0 million letter of credit subfacility that matures on March 6, 2020. Under its credit facility, the Partnership is permitted to (1) subject to certain conditions and the receipt of additional commitments by one or more lenders, increase the aggregate commitments under its credit facility by an additional amount not to exceed $500.0 million and (2) subject to certain conditions and the consent of the requisite lenders, on two separate occasions extend the maturity date of its credit facility by one year on each occasion. The Partnership’s credit facility contains certain financial, operational and legal covenants. Among other things, these covenants include maintaining a ratio of consolidated indebtedness to consolidated EBITDA (which is defined in its credit facility and includes projected EBITDA from certain capital expansion projects) of no more than 5.0 to 1.0. If the Partnership consummates one or more acquisitions in which the aggregate purchase price is $50.0 million or more, it can elect to increase the maximum allowed ratio of consolidated indebtedness to consolidated EBITDA to 5.5 to 1.0 for the quarter of the acquisition and the three following quarters.

Borrowings under the Partnership’s credit facility bear interest at its option at the Eurodollar Rate (the LIBOR Rate) plus an applicable margin or the Base Rate (the highest of the Federal Funds Rate plus 0.50%, the 30-day Eurodollar Rate plus 1.0% or the administrative agent’s prime rate) plus an applicable margin.

The applicable margins vary as shown in the table below depending on its credit rating. If the Partnership breaches certain covenants governing its credit facility, amounts outstanding under its credit facility, if any, may become due and payable immediately. At December 31, 2016, the Partnership was in compliance and expect to be in compliance with the covenants in the existing credit facility for at least the next twelve months.

Senior Unsecured Notes

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additional $15.5 million aggregate principal amount of the 2022 Notes for $17.0 million, including accrued interest. The Partnership recorded a gain on extinguishment of debt related to the redemption of the 2022 Notes of $2.4 million for the year ended December 31, 2014.

On November 12, 2014, the Partnership issued an additional $100.0 million aggregate principal amount of its 2024 Notes and $300.0 million aggregate principal amount of its 5.050% senior notes due 2045 (the “2045 Notes”), at prices to the public of 104.007% and 99.452%, respectively, of their face value. The new 2024 Notes were offered as an additional issue of the Partnership’s outstanding 4.400% Senior Notes due 2024, issued in an aggregate principal amount of $450.0 million on March 19, 2014. The 2024 Notes issued on March 19, 2014 and November 12, 2014 are treated as a single class of debt securities and have identical terms, other than the issue date. The 2045 Notes mature on April 1, 2045, and interest payments on the 2045 Notes are due semi-annually in arrears in April and October.

On July 14, 2016, the Partnership issued $500.0 million in aggregate principal amount of the Partnership’s 4.850% senior notes due 2026 (the “2026 Notes”) at a price to the public of 99.859% of their face value. The 2026 Notes mature on July 15, 2026. Interest payments on the 2026 Notes are payable on January 15 and July 15 of each year, beginning January 15, 2017. Net proceeds of approximately $495.7 million were used to repay outstanding borrowings under the Partnership’s revolving credit facility and for general partnership purposes.

Prior to June 1, 2017, the Partnership may redeem all or part of the remaining 2022 Notes at the redemption price equal to the sum of the principal amount thereof, plus a make-whole premium at the redemption date, plus accrued and unpaid interest to the redemption date. On or after June 1, 2017, the Partnership may redeem all or a part of the remaining 2022 Notes at redemption prices (expressed as percentages of principal amount) equal to 103.563% for the twelve-month period beginning on June 1, 2017, 102.375% for the twelve-month period beginning on June 1, 2018, 101.188% for the twelve-month period beginning on June 1, 2019 and 100.000% for the twelve-month period beginning on June 1, 2020 and at any time thereafter, plus accrued and unpaid interest, if any, to the applicable redemption date on the 2022 Notes.

Prior to March 1, 2019, the Partnership may redeem all or a part of the 2019 Notes at a redemption price equal to the greater of: (i) 100% of the principal amount of the 2019 Notes to be redeemed; or (ii) the sum of the remaining scheduled payments of principal and interest on the 2019 Notes to be redeemed that would be due after the related redemption date but for such redemption (exclusive of interest accrued to, but excluding, the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the applicable Treasury Rate plus 20 basis points; plus accrued and unpaid interest to, but excluding, the redemption date. At any time on or after March 1, 2019, the Partnership may redeem all or a part of the 2019 Notes at a redemption price equal to 100% of the principal amount of the 2019 Notes to be redeemed plus accrued and unpaid interest to, but excluding, the redemption date.

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Prior to January 1, 2024, the Partnership may redeem all or a part of the 2024 Notes at a redemption price equal to the greater of: (i) 100% of the principal amount of the 2024 Notes to be redeemed; or (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the 2024 Notes to be redeemed that would be due after the related redemption date but for such redemption (exclusive of interest accrued to, but excluding, the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the applicable Treasury Rate plus 25 basis points; plus accrued and unpaid interest to, but excluding, the redemption date. At any time on or after January 1, 2024, the Partnership may redeem all or a part of the 2024 Notes at a redemption price equal to 100% of the principal amount of the 2024 Notes to be redeemed plus accrued and unpaid interest to, but excluding, the redemption date.

Prior to March 1, 2025, the Partnership may redeem all or part of the 2025 Notes at a redemption price equal to the greater: (i) 100% of the principal amount of the 2025 Notes to be redeemed; or (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the 2025 Notes to be redeemed that would be due if the 2025 Notes matured on March 1, 2025 (exclusive of interest accrued to, but excluding, the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the applicable Treasury Rate plus 30 basis points; plus, in either case, accrued and unpaid interest to, but excluding, the redemption date. At any time on or after March 1, 2025, the Partnership may redeem all or part of the 2025 Notes at a redemption price equal to the greater, in whole or in part, at a redemption price equal to 100% of the principal amount of the 2025 Notes to be redeemed plus accrued and unpaid interest to, but excluding, the redemption date.

Prior to April 15, 2026, the Partnership may redeem all or part of the 2026 Notes at a redemption price equal to the greater: (i) 100% of the principal amount of the 2026 Notes to be redeemed; or (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the 2026 Notes to be redeemed that would be due if the 2026 Notes matured on April 15, 2026 (exclusive of interest accrued to, but excluding, the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the applicable Treasury Rate plus 50 basis points; plus, in either case, accrued and unpaid interest to, but excluding, the redemption date. At any time on or after April 15, 2026, the Partnership may redeem all or part of the 2026 Notes at a redemption price equal to the greater, in whole or in part, at a redemption price equal to 100% of the principal amount of the 2026 Notes to be redeemed plus accrued and unpaid interest to, but excluding, the redemption date.

Prior to October 1, 2043, the Partnership may redeem all or a part of the 2044 Notes at a redemption price equal to the greater of: (i) 100% of the principal amount of the 2044 Notes to be redeemed; or (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the 2044 Notes to be redeemed that would be due after the related redemption date but for such redemption (exclusive of interest accrued to, but excluding, the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the applicable Treasury Rate plus 30 basis points; plus accrued and unpaid interest to, but excluding, the redemption date. At any time on or after October 1, 2043, the Partnership may redeem all or a part of the 2044 Notes at a redemption price equal to 100% of the principal amount of the 2044 Notes to be redeemed plus accrued and unpaid interest to, but excluding, the redemption date.

Prior to October 1, 2044, the Partnership may redeem all or a part of the 2045 Notes at a redemption price equal to the greater of: (i) 100% of the principal amount of the 2045 Notes to be redeemed; or (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the 2045 Notes to be redeemed that would be due after the related redemption date but for such redemption (exclusive of interest accrued to, but excluding, the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the applicable Treasury Rate plus 30 basis points; plus, accrued and unpaid interest to, but excluding, the redemption date. At any time on or after October 1, 2044, the Partnership may redeem all or a part of the 2045 Notes at a redemption price equal to 100% of the principal amount of the 2045 Notes to be redeemed plus accrued and unpaid interest to, but excluding, the redemption date.

The indentures governing the Senior Notes contain covenants that, among other things, limit our ability to create or incur certain liens or consolidate, merge or transfer all or substantially all of our assets.

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Each of the following is an event of default under the indentures:

failure to pay any principal or interest when due;

failure to observe any other agreement, obligation or other covenant in the indenture, subject to the cure periods for certain failures; and

bankruptcy or other insolvency events involving the Partnership.

If an event of default relating to bankruptcy or other insolvency events occurs, the Senior Notes will immediately become due and payable. If any other event of default exists under the indenture, the trustee under the indenture or the holders of the Senior Notes may accelerate the maturity of the Senior Notes and exercise other rights and remedies. At December 31, 2016, the Partnership was in compliance and expects to be in compliance with the covenants in the Senior Notes for at least the next twelve months.

(7) Income Taxes

All taxes presented prior to March 7, 2014 relate to the predecessor’s results of continuing operations. Taxes presented for the periods subsequent to March 6, 2014 relate to the combined operations of ENLC, Predecessor and the remaining underlying operating entities.

The components of the provision for income tax expense are as follows (in millions):


	Year Ended December 31,
	2016		2015		2014
Current income tax expense	$	2.5	$	3.1	$	9.0
Deferred tax expense		2.1		22.6		67.4
Total income tax expense	$	4.6	$	25.7	$	76.4

The statutory federal income tax rate applied to pre-tax book income reconciles to income tax expense as follows in millions):


	Year Ended December 31,
	2016		2015		2014
Expected income tax expense (benefit) based on federal statutory rate of 35%	$	(159.4)	$	(116.0)	$	70.7
State income taxes, net of federal benefit and other		(9.8)		(7.7)		5.7
Goodwill impairment		173.8		149.4		—
Total income tax expense	$	4.6	$	25.7	$	76.4

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Deferred Tax Assets and Liabilities

Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Our deferred income tax assets and liabilities as of December 31, 2016 and 2015 are as follows (in millions):


	Year Ended December 31,
	2016		2015
Deferred income tax assets:
Asset retirement obligations and other	$	0.9	$	2.3
State net operating loss carryforward		6.5		3.6
Federal net operating loss carryforward		59.5		20.9
Total deferred tax assets		66.9		26.8
Deferred tax liabilities:
Property, plant, equipment, and intangible assets		(609.5)		(557.6)
Other		—		(1.3)
Total deferred tax liabilities		(609.5)		(558.9)
Deferred tax liability, net	$	(542.6)	$	(532.1)

(1)

Includes our investment in the Partnership, and primarily relates to differences between the book and tax bases of property, plant and equipment.

As of December 31, 2016, we had federal net operating loss carryforwards of $170.1 million that represent a net deferred tax asset of $59.5 million. As of December 31, 2016, we had state net operating loss carryforwards of $123.0 million that represent a net deferred tax asset of $6.5 million. These carryforwards will begin expiring in 2028 through 2036. Management believes that it is more likely than not that the future results of operations will generate sufficient taxable income to utilize these net operating loss carryforwards before they expire.

A reconciliation of the beginning and ending amounts of unrecognized tax benefits is as follows (in millions):


	Year Ended December 31,
	2016		2015		2014
Beginning balance, January 1	$	1.5	$	2.0	$	—
Unrecognized tax positions assumed in merger		—		—		3.8
Decrease due to prior year tax positions		(1.5)		(0.5)		(2.0)
Increases due to current year tax positions		—		—		0.2
Ending balance, December 31	$	—	$	1.5	$	2.0

There were no unrecognized tax benefits as of December 31, 2016.

Per our accounting policy election, penalties and interest related to unrecognized tax benefits are recorded to income tax expense. As of December 31, 2016, tax years 2012 through 2016 remain subject to examination by various taxing authorities.

(8) Certain Provisions of the Partnership Agreement

(a) Issuance of Common Units

In November 2014, the Partnership issued 12,075,000 common units representing limited partner interests in the Partnership at an offering price of $28.37 per unit for net proceeds of $332.3 million. The net proceeds from the common units offering were used for capital expenditures and general partnership purposes.

In October 2014, the Partnership issued 1,016,322 common units to ENLC representing limited partner interests in the Partnership as partial consideration for the E2 acquisition.

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In May 2014, the Partnership entered into an Equity Distribution Agreement (the “EDA”) with BMO Capital Markets Corp. (“BMOCM”). Pursuant to the terms of the EDA, the Partnership may from time to time through BMOCM, as its sales agent, sell common units representing limited partner interests having an aggregate offering price of up to $75.0 million. Through December 31, 2014, the Partnership sold an aggregate of 2.4 million common units under the EDA, generating proceeds of approximately $71.9 million (net of approximately $0.7 million of commissions to BMOCM). The Partnership used the net proceeds for general partnership purposes.

In November 2014, the Partnership entered into an Equity Distribution Agreement (the “BMO EDA”) with BMO Capital Markets Corp., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Citigroup Global Markets Inc., Jefferies LLC, Raymond James & Associates, Inc. and RBC Capital Markets, LLC (collectively, the “Sales Agents”) to sell up to $350.0 million in aggregate gross sales of the Partnership’s common units representing limited partner interests from time to time through an “at the market” equity offering program. The Partnership may also sell common units to any Sales Agent as principal for the Sales Agent’s own account at a price agreed upon at the time of sale. The Partnership has no obligation to sell any of the common units under the BMO EDA and may at any time suspend solicitation and offers under the BMO EDA. For the year ended December 31, 2014, the Partnership sold an aggregate of 0.3 million common units under the BMO EDA, generating proceeds of approximately $7.9 million (net of approximately $0.1 million of commissions). For the year ended December 31, 2015, the Partnership sold an aggregate of 1.3 million common units under the BMO EDA, generating proceeds of approximately $24.7 million (net of approximately $0.3 million of commissions). For the year ended December 31, 2016, the Partnership sold an aggregate of 10.0 million common units under the BMO EDA, generating proceeds of approximately $167.5 million (net of approximately $1.7 million of commissions). The Partnership used the net proceeds for general partnership purposes. As of December 31, 2016, approximately $147.8 million of gross common unit issuances remain available to be issued under the BMO EDA.

On October 29, 2015, the Partnership issued 2,849,100 common units at an offering price of $17.55 per unit to a subsidiary of ENLC for aggregate consideration of approximately $50.0 million in a private placement transaction.

(b) Class C Common Units

In March 2015, the Partnership issued 6,704,285 Class C Common Units representing a new class of limited partner interests as partial consideration for the acquisition of Coronado. The Class C Common Units were substantially similar in all respects to the Partnership’s common units, except that distributions paid on the Class C Common Units could be paid in cash or in additional Class C Common Units issued in kind, as determined by the general partner in its sole discretion. Distributions on the Class C Common Units for the three months ended March 31, 2015, June 30, 2015, and September 30, 2015 were paid-in-kind through the issuance of 99,794, 120,622, and 150,732 Class C Common Units on May 14, 2015, August 13, 2015, and November 12, 2015, respectively. Distributions on the Class C Common Units for the three months ended December 31, 2015 and March 31, 2016 were paid-in-kind through the issuance of 209,044 and 233,107 Class C Common Units on February 11, 2016 and May 12, 2016, respectively. All of the outstanding Class C Common Units were converted into common units on a one-for-one basis on May 13, 2016.

In February 2015, the Partnership issued 31,618,311 Class D Common Units to Acacia as consideration for a 25% interest in Midstream Holdings. For further discussion see “Note 3—Acquisitions.” Our Class D Common Units were substantially similar in all respects to our common units, except that they only received a pro rata distribution from the date of issuance for the fiscal quarter ended March 31, 2015. Our Class D Common Units automatically converted into our common units on a one-for-one basis on May 4, 2015.

(d) Class E Common Units

In May 2015, the Partnership issued 36,629,888 Class E Common Units to Acacia as consideration for the remaining 25% interest in Midstream Holdings. For further discussion, see “Note 3—Acquisitions.” The Partnership’s Class E Common Units were substantially similar in all respects to the Partnership’s common units, except that they only received a pro rata distribution from the date of issuance for the fiscal quarter ended June 30, 2015. The Partnership’s Class E Common Units automatically converted into the Partnership’s common units on a one-for-one basis on August 3, 2015.

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(e) Preferred Units

In January 2016, the Partnership issued an aggregate of 50,000,000 Series B Cumulative Convertible Preferred Units (the “Preferred Units”) representing the Partnership’s limited partner interests to Enfield Holdings, L.P. (“Enfield”) in a private placement for a cash purchase price of $15.00 per Preferred Unit (the “Issue Price”), resulting in net proceeds of approximately $724.1 million after fees and deductions. Proceeds from the private placement were used to partially fund the Partnership’s portion of the purchase price payable in connection with the EnLink Oklahoma T.O. acquisition. Affiliates of the Goldman Sachs Group, Inc. and affiliates of TPG Global, LLC own interests in the general partner of Enfield. The Preferred Units are convertible into the Partnership’s common units on a one-for-one basis, subject to certain adjustments, at any time after the record date for the quarter ending June 30, 2017 (a) in full, at the Partnership’s option, if the volume weighted average price of a common unit over the 30-trading day period ending two trading days prior to the conversion date (the “Conversion VWAP”) is greater than 150% of the Issue Price or (b) in full or in part, at Enfield’s option. In addition, upon certain events involving a change of control of the general partner or the managing member of ENLC, all of the Preferred Units will automatically convert into a number of common units equal to the greater of (i) the number of common units into which the Preferred Units would then convert and (ii) the number of Preferred Units to be converted multiplied by an amount equal to (x) 140% of the Issue Price divided by (y) the Conversion VWAP.

As a holder of Preferred Units, Enfield is entitled to receive a quarterly distribution, subject to certain adjustments, equal to (x) during the quarter ending March 31, 2016 through the quarter ending June 30, 2017, an annual rate of 8.5% on the Issue Price payable in-kind in the form of additional Preferred Units and (y) thereafter, an annual rate of 7.5% on the Issue Price payable in cash (the “Cash Distribution Component”) plus an in-kind distribution equal to the greater of (A) an annual rate of 1.0% of the Issue Price and (B) an amount equal to (i) the excess, if any, of the distribution that would have been payable had the Preferred Units converted into common units over the Cash Distribution Component, divided by (ii) the Issue Price. Distributions on the Preferred Units for the three months ended March 31, 2016, June 30, 2016 and September 30,2016, were paid-in kind through the issuance of 992,445, 1,083,589, and 1,106,616 Preferred Units on May 12, 2016, August 11, 2016, and November 10, 2016 respectively. A distribution on the Preferred Units was declared for the three months ended December 31, 2016, which will result in the issuance of 1,130,131 additional Preferred Units on February 13, 2016. Income was allocated to the Preferred Units in an amount equal to the quarterly distribution with respect to the period earned. For the year ended December 31, 2016, $69.9 million of income at the Partnership was allocated to the Preferred Units.

(f) Distributions

Unless restricted by the terms of the Partnership’s credit facility and/or the indentures governing the Partnership’s unsecured senior notes, the Partnership must make distributions of 100% of available cash, as defined in the partnership agreement, within 45 days following the end of each quarter. Distributions are made to the general partner in accordance with its current percentage interest with the remainder to the common unitholders, subject to the payment of incentive distributions as described below to the extent that certain target levels of cash distributions are achieved. The general partner was not entitled to its general partner or incentive distributions with respect to the Class C Common Units issued in kind. In addition, the General Partner is not entitled to its general partner or incentive distributions with respect to the Preferred Units until conversion to common units.

The Company owns the general partner interest in the Partnership and all of its incentive distribution rights. The Company is entitled to receive incentive distributions if the amount the Partnership distributes with respect to any quarter exceeds levels specified in our partnership agreement. Under the quarterly incentive distribution provisions, the Company is entitled to 13.0% of amounts the Partnership distributes in excess of $0.25 per unit, 23% of the amounts the Partnership distributes in excess of $0.3125 per unit and 48.0% of amounts the Partnership distributes in excess of $0.375 per unit.

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A summary of the Partnership’s distribution activity relating to the common units for the years ended December 31, 2016, 2015 and 2014 is provided below:


Declaration period	Distribution/unit		Date paid/payable
2016
First Quarter of 2016	$	0.390	May 12, 2016
Second Quarter of 2016	$	0.390	August 11, 2016
Third Quarter of 2016	$	0.390	November 11, 2016
Fourth Quarter of 2016	$	0.390	February 13, 2017

2015
First Quarter of 2015 (1)	$	0.380	May 14, 2015
Second Quarter of 2015 (2)	$	0.385	August 13, 2015
Third Quarter of 2015	$	0.390	November 12, 2015
Fourth Quarter of 2015	$	0.390	February 11, 2016

2014
First Quarter of 2014 (3)	$	0.360	May 14, 2014
Second Quarter of 2014	$	0.365	August 13, 2014
Third Quarter of 2014	$	0.370	November 13, 2014
Fourth Quarter of 2014	$	0.375	February 12, 2015

(1)

The Partnership’s partial first quarter 2015 distributions on its Class D Common Units of $0.18 per unit were paid on May 14, 2015. Distributions paid for the Class D Common Units represent a pro rata distribution for the number of days the Class D Common Units were issued and outstanding during the quarter. The Class D Common Units automatically converted into common units on a one-for-one basis on May 4, 2015.

(2)

The Partnership’s partial second quarter 2015 distributions on its Class E Common Units of $0.15 per unit were paid on August 13, 2015. Distributions paid for the Class E Common Units represent a pro rata distribution for the number of days the Class E Common Units were issued and outstanding during the quarter. The Class E Common Units automatically converted into common units on a one-for-one basis on August 3, 2015.

(3)

The Partnership’s first quarter 2014 distributions on its Class B Common Units of $0.10 per unit were paid on May 14, 2014. Distributions declared for the Class B Common Units represent a pro rata distribution for the number of days the Class B Common Units were issued and outstanding during the quarter. The Class B Common Units automatically converted into common units on a one-for-one basis on May 6, 2014.

(g) Allocation of Partnership Income

The General Partner’s share of the Partnership’s net income consists of incentive distribution rights to the extent earned, a deduction for unit-based compensation attributable to ENLC’s restricted units, the percentage interest of the Partnership’s net income adjusted for ENLC’s unit-based compensation specifically allocated to the General Partner and net income attributable to the drop down transactions described in “Note 3—Acquisitions.” The net income allocated to the General Partner is as follows (in millions):


	Year Ended December 31,
	2016		2015		2014 (1)
Income allocation for incentive distributions	$	56.8	$	47.5	$	20.6
Unit-based compensation attributable to ENLC’s restricted units		(14.7)		(18.3)		(10.4)
General Partner share of net income (loss)		(2.6)		(6.7)		1.1
General Partner interest in drop down transactions		—		35.5		127.0
General Partner interest in net income	$	39.5	$	58.0	$	138.3

(1) The year ended December 31, 2014 amounts consist only of the period from March 7, 2014 through December 31, 2014.

(9) Earnings per Unit and Dilution Computations

As required under ASC 260, Earnings Per Share, unvested share-based payments that entitle employees to receive non-forfeitable distributions are considered participating securities for earnings per unit calculations. Net income earned

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by the Predecessor prior to March 7, 2014 is not included for purposes of calculating earnings per unit as the Predecessor did not have any unitholders. Net income (loss) attributable to the VEX Interests acquired from Devon for periods prior to acquisition is not allocated for purposes of calculating net income (loss) per common unit. The following table reflects the computation of basic and diluted earnings per unit for the periods presented (in millions except per unit amounts):


	Year Ended December 31,
	2016		2015		2014 (1)
Enlink Midstream, LLC interest in net income (loss)	$	(460.0)	$	(357.0)	$	90.5
Distributed earnings allocated to:
Common units (2)	$	183.3	$	165.0	$	126.8
Unvested restricted units (2)		2.2		1.1		0.8
Total distributed earnings	$	185.5	$	166.1	$	127.6
Undistributed loss allocated to:
Common units	$	(638.0)	$	(519.5)	$	(36.9)
Unvested restricted units		(7.5)		(3.6)		(0.2)
Total undistributed loss	$	(645.5)	$	(523.1)	$	(37.1)
Net income (loss) allocated to:
Common units	$	(454.6)	$	(354.5)	$	89.9
Unvested restricted units		(5.4)		(2.5)		0.6
Total net income (loss)	$	(460.0)	$	(357.0)	$	90.5
Basic and diluted net income (loss) per unit:
Basic	$	(2.56)	$	(2.17)	$	0.55
Diluted	$	(2.56)	$	(2.17)	$	0.55

(1)

The 2014 amounts consist only of the period from March 7, 2014 through December 31, 2014.

(2)

Represents distribution activity consistent with the distribution activity table below.

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A summary of the Company’s distribution activity relating to the common units for the years ended December 31, 2016, 2015 and 2014 is provided below:


Declaration period	Distribution/unit		Date paid/payable
2016
First Quarter of 2016	$	0.255	May 12, 2016
Second Quarter of 2016	$	0.255	August 12, 2016
Third Quarter of 2016	$	0.255	November 14, 2016
Fourth Quarter of 2016	$	0.255	February 14, 2017

2015
First Quarter of 2015	$	0.245	May 15, 2015
Second Quarter of 2015	$	0.250	August 14, 2015
Third Quarter of 2015	$	0.255	November 13, 2015
Fourth Quarter of 2015	$	0.255	February 12, 2016

2014
First Quarter of 2014	$	0.180	May 15, 2014
Second Quarter of 2014	$	0.220	August 13, 2014
Third Quarter of 2014	$	0.230	November 14, 2014
Fourth Quarter of 2014	$	0.235	February 13, 2015

The following are the unit amounts used to compute the basic and diluted earnings per unit for the years ended December 31, 2016, 2015 and 2014 (in millions):


	Year Ended December 31,
	2016	2015	2014 (1)
Basic and diluted units outstanding:
Weighted average common units outstanding	179.7	164.2	164.0
Diluted weighted average units outstanding:
Weighted average basic common units outstanding	179.7	164.2	164.0
Dilutive effect of restricted units issued	—	—	0.3
Total weighted average diluted common units outstanding	179.7	164.2	164.3

(1)

The year ended December 31, 2014 amounts consist only of the period from March 7, 2014 through December 31, 2014.

All outstanding units were included in the computation of diluted earnings per unit and weighted based on the number of days such units were outstanding during the period presented. All common unit equivalents were antidilutive for the year ended December 31, 2016 and 2015 because common units were allocated a net loss.

(10) Asset Retirement Obligations

The schedule below summarizes the changes in the Partnership’s asset retirement obligations (in millions):


	Year Ended
	December 31,
	2016		2015
Beginning asset retirement obligations	$	14.0	$	20.6
Revisions to the fair values of existing liabilities		(0.5)		(4.0)
Accretion expense		0.6		0.6
Liabilities settled		(0.6)		(3.2)
Ending asset retirement obligations	$	13.5	$	14.0

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Asset retirement obligations of $13.5 million and $12.9 million were included in “Asset retirement obligations” as noncurrent liabilities on the consolidated balance sheets as of December 31, 2016 and 2015, respectively. Asset retirement obligations of $1.1 million were included in “Other current liabilities” on the consolidated balance sheet as of December 31, 2015. There were no asset retirement obligations included in “Other current liabilities” on the consolidated balance sheet as of December 31, 2016.

(11) Investments in Unconsolidated Affiliates

The Partnership’s unconsolidated investments consisted of:

a contractual right to the benefits and burdens associated with Devon’s 38.75% ownership interest in GCF at December 31, 2016, 2015 and 2014;

an approximate 31% ownership interest in HEP at December 31, 2016, 2015 and 2014; and

a 30.0% ownership in the Cedar Cove JV at December 31, 2016.

In December 2016, the Partnership entered into an agreement to sell its ownership interest in HEP for approximately $193.1 million, subject to customary closing conditions, including regulatory approvals. We expect the transaction to close in the first quarter of 2017. For the year ended December 31, 2016, we recorded an impairment of $20.1 million to reduce the carrying value of our investment to the expected sales price.

The following table shows the activity related to the Partnership’s investment in unconsolidated affiliates for the periods indicated (in millions):


	Gulf Coast		Howard Energy		Cedar Cove
	Fractionators		Partners		JV		Total
December 31, 2016
Contributions (1)	$	—	$	45.0	$	28.8	$	73.8
Distributions (2)	$	7.5	$	50.2	$	—	$	57.7
Equity in income (3)	$	3.4	$	(23.3)	$	—	$	(19.9)

December 31, 2015
Contributions	$	—	$	25.8	$	—	$	25.8
Distributions	$	14.5	$	28.2	$	—	$	42.7
Equity in income	$	13.0	$	7.4	$	—	$	20.4

December 31, 2014 (4)
Contributions	$	—	$	5.7	$	—	$	5.7
Distributions	$	11.0	$	12.7	$	—	$	23.7
Equity in income	$	17.1	$	1.8	$	—	$	18.9

(1)Contributions for the year ended December 31, 2016 include $32.7 million of contributions to HEP for preferred units through July 2016. These preferred units were redeemed during the third quarter of 2016.

(2)Distributions for the year ended December 31, 2016 include a redemption of $32.7 million of preferred units.

(3)Includes a $20.1 million impairment in our HEP investment to reduce the carrying value of our investment to the sales price that we expect to receive in the first quarter of 2017.

(4)Includes income, distributions and contributions for the period from March 7, 2014 through December 31, 2014.

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The following table shows the balances related to the Partnership’s investment in unconsolidated affiliates for the periods indicated (in millions):


	Year Ended December 31,
	2016		2015
Gulf Coast Fractionators	$	48.5	$	52.6
Howard Energy Partners (1)		193.1		221.7
Cedar Cove JV		28.8		—
Total investments in unconsolidated affiliates	$	270.4	$	274.3

(1)

Due to the expected completion of the sale of our investment in HEP in the first quarter of 2017, the HEP investment balance is classified as “Investment in unconsolidated affiliates – current” on the consolidated balance sheet as of December 31, 2016.

(12) Employee Incentive Plans

(a) Long-Term Incentive Plans

The Partnership accounts for unit-based compensation in accordance with ASC 718, Stock Compensation (“ASC 718”), which requires that compensation related to all unit-based awards, including unit options, be recognized in the consolidated financial statements. Effective April 6, 2016, the unitholders of the Partnership approved the amended and restated EnLink Midstream GP, LLC Long-Term Incentive Plan (the “GP Plan”). This Amendment and restatement to the GP Plan included an increase to the number of common units of the Partnership authorized for issuance under the GP Plan by 5,000,000 common units to an aggregate of 14,070,000 common units and other technical changes.

We and the Partnership each have similar unit-based compensation payment plans for officers and employees, which are described below. Unit-based compensation associated with the Company’s unit-based compensation plan awarded to officers and employees of the Partnership are recorded by the Partnership since the Company has no substantial or managed operating activities other than its interests in the Partnership and EnLink Oklahoma T.O. Amounts recognized in the consolidated financial statements with respect to these plans are as follows (in millions):


	Year Ended December 31,
	2016		2015		2014
Cost of unit-based compensation allocated to Predecessor general and administrative expense (1)	$	—	$	—	$	2.8
Cost of unit-based compensation charged to general and administrative expense		23.7		31.1		16.9
Cost of unit-based compensation charged to operating expense		6.6		5.0		2.7
Total amount charged to income	$	30.3	$	36.1	$	22.4
Interest of non-controlling partners in unit-based compensation	$	11.3	$	14.0	$	8.3
Amount of related income tax expense recognized in net income	$	7.1	$	8.3	$	5.3

(1)

Unit-based compensation expense was treated as a contribution by the Predecessor in the consolidated statements of changes in member’s equity for the year ended December 31, 2014.

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(b) EnLink Midstream Partners, LP’s Restricted Incentive Units

The restricted incentive units are valued at their fair value at the date of grant, which is equal to the market value of common units on such date. A summary of the restricted incentive unit activity for the year ended December 31, 2016 is provided below:


	Year Ended
	December 31, 2016
			Weighted
			Average
	Number of		Grant-Date
EnLink Midstream Partners, LP Restricted Incentive Units:	Units		Fair Value
Non-vested, beginning of period		1,253,729	$	29.59
Granted		1,149,105		10.71
Vested (1)		(316,677)		30.08
Forfeited		(61,337)		21.23
Non-vested, end of period		2,024,820	$	19.05
Aggregate intrinsic value, end of period (in millions)	$	37.3

(1)

Vested units include 91,110 units withheld for payroll taxes paid on behalf of employees.

A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) during the years ended December 31, 2016 and 2015 are provided below (in millions):


	Year Ended December 31,
EnLink Midstream Partners, LP Restricted Incentive Units:	2016		2015
Aggregate intrinsic value of units vested	$	4.1	$	7.5
Fair value of units vested	$	9.5	$	8.1

As of December 31, 2016, there was $13.9 million of unrecognized compensation cost related to Partnership non-vested restricted incentive units. That cost is expected to be recognized over a weighted-average period of 1.7 years.

In 2015 and 2016, the General Partner and our Managing Member granted performance awards under the GP Plan and the EnLink Midstream, LLC 2014 Long-Term Incentive Plan (the “2014 Plan”), respectively. The performance award agreements provide that the vesting of restricted incentive units granted thereunder is dependent on the achievement of certain total shareholder return (“TSR”) performance goals relative to the TSR achievement of a peer group of companies (the “Peer Companies”) over the applicable performance period. The performance award agreements contemplate that the Peer Companies for an individual performance award (the “Subject Award”) are the companies comprising the Alerian MLP Index for Master Limited Partnerships (“AMZ”), excluding the Partnership and the Company (collectively, “EnLink”), on the grant date for the Subject Award. The performance units will vest based on the percentile ranking of the average of the Partnership’s and our TSR achievement (“EnLink TSR”) for the applicable performance period relative to the TSR achievement of the Peer Companies.

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At the end of the vesting period, recipients receive distribution equivalents, if any, with respect to the number of performance units vested. The vesting of the Partnership’s performance units range from zero to 200% of the units granted depending on the EnLink TSR as compared to the Peer Companies on the vesting date. The fair value of each performance unit is estimated as of the date of grant using a Monte Carlo simulation with the following assumptions used for all performance unit grants made under the plan: (i) a risk-free interest rate based on United States Treasury rates as of the grant date; (ii) a volatility assumption based on the historical realized price volatility of the Partnership’s common units and the designated peer group securities; (iii) an estimated ranking of the Partnership among the designated peer group; and (iv) the distribution yield. The fair value of the performance unit on the date of grant is expensed over a vesting period of approximately three years. The following table presents a summary of the grant-date fair values of performance units granted and the related assumptions:


EnLink Midstream Partners, LP Performance Units:		Beginning TSR Price	Risk-free interest rate		Volatility factor		Distribution yield
2016
January 2016	$	14.82	1.10	%	39.71	%	12.10	%
February 2016	$	14.82	0.89	%	42.33	%	19.20	%
October 2016	$	17.71	0.91	%	44.62	%	8.80	%

2015
March 2015	$	27.68	0.99	%	33.01	%	5.66	%

The following table presents a summary of the Partnership’s performance units:


	Year Ended
	December 31, 2016
			Weighted
			Average
	Number of		Grant-Date
EnLink Midstream Partners, LP Performance Units:	Units		Fair Value
Non-Vested, beginning of period		118,126	$	35.41
Granted		293,309		11.53
Forfeited		(2,798)		36.18
Non-vested, end of period		408,637	$	11.53
Aggregate intrinsic value, end of period (in millions)	$	7.5

As of December 31, 2016, there was $4.1 million of unrecognized compensation expense that related to non-vested Partnership performance units. That cost is expected to be recognized over a weighted-average period of 1.8 years.

(d) EnLink Midstream, LLC’s Restricted Incentive Units

On February 5, 2014, the Company’s sole unitholder at the time, EnLink Midstream Manager, LLC, approved the EnLink Midstream, LLC 2014 Long-Term Incentive Plan (the “Company Plan”). The Company Plan provides for the issuance of 11,000,000 of the Company’s common units.

On March 7, 2014, effective as of the closing of the Business Combination, the Company (i) assumed the Crosstex Energy, Inc. 2009 Long-Term Incentive Plan (the “2009 Plan”) and all awards thereunder outstanding following the Business Combination and (ii) amended and restated the 2009 Plan to reflect the conversion of the awards under the 2009 Plan relating to EMI’s common stock to awards in respect of common units of the Company.

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The Company’s restricted incentive units are valued at their fair value at the date of grant which is equal to the market value of the common units on such date. A summary of the restricted incentive unit activities for the year ended December 31, 2016 is provided below:


	Year Ended
	December 31, 2016
			Weighted
			Average
	Number of		Grant-Date
EnLink Midstream, LLC Restricted Incentive Units:	Units		Fair Value
Non-vested, beginning of period		1,148,893	$	34.78
Granted		1,146,067		10.16
Vested (1)		(340,234)		36.55
Forfeited		(57,428)		22.67
Non-vested, end of period		1,897,298	$	19.96
Aggregate intrinsic value, end of period (in millions)	$	36.1

(1)

Vested units include 97,087 units withheld for payroll taxes paid on behalf of employees.

A summary of the restricted units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) during the years ended December 31, 2016 and 2015 are provided below (in millions):


	Year Ended December 31,
EnLink Midstream LLC Restricted Incentive Units:	2016		2015
Aggregate intrinsic value of units vested	$	4.1	$	9.2
Fair value of units vested	$	12.4	$	9.8

As of December 31, 2016, there was $13.6 million of unrecognized compensation costs related to our non-vested restricted incentive units for directors, officers and employees. The cost is expected to be recognized over a weighted average period of 1.6 years.

(e) EnLink Midstream, LLC’s Performance Units

In 2015 and 2016, the Company granted performance awards under the 2014 Plan discussed in section (c) above. At the end of the vesting period, recipients receive distribution equivalents, if any, with respect to the number of performance units vested. The vesting of units range from zero to 200% of the units granted depending on the EnLink TSR as compared to the TSR of the Peer Companies on the vesting date. The fair value of each performance unit is estimated as of the date of grant using a Monte Carlo simulation with the following assumptions used for all performance unit grants made under the 2014 Plan: (i) a risk-free interest rate based on United States Treasury rates as of the grant date; (ii) a volatility assumption based on the historical realized price volatility of the Company’s common units and the designated peer group securities; (iii) an estimated ranking of the Company among the designated peer group and (iv) the distribution yield. The fair value of the unit on the date of grant is expensed over a vesting period of three years. The following table presents a summary of the grant-date fair values of performance units granted and the related assumptions:


EnLink Midstream, LLC Performance Units:		Beginning TSR Price	Risk-free interest rate		Volatility factor		Distribution yield
2016
January 2016	$	15.38	1.10	%	46.02	%	8.60	%
February 2016	$	15.38	0.89	%	52.05	%	14.00	%
October 2016	$	16.75	0.91	%	52.89	%	6.10	%

2015
March 2015	$	34.24	0.99	%	33.02	%	2.98	%

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The following table presents a summary of the Company’s performance units:


	Year Ended
	December 31, 2016
			Weighted
			Average
	Number of		Grant-Date
EnLink Midstream, LLC Performance Units:	Units		Fair Value
Non-Vested, beginning of period		105,080	$	40.50
Granted		281,709		11.58
Forfeited		(2,525)		41.31
Non-vested, end of period		384,264	$	19.30
Aggregate intrinsic value, end of period (in millions)	$	7.3

As of December 31, 2016, there was $4.1 million of unrecognized compensation expense that related to the Company’s non-vested performance units. That cost is expected to be recognized over a weighted-average period of 1.8 years.

(f) Benefit Plan

The Partnership sponsors a single employer 401(k) plan whereby it matches 100% of every dollar contributed up to 8% of an employee’s salary. Contributions of $7.4 million and $7.0 million were made to the plan for the years ended December 31, 2016 and 2015, respectively.

(13) Derivatives

Interest Rate Swaps

The Partnership entered into interest rate swaps in 2016 in connection with the issuance of the 2026 Notes, in 2015 in connection with the issuance of the 2025 Notes, and in 2014 in connection with the issuance of the 2024 Notes and 2045 Notes. The Partnership had no open interest rate swap positions as of December 31, 2016.

The impact of the interest rate swaps on net income is included in other income (expense) in the consolidated statements of operations as part of interest expense, net, as follows (in millions):


	Year Ended December 31,
	2016		2015		2014
Settlement gains on derivatives	$	0.4	$	3.6	$	3.6

Commodity Swaps

The Partnership manages its exposure to fluctuation in commodity prices by hedging the impact of market fluctuations. Swaps are used to manage and hedge price and location risk related to these market exposures. Swaps are also used to manage margins on offsetting fixed-price purchase or sale commitments for physical quantities of natural gas and NGLs. The Partnership does not designate transactions as cash flow or fair value hedges for hedge accounting treatment under ASC 815. Therefore, changes in the fair value of the Partnership’s derivatives are recorded in revenue in the period incurred. In addition, the Partnership’s risk management policy does not allow the Partnership to take speculative positions with its derivative contracts.

The Partnership commonly enters into index (float-for-float) or fixed-for-float swaps in order to mitigate its cash flow exposure to fluctuations in the future prices of natural gas, NGLs and crude oil. For natural gas, index swaps are used to protect against the price exposure of daily priced gas versus first-of-month priced gas. They are also used to hedge the basis location price risk resulting from supply and markets being priced on different indices. For natural gas, NGLs, condensate and crude, fixed-for-float swaps are used to protect cash flows against price fluctuations: (1) where the Partnership receives a percentage of liquids as a fee for processing third-party gas or where the Partnership receives a portion of the proceeds of the sales of natural gas and liquids as a fee, (2) in the natural gas processing and fractionation

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components of its business and (3) where the Partnership is mitigating the price risk for product held in inventory or storage.

The components of gain (loss) on derivative activity in the consolidated statements of operations related to commodity swaps are (in millions):


	Year Ended December 31,
	2016		2015		2014 (1)
Change in fair value of derivatives	$	(20.1)	$	(7.7)	$	22.4
Realized gain (loss) on derivatives		9.0		17.1		(0.3)
Gain (loss) on derivative activity	$	(11.1)	$	9.4	$	22.1

(1)

Represents activity from the period between March 7, 2014 to December 31, 2014.

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


	Year Ended December 31,
	2016		2015
Fair value of derivative assets - current	$	1.3	$	16.8
Fair value of derivative liabilities - current		(7.6)		(2.9)
Fair value of derivative liabilities - long-term		—		(0.1)
Net fair value of derivatives	$	(6.3)	$	13.8

Assets and liabilities related to the Partnership’s derivative contracts are included in the fair value of derivative assets and liabilities and the change in fair value of these contracts are recorded at net as a gain (loss) on derivative activity in the consolidated statements of operations. The Partnership estimates the fair value of all of our derivative contracts using actively quoted prices. The total estimated fair value liability of derivative contracts of $6.3 million as of December 31, 2016 has a maturity date of less than one year.

Set forth below is the summarized notional volumes and fair value of all instruments held for price risk management purposes and related physical offsets at December 31, 2016 (in millions). The remaining term of the contracts extend no later than December 2017.


		December 31, 2016
Commodity	Instruments	Unit	Volume	Fair Value
NGL (short contracts)	Swaps	Gallons	(27.7)	$	(3.8)
NGL (long contracts)	Swaps	Gallons	8.3		0.2
Natural Gas (short contracts)	Swaps	MMBtu	(6.8)		(3.7)
Natural Gas (long contracts)	Swaps	MMBtu	3.5		1.0
Total fair value of derivatives				$	(6.3)

On all transactions where the Partnership is exposed to counterparty risk, the Partnership analyzes the counterparty’s financial condition prior to entering into an agreement, establishes limits and monitors the appropriateness of these limits on an ongoing basis. The Partnership primarily deals with two types of counterparties, financial institutions and other energy companies, when entering into financial derivatives on commodities. The Partnership has entered into Master International Swaps and Derivatives Association Agreements (“ISDAs”) that allow for netting of swap contract receivables and payables in the event of default by either party. If the Partnership’s counterparties failed to perform under existing swap contracts, the Partnership’s maximum loss of $1.3 million as of December 31, 2016 would be reduced to $0.1 million due to the offsetting of gross fair value payables against gross fair value receivables as allowed by the ISDAs.

(14) Fair Value Measurements

ASC 820, Fair Value Measurements and Disclosures (“ASC 820”), sets forth a framework for measuring fair value and required disclosures about fair value measurements of assets and liabilities. Fair value under ASC 820 is defined as the price at which an asset could be exchanged in a current transaction between knowledgeable, willing parties. A

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liability’s fair value is defined as the amount that would be paid to transfer the liability to a new obligor, not the amount that would be paid to settle the liability with the creditor. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, use of unobservable prices or inputs are used to estimate the current fair value, often using an internal valuation model. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the item being valued.

ASC 820 established a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value. These tiers include: Level 1, defined as observable inputs such as quoted prices in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions.

The Partnership’s derivative contracts primarily consist of commodity swap contracts which are not traded on a public exchange. The fair values of commodity swap contracts are determined using discounted cash flow techniques. The techniques incorporate Level 1 and Level 2 inputs for future commodity prices that are readily available in public markets or can be derived from information available in publicly quoted markets. These market inputs are utilized in the discounted cash flow calculation considering the instrument’s term, notional amount, discount rate and credit risk and are classified as Level 2 in hierarchy.

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


	Level 2
	December 31,
	2016		2015
Commodity Swaps (1)	$	(6.3)	$	13.8
Total	$	(6.3)	$	13.8

(1)

The fair value of derivative contracts included in assets or liabilities for risk management activities represents the amount at which the instruments could be exchanged in a current arms-length transaction adjusted for credit risk of the Partnership and/or the counterparty as required under ASC 820.

Fair Value of Financial Instruments

The estimated fair value of the Partnership’s financial instruments has been determined by the Partnership using available market information and valuation methodologies. Considerable judgment is required to develop the estimates of fair value; thus, the estimates provided below are not necessarily indicative of the amount the Partnership could realize upon the sale or refinancing of such financial instruments (in millions):


	December 31, 2016				December 31, 2015
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
Long-term debt	$	3,295.3	$	3,253.6	$	3,066.0	$	2,585.5
Installment Payables	$	473.2	$	476.6	$	—	$	—
Obligations under capital lease	$	6.6	$	6.1	$	16.7	$	15.6

(1)

The carrying values of long-term debt are reduced by debt issuance costs of $24.6 million and $23.8 million at December 31, 2016 and 2015, respectively. The respective fair values do not factor in debt issuance costs.

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

The Partnership had $120.0 million and $414.0 million in outstanding borrowings under its revolving credit facility as of December 31, 2016 and 2015, respectively. The Company had $27.8 million in outstanding borrowings under the credit facility as of December 31, 2016. As borrowings under these credit facilities accrue interest under floating interest rate structures, the carrying values of such indebtedness approximate fair values for the amounts outstanding under the credit facilities. As of December 31, 2016, the Partnership had total borrowings of $3.1 billion under senior unsecured

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notes maturing between 2019 and 2045 with fixed interest rates ranging from 2.7% to 7.1%. As of December 31, 2015, the Partnership had total borrowings of $2.7 billion maturing between 2019 and 2045 with fixed interest rates ranging from 2.7% to 7.1%. The fair value of all senior unsecured notes as of December 31, 2016 and 2015 was based on Level 2 inputs from third-party market quotations. The fair value of obligations under capital leases was calculated using Level 2 inputs from third-party banks.

(15) Commitments and Contingencies

(a) Leases—Lessee

The Partnership has operating leases for office space, office and field equipment.

The following table summarizes the Partnership’s remaining non-cancelable future payments under operating leases with initial or remaining non-cancelable lease terms in excess of one year (in millions):


2017	$	16.2
2018		15.4
2019		10.9
2020		8.6
2021		8.7
Thereafter		64.0
Total	$	123.8

Operating lease rental expense was approximately $59.6 million, $66.1 million and $51.4 million for the years ended December 31, 2016, 2015 and 2014, respectively.

(b) Change of Control and Severance Agreements

Certain members of the Partnership’s management are parties to severance and change of control agreements with EnLink Midstream Operating, LP, a Delaware limited partnership (the “Operating Partnership”). The severance and change in control agreements provide those individuals with severance payments in certain circumstances and prohibit such individual from, among other things, competing with the General Partner or its affiliates during his or her employment. In addition, the severance and change of control agreements prohibit subject individuals from disclosing confidential information about the General Partner or interfering with a client or customer of the General Partner or its affiliates, in each case during his or her employment and for certain periods (including indefinite periods) following the termination of such person’s employment.

The operation of pipelines, plants and other facilities for the gathering, processing, transmitting or disposing of natural gas, NGLs, crude oil, condensate, brine and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner, partner or operator of these facilities, the Partnership must comply with United States laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste management and disposal, and other environmental matters. The cost of planning, designing, constructing and operating pipelines, plants, and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of injunctions or restrictions on operation. Management believes that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on the Partnership’s results of operations, financial condition or cash flows.

As previously disclosed, a spill occurred in the Partnership’s West Virginia operations in the third quarter of 2015. In 2016, all clean-up and subsequent confirmatory sampling of the spill event were completed and analysis of the spilled

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constituents were below detectible limits. Accordingly, this matter has been completed with no material fine or penalty. Also as previously disclosed, in February 2016, a spill occurred at the Partnership’s Kill Buck Station in our Ohio operations. State and federal agencies were notified and clean-up response efforts were promptly executed, which significantly lessened the impact of the spill. The state agency determined that the clean-up recovery efforts were completed and issued to the Partnerships a “No Further Action” notice. The Partnership does not anticipate a material fine or penalty by either the state or federal agencies.

In the third quarter of 2016, in connection with the transition to our operational control of E2 Appalachian Compression, LLC in and preparation to commence operational control of E2 Ohio Compression, LLC, the Partnership discovered instances of noncompliance with air regulations and permits. This noncompliance was self-reported to the Ohio Environmental Protection Agency (“OEPA”), resulting in the issuance of notices of violations (“NOVs”). The Partnership has continued to work with OPEA and has taken appropriate measures to achieve compliance with applicable requirements, and, while the Partnership does not yet have information concerning any fine or penalty that may be assessed, it does not believe any such fine or penalty will be material to our operations. On July 29, 2016, after concluding a multi-year internal environmental compliance assessment of its Louisiana operations, the Partnership made an offer of $0.1 million in the form of a Global Settlement to the Louisiana Department of Environmental Quality (“LDEQ”) to resolve environmental noncompliance discovered or investigated during our assessment, which involved several of our Louisiana facilities. The noncompliance proposed to be covered by the Global Settlement include noncompliance that was self-reported to the LDEQ as the result of the Partnership’s assessment as well as noncompliance that was the subject of notices of potential violations and NOVs that the Partnership received from the LDEQ during the assessment time frame. The Partnership has taken the appropriate measures to resolve the instances of noncompliance, and the Partnership will continue to work with the LDEQ with respect to the proposed Global Settlement. Lastly, the Partnership will continue to work with Pipeline and Hazardous Materials Safety Administration regarding the notice of potential violation in its ORV operations. For more information refer to “Item 1. Business—Environmental Matters.”

(d) Litigation Contingencies

At times, the Partnership’s subsidiaries acquire pipeline easements and other property rights by exercising rights of eminent domain and common carrier. As a result, from time to time the Partnership (or its subsidiaries) is a party to a number of lawsuits under which a court will determine the value of pipeline easements or other property interests obtained by the Partnership’s 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, the Partnership does not expect that awards in these matters will have a material adverse impact on its consolidated results of operations, financial condition, or cash flows.

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of Appeals for the Fifth Circuit. The Partnership intends to continue vigorously defending the case. The success of the plaintiffs’ appeal as well as the Partnership’s costs and legal exposure, if any, related to the lawsuit are not currently determinable.

The Partnership owns and operates a high-pressure pipeline and underground natural gas and NGL storage reservoirs and associated facilities near Bayou Corne, Louisiana. In August 2012, a large sinkhole formed in the vicinity of this pipeline and underground storage reservoirs. The Partnership is seeking to recover its losses from responsible parties. The Partnership has sued Texas Brine Company, LLC (“Texas Brine”), the operator of a failed cavern in the area and its insurers, seeking recovery for these losses. The Partnership has also sued Occidental Chemical Company and Legacy Vulcan Corp. f/k/a Vulcan Materials Company, two Chlor-Alkali plant operators that participated in Texas Brine’s operational decisions regarding the mining of the failed cavern. The Partnership also filed a claim with its insurers, which the Partnership’s insurers denied. The Partnership disputed the denial and sued its insurers, but has agreed to stay the matter pending resolution of its claims against Texas Brine and its insurers. In August 2014, the Partnership received a partial settlement with respect to the Texas Brine claims in the amount of $6.1 million but additional claims remain outstanding. The Partnership cannot give assurance that the Partnership will be able to fully recover its losses through insurance recovery or claims against responsible parties.

In June 2014, a group of landowners in Assumption Parish, Louisiana added a subsidiary of the Partnership, EnLink Processing Services, LLC, as a defendant in a pending lawsuit they had filed against Texas Brine, Occidental Chemical Corporation, and Vulcan Materials Company relating to claims arising from the Bayou Corne sinkhole. The suit is pending in the 23rd Judicial Court, Assumption Parish, Louisiana. Although plaintiffs’ claims against the other defendants have been pending since October 2012, plaintiffs are now alleging that EnLink Processing Services, LLC’s negligence also contributed to the formation of the sinkhole. The amount of damages is unspecified. The validity of the causes of action, as well as the Partnership’s costs and legal exposure, if any, related to the lawsuit are not currently determinable. The Partnership intends to vigorously defend the case. The Partnership has also filed a claim for defense and indemnity with its insurers.

(16) Segment Information

Identification of the majority of the Company’s operating segments is based principally upon geographic regions served. The Company’s reportable segments consist of the following: natural gas gathering, processing, transmission and fractionation operations located in north Texas, south Texas and the Permian Basin in west Texas (“Texas”), the pipelines and processing plants located in Louisiana and NGL assets located in south Louisiana (“Louisiana”), natural gas gathering and processing operations located throughout Oklahoma (“Oklahoma”) and crude rail, truck, pipeline and barge facilities in west Texas, south Texas, Louisiana and Ohio River Valley (“Crude and Condensate”). Operating activity for intersegment eliminations is shown in the Corporate segment. Our sales are derived from external domestic customers.

Corporate expenses include general partnership expenses associated with managing all reportable operating segments. Corporate assets consist primarily of cash, property and equipment, including software, for general corporate support, debt financing costs, and unconsolidated affiliate investments in HEP, GCF and the Cedar Cove JV. The Company evaluates the performance of its operating segments based on operating revenues and segment profits.

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Summarized financial information for the Company’s reportable segments is shown in the following tables (in millions):


							Crude and
	Texas		Louisiana		Oklahoma		Condensate		Corporate		Totals
Year Ended December 31, 2016:
Product sales	$	237.2	$	1,632.5	$	48.5	$	1,090.7	$	—	$	3,008.9
Product sales - related parties		287.6		57.8		120.4		1.5		(333.0)		134.3
Midstream services		104.2		215.4		82.2		65.4		—		467.2
Midstream services - related parties		439.3		95.8		185.9		18.9		(86.8)		653.1
Cost of sales		(483.4)		(1,729.0)		(184.9)		(1,038.0)		419.8		(3,015.5)
Operating expenses		(168.5)		(96.6)		(52.1)		(81.3)		—		(398.5)
Loss on derivative activity		—		—		—		—		(11.1)		(11.1)
Segment profit (loss)	$	416.4	$	175.9	$	200.0	$	57.2	$	(11.1)	$	838.4
Depreciation and amortization	$	(196.9)	$	(114.8)	$	(140.6)	$	(42.4)	$	(9.2)	$	(503.9)
Impairments	$	(473.1)	$	—	$	—	$	(93.2)	$	(307.0)	$	(873.3)
Goodwill	$	232.0	$	—	$	190.3	$	—	$	1,119.9	$	1,542.2
Capital expenditures	$	217.9	$	79.1	$	295.7	$	74.3	$	9.1	$	676.1

Year Ended December 31, 2015:
Product sales	$	320.0	$	1,527.7	$	5.0	$	1,401.0	$	—	$	3,253.7
Product sales - related parties		123.3		48.5		13.0		0.8		(66.2)		119.4
Midstream services		100.2		244.1		28.3		78.4		—		451.0
Midstream services - related parties		456.7		20.0		140.7		18.0		(16.8)		618.6
Cost of sales		(412.2)		(1,567.6)		(17.9)		(1,330.6)		83.0		(3,245.3)
Operating expenses		(181.8)		(105.9)		(30.3)		(101.9)		—		(419.9)
Gain on derivative activity		—		—		—		—		9.4		9.4
Segment profit	$	406.2	$	166.8	$	138.8	$	65.7	$	9.4	$	786.9
Depreciation and amortization	$	(169.7)	$	(109.1)	$	(49.8)	$	(51.5)	$	(7.2)	$	(387.3)
Impairments	$	(496.3)	$	(787.3)	$	(0.6)	$	(279.2)	$	—	$	(1,563.4)
Goodwill	$	703.5	$	—	$	190.3	$	93.2	$	1,426.9	$	2,413.9
Capital expenditures	$	268.0	$	59.2	$	40.7	$	187.5	$	15.1	$	570.5

Year Ended December 31, 2014:
Product sales	$	216.5	$	1,612.7	$	13.1	$	317.0	$	—	$	2,159.3
Product sales - related parties		348.8		65.7		154.9		0.5		(64.3)		505.6
Midstream services		56.3		153.2		1.7		42.2		—		253.4
Midstream services - related parties		410.8		5.8		149.1		7.5		(5.8)		567.4
Cost of sales		(456.9)		(1,674.2)		(142.6)		(290.9)		70.1		(2,494.5)
Operating expenses		(146.8)		(64.9)		(28.7)		(43.2)		—		(283.6)
Gain on litigation settlement		—		6.1		—		—		—		6.1
Gain on derivative activity		—		—		—		—		22.1		22.1
Segment profit	$	428.7	$	104.4	$	147.5	$	33.1	$	22.1	$	735.8
Depreciation and amortization	$	(125.8)	$	(69.4)	$	(49.4)	$	(37.0)	$	(2.7)	$	(284.3)
Goodwill	$	1,168.2	$	786.8	$	190.3	$	112.5	$	1,426.9	$	3,684.7
Capital expenditures	$	271.0	$	273.1	$	17.1	$	183.6	$	13.9	$	758.7

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The table below represents information about segment assets as of December 31, 2016 and 2015 (in millions):


	Year Ended December 31,
Segment Identifiable Assets:	2016		2015
Texas	$	3,142.6	$	3,709.5
Louisiana		2,349.3		2,309.3
Oklahoma		2,524.5		873.4
Crude and Condensate		836.8		898.0
Corporate		1,422.7		1,751.1
Total identifiable assets	$	10,275.9	$	9,541.3

The following table reconciles the segment profits reported above to the operating income (loss) as reported in the consolidated statements of operations (in millions):


	Year Ended December 31,
	2016		2015		2014
Segment profits	$	838.4	$	786.9	$	735.8
General and administrative expenses		(122.5)		(136.9)		(97.3)
Depreciation and amortization		(503.9)		(387.3)		(284.3)
Gain (loss) on disposition of assets		(13.2)		(1.2)		0.1
Impairments		(873.3)		(1,563.4)		—
Operating income (loss)	$	(674.5)	$	(1,301.9)	$	354.3

(17) Quarterly Financial Data (Unaudited)

Summarized unaudited quarterly financial data is presented below (in millions, except per unit data):


	First		Second		Third		Fourth		Total
2016:
Revenues	$	889.7	$	1,033.2	$	1,104.6	$	1,224.9	$	4,252.4
Impairments	$	873.3	$	—	$	—	$	—	$	873.3
Operating income (loss)	$	(824.8)	$	45.2	$	65.9	$	39.2	$	(674.5)
Net income (loss) attributable to the non-controlling interest	$	(413.7)	$	0.4	$	10.4	$	(25.3)	$	(428.2)
Net income (loss) attributable to EnLink Midstream, LLC	$	(457.6)	$	0.8	$	0.7	$	(3.9)	$	(460.0)
Net income (loss) per common unit-basic	$	(2.56)	$	0.01	$	—	$	(0.02)	$	(2.56)
Net income (loss) per common unit-diluted	$	(2.56)	$	0.01	$	—	$	(0.02)	$	(2.56)

2015:
Revenues	$	940.5	$	1,274.5	$	1,170.6	$	1,066.5	$	4,452.1
Impairments	$	—	$	—	$	799.2	$	764.2	$	1,563.4
Operating income (loss)	$	50.5	$	71.4	$	(731.8)	$	(692.0)		(1,301.9)
Net income (loss) attributable to the non-controlling interest	$	8.0	$	28.4	$	(562.5)	$	(528.4)	$	(1,054.5)
Net income (loss) attributable to EnLink Midstream, LLC	$	17.0	$	16.2	$	(193.4)	$	(195.0)	$	(355.2)
Net income (loss) per common unit-basic	$	0.10	$	0.09	$	(1.18)	$	(1.18)	$	(2.17)
Net income (loss) per common unit-diluted	$	0.10	$	0.09	$	(1.18)	$	(1.18)	$	(2.17)

(18) Discontinued Operations

The Predecessor’s historical assets comprised all of Devon’s U.S. midstream assets and operations. However, only the Partnership’s assets serving the Barnett, Cana-Woodford and Arkoma-Woodford Shales, as well as contractual rights to the benefits and burdens associated with Devon’s 38.75% interest in GCF, were contributed to Midstream Holdings in

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connection with the Business Combination on March 7, 2014. All operations activity related to the non-contributed assets prior to March 7, 2014 are classified as discontinued operations.

The following schedule summarizes net income from discontinued operations (in millions):


	Year Ended December 31,
	2014
Revenues:
Revenues	$	6.8
Revenues - related parties		10.5
Total revenues		17.3

Operating costs and expenses:
Operating costs and expenses		15.7
Total operating costs and expenses		15.7

Income before income taxes		1.6
Income tax provision		(0.6)
Net income	$	1.0

(19) Supplemental Cash Flow Information

The following schedule summarizes the Partnership’s non-cash financing activities for the period presented (in millions):


	Year ended
	December 31,
	2016		2015
Non-cash financing activities:
Non-cash issuance of common units (1)	$	214.9	$	—
Non-cash issuance of common units of the Partnership (2)		—		180.0
Non-cash issuance of Class C Common Units of the Partnership (2)		—		180.0
Installment payable, net of discount of $79.1 million (3)		420.9		—

(1)

Non-cash common units were issued as partial consideration for the acquisition of EnLink Oklahoma T.O. assets. See “Note 3—Acquisitions” for further discussion.

(2)

Non-cash common units and Class C Common Units were issued by the Partnership as partial consideration for the Coronado acquisition. See “Note 3—Acquisitions” for further discussion.

(3)

The Partnership incurred installment purchase obligations, net of discount, assuming payments of $250.0 million are made on January 7, 2017 and 2018, payable to the seller in connection with the acquisition of EnLink Oklahoma T.O. assets. See “Note 3—Acquisitions” for further discussion.

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(20) Other Information

The following table presents additional detail for certain balance sheet captions.

Other Current Liabilities

Other current liabilities consisted of the following (in millions):


	Year Ended December 31,
	2016		2015
Accrued interest	$	34.2	$	23.2
Accrued wages and benefits, including taxes		19.0		27.7
Accrued ad valorem taxes		23.5		27.0
Capital expenditure accruals		64.6		22.3
Onerous performance obligations		15.9		17.0
Other		60.3		57.6
Other current liabilities	$	217.5	$	174.8

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Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

(a) Evaluation of Disclosure Controls and Procedures

We carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer of EnLink Midstream GP, LLC, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report pursuant to Exchange Act Rules 13a-15 and 15d-15. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of the period covered by this report (December 31, 2016), our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported, within the time period specified in the applicable rules and forms, and that such information is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding disclosure.

(b) Changes in Internal Control Over Financial Reporting

There has been no change in our internal control over financial reporting that occurred in the three months ended December 31, 2016 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Internal Control Over Financial Reporting

See “Item 8. Financial Statements and Supplementary Data—Management’s Report on Internal Control over Financial Reporting.”

Item 9B. Other Information

None.

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PART III

Item 10. Directors, Executive Officers and Corporate Governance

The following table shows information for the members of the board of directors (the “Board”) of EnLink Midstream Manager, LLC, our managing member (the “Managing Member”). Executive officers and directors serve until their successors are duly appointed or elected.


Name	Age	Position with the Managing Member
Barry E. Davis	55	Chief Executive Officer and Chairman of the Board
Michael J. Garberding	48	President and Chief Financial Officer
Steve J. Hoppe	54	Executive Vice President and President of Gas Gathering, Processing and Transmission
McMillan (Mac) Hummel	54	Executive Vice President and President of Natural Gas Liquids and Crude
Alaina Brooks	42	Senior Vice President, General Counsel and Secretary
Benjamin D. Lamb	37	Executive Vice President, Corporate Development
Mary P. Ricciardello (2)	61	Director and Member of the Audit Committee
James C. Crain (2)	68	Director and Member of the Audit and Conflicts (1) Committees
Leldon E. Echols (2)	61	Director and Member of the Audit Committee (1)
Rolf A. Gafvert (2)	63	Director and Member of the Conflicts and Governance and Compensation (1) Committees
David A. Hager	60	Director and Member of the Governance and Compensation Committee
Sue Alberti	59	Director
Thomas L. Mitchell	56	Director
Lyndon Taylor	57	Director

(1)Chairman of committee.

(2)Independent director.

Barry E. Davis, Chief Executive Officer and Chairman of the Board, led the management buyout of the midstream assets of Comstock Natural Gas, Inc. in December 1996, which transaction resulted in the formation of the Partnership’s predecessor. Mr. Davis has served as director since the Partnership’s initial public offering in December 2002. Mr. Davis was President and Chief Operating Officer of Comstock Natural Gas and founder of Ventana Natural Gas, a gas marketing and pipeline company that was purchased by Comstock Natural Gas. Mr. Davis started Ventana Natural Gas in June 1992. Prior to starting Ventana, he was Vice President of Marketing and Project Development for Endevco, Inc. Before joining Endevco, Mr. Davis was employed by Enserch Exploration in the marketing group. Mr. Davis holds a B.B.A. in Finance from Texas Christian University. Mr. Davis also serves as a director for EnLink Midstream, LLC. Mr. Davis’s leadership skills and experience in the midstream natural gas industry, among other factors, led the Board to conclude that he should serve as Chairman of the Board.

Michael J. Garberding, President and Chief Financial Officer, joined the Managing Member in March 2014 and the General Partner in February 2008. Mr. Garberding assumed his current role in September 2016, having previously served as Senior Vice President and Chief Financial Officer, and Executive Vice President and Chief Financial Officer. Mr. Garberding previously led the finance and business development organization for the Partnership. Mr. Garberding has more than 25 years of experience in finance and accounting. From 2002 to 2008, Mr. Garberding held various finance and business development positions at TXU Corporation, including assistant treasurer. In addition, Mr. Garberding worked at Enron North America as a Finance Manager and Arthur Andersen LLP as an Audit Manager. He received his Masters in Business Administration from the University of Michigan in 1999 and his B.B.A. in Accounting from Texas A&M University in 1991.

Steve J. Hoppe, Executive Vice President and President of Gas Gathering, Processing and Transmission, joined the Managing Member and the General Partner in March 2014. Previously, Mr. Hoppe served as Senior Vice President of Midstream Operations for Devon, which he joined in 2007. Mr. Hoppe has more than 25 years of midstream energy-industry experience, including eight years at Thunder Creek Gas Services, where he most recently served as President. Mr. Hoppe holds a Bachelor of Science degree in civil engineering from the University of Wyoming.

McMillan (Mac) Hummel, Executive Vice President and President of Natural Gas Liquids and Crude, joined the Managing Member and the General Partner in March 2014. Previously, Mr. Hummel served in various positions with

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The Williams Companies, which he joined in 1985, including Vice President of Commodity Services, Vice President of Natural Gas Liquids and Petchem Services and Vice President of Western Region Gathering and Processing. Mr. Hummel began his career with Williams’ Northwest Pipeline while living in Salt Lake City, Utah. Mr. Hummel also served as Director of Business Development for Williams while living in Calgary, Alberta. Mr. Hummel has been a member of the American Fuel & Petrochemical Manufacturers Petrochemical Committee, the Association of Oil Pipe Lines Pipeline Subcommittee and the board of Aux Sable Liquids Partners. Mr. Hummel earned a Bachelor of Science degree in accounting and a Masters of Business Administration from the University of Utah.

Alaina K. Brooks, Senior Vice President, General Counsel and Secretary, joined the Managing Member in March 2014 and the General Partner in 2008. Ms. Brooks has served in several legal roles within EnLink Midstream, most recently as Deputy General Counsel before assuming the role of Senior Vice President, General Counsel and Secretary in September 2014. In Ms. Brooks’ current role, she serves on EnLink Midstream’s Senior Leadership Team and leads the legal and regulatory functions. Before joining the General Partner in 2008, Ms. Brooks practiced law at Weil, Gotshal & Manges LLP and Baker Botts LLP, where she counseled clients on matters of complex commercial litigation, risk management and taxation. Ms. Brooks is a licensed Certified Public Accountant and holds a Juris Doctor degree from Duke University School of Law and Bachelor of Science and Master of Science degrees in accounting from Oklahoma State University.

Benjamin D. Lamb, Executive Vice President, Corporate Development, joined the Managing Member in March 2014 and the General Partner in December 2012. Mr. Lamb assumed his current role in September 2016, having previously served as Vice President – Finance, and Senior Vice President, Finance and Corporate Development. Prior to joining the General Partner, Mr. Lamb served as a Principal at the investment banking firm Greenhill & Co., which he joined in 2005. In that role he focused on the evaluation and execution of mergers, acquisitions and restructuring transactions for clients primarily in the midstream energy, power and utility industries. Prior to joining Greenhill he served as an investment banker at UBS Investment Bank in its Mergers and Acquisitions Group and in its Global Energy Group, and at Merrill Lynch in its Global Energy and Power Group. Mr. Lamb received his Bachelor of Business Administration degree from Baylor University in 2000.

Mary P. Ricciardello was Senior Vice President and Chief Accounting Officer at Reliant Energy Inc., a leading independent power producer and marketer until 2002. She began her career with Reliant in 1982 and served in various financial management positions with the company including Comptroller, Senior Vice President and Chief Accounting Officer. Ms. Ricciardello has served as a director of the Managing Member and the General Partner since March 2014. Ms. Ricciardello also serves as a director on the boards of Devon and Noble Corporation and has served as a director on the Board of Midstates until March 2015. Ms. Ricciardello is also a NACD Board Leadership Fellow. Ms. Ricciardello holds a Bachelor of Science degree in Business Administration from the University of South Dakota and a Master’s in Business Administration with an emphasis in Finance from the University of Houston. She is a licensed Certified Public Accountant. Ms. Ricciardello was selected to serve as a director due to her qualifications as a financial expert and her extensive experience in the energy industry, as well as corporate finance and tax matters.

James C. Crain joined Crosstex Energy, Inc. as a director in July 2006 and has served as a director of the Managing Member since March 7, 2014. Mr. Crain retired as president of Marsh Operating Company in July 2013, where he worked since 1984 and currently serves as an advisor to Marsh Operating Company and is a private investor. Prior to Marsh, he was a partner at the law firm of Jenkens & Gilchrist. Mr. Crain also serves on the board of Approach Resources, Inc. Mr. Crain served as a director of the General Partner from December 2005 to August 2008. He graduated from the University of Texas at Austin with a B.B.A. degree, a master of professional accounting and a doctor of jurisprudence. Mr. Crain was selected to serve as a director due to his legal background and his experience in the oil and natural gas industry, among other factors.

Leldon E. Echols joined Crosstex Energy, Inc. as a director in January 2008. Mr. Echols is a private investor. Mr. Echols also currently serves as an independent director of the managing member of EnLink Midstream, Trinity Industries, Inc. and HollyFrontier Corporation, an independent petroleum refiner and marketer. Mr. Echols brings 30 years of financial and business experience to EnLink Midstream. After 22 years with the accounting firm Arthur Andersen LLP, which included serving as managing partner of the firm’s audit and business advisory practice in North Texas, Colorado and Oklahoma, Mr. Echols spent six years with Centex Corporation as executive vice president and chief financial officer. He retired from Centex Corporation in June 2006. Mr. Echols previously served as a member of the board of directors of Roofing Supply Group Holdings, Inc., a private company. He also served on the board of TXU Corporation where he chaired the Audit Committee and was a member of the Strategic Transactions Committee until the

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completion of the private equity buyout of TXU in October 2007. Mr. Echols earned a Bachelor of Science degree in accounting from Arkansas State University. He is a member of the American Institute of Certified Public Accountants and the Texas Society of CPAs. Mr. Echols served as a director of Crosstex Energy Inc. from January 2008 until the Mergers. Mr. Echols was selected to serve as a director due to his accounting and financial experience and service as the chief financial officer for another public company, among other factors.

Rolf A. Gafvert was President, CEO and director of Boardwalk GP, LLP, the general partner of Boardwalk Pipeline Partners, LP from 2007 to 2011. Prior to that, Mr. Gafvert served as Co-President of Boardwalk GP, LLC from 2005 to 2007. Mr. Gafvert served as President of Gulf South Pipeline, which became affiliated with Boardwalk Pipeline Partners, LP in 2005, from 2000 to 2011. Mr. Gafvert was involved in Gulf South and its affiliates from 1993 to 2000, including acting as Managing Director of Koch Energy International, VP of Corporate Development for Koch Energy, Inc. and President of Gulf South. Mr. Gafvert has served as a director of the Managing Member since March 7, 2014. He holds a Master’s degree in Agricultural Economics and a Bachelor of Science degree in Psychology from Iowa State University. Mr. Gafvert was selected to serve as a director due to his knowledge of the energy business and his business expertise, among other factors.

David A. Hager has served as the President and Chief Executive officer of Devon since August 1, 2015. Prior to that, Mr. Hager served as Chief Operating Officer of Devon since June 2013. He joined Devon in 2009 as Executive Vice President of Exploration and Production. Prior to Devon, Mr. Hager held several positions within Kerr-McGee Corp, most recently as Chief Operating Officer in the period just before its merger with Anadarko Petroleum. Mr. Hager was a Director and Chairman of the Reserves Committee on Devon’s Board from 2007 until 2009 and has served as a director for Pride International, Inc. Mr. Hager has served as a director of the Managing Member and the General Partner since completion of the Business Combination on March 7, 2014. He holds a Bachelor of Science degree in Geophysics from Purdue University and a Master’s in Business Administration degree from Southern Methodist University. Mr. Hager was selected to serve as a director due to his affiliation with Devon, his knowledge of the energy business and his business expertise.

Sue Alberti, has been Senior Vice President of Marketing, Supply Chain and Strategic Planning for Devon since September 2016. She previously served as Vice President Compensation and Benefits. Ms. Alberti has been with Devon since 2008. Prior to joining Devon, Ms. Alberti worked at Texas Instruments for seven years, most recently serving as Vice President of worldwide compensation, benefits and human resources mergers and acquisitions. Ms. Alberti holds a bachelor’s degree in chemical engineering from the University of Michigan and a master's in business administration and finance from the University of Chicago.

Thomas L. Mitchell has over 30 years of experience in the oil and gas industry and joined Devon as Executive Vice President and Chief Financial Officer in February 2014. Prior to Devon, Mr. Mitchell served on the board of directors and as the Executive Vice President and Chief Financial Officer of Midstates Petroleum Company throughout its initial public offering process. Prior to that, Mr. Mitchell served as Senior Vice President and Chief Financial Officer of Noble Corporation and spent 18 years with Apache Corporation in various financial and commercial roles. Mr. Mitchell has served as a director of the Managing Member and the General Partner since completion of the Business Combination on March 7, 2014. He also is a director on the Board of Hines Global REIT, Inc., a public real estate investment trust managed by Hines Interests, and holds a Bachelor of Science degree in Accounting from Bob Jones University. Mr Mitchell is an inactive Certified Public Accountant. Mr. Mitchell was selected to serve as a director due to his affiliation with Devon, his knowledge of the energy business and his financial and business expertise.

Lyndon Taylor was elected to the position of Executive Vice President and general counsel of Devon in February 2007. Mr. Taylor had served as Devon's deputy general counsel since August 2005. Prior to joining Devon, Mr. Taylor was with Skadden, Arps, Slate, Meagher & Flom, LLP for 20 years and served as managing partner of the firm's Houston office from 1993 to 2005. He is admitted to practice law in Oklahoma and Texas. Mr. Taylor received his Bachelor of Science degree in industrial engineering from Oklahoma State University and his law degree from the University of Oklahoma.

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“Independent” Directors

Because we are a “controlled company” within the meaning of the NYSE rules, the NYSE does not require the Board to be composed of a majority of directors who meet the criteria for independence required by the NYSE or to maintain nominating/corporate governance and compensation committees composed entirely of independent directors. Our Board has adopted Governance Guidelines that require at least three members of our Board to be independent directors as defined by the rules of the NYSE.

For a director to be “independent” under the NYSE standards, the Board must affirmatively determine that the director has no material relationship with the Company (either directly or as a partner, shareholder or officer of any organization that has a relationship with the Company, other than in his or her capacity as a director of the Company). In addition, the director must meet certain independence standards specified by the NYSE, including a requirement that the director was not employed by the Managing Member or engaged in certain business dealings with the Managing Member. Using these standards for determining independence, the Board has determined that Messrs. Crain, Echols, Gafvert and Ms. Ricciardello qualify as “independent” directors.

In addition, the members of the Audit Committee of our Board each qualify as “independent” under special standards established by the Securities and Exchange Commission (“SEC”) for members of audit committees, and the Audit Committee includes at least one member who is determined by our Board to meet the qualifications of an “audit committee financial expert” in accordance with SEC rules, including that the person meets the relevant definition of an “independent” director. Mr. Echols and Ms. Ricciardello are both independent directors who have been determined to be audit committee financial experts. Unitholders should understand that this designation is a disclosure requirement of the SEC related to their experience and understanding with respect to certain accounting and auditing matters. The designation does not impose on such directors any duties, obligations or liabilities that are greater than are generally imposed on them as members of the Audit Committee and the Board, and the designation of a director as audit committee financial experts pursuant to this SEC requirement does not affect the duties, obligations or liabilities of any other member of the Audit Committee or the Board. Additionally, the Board has determined that the simultaneous service by Mr. Echols and Ms. Ricciardello on the Audit Committees of three other publicly traded companies on which they serve does not impair their ability to effectively serve on the Audit Committee of the Company.

Board Committees

The Board established three standing committees in March 2014: the Audit Committee, the Conflicts Committee and Governance and Compensation Committee. Each member of the Audit Committee is an independent director in accordance with the NYSE standards described above. Each of the Board committees has a written charter approved by the Board. Copies of the charters and our Code of Business Conduct and Ethics are available to any person, free of charge, at our website: www.enlink.com.

The Audit Committee comprised of Mr. Echols (chair), Mr. Crain and Ms. Ricciardello assists the Board in its general oversight of our financial reporting, internal controls and audit functions, and is directly responsible for the appointment, retention, compensation and oversight of the work of our independent auditors.

The Conflicts Committee comprised of Messrs. Crain (chair) and Gafvert reviews specific matters that the Board believes may involve conflicts of interest. The Conflicts Committee determines if the resolution of a conflict of interest is fair and reasonable to us. The members of the Conflicts Committee are not directors, officers or employees of EnLink Midstream GP, LLC. Any matters approved by the Conflicts Committee will be conclusively deemed to be fair and reasonable to us, approved by all of our unitholders and not a breach by our Managing Member of any duties owed to us or our unitholders.

The Governance and Compensation Committee is comprised of Messrs. Gafvert (chair) and Hager. The Governance and Compensation Committee reviews matters involving governance, including assessing the effectiveness of current policies, monitoring industry developments, and oversees certain compensation decisions as well as the compensation plans described herein.

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Board Meetings and Attendance

Our Board met seven times in 2016. All incumbent directors attended in excess of 95% of the total number of meetings of our Board and committees of our Board on which they served.

The non-management directors meet in executive session without management participation at least quarterly. Unitholders or interested parties may communicate with non-management directors by sending written communications to the following address, to the attention of the Chairman of the Board, who presides at the executive sessions of the non-management directors of the Board: EnLink Midstream, LLC, 2501 Cedar Springs Rd., Suite 100, Dallas, Texas 75201.

Code of Ethics and Governance Guidelines

We adopted a Code of Business Conduct and Ethics (the “Code of Ethics”) applicable to all of our employees, officers, and directors, with regard to company-related activities. The Code of Ethics incorporates guidelines designed to deter wrongdoing and to promote honest and ethical conduct and compliance with applicable laws and regulations. It also incorporates our expectations of our employees that enable us to provide accurate and timely disclosure in our filings with the SEC and other public communications. A copy of the Code of Ethics and the Governance Guidance are available to any person, free of charge, within the “Governance Documents” subsection of the “Corporate Governance” section of the investors section of our website at www.enlink.com If any substantive amendments are made to the Code of Ethics or if we grant any waiver, including any implicit waiver, from a provision of the Code of Ethics to any of our executive officers and directors, we will disclose the nature of such amendment or waiver on our website. The information contained on, or connected to, our website is not incorporated by reference into this annual report on Form 10-K and should not be considered part of this or any other report that we file with or furnish to the SEC.

Section 16(a)—Beneficial Ownership Reporting Compliance

Section 16(a) of the Securities Exchange Act of 1934 requires our directors, executive officers and 10% unitholders to file with the SEC reports of ownership and changes in ownership of our equity securities. Based solely upon a review of the copies of the Forms 3, 4 and 5 reports furnished to us and written representations from our directors and executive officers, except as set forth below, we believe that during 2016, all of our directors, executive officers and beneficial owners of more than 10% of our common units complied with Section 16(a) filing requirements applicable to them, other than a Form 3 for Susan Alberti, which was filed one day late due to administrative issues on July 6, 2016.

Item 11. Executive Compensation

Governance and Compensation Committee Report

Each member of the Governance and Compensation Committee is an independent director in accordance with NYSE standards. The Governance and Compensation Committee has reviewed and discussed with management the following section titled “Compensation Discussion and Analysis.” Based upon its review and discussions, the Governance and Compensation Committee has recommended to the Board that the Compensation Discussion and Analysis be included in this Annual Report on Form 10-K.

By the Members of the Compensation Committee:

Rolf Gafvert (Chair)

David A. Hager

Compensation Discussion and Analysis

The following Compensation Discussion and Analysis contains statements regarding our compensation programs and our executive officers’ business priorities related to our compensation programs and target payouts under the programs. These business priorities are disclosed in the limited context of our compensation programs and should not be understood to be statements of management’s expectations or estimates of results or other guidance.

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Overview

We do not directly employ any of the persons responsible for managing our business. The Managing Member manages our operations and activities, and its Board and officers make decisions on our behalf. The compensation of the executive officers and directors of the Managing Member is determined by the Board upon the recommendation of its Governance and Compensation Committee. Our named executive officers also serve as named executive officers of EnLink Midstream GP, LLC, our indirect wholly-owned subsidiary and the general partner of the Partnership; therefore, the compensation of our named executive officers reflects total compensation for services to all EnLink entities during the year ended December 31, 2016. We pay or reimburse all expenses incurred on our behalf, including the costs of employee, officer and director compensation and benefits, as well as all other expenses necessary or appropriate to the conduct of our business. We currently pay a monthly fee to the General Partner to cover our portion of administrative and compensation costs, including compensation costs relating to the named executive officers.

Based on the information that we track regarding the amount of time spent by each of our named executive officers on business matters relating to EnLink Midstream, LLC, we estimate that such officers devoted the following percentage of their time to the business of EnLink Midstream Partners, LP, and to EnLink Midstream, LLC, respectively, for 2016:


	Percentage of Time		Percentage of Time
	Devoted to		Devoted to
	Business of		Business of
	EnLink Midstream		EnLink Midstream,
Executive Officer or Director	Partners, LP		LLC
Barry E. Davis	80	%	20	%
Michael Garberding	60	%	40	%
Steve J. Hoppe	90	%	10	%
Mac Hummel	90	%	10	%
Benjamin D. Lamb	90	%	10	%

Compensation Philosophy and Principles

Our executive compensation is designed to attract, retain and motivate top-tier executives and align their individual interests with the interests of our unitholders. It is the Governance and Compensation Committee’s responsibility to design and administer compensation programs that achieve these goals, and to make recommendations to the Board to approve and adopt these programs. The compensation of each of our executives is primarily comprised of base salary, bonus opportunity and equity-based awards under our long-term incentive plans. The Governance and Compensation Committee’s philosophy is to generally target the 50th percentile of our Peer Group (discussed below) for base salaries and bonuses (but retain discretion to reduce or increase bonus amounts to address individual performance) and to provide executives the opportunity to earn long-term incentive compensation, in the form of equity, targeted at the 75th percentile our Peer Group.

The Governance and Compensation Committee considers the following principles in determining the total compensation of the named executive officers:

the total compensation program, including base salary and bonus opportunities, should be competitive with the market in which we compete for executive talent in order to attract, retain and motivate highly qualified executive officers;

equity-based incentive compensation should represent a significant portion of the executive’s total compensation in order to retain and incentivize highly qualified executives and align their individual long-term interests with the interests of unitholders;

compensation programs should be sufficiently flexible to address special circumstances, which include payments under retention plans specifically targeted to retain highly qualified executives during challenging times; and

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the overall compensation program should drive performance and reward contributions in support of our business strategies and achievements.

Compensation Methodology

Annually, the Governance and Compensation Committee reviews our executive compensation program in total and each element of compensation specifically. The review includes an analysis of the compensation practices of other companies in our industry, the competitive market for executive talent, the evolving demands of the business, specific challenges that we may face and individual contributions to us and the Managing Member. The Governance and Compensation Committee recommends to the Board adjustments to the overall compensation program and to its individual components as the Governance and Compensation Committee determines necessary to achieve our goals. The Governance and Compensation Committee periodically retains consultants to assist in its review and to provide input regarding the compensation program and each of its elements.

Role of Compensation Consultant

The Governance and Compensation Committee has retained Meridian Compensation Partners, LLC (“Meridian”) as its independent compensation consultant to conduct a compensation review and advise the Governance and Compensation Committee on certain matters relating to compensation programs applicable to the named executive officers and other employees of the General Partner. In particular, Meridian has assisted the Governance and Compensation Committee’s decision making with respect to executive officer and director compensation matters, including providing advice on our executive pay philosophy, compensation peer group, incentive plan design and employment agreement design, providing competitive market studies and apprising the Governance and Compensation Committee about emerging best practices and changes in the regulatory and governance environment. Meridian provided information to the Governance and Compensation Committee regarding the compensation programs of the EnLink entities for 2016. Meridian’s work for the Governance and Compensation Committee did not raise any conflicts of interest in 2016.

Role of Peer Group and Benchmarking

For 2016, the Governance and Compensation Committee and Meridian collaborated to identify the following companies as our peer companies: Boardwalk Partners, L.P., Buckeye Partners, L.P., Enable Midstream Partners, LP, Enbridge Energy Partners, L.P., Genesis Energy, L.P., HollyFrontier Corp., Magellan Midstream Partners, L.P., ONEOK Partners, L.P., Pembina Pipeline Corp., Plains All American Pipeline, L.P., Spectra Energy Corp., Sunoco Logistics Partners, L.P., Targa Resource Partners, L.P. and Western Gas Partners, L.P. (the “Peer Group”). We believe that this group of companies is representative of the industry in which we operate. The individual companies were chosen based on a number of factors, including each company’s, relative size/market capitalization, relative complexity of its business, similar organizational structure, competition for similar executive talent and the roles and responsibilities of its named executive officers. The Governance and Compensation Committee considers the Peer Group companies annually, but historically there have been few changes from year to year. Companies are typically added or removed from the Peer Group as the result of a change in organizational structure or relative size/market capitalization as compared to us.

When evaluating annual compensation levels for each named executive officer, the Governance and Compensation Committee, with the assistance of Meridian, reviews publicly available compensation data for executives in our Peer Group, including data on base salaries, annual cash bonuses, and long-term equity incentive awards, as well as compensation surveys. The Governance and Compensation Committee then uses that information to help set compensation levels and compensation program elements for the named executive officers in the context of their roles, levels of responsibility, accountability and decision-making authority within our organization and in the context of company size relative to the other Peer Group members. In addition, Meridian has provided guidance on current industry trends and best practices to the Governance and Compensation Committee relating to all aspects of executive compensation, bonus structure and bonus methodology.

While compensation data from the Peer Group is considered, the Governance and Compensation Committee does not attempt to set compensation components to meet specific benchmarks. The Peer Group data that is reviewed by the Governance and Compensation Committee is simply one factor out of many that is used in connection with the establishment of compensation opportunities for our named executive officers. The other factors considered include, but are not limited to, (i) available compensation data, rankings and comparisons, (ii) effort and accomplishment on a group

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and individual basis, (iii) challenges faced and challenges overcome, (iv) unique skills, (v) contribution to the management team, (vi) succession planning and retention of our executive officers and (vii) the perception of both the Board and the Governance and Compensation Committee of our performance relative to expectations and actual market/business conditions. All of these factors, including Peer Group data and analysis, are utilized in a subjective assessment of each year’s decisions relating to base salary, annual cash bonus, and long-term equity incentive award decisions.

Elements of Compensation

For fiscal year 2016, the principal elements of compensation for the named executive officers were the following:

base salary;

annual bonus awards;

long-term incentive plan awards;

retirement and health benefits; and

severance and change of control benefits.

The Governance and Compensation Committee reviews and makes recommendations regarding the mix of compensation, both among short- and long-term compensation and cash and non-cash compensation, to establish structures that it believes are appropriate for each of the named executive officers. We believe that the mix of base salary, annual bonus awards, awards under the long-term incentive plan, retirement and health benefits, severance and change of control benefits and perquisites and other compensation fit our overall compensation objectives. We believe this mix of compensation provides competitive compensation opportunities to align and drive employee performance in support of our business strategies and to attract, motivate and retain high quality talent with the skills and competencies that we require.

Base Salary. The Governance and Compensation Committee recommends base salaries for the named executive officers based on the historical salaries for services rendered to us and our affiliates, market data provided by Meridian and from compensation surveys and responsibilities of the named executive officers. Base salaries are generally determined by considering the employee’s performance and prevailing levels of compensation in areas in which a particular employee works. The base salaries paid to our named executive officers for fiscal year 2016 (and payable for fiscal 2017) are as follows:


			Base Salary
			Effective		Percent
	Prior Salary		For 2017 (1)		Increase
Barry E. Davis	$	660,000	$	695,000	5.3	%
Michael J. Garberding		450,000		500,000	11.1	%
Steve J. Hoppe		390,000		420,000	7.7	%
Mac Hummel		390,000		420,000	7.7	%
Benjamin D. Lamb		310,000		345,000	11.3	%

(1)

In association with a promotion effective September 22, 2016, Michael Garberding’s and Benjamin Lamb’s base salaries were increased to $500,000 and $345,000, respectively. All other base salary increases were effective as of January 1, 2017.

Bonus Awards. All employees, including our named executive officers, are eligible to receive annual bonuses under the short-term incentive program (the “STI Program”). The Governance and Compensation Committee and the Board oversee the STI Program. Under the STI Program, bonuses are awarded to employees based on an approach that utilizes certain metrics to measure success and are subject to the discretion of the Governance and Compensation Committee and the Board. The named executive officers are designated as corporate officers, gas business unit officers or liquids business unit officers for purposes of the STI Program. The metrics employed by the STI Program vary depending on the applicable officer’s business unit designation. The STI Program contemplates that (i) named executive officers designated as corporate officers will be eligible for bonuses based on the overall Company’s achievement level of EBITDA (see “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Measures” for definition) and certain safety metrics, (ii) named executive officers designated as gas business unit officers will be eligible for bonuses based on a weighted average of (x) our achievement of EBITDA and safety metrics and (y) our gas business unit’s achievement of net operating income (“NOI”) and safety metrics and (iii) named

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executive officers designated as liquids business unit officers will be eligible for bonuses based on a weighted average of (A) our achievement of EBITDA and safety metrics and (B) our liquids business unit’s achievement of NOI and safety metrics. The Governance and Compensation Committee recommends and the Board sets annual weightings used in the foregoing bonus calculations applicable to gas business unit and liquids business unit officers.

In addition, the Governance and Compensation Committee and the Board, with input from management, will set annual EBITDA and NOI threshold, target and maximum goals based on a number of considerations, including reasonable market expectations, internal company forecasts, available investment opportunities and company performance. Such goals will vary from year to year. The Governance and Committee and the Board, with input from management, will also set annual safety index score threshold, target and maximum goals for each of corporate, gas business unit and liquids business unit. The safety goals will vary from year to year and will vary among each of corporate, gas business unit and liquids business unit. The safety index score is developed based on four categories: (i) safety statistics, including certain incident rates; (ii) leading indicators, such as safety meeting and training attendance; (iii) knowledge and development, which is based on standard assessments; and (iv) safety programs, including completed facility assessments and implementation of environmental, health and safety standards. Management of each of the gas business unit and the liquids business unit will participate in setting specific goals within the foregoing categories to ensure that the safety program influences and incents desired outcomes.

The Board, based on recommendations of the Governance and Compensation Committee, will determine final bonus amounts under the STI Program for the named executive officers. The Governance and Compensation Committee believes that a portion of executive compensation must remain discretionary and subject to the discretion of the Governance and Compensation Committee and the Board with respect to bonus awards payable to its named executive officers. Therefore, the STI Program contemplates that the Governance and Compensation Committee and the Board retain discretion with respect to bonus awards payable to named executive officers. The Governance and Compensation Committee may exercise its discretion to reduce or supplement the amount of the bonus for a particular named executive officer to reward or address extraordinary individual performance, challenges and opportunities not reasonably foreseeable at the beginning of a performance period, internal equities, and external competition or opportunities.

The final amount of bonus for each named executive officer was approved by the Board, based upon the Governance and Compensation Committee’s recommendation and assessment of whether such officer met his or her performance objectives established at the beginning of the performance period. These performance objectives included the quality of leadership within the named executive officer’s assigned area of responsibility, the achievement of technical and professional proficiencies by the named executive officer, the execution of identified priority objectives by the named executive officer and the named executive officer’s contribution to, and enhancement of, the desired company culture. These performance objectives were reviewed and evaluated by the Governance and Compensation Committee as a whole. All of our named executive officers met or exceeded their minimum personal performance objectives for 2016. Accordingly, the Governance and Compensation Committee and the Board awarded bonuses to the named executive officers as follows:


	Target Bonus
	Percentage (as		2016 Bonus (as
	a % of Base		a % of Base		2016 Bonus
	Salary)		Salary)		Amount
Barry E. Davis	125	%	99	%	650,000
Michael J. Garberding	90	%	83	%	416,000
Steve J. Hoppe	90	%	72	%	280,000
Mac Hummel	90	%	58	%	225,000
Benjamin D. Lamb (1)	90	%	72	%	250,000

(1)

In association with a promotion effective September 22, 2016, Benjamin Lamb’s target bonus percentage increased from 60% to 90%.

Target adjusted EBITDA was based upon a standard of reasonable market expectations and company performance, and varies from year to year. Several factors are reviewed in determining target adjusted EBITDA, including market expectations, internal forecasts and available investment opportunities. For 2016, our adjusted EBITDA levels for bonuses were $770.0 million for minimum bonuses, $806.0 million for target bonuses and $844.0 million for maximum bonuses. For 2016, the STI Program provided for named executive officers to receive bonus payouts of 45% to 62.5% of base salary at the minimum threshold, 90% to 125% of base salary at the target level and 180% to 250% of base salary at the maximum level.

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Long-Term Incentive Plans. We believe that equity awards are instrumental in attracting, retaining and motivating employees, and that they align the interests of the Managing Member’s officers and directors with the interests of our unitholders. Accordingly, such directors and officers are eligible to participate in the EnLink Midstream, LLC 2014 Long-Term Incentive Plan (the “2014 Plan”). Finally, certain directors, officers and employees participate, to the extent consistent with terms and agreed in connection with the Business Combination, in the EnLink Midstream, LLC 2009 Long-Term Incentive Plan (the “2009 Plan”). In addition, the Managing Member’s officers and directors also are eligible to participate in the EnLink Midstream GP, LLC Long-Term Incentive Plan (the “GP Plan”).

The Board, at the recommendation of the Governance and Compensation Committee, approves the grants of awards to our named executive officers. The Governance and Compensation Committee believes that equity compensation should comprise a significant portion of a named executive officer’s compensation, and considers a number of factors when determining the grants to each individual. The factors considered include: the general goal of allowing the named executive officer the opportunity to earn aggregate equity compensation (comprised of our units and Partnership units) targeted at the 75th percentile of our Peer Group; the amount of unvested equity held by the individual named executive officer; the named executive officer’s performance; and other factors as determined by the Governance and Compensation Committee.

A discussion of each plan follows:

EnLink Midstream, LLC 2014 Long-Term Incentive Plan . Employees, non-employee directors and other individuals who provide services to us or our affiliates may be eligible to receive awards under the 2014 Plan; however, the Governance and Compensation Committee of the board of directors of the Managing Manager determines which eligible individuals receive awards under the 2014 Plan, subject to the Board’s approval of awards of our named executive officers. The 2014 Plan is administered by the Governance and Compensation Committee and permits the grant of cash and equity-based awards, which may be awarded in the form of options, restricted unit awards, restricted incentive units, unit appreciation rights (“UARs”), distribution equivalent rights (“DERs”), unit awards, cash awards and performance awards. At the time of adoption of the 2014 Plan, 11,000,000 common units representing limited liability company interests in us were initially reserved for issuance pursuant to awards under the 2014 Plan. Common units subject to an award under the 2014 Plan that are canceled, forfeited, exchanged, settled in cash or otherwise terminated, including withheld to satisfy exercise prices or tax withholding obligations, will again become available for delivery pursuant to other awards under the 2014 Plan. Of the 11,000,000 common units that may be awarded under the 2014 Plan, 8,572,402 common units remain eligible for future grants by the Managing Member as of December 31, 2016. The long-term compensation structure is intended to align the performance of participants with long-term performance for our unitholders.

The 2014 Plan will automatically expire on February 5, 2024. The Board may amend or terminate the 2014 Plan at any time, subject to any requirement of unitholder approval required by applicable law, rule or regulation. The Governance and Compensation Committee may generally amend the terms of any outstanding award under the 2014 Plan at any time. However, no action may be taken by the Board or the Governance and Compensation Committee under the 2014 Plan that would materially and adversely affect the rights of a participant under a previously granted award without the participant’s consent.

The following forms of awards may be awarded under the 2014 Plan:

Options. The 2014 Plan currently permits the grant of options. These options are rights to purchase a specified number of common units of EnLink Midstream at a specified price. The exercise price of an option cannot be less than the fair market value per common unit on the date on which the option is granted and the term of the option cannot exceed ten years from the date of grant. Options will be exercisable on such terms as the Manager Committee determines. The Manager Committee will also determine the time or times at which, and the circumstances under which, an option may be exercised in whole or in part (including based on achievement of performance goals and/or future service requirements), the method of exercise, form of consideration payable in settlement, method by or forms in which common units will be delivered to participants, and whether or not an option will be in tandem with a UAR award. Under no circumstances will distributions or DERs be granted or made with respect to option awards. An option granted to an employee may consist of an option that complies with the requirements of Section 422 of the Internal Revenue Code, referred to in the 2014 Plan as an “incentive unit option.” In the case of an incentive unit option granted to an employee who owns (or is deemed

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to own) more than 10% of the total combined voting power of all classes of units, the exercise price of the option must be at least 110% of the fair market value per common unit on the date of grant and the term of the option cannot exceed five years from the date of grant.

Unit Appreciation Rights or UARs. The 2014 Plan currently permits the grant of UARs. A UAR is a right to receive an amount equal to the excess of the fair market value of one common unit of EnLink Midstream on the date of exercise over the grant price of the UAR. UARs will be exercisable on such terms as the Manager Committee determines. The Manager Committee will also determine the time or times at which and the circumstances under which a UAR may be exercised in whole or in part (including based on achievement of performance goals and/or future service requirements), the method of exercise, method of settlement, form of consideration payable in settlement, method by or forms in which common units will be delivered or deemed to be delivered to participants, whether or not a UAR shall be in tandem with an option award, and any other terms and conditions of any UAR. UARs may be either freestanding or in tandem with other awards. Under no circumstances will distributions or DERs be granted or made with respect to UAR awards.

Restricted Units. The 2014 Plan currently permits the grant of restricted units. A restricted unit is a grant of a common unit of EnLink Midstream subject to a substantial risk of forfeiture, restrictions on transferability and any other restrictions determined by the Manager Committee. The Manager Committee may provide, in its discretion, that the distributions made by EnLink Midstream with respect to the restricted units will be subject to the same forfeiture and other restrictions as the restricted unit and, if so restricted, such distributions will be held, without interest, until the restricted unit vests or is forfeited with the unit distribution right being paid or forfeited at the same time, as the case may be. In addition, the Manager Committee may provide that such distributions be used to acquire additional restricted units for the participant. Under no circumstances will DERs be granted or made with respect to restricted unit awards.

Restricted Incentive Units. The 2014 Plan currently permits the grant of restricted incentive units. Restricted incentive units are rights to receive cash, common units of EnLink Midstream or a combination of cash and common units of EnLink Midstream at the end of a specified period. Restricted incentive units may be subject to restrictions, including a risk of forfeiture, as determined by the Manager Committee. The Manager Committee may, in its sole discretion, grant DERs with respect to restricted incentive units. EnLink Midstream intends for the issuance of the common units upon vesting of the restricted incentive units under the 2014 Plan to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of the common units. Therefore, under the current policy, 2014 Plan participants will not pay any consideration for the common units they receive, and EnLink Midstream will receive no remuneration for the units.

Distribution Equivalent Rights or DERs. The 2014 Plan currently permits the grant of DERs. DERs entitle a participant to receive cash or additional awards equal to the amount of any cash distributions made by EnLink Midstream with respect to an ENLC common unit during the period the right is outstanding. DERs may be granted as a stand-alone award or with respect to awards other than restricted units, options or UARs. Subject to Section 409A of the Internal Revenue Code, payment of a DER issued in connection with another award may be subject to the same vesting terms as the award to which it relates or different vesting terms, in the discretion of the Manager Committee.

Unit Awards. The 2014 Plan currently permits the grant of unit awards, which are common units of EnLink Midstream that are not subject to vesting restrictions.

Cash Awards. The 2014 Plan currently permits the grant of cash awards, which are awards denominated and payable in cash.

Performance Awards. The 2014 Plan currently permits the grant of performance awards. Performance awards represent a participant’s right to receive an amount of cash, common units of EnLink Midstream, or a combination of both, contingent upon the annual attainment of specified performance measures within a specified period. The Manager Committee or other committee that is intended to satisfy the requirements of Section 162(m) of the Internal Revenue Code (the “Section 162(m) Committee”), as applicable, will determine the applicable performance period, the performance goals and such other conditions that apply to each performance award. In addition, the 2014 Plan permits, but does not require, the Manager Committee or the

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Section 162(m) Committee, as applicable, to structure any performance award made to a covered employee as qualified performance-based compensation under Section 162(m) of the Internal Revenue Code. Section 162(m) of the Internal Revenue Code generally limits the deductibility for federal income tax purposes of annual compensation paid to certain top executives of a company to $1 million per covered employee in a taxable year (to the extent such compensation does not constitute qualified performance-based compensation under Section 162(m) of the Internal Revenue Code). Prior to the payment of any compensation based on the achievement of performance goals applicable to performance awards that are intended to provide qualified performance-based compensation under Section 162(m) of the Internal Revenue Code, the Manager Committee or the Section 162(m) Committee, as applicable, must certify in writing that applicable performance goals and any of the material terms thereof were, in fact, satisfied.

Upon a change of control of us, the Partnership or the General Partner and except as provided in the applicable award agreement, the Governance and Compensation Committee may cause unit options and UAR grants to be vested, may cause change of control consideration to be paid in respect of some or all of such awards, or may make other adjustments (if any) that it deems appropriate with respect to such awards. With respect to other awards, upon a change of control of us and except as provided in the applicable award agreement, the Governance and Compensation Committee may cause such awards to be adjusted, which adjustments may relate to the vesting, settlement or the other terms of such awards.

EnLink Midstream 2009 Long-Term Incentive Plan . The 2009 Plan provides for the award of unit options, restricted units, restricted incentive units and other awards (collectively, “Awards”). As a result of the consummation of the Business Combination, however, it is anticipated that no future Awards will be granted under the 2009 Plan. The Governance and Compensation Committee administers the 2009 Plan and has the authority to grant waivers of the applicable plan terms, conditions, restrictions and limitations. As of December 31, 2016, no common units are reserved for issuance under the 2009 Plan. Each outstanding unit award under the 2009 Plan has a vesting period that was established in the sole discretion of the Governance and Compensation Committee and as modified by the waivers entered into by certain individuals in connection with the Business Combination, provided that earlier vesting may arise by reason of death, disability, retirement or otherwise.

The Governance and Compensation Committee may amend, modify, suspend or terminate the 2009 Plan, except that no amendment that would impair the rights of any participant to any Award may be made without the consent of such participant, and no amendment requiring unitholder approval under any applicable legal requirements will be effective until such approval has been obtained.

EnLink Midstream GP, LLC Long-Term Incentive Plan . EnLink Midstream GP, LLC adopted the GP Plan for employees, consultants and independent contractors of EnLink Midstream GP, LLC and its affiliates and outside directors of the GP Board who perform services for the Partnership. The GP Plan is administered by the Compensation Committee and permits the grant of awards, which may be awarded in the form of restricted incentive units or unit options. On May 9, 2013, our unitholders approved the amendment and restatement of the GP Plan, which increased the number of common units representing limited partner interests in the Partnership authorized for issuance under the GP Plan by 3,470,000 common units to an aggregate of 9,070,000 common units and made certain other technical amendments. Effective on April 6, 2016, the unitholders of the Partnership approved the amendment and restatement of the GP Plan, which increased the number of common units representing limited partner interests in the Partnership authorized for issuance under the GP Plan by 5,000,000 common units to an aggregate of 14,070,000 common units and other technical changes. Of the 14,070,000 common units that may be awarded under the GP Plan, 6,012,007 common units remain eligible for future grants as of December 31, 2016. The long-term compensation structure of the GP Plan is intended to align the participant’s performance with long-term performance for our unitholders.

The GP Plan will automatically expire on the tenth anniversary of the date of the GP Plan’s most recent approval by unitholders of the Partnership, which was on March 3, 2016. The GP Board, in its discretion, may terminate or amend the GP Plan at any time with respect to any units for which a grant has not yet been made. The GP Board or GP Committee also has the right to alter or amend the GP Plan or any part of the GP Plan from time to time, including increasing the number of units that may be granted subject to the approval requirements of the exchange upon which the common units are listed at that time. The GP Committee may generally amend the terms of any outstanding award under the GP Plan at any time. However, no action may be taken by the GP Board or the GP Committee under the GP Plan that would materially reduce the benefits of a participant under a previously granted award without the consent of the participant.

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The following forms of awards may be awarded under the GP Plan:

Unit Options. The GP Plan currently permits the grant of options covering common units of the Partnership. These options are rights to purchase a specified number of common units of the Partnership at a specified price. All unit option grants will have an exercise price that is not less than 100% of the fair market value of the common units on the date of grant. In general, unit options granted will become exercisable over a period determined by the Compensation Committee and the term of the options cannot exceed ten years from the date of grant. Under no circumstances will distributions or DERs be granted or made with respect to option awards. In addition, the unit options may, pursuant to their terms, become exercisable upon a change of control of us, the Partnership or the General Partner, as discussed below under "-Potential Payments Upon a Change of Control. " Common units to be delivered upon the exercise of a unit option may be common units acquired by the General Partner in the open market, common units already owned by the General Partner, common units acquired by the General Partner directly from the Partnership or any other person, or any combination of the foregoing. The General Partner will be entitled to reimbursement by the Partnership for the difference between the cost incurred by it in acquiring these common units and the proceeds received by it from an optionee at the time of exercise. Thus, the cost of the unit options will be borne by the Partnership. If the Partnership issues new common units upon exercise of the unit options the General Partner will pay the Partnership the proceeds it received from the optionee upon exercise of the unit option.

Restricted Incentive Units. The GP Plan currently permits the grant of restricted incentive units. These awards of restricted incentive units are rights that entitle the grantee to receive common units upon the vesting of such restricted incentive units. The Compensation Committee will determine the terms, conditions and limitations applicable to any awards of restricted incentive units. Awards of restricted incentive units will have a vesting period established in the sole discretion of the Compensation Committee, which may include, without limitation, vesting upon the achievement of specified performance goals. In addition, the restricted incentive units may, pursuant to their terms, vest upon a change of control of us, our general partner or EnLink Midstream, as discussed below under “-Potential Payments Upon a Change of Control.” Common units to be delivered upon the vesting of restricted incentive units may be common units acquired by our general partner in the open market, common units already owned by our general partner, common units acquired by our general partner directly from the Partnership or any other person or any combination of the foregoing. Our general partner will be entitled to reimbursement by us for the cost incurred in acquiring common units. The Compensation Committee, in its discretion, may grant tandem distribution equivalent rights (“DERs”) with respect to restricted incentive units, which entitles a participant to receive cash or additional awards equal to the amount of any cash distributions made by us with respect to a common unit during the period the DER is outstanding. The Compensation Committee may provide, in its discretion, that the DERs will be subject to the same forfeiture and other restrictions as a restricted incentive unit and, if so restricted, such distributions will be held, without interest, until the restricted incentive unit vests or is forfeited with the distribution being paid or forfeited at the same time, as the case may be. We intend for the issuance of the common units upon vesting of the restricted incentive units under the GP Plan to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of the common units. Therefore, under the current policy, GP Plan participants will not pay any consideration for the common units they receive, and we will receive no remuneration for the units.

Performance Unit Awards. In 2015 and 2016, the Managing Member and the General Partner granted performance awards under 2014 Plan and the GP Plan, respectively. The performance award agreements provide that the vesting of restricted incentive units granted under the GP Plan and 2014 Plan is dependent on the achievement of certain total shareholder return (“TSR”) performance goals relative to the TSR achievement of a peer group of companies (the “Peer Companies”) over the applicable performance period. The performance award agreements contemplate that the Peer Companies for an individual performance award (the “Subject Award”) are the companies comprising the Alerian MLP Index for Master Limited Partnerships (“AMZ”), excluding us and the Partnership (collectively, “EnLink”), on the grant date for the Subject Award. The performance units will vest based on the percentile ranking of the average of our and the Partnership’s TSR achievement (“EnLink TSR”) for the applicable performance period relative to the TSR achievement of the Peer Companies.

At the end of the vesting period, recipients receive distribution equivalents, if any, with respect to the number of performance units vested. The vesting of units range from 0% to 200% of the units granted depending on the EnLink

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TSR as compared to the Peer Companies on the vesting date. The fair value of each performance unit is estimated as of the date of grant using a Monte Carlo simulation with the following assumptions used for all performance unit grants made under the plan: (i) a risk-free interest rate based on United States Treasury rates as of the grant date; (ii) a volatility assumption based on the historical realized price volatility of our common units and the designated peer group securities; (iii) an estimated ranking of us among the designated peer group and (iv) the distribution yield. The fair value of the unit on the date of grant is expensed over a vesting period of three years.

The total value of the equity compensation granted to our executive officers generally has been awarded 50% in our restricted incentive units and 50% in restricted incentive units of the Partnership, a portion of which are in the form of our performance units and performance units of the Partnership for fiscal year 2016. In addition, our executive officers may receive additional grants of equity compensation in certain circumstances, such as promotions. For fiscal year 2016, the Managing Member granted 161,031, 147,520, 70,451, 70,451 and 91,636 performance and restricted incentive units to Barry E. Davis, Michael J. Garberding, Steve J. Hoppe, Mac Hummel and Benjamin D. Lamb, respectively. In addition, for fiscal year 2016, the General Partner granted 186,393, 158,774, 81,547, 81,547 and 98,081 performance and restricted incentive units to Barry E. Davis, Michael J. Garberding, Steve J. Hoppe, Mac Hummel and Benjamin D. Lamb, respectively. All performance and restricted incentive units that we grant are charged against earnings according to ASC 718.

Retirement and Health Benefits . We offer a variety of health and welfare and retirement programs to all eligible employees. The named executive officers are generally eligible for the same programs on the same basis as our other employees. We maintain a tax-qualified 401(k) retirement plan that provides eligible employees with an opportunity to save for retirement on a tax deferred basis. In 2016, we matched 100% of every dollar contributed for contributions of up to 8% of salary (not to exceed the maximum amount permitted by law) made by eligible participants. The retirement benefits provided to the named executive officers were allocated to us as general and administration expenses.

Perquisites. The Managing Member generally does not pay for perquisites for any of the named executive officers, other than payment of dues, sales tax and related expenses for membership in an industry related private lunch club (totaling less than $2,500 per year per person).

Change in Control and Severance Agreements

All of our named executive officers and certain members of senior management entered into amended change in control agreements (the “Change in Control Agreements”) with the Operating Partnership as of June 15, 2015 and amended severance agreements (the “Severance Agreements” and collectively with the Change in Control Agreements, the “Agreements”) with the Operating Partnership as of June 15, 2015. Additionally, as certain individuals become members of senior management, the individual may become a party to a change in control agreement and/or a severance agreement in substantially the same form as the applicable Agreement.

The Agreements restrict the officers from competing with us, our manager, the Operating Partnership, the Partnership, its general partner, and their respective affiliates and subsidiaries (the “Company Group”) during the term of employment. The Agreements also restrict the officers from disclosing confidential information of the Company Group and disparaging any member of the Company Group, in each case, during or after the term of their employment. In addition, the Agreements restrict the officers, both during their employment and for varying periods following the termination of employment, from (i) soliciting other employees to terminate their employment with any member of the Company Group or accept employment with a third party and (ii) diverting the business of a client or customer of any member of the Company Group or attempting to convert a client or customer of any member of the Company Group. The Agreements provide the Operating Partnership with equitable remedies and with the right to clawback benefits if the restrictions described in this paragraph are breached by the officer. In the event of a termination, the terminated employee is required to execute a general release of the Company Group in order to receive any benefits under the Agreements.

Under the Severance Agreements, if an officer’s employment is terminated without cause (as defined in the Severance Agreement) or is terminated by the officer for good reason (as defined in the Severance Agreement), such officer will be entitled to receive (i) his or her accrued base salary up to the date of termination, (ii) any unpaid annual bonus with respect to the calendar year ending prior to the officer’s termination date that has been earned as of such date, (iii) a prorated amount of the bonus (to the extent such bonus would have otherwise been earned by such officer) for the calendar year in which the termination occurs, (iv) such other fringe benefits (other than any bonus, severance pay

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benefit or medical insurance benefit) normally provided to employees that are already earned or accrued as of the date of termination (the foregoing items in clauses (i) - (iv) are referred to as the “General Benefits”), (v) certain outplacement services (the “Outplacement Benefits”), (vi) a lump sum severance equal to the sum of (A) the officer’s then-current base salary and (B) any target bonus (as defined in the applicable Agreement) for the year that includes the date of termination (the “Severance Benefit”) times two for the officer (other members of senior management are each entitled to one times the Severance Benefit), plus (vii) an amount equal to the cost to the officer to extend his or her then-current medical insurance benefits for 18 months following the effective date of the termination (the “Medical Severance Benefit”).

Potential Payments Upon a Change of Control

Under the Change in Control Agreements, if, within a period that begins 120 days prior to and ends 24 months following a change in control (as defined in the Change in Control Agreement), an officer’s employment is terminated without cause (as defined in the Change in Control Agreement) or is terminated by the officer for good reason (as defined in the Change in Control Agreement), such officer will be entitled to the General Benefits, the Outplacement Benefits, the Medical Severance Benefit and the Severance Benefit; provided, however, that the Chief Executive Officer would be entitled to three times the Severance Benefit, and the other officers would be entitled to two times the Severance Benefit. Other members of senior management do not receive an increase in the Severance Benefit if they are terminated in connection with a change in control.

In addition, the Agreements provide for the General Benefits upon the officer’s termination of employment due to his or her death or disability (as defined in the Agreements).

The Agreements provide that an officer may only become entitled to payments under the Severance Agreement or the Change in Control Agreement, but not under both Agreements. Upon execution of a Severance Agreement, the Severance Agreement will continue in effect until (i) the first anniversary of the execution date; provided that the term will be automatically renewed for additional one-year periods beginning on the day following the first anniversary of the execution date (each, a “Renewal Date”), unless the board of directors of the General Partner (the “Partnership Board”) or its compensation committee, as applicable, provides the officer with written notice (a “Non-Renewal Notice”) of the Operating Partnership’s election not to renew the term at least 30 days prior to any Renewal Date or (ii) the termination of the officer’s employment; provided that an officer’s employment may not be terminated by the Operating Partnership for any reason other than cause (as defined in the Severance Agreement) for the 90-day period that follows the termination of the Severance Agreement pursuant to a Non-Renewal Notice. Upon execution of a Change in Control Agreement, the Change in Control Agreement will continue in effect until (i) the applicable Renewal Date and be automatically renewed for additional one-year periods unless the Partnership Board or its compensation committee, as applicable, provides the officer with a Non-Renewal Notice at least 90 days prior to any Renewal Date or (ii) the termination of the officer’s employment, except that a Change in Control Agreement may not be terminated for a period that begins 120 days prior to, and ends 24 months following, a change in control.

If the payments and benefits provided to an officer under the Agreements (i) constitute a “parachute payment” as defined in Section 280G of the Internal Revenue Code and exceed three times the officer’s “base amount” as defined under Section 280G(b)(3) of the Internal Revenue Code, and (ii) would be subject to the excise tax imposed by Section 4999 of the Internal Revenue Code, then the officer’s payments and benefits will be either (A) paid in full, or (B) reduced and payable only as to the maximum amount that would result in no portion of the payments and benefits being subject to such excise tax, whichever results in the receipt by the officer on an after-tax basis of the greatest amount (taking into account the applicable federal, state and local income taxes, the excise tax imposed by Section 4999 of the Internal Revenue Code and all other taxes, including any interest and penalties, payable by the officer).

With respect to the long-term incentive plans, the amounts to be received by our named executive officers in the event of a change of control (as defined in the long-term incentive plans) will be automatically determined based on the number of units underlying any unvested equity incentive awards held by a named executive officer at the time of a change of control. The terms of the long-term incentive plans were determined based on past practice and the applicable compensation committee’s understanding of similar plans utilized by public companies generally at the time we adopted such plans. The determination of the reasonable consequences of a change of control is periodically reviewed by the applicable compensation committee.

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Upon a change of control, and except as provided in the award agreement, the applicable compensation committee may cause unit options and UAR grants to be vested, may cause change of control consideration to be paid in respect of some or all of such awards, or may make other adjustments (if any) that it deems appropriate with respect to such awards. With respect to other awards, upon a change of control and except as provided in the award agreement, the applicable compensation committee may cause such awards to be adjusted, which adjustments may relate to the vesting, settlement or the other terms of such awards.

The potential payments that may be made to the named executive officers upon a termination of their employment or in connection with a change of control as of December 31, 2016 are set forth in the table in the section below entitled Payments Upon Termination or Change in Control.

Role of Executive Officers in Executive Compensation

The Board, upon recommendation of the Governance and Compensation Committee, determines the compensation payable to each of the named executive officers. None of the named executive officers serves as a member of the Governance and Compensation Committee. Barry E. Davis, the Chief Executive Officer, reviews his recommendations regarding the compensation of his leadership team with the Governance and Compensation Committee, including specific recommendations for each element of compensation for the named executive officers. Barry E. Davis does not make any recommendations regarding his personal compensation.

Tax and Accounting Considerations

Our equity compensation grant policies have been impacted by the implementation of ASC 718, which we adopted effective January 1, 2006. Under this accounting pronouncement, we are required to value unvested unit options granted prior to our adoption of ASC 718 under the fair value method and expense those amounts in the income statement over the unit options’ remaining vesting period. We have discontinued grants of unit option awards and instead grant restricted unit and restricted incentive unit awards to the named executive officers and other employees. We have structured the compensation program in a manner intended to comply with Section 409A of the Internal Revenue Code. If an executive is entitled to nonqualified deferred compensation benefits that are subject to Section 409A, and such benefits do not comply with Section 409A of the Internal Revenue Code, then the benefits are taxable in the first year they are not subject to a substantial risk of forfeiture. In such case, the service provider is subject to regular federal income tax, interest and an additional federal income tax of 20% of the benefit includible in income.

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Summary Compensation Table

The following table sets forth certain compensation information for our named executive officers:


							Change in
							Pension
							value and
				Restricted		Non-Equity	Nonqualified
				Incentive Unit,		Incentive	Deferred
				and Performance	Option	Plan	Compensation	All Other
		Salary	Bonus	Unit Awards	Awards	Compensation	Earnings	Compensation		Total
Name and Principal Position	Year	($)	($)(1)	($)(2)	($)	($) (3)	($)	($)		($)
Barry E. Davis	2016	660,000	650,000	2,498,230				570,612	(4)	4,378,842
Chairman of the Board and Chief Executive Officer	2015	659,308	690,000	3,435,500	—	—	—	440,742		5,225,550
	2014	587,885	800,000	6,000,000	—	1,600,000	—	683,607		9,671,492

Michael J. Garberding	2016	462,885	416,000	3,409,650				376,304	(5)	4,664,839
President and Chief Financial Officer	2015	449,423	400,000	1,963,183	—	—	—	281,294		3,093,900
	2014	391,923	500,000	3,000,000	—	800,000	—	480,884		5,172,807

Steve J. Hoppe	2016	390,000	280,000	1,092,502				261,800	(6)	2,024,302
Executive Vice President and President of Gathering	2015	389,827	300,000	1,570,488	—	—	—	147,699		2,408,014
	2014	304,327	350,000	2,500,000	—	—	—	93,832		3,248,159

Mac Hummel	2016	390,000	225,000	1,092,502				317,871	(7)	2,025,373
Executive Vice President and President of NGL and Crude	2015	389,538	300,000	1,570,488	—	—	—	203,570		2,463,596
	2014	325,569	350,000	2,131,596	—	—	—	84,625		2,891,790

Benjamin D. Lamb (9)	2016	318,558	250,000	2,181,257				212,310	(8)	2,962,125
Executive Vice President, Corporate Development	2015	283,904	225,000	1,702,321	—	—	—	92,414		2,303,639

(1)

Bonuses include all annual bonus payments. For 2015, all annual bonus payments were paid in cash. For 2016 and 2014, the named executive officers received bonuses in the form of equity awards that immediately vest. The amounts shown for 2014 represent the grant date fair value of awards computed in accordance with ASC 718. Such awards were allocated 50% in restricted units or restricted incentive units of EnLink Midstream Partners, L.P. and 50% in restricted units or restricted incentive units of EnLink Midstream, LLC.

(2)

The amounts shown represent the grant date fair value of awards computed in accordance with ASC 718. See “Item 8. Financial Statements and Supplementary Data—Note 9” for the assumptions made in our valuation of such awards.

(3)

Non-Equity Incentive Plan Compensation includes payments made under the cash bonus plan funded by EnLink Midstream Partners, LP in January 2014, which was designed to reward a broad base of employees for successful consummation of the transactions with Devon. These amounts were awarded in February 2014.

(4)

Amount of all other compensation for Mr. Barry Davis includes professional organization and social club dues, a matching 401(k) contribution of $15,900, a 401(k) non-discretionary contribution of $11,713, DERs with respect to restricted incentive units of EnLink Midstream Partners, LP in the amount of $346,457 in 2016 and distributions on restricted units or DERs with respect to restricted incentive units and performance awards of EnLink Midstream, LLC in the amount of $196,543 in 2016.

(5)

Amount of all other compensation for Mr. Michael Garberding includes professional organization and social club dues, a matching 401(k) contribution of $15,900, a 401(k) non-discretionary contribution of $11,713, DERs with respect to restricted incentive units of EnLink Midstream Partners, LP in the amount of $220,722 in 2016 and distributions on restricted units or DERs with respect to restricted incentive units of EnLink Midstream, LLC in the amount of $127,969 in 2016.

(6)

Amount of all other compensation for Mr. Steve Hoppe includes professional organization and social club dues, a matching 401(k) contribution of $16,135, a 401(k) non-discretionary contribution of $11,713, DERs with respect to restricted incentive units of EnLink Midstream Partners, LP in the amount of $149,248 in 2016 and DERs with respect to restricted incentive units and performance awards of EnLink Midstream, LLC in the amount of $84,704 in 2016.

(7)

Amount of all other compensation for Mr. Mac Hummel includes professional organization and social club dues, a matching 401(k) contribution of $16,500, a 401(k) non-discretionary contribution of $11,713, $68,510 toward relocation and temporary housing expenses, DERs with respect to restricted incentive units of EnLink Midstream Partners, LP in the amount of $143,412 in 2016, and DERs with respect to restricted incentive units and performance awards of EnLink Midstream, LLC in the amount of $77,736 in 2016.

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(8)

Amount of all other compensation for Mr. Ben Lamb includes a matching 401(k) contribution of $16,500, a 401(k) non-discretionary contribution of $11,713, DERs with respect to restricted incentive units of EnLink Midstream Partners, LP in the amount of $117,948 in 2016, and dividends or distributions on restricted units or DERs with respect to restricted incentive units of EnLink Midstream, LLC in the amount of $66,148 in 2016.

(9)

Mr. Lamb became a named executive officer in fiscal year 2015, and, therefore, summary compensation information is presented only for fiscal years 2016 and 2015.

Grants of Plan-Based Awards for Fiscal Year 2016 Table

The following tables provide information concerning each grant of an award made to a named executive officer for fiscal year 2016, including, but not limited to, awards made under the GP Plan and the 2014 Plan:

ENLINK MIDSTREAM, LLC—GRANTS OF PLAN-BASED AWARDS


							Grant Date
					All Other		Fair Value of
		Estimated Future Payouts Under Equity			Awards:		Shares
		Incentive Plan Awards			Number of		Awards
Name	Grant Date	Threshold (#)	Target (#)	Maximum (#)	Units		($)
Barry E. Davis	2/19/2016				110,709	(1)	$	807,069
	2/19/2016	—	50,322	100,644			$	366,847

Michael J. Garberding	2/19/2016				71,457	(1)	$	520,922
	2/19/2016	—	29,187	58,374			$	212,773
	10/1/2016				23,438	(2)	$	392,587
	10/1/2016	—	23,438	46,876			$	392,587

Steve J. Hoppe	2/19/2016				48,309	(1)	$	352,173
	2/19/2016	—	22,142	44,284			$	161,415

Mac Hummel	2/19/2016				48,309	(1)	$	352,173
	2/19/2016	—	22,142	44,284			$	161,415

Benjamin D. Lamb	2/19/2016				46,296	(1)	$	337,498
	2/19/2016	—	14,090	28,180			$	102,716
	10/1/2016				15,625	(2)		261,719
	10/1/2016	—	15,625	31,250			$	261,719

(1)

These grants include DERs that provide for distribution on restricted incentive units if made on unrestricted common units during the restriction period unless otherwise forfeited and vest 100% on January 1, 2019.

(2)

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ENLINK MIDSTREAM GP, LLC—GRANTS OF PLAN-BASED AWARDS


					All Other Unit		Grant Date
		Estimated Future Payouts Under Equity			Awards:		Fair Value of
		Incentive Plan Awards			Number of		Unit Awards
Name	Grant Date	Threshold (#)	Target (#)	Maximum (#)	Units		($)
Barry E. Davis	2/19/2016				128,145	(1)	$	1,040,537
	2/19/2016	—	58,248	116,496			$	472,974

Michael J. Garberding	2/19/2016				82,712	(1)	$	671,621
	2/19/2016	—	33,784	67,568			$	274,326
	10/1/2016				21,139	(2)		374,372
	10/1/2016	—	21,139	42,278				374,372

Steve J. Hoppe	2/19/2016				55,918	(1)	$	454,054
	2/19/2016	—	25,629	51,258			$	208,107

Mac Hummel	2/19/2016				55,918	(1)	$	454,054
	2/19/2016	—	25,629	51,258			$	208,107

Benjamin D. Lamb	2/19/2016				53,588	(1)	$	435,135
	2/19/2016	—	16,309	32,618			$	132,429
	10/1/2016				14,092	(2)	$	249,569
	10/1/2016	—	14,092	28,184			$	249,569

(1)

(2)

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Outstanding Equity Awards at Fiscal Year-End Table for Fiscal Year 2016

The following tables provide information concerning all outstanding equity awards made to a named executive officer as of December 31, 2016, including, but not limited to, awards made under the 2014 Plan, the 2009 Plan and the GP Plan:

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


	Option Awards					Stock Awards


			Equity
			Incentive
			Plan						Equity
			Awards:						Incentive Plan		Equity Incentive
	Number of	Number of	Number of					Market	Awards:		Plan Awards:
	Securities	Securities	Securities					Value of	Number of		Market or
	Underlying	Underlying	Underlying			Number		Units	Unearned		Payout Value
	Unexercised	Unexercised	Unexercised	Option		or Units That		That	Units or Other		of Unearned
	Options	Options	Unearned	Exercise	Option	Have Not		Have Not	Rights that		Units or Other
	(#)	(#)	Options	Price	Expiration	Vested		Vested	Have Not		Rights That Have
Name	Exercisable	Unexercisable	(#)	($)	Date	(#)		($)(2)	Vested (#)		Not Vested ($)
Barry E. Davis	—	—	—	—	—	81,967	(2)	1,561,471	27,690	(8)	527,495
						27,690	(4)	527,495	50,322	(9)	958,634
						110,709	(6)	2,109,006
Michael J. Garberding	—	—	—	—	—	40,984	(2)	780,745	15,823	(8)	301,428
						15,823	(4)	301,428	29,187	(9)	556,012
						71,457	(6)	1,361,256	23,438	(10)	446,494
						23,438	(7)	446,494
Steve J. Hoppe	—	—	—	—	—	34,153	(2)	650,615	12,658	(8)	241,135
						12,658	(4)	241,135	22,142	(9)	421,805
						48,309	(6)	920,286
Mac Hummel	—	—	—	—	—	27,322	(2)	520,484	12,658	(8)	241,135
						12,658	(4)	241,135	22,142	(9)	421,805
						48,309	(6)	920,286
Benjamin D. Lamb	—	—	—	—	—	6,148	(2)	117,119	10,074	(8)	191,910
						6,445	(3)	122,777	14,090	(9)	268,415
						10,074	(4)	191,910	15,625	(10)	297,656
						3,556	(5)	67,742
						46,296	(6)	881,939
						15,625	(7)	297,656

(1)

Restricted incentive units vest on March 7, 2017.

(2)

The closing price for the common units was $19.05 as of December 30, 2016.

(3)

Restricted incentive units vest on July 23, 2017.

(4)

Restricted incentive units vest on January 1, 2018.

(5)

Restricted incentive units vest on April 1, 2018.

(6)

Restricted incentive units vest on January 1, 2019.

(7)

Restricted incentive units vest on January 1, 2020.

(8)

Reflects the target number of performance units granted to the named executive officers on March 17, 2015 multiplied by a performance percentage of 100%. Vesting of these awards on January 1, 2018, is contingent upon EnLink TSR performance over the applicable performance period measured against a peer group of companies.

(9)

Reflects the target number of performance units granted to the named executive officers on February 19, 2016 multiplied by a performance percentage of 100%. Vesting of these awards on January 1, 2019, is contingent upon EnLink TSR performance over the applicable performance period measured against a peer group of companies.

(10)

Reflects the target number of performance units granted to Mr. Lamb and Mr Garberding on October 1, 2016 multiplied by a performance percentage of 100%. Vesting of these awards on January 1, 2020, is contingent upon EnLink TSR performance over the applicable performance period measured against a peer group of companies.

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


	Option Awards					Stock Awards





			Equity
			Incentive
			Plan						Equity
			Awards:						Incentive Plan		Equity Incentive
	Number of	Number of	Number of					Market	Awards:		Plan Awards:
	Securities	Securities	Securities			Number		Value of	Number of		Market or
	Underlying	Underlying	Underlying			of Units		Units	Unearned		Payout Value
	Unexercised	Unexercised	Unexercised	Option		That		That	Units or Other		of Unearned
	Options	Options	Unearned	Exercise	Option	Have Not		Have Not	Rights that		Units or Other
	(#)	(#)	Options	Price	Expiration	Vested		Vested	Have Not		Rights That Have
Name	Exercisable	Unexercisable	(#)	($)	Date	(#)		($)(2)	Vested (#)		Not Vested ($)
Barry E. Davis	—	—	—	—	—	95,299	(2)	1,755,408	30,680	(8)	565,126
						30,680	(4)	565,126	58,248	(9)	1,072,928
						128,145	(6)	2,360,431
Michael J. Garberding	—	—	—	—	—	47,649	(2)	877,695	17,532	(8)	322,939
						17,532	(4)	322,939	33,784	(9)	622,301
						82,712	(6)	1,523,555	21,139	(10)	389,380
						21,139	(7)	389,380
Steve J. Hoppe	—	—	—	—	—	39,708	(2)	731,421	14,025	(8)	258,341
						14,025	(4)	258,341	25,629	(9)	472,086
						55,918	(6)	1,030,010
Mac Hummel	—	—	—	—	—	31,766	(2)	585,130	14,025	(8)	258,341
						4,201	(2)	77,382	25,629	(9)	472,086
						14,025	(4)	258,341
						55,918	(6)	1,030,010
Benjamin D. Lamb	—	—	—	—	—	7,147	(2)	131,648	11,695	(8)	215,422
						8,194	(3)	150,933	16,309	(9)	300,412
						11,695	(4)	215,422	14,092	(10)	259,575
						4,858	(5)	89,484
						53,588	(6)	987,091
						14,092	(7)	259,575

(1)

Restricted incentive units vest on March 7, 2017.

(2)

The closing price for the common units was $18.42 as of December 30, 2016.

(3)

Restricted incentive units vest on July 23, 2017.

(4)

Restricted incentive units vest on January 1, 2018.

(5)

Restricted incentive units vest on April 1, 2018.

(6)

Restricted incentive units vest on January 1, 2019.

(7)

Restricted incentive units vest on January 1, 2020.

(8)

(9)

(10)

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Units Vested Table for Fiscal Year 2016

The following table provides information related to the vesting of restricted units and restricted incentive units during fiscal year ended 2016:

UNITS VESTED


	EnLink Midstream, LLC				EnLink Midstream Partners, LP
	Unit Awards				Unit Awards
	Number of				Number of
	Units		Value		Units	Value
	Acquired		Realized on		Acquired	Realized on
Name	on Vesting		Vesting		on Vesting	Vesting
Barry E. Davis	52,301	$	789,222	(1)	51,546	$	854,633	(3)
Michael J. Garberding	43,648	$	662,819	(2)	42,913	$	717,610	(4)

(1)

Consists of 51,546 units at $16.58 per unit.

(2)

Consists of 30,928 units at $16.58 per unit and 11,985 units at $17.09 per unit.

(3)

Consists of 52,301 units at $15.09 per unit.

(4)

Consists of 31,381 units at $15.09 per unit and 12,267 units at $15.43 per unit.

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Payments Upon Termination or Change of Control

The following tables show potential payments that would have been made to the named executive officers as of December 31, 2016:


	Payment Under	Health Care
	Severance	Benefits Under
	Agreements Upon	Change in Control	Payment and Health		Acceleration of
	Termination	and Severance	Care Benefits Under	Payment Under	Vesting Under
	Other	Agreements Upon	Change in Control and	Change in Control	Long-Term
	Than For Cause	Termination Other	Severance Agreements	Agreements Upon	Incentive Plans
	or With Good	Than For Cause or	Upon Termination For	Termination and	Upon Change of
	Reason	With Good Reason	Cause or Without Good	Change of Control	Control
Name and Principal Position	($)(1)	($)(2)	Reason ($)(3)	($)(4)	($)(5)
Barry E. Davis	3,795,000	33,556	—	5,280,000	12,003,119
Chairman of the Board and Chief Executive Officer
Michael J. Garberding	2,350,000	30,682	—	2,350,000	8,642,048
President and Chief Financial Officer
Steve J. Hoppe	1,833,000	33,556	—	1,833,000	5,225,174
Executive Vice President and President of Gas Gathering, Processing and Transmission
Mac Hummel	1,833,000	30,682	—	1,833,000	5,026,134
Executive Vice President and President of Natural Gas Liquids and Crude
Benjamin D. Lamb	1,621,500	33,556	—	1,311,000	5,046,685
Senior Vice President

(1)

Each named executive officer is entitled to a lump sum amount equal to two times the Severance Benefit, and when applicable, the bonus amounts comprising the General Benefits will be paid if he is terminated without cause (as defined in the Severance Agreement) or if he terminates employment for good reason (as defined in the Severance Agreement), subject to compliance with certain non-competition and non-solicitation covenants described elsewhere in this Annual Report on Form 10-K. The figures shown do not include amounts of base salary previously paid or fringe benefits previously received.

(2)

Each named executive officer is entitled to health care benefits equal to a lump sum payment of the estimated monthly cost of the benefits under COBRA for 18 months if he is terminated without cause (as defined in the applicable Severance Agreement or Change of Control Agreement (the “Applicable Agreement”) or if he terminates employment for good reason (as defined in the Applicable Agreement).

(3)

Each named executive officer is entitled to his then current base salary up to the date of termination plus such other fringe benefits (other than any bonus, severance pay benefit, participation in the company’s 401(k) employee benefit plan, or medical insurance benefit) normally provided to employees of the company as earned up to the date of termination if he is terminated for cause (as defined in the Applicable Agreement) or he terminates employment without good reason (as defined in the Applicable Agreement). The figures shown do not include amounts of base salary previously paid or fringe benefits previously received.

(4)

Each named executive officer is entitled to a lump sum payment equal to two times the Severance Benefit (three times in the case of the Chief Executive Officer) and when applicable, the bonus amounts comprising the General Benefits will be paid if he is terminated without cause (as defined in the Change of Control Agreement) or if he terminates employment for good reason (as defined in the Change of Control Agreement) within one-hundred and twenty (120) days prior to or two (2) years following a change in control (as defined in the Change of Control Agreement), subject to compliance with certain non-competition, non-solicitation and other covenants described elsewhere in this Annual Report on Form 10-K. The figures shown do not include amounts of base salary previously paid or fringe benefits previously received.

(5)

Each named executive officer is entitled to accelerated vesting of certain outstanding equity awards in the event of a change of control (as defined under the long-term incentive plans). These amounts correspond to the values set forth in the table in the section above entitled Outstanding Equity Awards at Fiscal Year-End Table for Fiscal Year 2016.

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Compensation of Directors for Fiscal Year 2016

DIRECTOR COMPENSATION


	Fees Earned
	or Paid	Unit	All Other
	in Cash	Awards(1)	Compensation(2)	Total
Name	($)	($)	($)	($)
James C. Crain	104,500	100,000	8,396	212,896
Leldon E. Echols	102,875	99,992	10,319	213,186
Rolf A. Gafvert	94,125	100,000	8,396	202,521
John Richels (3)	54,750	99,992	6,119	160,861
Mary P. Ricciardello	92,000	99,992	10,319	202,311

(1)

Mr. Crain, Echols, Gafvert, Richels and Ms. Ricciardello were granted awards of restricted units of EnLink Midstream LLC on March 7, 2016 with a fair market value of $10.10 per unit and that will vest on March 7, 2017 in the following amounts, respectively: 9,901, 4,950, 9,901, 4,950 and 4,950. Mr. Echols, Richels and Ms. Ricciardello were granted awards of restricted incentive units of EnLink Midstream Partners, LP on March 7, 2016 with a fair market value of $10.85 per unit and that will vest on March 7, 2017 in the following amounts, respectively: 4,608, 4608 and 4,608. The amounts shown represent the grant date fair value of awards computed in accordance with ASC 718. See “Item 8. Financial Statements and Supplementary Data—Note 12” for the assumptions made in our valuation of such awards. At December 31, 2016, Mr. Crain, Echols, Gafvert and Ms. Ricciardello held aggregate outstanding restricted unit awards, in the following amounts, respectively: 9,901, 4,950, 9,901 and 4,950. At December 31, 2016, Mr. Echols and Ms. Ricciardello held aggregate outstanding restricted incentive units of EnLink Midstream Partnership, LP in the following amounts, respectively: 4,608 and 4,608.

(2)

Other Compensation is comprised of DERs with respect to restricted units and distributions on restricted incentive units.

(3)

Mr. Richels retired effective June 22, 2016.

Each director of the Managing Member who is not an employee of the Managing Member or Devon will be paid an annual retainer fee of $50,000 and equity compensation valued at $100,000. Directors do not receive an attendance fee for each regularly scheduled quarterly board meeting but are paid $1,500 for each additional meeting that they attend. Also, an attendance fee of $1,500 is paid to each director for each committee meeting that is attended, other than the Audit Committee which pays a fee of $3,000 per meeting. The respective chairs of each committee receive the following annual fees: Audit-$12,500, Governance and Compensation-$10,000 and Conflicts-$10,000. Directors are also reimbursed for related out-of-pocket expenses. John Richels, Barry E. Davis, Thomas Mitchell, David Hager, Lyndon Taylor and Sue Alberti, as officers of the Managing Member or Devon, receive no separate compensation for their respective service as directors. For directors that serve on both the Board and GP Board, the annual retainer fee is generally allocated 25% to us and 75% to the Partnership and equity grants are comprised of 50% of our units and 50% of Partnership units.

Governance and Compensation Committee Interlocks and Insider Participation

Our Governance and Compensation Committee is comprised of Rolf A. Gafvert and David A. Hager. As described elsewhere in this report, Mr. Hager is an executive officer of Devon and may have an interest in the transactions among Devon, the Partnership and us. Please see “Item 13. Certain Relationships and Related Party Transactions.”

Board Leadership Structure and Risk Oversight

The Board has no policy that requires that the positions of the Chairman of the Board (the “Chairman”) and the Chief Executive Officer be separate or that they be held by the same individual. The Board believes that this determination should be based on circumstances existing from time to time, including the composition, skills, and experience of the Board and its members, specific challenges faced by us or the industry in which we operate, and governance efficiency. Based on these factors, the Board has determined that having Barry Davis serve as Chairman and Chief Executive Officer is in our best interest at this time, and that such arrangement makes the best use of Mr. Davis’ unique skills and experience in the industry.

The Board is responsible for risk oversight. Management has implemented internal processes to identify and evaluate the risks inherent in our business and to assess the mitigation of those risks. The Audit Committee will review the risk assessments with management and provide reports to the Board regarding the internal risk assessment processes, the risks identified, and the mitigation strategies planned or in place to address the risks in the business. The Board and

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the Audit Committee each provide insight into the issues, based on the experience of their members, and provide constructive challenges to management’s assumptions and assertions.

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

EnLink Midstream, LLC Ownership and Devon Energy Corporation Ownership

The following table shows the beneficial ownership of EnLink Midstream, LLC, as well as the beneficial ownership of shares of common stock of Devon Energy Corporation, as of February 8, 2017, held by:

each person who beneficially owns 5% or more of any class of units then outstanding;

all the directors of EnLink Midstream Manager, LLC;

each named executive officer of EnLink Midstream Manager, LLC; and

all the directors and executive officers of EnLink Midstream Manager, LLC as a group.

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The percentage of total common units of EnLink Midstream, LLC beneficially owned is based on a total of 180,335,062 units (including 259,686 restricted incentive units that are deemed beneficially owned) as of February 8, 2017. The percentage of total shares of Devon Energy Corporation beneficially owned is based on a total of 524,553,353 shares of common stock outstanding as of February 8, 2017.


	EnLink Midstream, LLC			Devon Energy Corporation
				Shares of
	Common			Common
	Units			Stock
	Beneficially			Beneficially
Name of Beneficial Owner (1)	Owned	Percent		Owned	Percent
Devon Energy Corporation (2)	115,495,669	64.05	%	—	*
Chickasaw Capital Management, LLC	9,529,926	5.28	%	—	*
Barry E. Davis (3)	1,912,330	1.06	%	—	*
Michael J. Garberding (4)	155,743	*		500	*
Steve J. Hoppe (5)	43,452	*		15,500	*
Mac Hummel (6)	39,704	*		3,598	*
Benjamin D. Lamb (7)	7,147	*		—	*
James C. Crain (8)	69,069	*		—	*
Leldon E. Echols (9)	30,785	*		—	*
Thomas L. Mitchell	—	*		57,916	*
David A. Hager	—	*		393,604	*
Mary P. Ricciardello (10)	6,336	*		41,593	*
Rolf A. Gafvert (11)	12,673	*		—	*
Lyndon Taylor	—	*		221,669	*
Sue Alberti	—	*		40,601	*
All directors and executive officers as group (14 persons)	2,299,574	1.28	%	774,981	0.15	%

* Less than 1%.

(1)

The address of each person listed above is 2501 Cedar Springs, Suite 100, Dallas, Texas 75201, except for (i) Devon Energy Corporation, whose address is 333 W. Sheridan Avenue, Oklahoma City, Oklahoma 73102, and (ii) Chickasaw Capital Management, LLC, whose address is 6075 Poplar Avenue, Suite 720, Memphis, Tennessee, 38119.

(2)

Devon Gas Services, L.P. (“Devon Gas Services”) is the record holder of 115,495,669 common units. As the indirect owner of 100% of the outstanding limited and general partner interests in Devon Gas Services, Devon Energy Corporation may be deemed to beneficially own all of the common units held by Devon Gas Services.

(3)

Includes 1,817,031 common units owned of record by Mr. Davis and 95,299 restricted incentive units that are deemed beneficially owned. 1,025,000 of these common units are held by MK Holdings, LP, a family limited partnership, which Mr. Davis controls, and Mr. Davis disclaims beneficial ownership of these securities except to the extent of his pecuniary interest therein.

(4)

Includes 108,094 common units owned of record by Mr. Garberding and 47,649 restricted incentive units that are deemed beneficially owned.

(5)

Includes 3,744 common units owned of record by Mr. Hoppe and 39,708 restricted incentive units that are deemed beneficially owned.

(6)

Includes 3,737 common units owned of record by Mr. Hummel and 35,967 restricted incentive units that are deemed beneficially owned.

(7)

Includes 7,147 restricted incentive units that are deemed beneficially owned.

(8)

Includes 59,168 common units owned of record by Mr. Crain and 9,901 restricted incentive units that are deemed beneficially owned. 1,000 of these common units are held by the James C. Crain Trust, and Mr. Crain disclaims beneficial ownership of these securities except to the extent of his pecuniary interest therein.

(9)

Includes 25,835 common units owned of record by Mr. Echols and 4,950 restricted incentive units that are deemed beneficially owned.

(10)

Includes 1,386 common units owned of record by Ms. Ricciardello and 4,950 restricted incentive units that are deemed beneficially owned.

(11)

Includes 2,772 common units owned of record by Mr. Gafvert and 9,901 restricted incentive units that are deemed beneficially owned.

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EnLink Midstream Partners, LP Ownership

The following table shows the beneficial ownership of units of EnLink Midstream Partners, LP as of February 8, 2017, held by:

each person who beneficially owns 5% or more of any class of units then outstanding;

all the directors of EnLink Midstream GP, LLC;

each named executive officer of EnLink Midstream GP, LLC; and

all the directors and executive officers of EnLink Midstream GP, LLC as a group.

The percentage of total units beneficially owned is based upon a total of 343,104,673 common units as of February 8, 2017.


		Percentage of		Series B	Percentage of
	Common	Common		Convertible	Preferred		Percentage of
	Units	Units		Preferred Units	Units	Total Units	Total Units
	Beneficially	Beneficially		Beneficially	Beneficially	Beneficially	Beneficially
Name of Beneficial Owner (1)	Owned	Owned (2)		Owned	Owned	Owned	Owned (3)
Barry E. Davis (4)	509,829	*		—	—	509,829	*
Michael J. Garberding (5)	130,230	*		—	—	130,230	*
Steve J. Hoppe (6)	38,894	*		—	—	38,894	*
Mac Hummel (7)	32,063	*		—	—	32,063	*
Benjamin D. Lamb (8)	11,025	*		—	—	11,025	*
James C. Crain	—	*		—	—	—	*
Leldon E. Echols (9)	27,246	*		—	—	27,246	*
Thomas L. Mitchell	—	*		—	—	—	*
David A. Hager	—	*		—	—	—	*
Mary P. Ricciardello (10)	6,122	*		—	—	6,122	*
Rolf A. Gafvert	—	*		—	—	—	*
Lyndon Taylor	—	*		—	—	—	*
Sue Alberti	—	*		—	—	—	*
All directors and executive officers as a group (14 persons)	782,382	0.23	%	—	—	782,382	0.20	%

* Less than 1%

(1)

The address of each person listed above is 2501 Cedar Springs, Suite 100, Dallas, Texas 75201.

(2)

The percentages reflected in the column below are based on a total of 343,104,673 common units, including 221,848 restricted incentive units that are deemed beneficially owned.

(3)

The percentages reflected in the column below are based on a total of 396,287,324 common units, which includes the units described in (2) above, and 53,182,651 Series B Convertible Preferred units.

(4)

Includes 427,862 common units owned of record by Mr. Davis and 81,967 restricted incentive units that are deemed beneficially owned. 88,652 of these common units are held by MK Holdings, LP, a family limited partnership, which Mr. Davis controls, and Mr. Davis disclaims beneficial ownership of these securities except to the extent of his pecuniary interest therein.

(5)

Includes 89,246 common units owned of record by Mr. Garberding and 40,984 restricted incentive units that are deemed beneficially owned.

(6)

Includes 4,741 common units owned of record by Mr. Hoppe and 34,153 restricted incentive units that are deemed beneficially owned.

(7)

Includes 4,741 common units owned of record by Mr. Hummel and 27,322 restricted incentive units that are deemed beneficially owned.

(8)

Includes 4,877 common units owned of record by Mr. Lamb and 6,148 restricted incentive units that are deemed beneficially owned.

(9)

Includes 22,638 common units owned of record by Mr. Echols and 4,608 restricted incentive units that are deemed beneficially owned.

(10)

Includes 1,514 common units owned of record by Ms. Ricciardello and 4,608 restricted incentive units that are deemed beneficially owned.

Beneficial Ownership of General Partner Interest

EnLink Midstream GP, LLC owns all of the Partnership’s general partner interest and all of the Partnership’s incentive distribution rights. EnLink Midstream GP, LLC is 100% indirectly owned by EnLink Midstream, LLC.

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Equity Compensation Plan Information


	Number of Securities			Number of Securities
	to be Issued			Remaining Available for
	Upon Exercise		Weighted-Average	Future Issuance Under
	of Outstanding		Price of	Equity Compensation Plan
	Options, Warrants,		Outstanding Options,	(Excluding Securities
Plan Category	and Rights		Warrants and Rights	Reflected in Column(a))
	(a)		(b)	(c)
Equity Compensation Plans Approved By Security Holders(1)	2,281,562	(2)	N/A	8,556,000
Equity Compensation Plans Not Approved By Security Holders	N/A		N/A	N/A

(1)

Our 2014 Long-Term Incentive Plan was approved by our unitholders in March 2014 for the benefit of our officers, employees and directors. See Item 11, “Executive Compensation—Compensation Discussion and Analysis.” The plan, as amended, provides for the issuance of a total of 11,000,000 common units under the plan.

(2)

The number of securities includes 1,897,298 restricted units that have been granted under our long-term incentive plan that have not vested. In addition, the number of securities includes 384,264 performance unit awards granted under the plan, assuming the target distribution at the time of vesting. Actual issuance of these performance unit awards may range from 0% to 200% of the target distribution depending on performance actually attained.

Item 13. Certain Relationships and Related Transactions and Director Independence

Relationship with EnLink Midstream Partners, LP

As of December 31, 2016, we indirectly owned 88,528,451 common units, representing an approximate 22.3% limited partnership interest, of the Partnership, the general partner interest in the Partnership and the incentive distribution rights in the Partnership. Through our ownership of the General Partner, we have the power to appoint all of the officers and directors of the General Partner and to manage and operate the Partnership and effectively to veto some of the Partnership’s actions. We pay the Partnership a fee for administrative and compensation costs incurred by the Partnership on our behalf.

Relationship with Devon Energy Corporation

We are managed by our managing member, which is wholly-owned by Devon. Therefore, Devon controls us and our ability to manage and operate our business. Additionally, five of our directors, including David Hager, Thomas Mitchell, Sue Alberti, Lyndon Taylor and Tony Vaughn are officers of Devon. Those individuals do not receive separate compensation for their service on the Board, but they are entitled to indemnification related to their service as directors pursuant to the indemnification agreements as described below.

Related Party Transactions

Reimbursement of Costs. We paid the Partnership $2.3 million, $2.1 million and 1.2 million during the years ended December 31, 2016, 2015 and 2014, respectively, to cover its portion of administrative and compensation costs for officers and employees that perform services for us. This reimbursement is evaluated on an annual basis. Officers and employees that perform services for us provide an estimate of the portion of their time devoted to such services. A portion of their annual compensation (including bonuses, payroll taxes and other benefit costs) is allocated to us for reimbursement based on these estimates. In addition, an administrative burden is added to such costs to reimburse us for additional support costs, including, but not limited to, consideration for rent, office support and information service support.

E2 Drop Down. On October 22, 2014, the Partnership acquired from EMI, a wholly-owned subsidiary of ENLC, certain equity interests in EnLink Appalachian Compression, LLC (formerly, E2 Appalachian Compression, LLC) and E2 Energy Services, LLC through its purchase of the EnLink Appalachian Units and the E2 Energy Services Units, respectively. The total consideration paid by the Partnership to EMI for such units included (i) $13.0 million in cash for the E2 Energy Services Units and (ii) $150.0 million in cash and 1,016,322 common units representing limited partner

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interests in the Partnership for the EnLink Appalachian Units. In April 2016, pursuant to rights in the Limited Liability Company agreement, the Partnership acquired the remaining EnLink Appalachian Units

Midstream Holdings Drop Down. On February 17, 2015, the Partnership acquired the February 2015 Transferred Interests from Acacia, a wholly-owned subsidiary of us, in the February 2015 EMH Drop Down. As consideration for the February 2015 Transferred Interests, the Partnership issued 31.6 million of its common units to Acacia.

On May 27, 2015, the Partnership acquired the May 2015 Transferred Interests from Acacia in exchange for 36.6 million of its common units. After giving effect to the EMH Drop Downs, the Partnership owns 100% of Midstream Holdings.

VEX Pipeline. On April 1, 2015, the Partnership acquired the VEX Interests from Devon, which are located in the Eagle Ford Shale in south Texas. The aggregate consideration paid by the Partnership consisting of $166.7 million in cash, 338,159 common units representing limited partner interests in the Partnership with an aggregate value of approximately $9.0 million and the Partnership’s assumption of up to $40.0 million in certain construction costs related to the VEX Interests, subject to certain adjustments set forth in the contribution agreement.

On October 29, 2015, the Partnership issued 2,849,100 common units to one of our subsidiaries at an offering price of $17.55 per unit for aggregate consideration of approximately $50.0 million in a private placement transaction.

In January 2016, the Partnership issued an aggregate of 50,000,000 Series B Cumulative Convertible Preferred Units (the “Preferred Units”) representing its limited partner interests to Enfield Holdings, L.P. (“Enfield”) in a private placement for a cash purchase price of $15.00 per Preferred Unit (the “Issue Price”), resulting in net proceeds of approximately $724.1 million after fees and deductions.

Commercial Arrangements

The Partnership conducts business with Devon pursuant to gathering and processing agreements described below. The Partnership also historically has maintained a relationship with Devon as a customer, as described in more detail below.

Gathering and Processing Agreements

As described elsewhere, Midstream Holdings was previously a wholly-owned subsidiary of Devon, and all of its assets were contributed to it by Devon. In connection with the consummation of the Business Combination, Midstream Holdings entered into gathering and processing agreements with certain subsidiaries of Devon pursuant to which Midstream Holdings provides gathering, treating, compression, dehydration, stabilization, processing and fractionation services, as applicable, for natural gas delivered by Devon to Midstream Holdings gathering systems in the Barnett, Cana-Woodford and Arkoma-Woodford Shales. These agreements provide Midstream Holdings with dedication of all of the natural gas owned or controlled by Devon and produced from or attributable to existing and future wells located on certain oil, natural gas and mineral leases covering lands within the acreage dedications, excluding properties previously dedicated to other natural gas gathering systems not owned and operated by Devon.

Pursuant to the gathering and processing agreements, Devon has committed to deliver specified average minimum daily volumes of natural gas to Midstream Holdings’ gathering systems in the Barnett, Cana-Woodford and Arkoma-Woodford Shales during each calendar quarter for a five-year period following execution. These commitments account for substantially all of Midstream Holdings’ natural gas supply and approximately 14.4% of the Partnership’s combined revenues, or $611.8 million for the year ended December 31, 2016, 13.4% of our combined revenues, or $596.3 million for the year ended December 31, 2015 and approximately 26.7% of our combined revenues, or $938.2 million for the year ended December 31, 2014. Devon is entitled to firm service, meaning that if capacity on a system is curtailed or reduced, or capacity is otherwise insufficient, Midstream Holdings will take delivery of as much Devon natural gas as is permitted in accordance with applicable law.

The gathering and processing agreements are fee-based, and Midstream Holdings is paid a specified fee per MMBtu for natural gas gathered on Midstream Holdings’ gathering systems and a specified fee for natural gas processed. The particular fees, all of which are subject to an automatic annual inflation escalator at the beginning of each year, differ from one system to another and do not contain a fee redetermination clause.

Please see “Item 1A. Risk Factors” for a description of the risks associated with our dependence on Devon pursuant to these agreements.

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Historical Customer Relationship with Devon

As noted above, the Partnership has historically maintained a customer relationship with Devon pursuant to which certain of the Partnership’s subsidiaries provide gathering, transportation, processing and gas lift services to Devon subsidiaries in exchange for fee-based compensation under several agreements with such Devon subsidiaries. The terms of these agreements vary, but the agreements expire between March 2017 and July 2021 and they automatically renew for month-to-month or year-to-year periods unless canceled by Devon prior to expiration. In addition, one of the Partnership’s subsidiaries has agreements with a subsidiary of Devon pursuant to which the Partnership’s subsidiary purchases and sells NGLs and pays or receives, as applicable, a margin-based fee. These NGL purchase and sale agreements have month-to-month terms. These historical agreements collectively comprise $107.2 million, $107.5 million and $112.3 million, or 2.5%, 2.4% and 3.2%, of the Partnership’s combined revenue for the years ended December 31, 2016, 2015 and 2014 respectively.

VEX Arrangement

The Partnership entered into to a five-year minimum transportation volume commitment with Devon related to its Victoria Express Pipeline (“VEX Pipeline”). The MVC was executed in June 2014 and the initial term expires July 2019. This agreement accounted for approximately 0.3%, 0.4% and 0.2% of the Partnership’s combined revenues, or $12.3 million, $17.8 million and $7.4 million, for the years ended December 31, 2016, 2015 and 2014 respectively.

Transition Services Agreement

In connection with the consummation of the Business Combination, the Partnership entered into a transition services agreement with Devon pursuant to which Devon is providing certain services to the Partnership with respect to the business and operations of Midstream Holdings and the Partnership provides certain services to Devon. General and administrative expenses related to the transition service agreement were $0.3 million, $0.2 million and $3.0 million for the years ended December 31, 2016, 2015 and 2014, respectively. We received $0.3 million from Devon under the transition services agreement for the years ended December 31, 2016, 2015 and 2014.

GCF Agreement

In connection with the consummation of the Business Combination, the Partnership entered into an agreement with a wholly-owned subsidiary of Devon pursuant to which Devon agreed, from and after the closing of the Business Combination, to hold for the benefit of Midstream Holdings the economic benefits and burdens of Devon’s 38.75% general partner interest in Gulf Coast Fractionators in Mont Belvieu, Texas. This agreement contributed approximately $3.4 million, $13.0 million and $14.3 million to our income from unconsolidated affiliate investments for the years ended December 31, 2016, 2015 and 2014, respectively.

Lone Camp Gas Storage Agreement

In connection with the consummation of the Business Combination, the Partnership entered into an agreement with a wholly-owned subsidiary of Devon under which the Partnership provides gas storage services at its Lone Camp storage facility. Under this agreement, the wholly-owned subsidiary of Devon will reimburse the Partnership for the expenses it incurs in providing the storage services. The gas storage agreement accounted for an immaterial amount of revenue in 2016.

Acacia Transportation Agreement

In connection with the consummation of the Business Combination, a subsidiary of the Partnership entered into an agreement with a wholly-owned subsidiary of Devon pursuant to which the Partnership provides transportation services to Devon on its Acacia line. This agreement accounted for approximately 0.4% of our combined revenues, or $15.2 million, $16.4 million and $15.1 million, for the years ended December 31, 2016, 2015 and 2014, respectively.

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EnLink Oklahoma T.O. Gathering and Processing Agreement with Devon

Cedar Cove Joint Venture

On November 9, 2016, the Partnership formed a joint venture (the “Cedar Cove JV”) with Kinder Morgan, Inc. consisting of gathering and compression assets in Blaine County, Oklahoma. Under a fifteen year, fixed-fee agreement, all gas gathered by the Cedar Cove JV will be processed at the Partnership’s central Oklahoma processing system. For the period from November 9, 2016 through December 31, 2016, revenue generated from processing gas from the Cedar Cove JV was classified as “Midstream services – related parties” on the consolidated statements of operations and was immaterial to the Partnership’s overall financial results.

Office Leases

In connection with the consummation of the Business Combination, the Partnership entered into three office lease agreements with a wholly-owned subsidiary of Devon pursuant to which we will lease office space at Devon’s Bridgeport, Oklahoma City and Cresson office buildings. Rent payable to Devon under these lease agreements is $174,000, $31,000 and $66,000, respectively, on an annual basis.

Certain Relationships

From time to time, the Partnership may do business with other companies affiliated with TPG, which holds an interest in Enfield Holdings, L.P., the beneficial owner of the Partnership’s preferred units, or with NGP or Kinder Morgan, Inc., the Partnership’s joint venture partners in the Delaware Basin JV and Cedar Cove JV, respectively. The Partnership believes that any such arrangements have been or will be conducted on an arms-length basis.

Tax Sharing Agreement

In connection with the consummation of the Business Combination, we, the Partnership and Devon, entered into a tax sharing agreement providing for the allocation of responsibilities, liabilities and benefits relating to any tax for which a combined tax return is due. In 2016 and 2015, we incurred approximately $2.3 million and $3.0 million, respectively, in taxes that are subject to the tax sharing agreement.

Indemnification of Directors and Officers

We have entered into indemnification agreements (the “Indemnification Agreements”) with each of the Managing Member’s directors and executive officers (collectively, the “Indemnitees”). Under the terms of the Indemnification Agreements, we agree to indemnify and hold each Indemnitee harmless, subject to certain conditions, against any and all losses, claims, damages, liabilities, expenses (including legal fees and expenses), judgments, fines, ERISA-related excise taxes, penalties, interest, settlements or other amounts arising from any and all threatened, pending or completed claims, demands, actions, suits or proceedings, whether civil, criminal, administrative or investigative, and whether formal or informal and including appeals, in which the Indemnitee is involved, or is threatened to be involved, as a party or otherwise, because the Indemnitee is or was a director, manager or officer of the Managing Member or us, or is or was serving at the request of the Managing Member or us as a manager, managing member, general partner, director, officer, fiduciary, or trustee of another entity, organization or person of any nature. We have also agreed to advance the expenses of an Indemnitee relating to the foregoing. To the extent that a change in the laws of the State of Delaware permits greater indemnification under any statute, agreement, organizational document or governing document than would be

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afforded under the Indemnification Agreements as of the date of the Indemnification Agreements, the Indemnitee shall enjoy the greater benefits so afforded by such change.

Approval and Review of Related Party Transactions.

If we contemplate entering into a transaction, other than a routine or in the ordinary course of business transaction, in which a related person will have a direct or indirect material interest, the proposed transaction is submitted for consideration to the Board or our senior management, as appropriate. If the Board is involved in the approval process, it determines whether it is advisable to refer the matter to the Conflicts Committee of the Board, comprised entirely of independent directors, as constituted under our operating agreement. The Conflicts Committee operates pursuant to its written charter and our operating agreement. If a matter is referred to the Conflicts Committee, the Conflicts Committee obtains information regarding the proposed transaction from management and determines whether it is advisable to engage independent legal counsel or an independent financial advisor to advise the members of the committee regarding the transaction. If the committee retains such counsel or financial advisor, it considers the advice and, in the case of a financial advisor, such advisor’s opinion as to whether the transaction is fair and reasonable to us and to our unitholders.

Director Independence

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

Item 14. Principal Accounting Fees and Services

Audit Fees

The fees for professional services rendered for the audit of our annual financial statements for the fiscal years ended December 31, 2016 and 2015, review of our internal control procedures for the fiscal years ended December 31, 2016 and 2015 and the reviews of the financial statements included in our Quarterly Reports on Form 10-Q or services that are normally provided by KPMG in connection with statutory or regulatory filings or engagements for each of those fiscal years were $0.3 million. These amounts also included fees associated with comfort letters and consents related to debt and equity offerings.

Audit-Related Fees

KPMG did not perform any assurance and related services related to the performance of the audit or review of our financial statements for the fiscal years ended December 31, 2016 and 2015 that were not included in the audit fees listed above.

Tax Fees

KPMG did not perform any tax related services for the years ended December 31, 2016 and 2015.

All Other Fees

KPMG did not render services to us, other than those services covered in the section captioned “Audit Fees” for the fiscal years ended December 31, 2016 and 2015.

Audit Committee Approval of Audit and Non-Audit Services

All audit and non-audit services and any services that exceed the annual limits set forth in our annual engagement letter for audit services must be pre-approved by the Audit Committee. In 2016, the Audit Committee has not pre-approved the use of KPMG for any non-audit related services. The Chairman of the Audit Committee is authorized by the Audit Committee to pre-approve additional KPMG audit and non-audit services between Audit Committee meetings; provided that the additional services do not affect KPMG’s independence under applicable Securities and Exchange Commission rules and any such pre-approval is reported to the Audit Committee at its next meeting.

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PART IV

Item 15. Exhibits and Financial Statement Schedules

(a)

Financial Statements and Schedules

See “Item 8. Financial Statements and Supplementary Data.”

Exhibits

The exhibits filed as part of this report are as follows (exhibits incorporated by reference are set forth with the name of the registrant, the type of report and registration number or last date of the period for which it was filed, and the exhibit number in such filing):

Number			Description
2.1	**	—	TOM-STACK Securities Purchase Agreement, dated as of December 6, 2015, among Tall Oak Midstream, LLC, FE-STACK, LLC, TOM-STACK Holdings, LLC, TOM-STACK, LLC, EnLink TOM Holdings, LP and EnLink Midstream, LLC and, solely for purposes of Section 6.19 thereof, EnLink Midstream Partners, LP (incorporated by reference to Exhibit 2.1 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated December 7, 2015, filed with the Commission on December 7, 2015, file No. 001-36340).
2.2	**	—	TOMPC Securities Purchase Agreement, dated as of December 6, 2015, among TOMPC LLC, Tall Oak Midstream, LLC, EnLink TOM Holdings, LP, and EnLink Midstream, LLC and, solely for purposes of Section 6.19 thereof, EnLink Midstream Partners, LP (incorporated by reference to Exhibit 2.2 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated December 7, 2015, filed with the Commission on December 7, 2015, file No. 001-36340).
3.1		—	Certificate of Formation of EnLink Midstream, LLC (incorporated by reference to Exhibit 3.1 to our Registration Statement on Form S-4, file No. 333-192419).
3.2		—	Certificate of Amendment to Certificate of Formation of EnLink Midstream, LLC (incorporated by reference to Exhibit 3.2 to our Registration Statement on Form S-4, file No. 333-192419).
3.3		—	First Amended and Restated Operating Agreement of EnLink Midstream, LLC, dated as of March 7, 2014 (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K dated March 7, 2014, filed with the Commission on March 11, 2014, file No. 001-36336).
3.4		—	Certificate of Formation of EnLink Midstream Manager, LLC (incorporated by reference to Exhibit 3.12 to our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2014).
3.5		—	Certificate of Amendment to the Certificate of Formation of EnLink Midstream Manager, LLC (incorporated by reference to Exhibit 3.13 to our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2014).
3.6		—	First Amended and Restated Limited Liability Company Agreement of EnLink Midstream Manager, LLC (incorporated by reference to Exhibit 3.14 to our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2014).
3.7		—	Certificate of Formation of EnLink Midstream GP, LLC (incorporated by reference to Exhibit 3.7 to EnLink Midstream Partners, LP’s Registration Statement on Form S-1, file No. 333-97779).
3.8		—	Certificate of Amendment to the Certificate of Formation of EnLink Midstream GP, LLC (incorporated by reference to Exhibit 3.12 to EnLink Midstream Partners, LP’s Registration Statement on Form S-3, file No. 333-194465).
3.9		—	Third Amended and Restated Limited Liability Company Agreement of EnLink Midstream GP, LLC, dated as of July 7, 2014 (incorporated by reference to Exhibit 3.2 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated July 7, 2014, filed with the Commission on July 7, 2014, file No. 001-36340).
3.10		—	Amendment No. 1 to Third Amended and Restated Limited Liability Company Agreement of EnLink Midstream GP, LLC, dated as of January 7, 2016 (incorporated by reference to Exhibit 3.2 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated January 12, 2016, filed with the Commission on January 12, 2016, file No. 001-36340).
3.11		—	Certificate of Limited Partnership of EnLink Midstream Partners, LP (incorporated by reference to Exhibit 3.1 to EnLink Midstream Partners, LP’s Registration Statement on Form S-1, file No. 333-97779).

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3.12	—	Certificate of Amendment to the Certificate of Limited Partnership of EnLink Midstream Partners, LP (incorporated by reference to Exhibit 3.2 to EnLink Midstream Partners, LP’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2012, filed with the Commission on August 7, 2012, file No. 000-50067).
3.13	—	Second Amendment to the Certificate of Limited Partnership of EnLink Midstream Partners, LP (incorporated by reference to Exhibit 3.3 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated March 6, 2014, filed with the Commission on March 11, 2014, file No. 001-36340).
3.14	—	Eighth Amended and Restated Agreement of Limited Partnership of EnLink Midstream Partners, LP, dated as of January 7, 2016 (incorporated by reference to Exhibit 3.1 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated January 12, 2016, filed with the Commission on January 12, 2016, file No. 001-36340).
4.1	—	Registration Rights Agreement, dated as of March 7, 2014, by and among Devon Gas Services, L.P. and EnLink Midstream, LLC (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K dated March 7, 2014, filed with the Commission on March 11, 2014, file No. 001-36336).
4.2	—	Registration Rights Agreement, dated as of January 7, 2016, by and between EnLink Midstream Partners, LP and Enfield Holdings, L.P. (incorporated by reference to Exhibit 4.1 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated January 12, 2016, filed with the Commission on January 12, 2016).
4.3	—	Registration Rights Agreement, dated as of January 7, 2016, by and among EnLink Midstream, LLC, Tall Oak Midstream, LLC and FE-STACK, LLC (incorporated by reference to Exhibit 4.2 to our Current Report on Form 8-K dated January 12, 2016, filed with the Commission on January 12, 2016, file No. 001-36336).
4.4	—	Unitholder Agreement, dated as of March 7, 2014, by and among Devon Energy Corporation, Devon Gas Corporation, Devon Gas Services, L.P., Southwestern Gas Pipeline, Inc. and EnLink Midstream Partners, LP (incorporated by reference to Exhibit 4.1 to EnLink Midstream Partner’s Current Report on Form 8-K dated March 6, 2014, filed with the Commission on March 11, 2014), file No. 001-36340).
4.5	—	Specimen Certificate representing common units (incorporated by reference to Exhibit 5 to our Registration Statement on Form 8-A, file No. 001-36336).
4.6	—	Indenture, dated as of March 19, 2014, by and between EnLink Midstream Partners, LP and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.2 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated March 19, 2014, filed with the Commission on March 21, 2014, file No. 001-36340).
4.7	—	First Supplemental Indenture, dated as of March 19, 2014, by and between EnLink Midstream Partners, LP and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.3 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated March 19, 2014, filed with the Commission on March 21, 2014, file No. 001-36340).
4.8	—	Second Supplemental Indenture, dated as of November 12, 2014, by and between EnLink Midstream Partners, LP and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.3 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated November 6, 2014, filed with the Commission on November 12, 2014, file No. 001-36340).
4.9	—	Third Supplemental Indenture, dated as of May 12, 2015, by and between EnLink Midstream Partners, LP and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.3 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated May 7, 2015, filed with the Commission on May 12, 2015).
4.10	—	Fourth Supplemental Indenture, dated as of July 14, 2016, by and between EnLink Midstream Partners, LP and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.2 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated July 11, 2016, filed with the Commission on July 14, 2016, file No. 001-36340).
4.11	—	Indenture governing the 7 ⅛% senior unsecured notes due 2022, dated as of May 24, 2012, by and among Crosstex Energy, L.P., Crosstex Energy Finance Corporation, the Guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated May 23, 2012, filed with the Commission on May 24, 2012, file No. 000-50067).
10.1	—	First Offer Agreement, dated as of March 7, 2014, by and between EnLink Midstream, LLC and Devon Energy Corporation (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K dated March 7, 2014, filed with the Commission on March 11, 2014, file No. 001-36336).
10.2	—	Preferential Rights Agreement, dated as of March 7, 2014, by and among Crosstex Energy, Inc., EnLink Midstream Partners, LP and EnLink Midstream, LLC (incorporated by reference to Exhibit 10.1 to EnLink Midstream Partner LP’s Current Report on Form 8-K dated March 6, 2014, filed with the Commission on March 11, 2014, file No. 001-36340).

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10.3		—	Gas Gathering and Processing Contract-Bridgeport Plant, dated as of March 7, 2014, by and between Devon Gas Services, L.P. and EnLink Midstream Services, LLC (incorporated by reference to Exhibit 10.2 to EnLink Midstream Partner LP’s Current Report on Form 8-K dated March 6, 2014, filed with the Commission on March 11, 2014, file No. 001-36340).
10.4		—	Gas Gathering and Processing Contract-Northridge Plant, dated as of March 7, 2014, by and between Devon Gas Services, L.P. and EnLink Midstream Services, LLC (incorporated by reference to Exhibit 10.4 to EnLink Midstream Partner LP’s Current Report on Form 8-K dated March 6, 2014, filed with the Commission on March 11, 2014, file No. 001-36340).
10.5		—	Gas Gathering and Processing Contract-East Johnson County System, dated as of March 7, 2014, by and between Devon Gas Services, L.P. and EnLink Midstream Services, LLC (incorporated by reference to Exhibit 10.5 to EnLink Midstream Partner LP’s Current Report on Form 8-K dated March 6, 2014, filed with the Commission on March 11, 2014, file No. 001-36340).
10.6		—	Form of Indemnification Agreement (incorporated by reference to Exhibit 10.6 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated March 6, 2014, filed with the Commission on March 11, 2014, file No. 001-36340).
10.7		—	Form of Indemnification Agreement (incorporated by reference to Exhibit 10.8 to our Current Report on Form 8-K dated March 7, 2014, filed with the Commission on March 11, 2014, file No. 001-36336).
10.8	†	—	EnLink Midstream GP, LLC Long-Term Incentive Plan, as amended and restated in 2016 (incorporated by reference to Exhibit 10.1 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated March 9, 2016, filed with the Commission on March 9, 2016, file No. 001-36340).
10.9	†	—	EnLink Midstream, LLC 2014 Long-Term Incentive Plan (incorporated by reference to Exhibit 4.4 to our Registration Statement on Form S-8 dated March 7, 2014, filed with the Commission on March 7, 2014 file No. 333-194395).
10.10	†	—	Form of Severance Agreement (incorporated by reference to Exhibit 10.1 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated September 17, 2014, filed with the Commission on September 23, 2014, file No. 001-36340).
10.11	†	—	Form of Amended and Restated Severance Agreement (incorporated by reference to Exhibit 10.1 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated October 31, 2014, filed with the Commission on November 3, 2014, file No. 001-36340).
10.12		—	Form of Amended and Restated Change in Control Agreement (incorporated by reference to Exhibit 10.1 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated June 12, 2015, filed with the Commission June 15, 2015).
10.13	†	—	Form of Restricted Incentive Unit Agreement made under the 2014 Plan (Executive Form) (incorporated by reference to Exhibit 4.6 to our Registration Statement on Form S-8, file No. 333-194395).
10.14	†	—	Form of Restricted Incentive Unit Agreement made under the 2014 Plan (Employee Form) (incorporated by reference to Exhibit 4.6 to our Registration Statement on Form S-8, file No. 333-194395).
10.15	†	—	Form of Restricted Unit Agreement made under the GP Plan (incorporated by reference to Exhibit 10.9 to our Annual Report on Form 10-K for the year ended December 31, 2009, file No. 000-50067).
10.16		—	Form of Restricted Incentive Unit Agreement made under the GP Plan (incorporated by reference to Exhibit 10.2 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated May 9, 2013, filed with the Commission on May 13, 2013, file No. 000-50067).
10.17		—	Credit Agreement, dated as of March 7, 2014, among EnLink Midstream, LLC, Bank of America, N.A., as Administrative Agent, Swing Line Lender and L/C Issuer thereunder, Citibank, N.A. and Wells Fargo Bank, National Association, as Co-Syndication Agents, Royal Bank of Canada and Bank of Montreal, as Co-Documentation Agents, and the other lenders party thereto (incorporated by reference to Exhibit 10.7 to our Current Report on Form 8-K dated March 7, 2014, filed with the Commission on March 11, 2014, file No. 001-36336).
10.18		—	First Amendment to Credit Agreement and Waiver, dated as of December 23, 2015, by and among EnLink Midstream, LLC, Bank of America, N.A., as Administrative Agent, and the lenders party thereto (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K dated December 29, 2015, filed with the Commission on December 29, 2015, file No. 001-36336).
10.19		—	Credit Agreement, dated as of February 20, 2014, by and among Crosstex Energy, L.P., Bank of America, N.A., as Administrative Agent, Swing Line Lender and L/C Issuer thereunder, Citibank, N.A. and Wells Fargo Bank, National Association, as Co-Syndication Agents, Royal Bank of Canada and Bank of Montreal, as Co-Documentation Agents, and the other lenders party thereto (incorporated by reference to Exhibit 10.1 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated February 20, 2014, filed with the Commission on February 21, 2014, file No. 000-50067).

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10.20		—	First Amendment to Credit Agreement, dated as of December 23, 2015, by and among EnLink Midstream Partners, LP, Bank of America, N.A., as Administrative Agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated December 29, 2015, filed with the Commission on December 29, 2015, file No. 001-36340).
10.21	†	—	Form of Performance Unit Agreement made under the GP Plan (incorporated by reference to Exhibit 10.1 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated January 30, 2015, filed with the Commission February 5, 2015, file No. 001-36340).
10.22	†	—	Form of Performance Unit Agreement made under the 2014 Plan (incorporated by reference to Exhibit 10.2 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated January 30, 2015, filed with the Commission February 5, 2015, file No. 001-36340).
10.23	†	—	Form of Restricted Incentive Unit Agreement made under the GP Plan (incorporated by reference to Exhibit 10.3 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated January 30, 2015, filed with the Commission February 5, 2015, file No. 001-36340).
10.24	†	—	Form of Restricted Incentive Unit Agreement made under the 2014 Plan (incorporated by reference to Exhibit 10.4 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated January 30, 2015, filed with the Commission February 5, 2015, file No. 001-36340).
10.25		—	Commitment Increase and Extension Agreement, dated as of February 5, 2015, by and among EnLink Midstream Partners, LP, the Lenders party thereto, and Bank of America, N.A., as an L/C Issuer, as Swing Line Lender, and as Administrative Agent for the Lenders (incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K dated February 5, 2015, filed with the Commission on February 11, 2015, file No. 001-36340).
10.26		—	Convertible Preferred Unit Purchase Agreement, dated as of December 6, 2015, by and between EnLink Midstream Partners, LP and Enfield Holdings, L.P. (incorporated by reference to Exhibit 2.1 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated December 7, 2015, filed with the Commission on December 7, 2015, file No. 001-36340).
10.27		—	Board Representation Agreement, dated as of January 7, 2016, by and among EnLink Midstream GP, LLC, EnLink Midstream Partners, LP, EnLink Midstream, Inc. and TPG VII Management, LLC (incorporated by reference to Exhibit 10.1 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated January 12, 2016, filed with the Commission on January 12, 2016, file No. 001-36340).
21.1	*	—	List of Subsidiaries.
23.1	*	—	Consent of KPMG LLP.
31.1	*	—	Certification of the Principal Executive Officer.
31.2	*	—	Certification of the Principal Financial Officer.
32.1	*	—	Certification of the Principal Executive Officer and the Principal Financial Officer of the Partnership pursuant to 18 U.S.C. Section 1350.
101	*	—	The following financial information from EnLink Midstream, LLC’s Annual Report on Form 10-K for the year ended December 31, 2016, formatted in XBRL (eXtensible Business Reporting Language): (i) Consolidated Statements of Operations for the years ended December 31, 2015, 2014 and 2013, (ii) Consolidated Balance Sheets as of December 31, 2016 and 2015, (iii) Consolidated Statements of Cash Flows for the years ended December 31, 2016, 2015 and 2014, (iv) Consolidated Statements of Changes in Members’ Equity for the years ended December 31, 2016, 2015 and 2014 and (v) the Notes to Consolidated Financial Statements.

* Filed herewith.

** In accordance with the instruction on Item 601(b)(2) of Regulation S-K, the exhibits and schedules to Exhibits 2.1 and 2.2 are not filed herewith. The agreements identify such exhibits and schedules, including the general nature of their content. We undertake to provide such exhibits and schedules to the Commission upon request.

† As required by Item 15(a)(3), this Exhibit is identified as a compensatory benefit plan or arrangement.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 15th day of February 2017.

	ENLINK MIDSTREAM, LLC

	By:	EnLink Midstream Manager, LLC, its managing member

	By:	/s/ BARRY E. DAVIS
		Barry E. Davis,
		Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below on the dates indicated by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.


Signature	Title	Date

/s/ BARRY E. DAVIS	Chief Executive Officer and Chairman of the Board	February 15, 2017
Barry E. Davis	(Principal Executive Officer)

/s/ SUE ALBERTI	Director	February 15, 2017
Sue Alberti

/s/ JAMES C. CRAIN	Director	February 15, 2017
James C. Crain

/s/ LELDON E. ECHOLS	Director	February 15, 2017
Leldon E. Echols

/s/ ROLF A. GAFVERT	Director	February 15, 2017
Rolf A. Gafvert

/s/ DAVID A. HAGER	Director	February 15, 2017
David A. Hager

/s/ THOMAS L. MITCHELL	Director	February 15, 2017
Thomas L. Mitchell

/s/ MARY P. RICCIARDELLO	Director	February 15, 2017
Mary P. Ricciardello

/s/ LYNDON C. TAYLOR	Director	February 15, 2017
Lyndon C. Taylor

/s/ MICHAEL J. GARBERDING	President and Chief Financial Officer	February 15, 2017
Michael J. Garberding	(Principal Financial and Accounting Officer)

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ENLINK MIDSTREAM, LLC (PARENT COMPANY)

The condensed parent only financial statements represent the financial information required by Rule 5-04 of the Securities and Exchange Commission Regulation S-X for the Company.

In the condensed financial statements, the Company’s investment in both the Partnership and EnLink Oklahoma T.O. is presented under the equity method of accounting. Under this method, the assets and liabilities of the Partnership and EnLink Oklahoma T.O. are not consolidated. The investment in the Partnership and EnLink Oklahoma T.O. is recorded as investment in unconsolidated affiliate investments in the balance sheet. The income (loss) from the Partnership and EnLink Oklahoma T.O. is reported as income (loss) from unconsolidated affiliate investments.

All financial results prior to March 7, 2014 reflect the historical operations of Midstream Holdings and its majority-owned subsidiaries.

The condensed financial statements should be read in conjunction with the Company’s consolidated financial statements, which are contained in “Item 8. Financial Statements and Supplementary Schedules” of this Annual Report.

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Schedule 1

ENLINK MIDSTREAM, LLC (PARENT COMPANY)

CONDENSED BALANCE SHEET


	December 31,
	2016		2015
	(In millions)
ASSETS
Current assets:
Cash and cash equivalents	$	0.1	$	12.1
Accounts receivable		—		0.1
Related party receivable		—		2.1
Prepaid expenses and other		2.6		9.7
Total current assets		2.7		24.0
Goodwill		1,119.9		1,426.9
Investment in unconsolidated affiliate investments		1,255.7		1,292.9
Other assets, net		—		0.8
Total assets	$	2,378.3	$	2,744.6
LIABILITIES AND MEMBERS' EQUITY
Current liabilities:
Other current liabilities	$	0.5	$	0.4
Total current liabilities		0.5		0.4
Deferred tax liability		469.6		458.5
Long-Term Debt		27.3		—
		497.4		458.9
Members' equity:
Members' equity		1,880.9		2,285.7
Total liabilities and members' equity	$	2,378.3	$	2,744.6

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ENLINK MIDSTREAM, LLC (PARENT COMPANY)

CONDENSED STATEMENT OF OPERATIONS


	Year Ended December 31,
	2016		2015		2014
	(In millions, except per share data)
Revenues:
Income (loss) from unconsolidated affiliate investments	$	(145.1)	$	(325.5)	$	185.7
Total revenues		(145.1)		(325.5)		185.7
Operating costs and expenses:
General and administrative expenses		3.1		4.5		3.0
Impairment		307.0		—		—
Total operating costs and expenses		310.1		4.5		3.0
Operating income (loss)		(455.2)		(330.0)		182.7
Other income (expense):
Interest and other expense		(1.4)		(0.8)		(2.4)
Income (loss) before income taxes		(456.6)		(330.8)		180.3
Income tax provision		(3.4)		(26.2)		(54.3)
Net income (loss)	$	(460.0)	$	(357.0)	$	126.0
Net income (loss) attributable to EnLink Midstream, LLC per unit:
Basic	$	(2.56)	$	(2.17)	$	0.55
Diluted	$	(2.56)	$	(2.17)	$	0.55
Weighted average common units outstanding:
Basic		179.7		164.2		164.0
Diluted		179.7		164.2		164.3

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ENLINK MIDSTREAM, LLC (PARENT COMPANY)

CONDENSED STATEMENT OF CASH FLOWS


	Year Ended December 31,
	2016		2015
	(In millions)
Cash flows from operating activities:
Net income (loss)	$	(460.0)	$	(357.0)
Adjustments to reconcile net income (loss) to net cash used in operating activities:
(Income) loss from unconsolidated affiliate investments		145.1		325.5
Deferred tax expense		2.8		23.9
Stock-based compensation		0.4		0.4
Amortization of debt issue cost		0.1		0.3
Impairments		307.0		—
Changes in assets and liabilities:
Accounts receivable, prepaid expenses and other		10.7		(8.5)
Accounts payable, and other accrued liabilities		0.1		(1.8)
Net cash used in operating activities		6.2		(17.2)
Cash flows from investing activities:
Acquisition of business		(237.1)		—
Distributions from the affiliates		202.3		186.3
Investment in unconsolidated affiliate investment		(39.5)		(50.0)
Net cash provided by investing activities		(74.3)		136.3
Cash flows from financing activities:
Proceeds from borrowings		92.7		—
Payments on borrowings		(64.9)		—
Debt refinancing cost		—		(0.1)
Conversion of restricted units, net of units withheld for taxes		(1.2)		(2.9)
Proceeds from issuance of common units		214.9
Distribution to members		(185.4)		(162.8)
Net cash used in financing activities		56.1		(165.8)
Net increase (decrease) in cash and cash equivalents		(12.0)		(46.7)
Cash, beginning of year		12.1		58.8
Cash, end of year	$	0.1	$	12.1
Non-cash transactions:
Gain (loss) from issuance of Partnership units	$	18.9	$	13.7

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