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

 

OR

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

 

For the transition period from                    to

 

Commission file number: 001-36336

 

ENLINK MIDSTREAM, LLC

(Exact name of registrant as specified in its charter)

 

 

(Registrant's telephone number, including area code)

(214) 953-9500

 

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

 

 

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):

 

 

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.

 

 

 

TABLE OF CONTENTS

 

 

 

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.

 

 

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:

 

 

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:

 

 

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.

 

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

 

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 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’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’s operations are based in the United States and its sales are derived primarily from external domestic customers.

 

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:

 

 

 

 

 

 

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:

 

 

 

 

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:

 

 

 

 

 

 

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.”

 

The Partnership’s Contractual Relationship with Devon

 

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

 

 

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:

 

 

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.

 

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.

 

 

 

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

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

 

 

 

 

 

 

 

 

 

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:

 

 

 

 

 

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. 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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.

 

 

 

 

 

 

 

 

 

 

 

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.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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.

 

 

 

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.

 

 

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.

 

 

 

 

Industry Overview

 

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

 

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

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

 

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

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

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.

 

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

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

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

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.

 

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

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

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.

 

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:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

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:

 

 

 

 

 

 

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:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

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:

 

 

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

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:

 

 

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:

 

 

 

 

 

 

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

 

Our cash flow consists almost exclusively of 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:

 

 

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:

 

 

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

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:

 

 

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.

 

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:

 

 

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

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:

 

 

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

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

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:

 

 

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

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.

 

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:

 

 

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.

 

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:

 

 

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:

 

 

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.

 

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:

 

 

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:

 

 

 

 

 

 

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.

 

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:

 

 

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.

 

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.

 

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.

 

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.

 

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, 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

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

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:

 

 

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.

 

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