SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
ý ANNUAL REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2017
¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission file number: 001-36340
ENLINK MIDSTREAM PARTNERS, LP
(Exact name of registrant as specified in its charter)
(State of organization)
(I.R.S. Employer Identification No.)
1722 Routh St., Suite 1300
(Address of principal executive offices)
(Registrant’s telephone number, including area code)
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
Title of Each Class
Name of Exchange on which Registered
Common Units Representing Limited
The New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None.
Indicate by check mark if registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x No ¨
Indicate by check mark if registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No x
Indicate by check mark whether registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Securities Exchange Act. (Check one):
Large accelerated filer x
Accelerated filer ¨
Non-accelerated filer ¨ (Do not check if a smaller reporting company)
Smaller reporting company ¨
Emerging growth company ¨
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ¨ No x
The aggregate market value of the common units representing limited partner interests held by non-affiliates of the registrant was approximately $2.8 billion on June 30, 2017, based on $16.96 per unit, the closing price of the common units as reported on the New York Stock Exchange on such date.
At February 14, 2018, there were 350,022,931 common units outstanding.
DOCUMENTS INCORPORATED BY REFERENCE:
TABLE OF CONTENTS
UNRESOLVED STAFF COMMENTS
MINE SAFETY DISCLOSURES
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
SELECTED FINANCIAL DATA
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
CONTROLS AND PROCEDURES
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
PRINCIPAL ACCOUNTING FEES AND SERVICES
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
The following terms as defined generally are used in the energy industry and in this document:
/d = per day
Bbls = barrels
Bcf = billion cubic feet
CO2= Carbon dioxide
CPI= Consumer Price Index
HP = horsepower
MMBtu = million British thermal units
MMcf = million cubic feet
NGL = natural gas liquid
Capacity volumes for our facilities are measured based on physical volume and stated in cubic feet (“Bcf”, “Mcf” or “MMcf”). Throughput volumes are measured based on energy content and stated in British thermal units (“Btu” or “MMBtu”). A volume of capacity of 100 MMcf correlates to an approximate energy content of 100,000 MMBtu, although this correlation will vary depending on the composition of natural gas and is typically higher for unprocessed gas, which contains a higher concentration of NGLs. Fractionated volumes are measured based on physical volumes and stated in gallons. Crude oil, condensate and brine services volumes are measured based on physical volume and stated in barrels (“Bbls”).
We define “gross operating margin,” a non-GAAP financial measure, as revenues less cost of sales. We disclose gross operating margin in addition to total revenue because it is the primary performance measure used by our management. We believe gross operating margin is an important measure because, in general, our business is to purchase and resell natural gas, NGLs, condensate and crude oil for a margin and to gather, process, store, transport or market natural gas, NGLs, condensate and crude oil for a fee. The GAAP measure most directly comparable to gross operating margin is operating income (loss). For more information on gross operating margin, including its limitations as a financial measure, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures.”
ENLINK MIDSTREAM PARTNERS, LP
Item 1. Business
EnLink Midstream Partners, LP is a publicly traded Delaware limited partnership formed in 2002. Our common units are traded on the New York Stock Exchange (“NYSE”) under the symbol “ENLK.” Our business activities are conducted through our subsidiary, EnLink Midstream Operating, LP, a Delaware limited partnership (the “Operating Partnership”), and the subsidiaries of the Operating Partnership. Our executive offices are located at 1722 Routh Street, Suite 1300, Dallas, Texas 75201, and our telephone number is (214) 953-9500. Our Internet address is www.enlink.com. We post the following filings in the “Investors” section of our website as soon as reasonably practicable after they are electronically filed with or furnished to the Securities and Exchange Commission (“SEC”): 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. In this report, the terms “Partnership,” “ENLK” and “Registrant,” as well as the terms “our,” “we,” “us” and “its,” are sometimes used as abbreviated references to EnLink Midstream Partners, LP itself or EnLink Midstream Partners, LP together with its consolidated subsidiaries, including the Operating Partnership.
EnLink Midstream GP, LLC, a Delaware limited liability company, is our general partner. Our general partner manages our operations and activities. Our general partner is an indirect, wholly-owned subsidiary of EnLink Midstream, LLC (“ENLC” or “EnLink Midstream”). ENLC’s units are traded on the NYSE under the symbol “ENLC.” ENLC’s manager is an indirect, wholly-owned subsidiary of Devon Energy Corporation (“Devon”).
Effective as of March 7, 2014, the Operating Partnership acquired (the “Acquisition”) 50% of the outstanding equity interests in EnLink Midstream Holdings, LP (“Midstream Holdings”) and all of the outstanding equity interests in EnLink Midstream Holdings GP, LLC, the general partner of Midstream Holdings, in exchange for the issuance by us of 120,542,441 units representing a new class of limited partnership interests in our partnership. At the same time, EnLink Midstream, Inc. (“EMI”), the entity that directly owns our general partner, became a wholly-owned subsidiary of ENLC (together with the Acquisition, the “Business Combination”). At the conclusion of the Business Combination, another wholly-owned subsidiary of ENLC, Acacia Natural Gas Corp. I, Inc. (“Acacia”), owned the remaining 50% of the outstanding equity interests in Midstream Holdings. In 2015, Acacia contributed the remaining 50% interest in Midstream Holdings to us in exchange for 68.2 million units of our limited partnership interests in two separate drop down transactions, with 25% contributed in February 2015 and 25% contributed in May 2015 (the “EMH Drop Downs”). After giving effect to the EMH Drop Downs, we own 100% of Midstream Holdings.
Midstream Holdings was formerly a wholly-owned subsidiary of Devon, and it gathers, processes and transports natural gas, primarily for Devon. Midstream Holdings also fractionates NGLs into component NGL products. Under the acquisition method of accounting, Midstream Holdings is considered the historical predecessor of our business because Devon obtained control of us through its control of ENLC and through the indirect acquisition of our general partner.
On January 7, 2016, EnLink Oklahoma Gas Processing, LP (“EnLink Oklahoma T.O.”), an indirect subsidiary of ENLK, completed its acquisition of 100% of the issued and outstanding membership interests of TOMPC LLC and TOM-STACK, LLC. EnLink Oklahoma T.O. is sometimes used herein to refer to EnLink Oklahoma Gas Processing, LP itself or EnLink Oklahoma Gas Processing, LP, together with its consolidated subsidiaries. As a result of the acquisition, the Operating Partnership owns an 83.9% limited partnership interest in EnLink Oklahoma T.O., and EMI owns a 16.1% limited partnership interest in EnLink Oklahoma T.O. In addition, EnLink Energy GP, LLC, the general partner of EnLink Oklahoma T.O. and an indirect subsidiary of our partnership, owns the non-economic general partnership interest.
The following diagram depicts our organization and ownership as of December 31, 2017:
The general partner (“GP”) ownership percentage for EnLink Midstream Partners, LP accounts for general partner units, while the limited partner (“LP”) ownership percentages for EnLink Midstream Partners, LP account for ENLK common units and Series B Preferred Units (as defined below), which are convertible into ENLK common units on a one-for-one basis, subject to certain adjustments.
Series C Preferred Units (as defined below) are perpetual preferred units that are not convertible into ENLK common units, and therefore, are not factored into the EnLink Midstream Partners, LP ownership calculations for the limited partner and general partner ownership percentages presented.
We primarily focus on providing midstream energy services, including:
gathering, compressing, treating, processing, transporting, storing and selling natural gas;
fractionating, transporting, storing, exporting and selling NGLs; and
gathering, transporting, stabilizing, storing, trans-loading and selling crude oil and condensate.
Our midstream energy asset network includes approximately 11,000 miles of pipelines, 20 natural gas processing plants with approximately 4.8 Bcf/d of processing capacity, 7 fractionators with approximately 260,000 Bbls/d of fractionation capacity, barge and rail terminals, product storage facilities, purchasing and marketing capabilities, brine disposal wells, a crude
oil trucking fleet, and equity investments in certain joint ventures. Our operations are based in the United States, and our sales are derived primarily from domestic customers.
We connect the wells of producers in our market areas to our gathering systems, which consist of networks of pipelines that collect natural gas from points near producing wells and transport it to our processing plants or to larger pipelines for further transmission. We operate processing plants that remove NGLs from the natural gas stream that is transported to the processing plants by our own gathering systems or by third-party pipelines. In conjunction with our gathering and processing business, we may purchase natural gas and NGLs from producers and other supply sources and sell that natural gas or NGLs to utilities, industrial consumers, other markets and pipelines. Our transmission pipelines receive natural gas from our gathering systems and from third-party gathering and transmission systems and deliver natural gas to industrial end-users, utilities and other pipelines.
Our fractionators separate NGLs into separate purity products, including ethane, propane, iso-butane, normal butane and natural gasoline. Our fractionators receive NGLs primarily through our transmission lines that transport NGLs from East Texas and from our South Louisiana processing plants, and our fractionators also have the capability to receive NGLs by truck or rail terminals. We also have agreements pursuant to which third parties transport NGLs from our West Texas and Central Oklahoma operations to our NGL transmission lines that then transport the NGLs to our fractionators. In addition, we have NGL storage capacity to provide storage for customers.
Our crude oil and condensate business includes gathering and transmission via pipelines, barges, rail and trucks, condensate stabilization and brine disposal. We may purchase crude oil and condensate from producers and other supply sources and sell that crude oil and condensate through our terminal facilities that provide market access.
Across our businesses, we primarily earn our fees through various fee-based contractual arrangements, which include stated fee-only contract arrangements or arrangements with fee-based components where we purchase and resell commodities in connection with providing the related service and earn a net margin as our fee. We earn our net margin under our purchase and resell contract arrangements primarily as a result of stated service-related fees that are deducted from the price of the commodities purchased. While our transactions vary in form, the essential element of each transaction is the use of our assets to transport a product or provide a processed product to an end-user or other marketer or pipeline at the tailgate of the plant, barge terminal or pipeline.
Our assets are included in five primary segments:
Texas Segment. The Texas segment includes our natural gas gathering, processing and transmission operations in North Texas and the Midland and Delaware Basins (together, the “Permian Basin”) in West Texas;
Oklahoma Segment. The Oklahoma segment includes our natural gas gathering, processing and transmission activities in Cana-Woodford, Arkoma-Woodford, Northern Oklahoma Woodford, Sooner Trend Anadarko Basin Canadian and Kingfisher Counties (“STACK”) and Central Northern Oklahoma Woodford (“CNOW”) shale areas;
Louisiana Segment. The Louisiana segment includes our natural gas pipelines, natural gas processing plants, gas and NGL storage facilities, fractionation facilities and NGL pipelines located in Louisiana;
Crude and Condensate Segment. The Crude and Condensate segment includes our crude oil operations in the Permian Basin and Central Oklahoma, our Ohio River Valley (“ORV”) crude oil, condensate stabilization, natural gas compression and brine disposal activities in the Utica and Marcellus Shales and our crude oil activities associated with our Victoria Express Pipeline and related truck terminal and storage assets (“VEX”) located in the Eagle Ford Shale; and
Corporate Segment. The Corporate segment includes our unconsolidated affiliate investments in the Cedar Cove joint venture (“Cedar Cove JV”) in Oklahoma, our contractual right to the economic benefits and burdens associated with Devon’s 38.75% ownership interest in Gulf Coast Fractionators (“GCF”) and our general corporate property and expenses.
For more information about our segment reporting, see “Item 8. Financial Statements and Supplementary Data—Note 15.”
Devon (NYSE: DVN) is a leading independent energy company engaged primarily in the exploration, development and production of crude oil, natural gas and NGLs. Devon’s operations are concentrated in various onshore areas in the U.S. and Canada. Please see Devon’s Annual Report on Form 10-K for the year ended December 31, 2017 (the “Devon Annual Report”) for additional information concerning Devon’s business. The information contained in the Devon Annual Report is not incorporated by reference into this Annual Report on Form 10-K and should not be considered part of this or any other report that we file with or furnish to the SEC.
Our Business Strategies
Our primary business objective is to provide cash flow stability in our business while growing prudently and profitably. We intend to accomplish this objective by executing the following strategies:
Execute in our core growth areas. We believe our assets are positioned in some of the most economically advantageous basins in the U.S., as well as key demand centers with growing end-use customers. We expect to grow certain of our systems organically over time by meeting our customers’ midstream service needs that result from their drilling activity in our areas of operation or growth in supply needs. We continually evaluate economically attractive organic expansion opportunities in our areas of operation that allow us to leverage our existing infrastructure, operating expertise and customer relationships by constructing and expanding systems to meet new or increased demand for our services.
Maintain a strong financial position. We believe that maintaining a conservative and balanced capital structure, appropriate leverage and other key financial metrics will afford us better access to the capital markets at a competitive cost of capital. We also believe a strong financial position provides us the opportunity to grow our business in a prudent manner throughout the cycles in our industry.
Maintain stable cash flows supported by long-term, fee-based contracts. We will seek to generate cash flows pursuant to long-term, firm contracts with creditworthy customers. We will continue to pursue opportunities to increase the fee-based components of our contract portfolio to minimize our direct commodity price exposure.
Our Competitive Strengths
We believe that we are well-positioned to execute our strategies and to achieve our primary business objective due to the following competitive strengths:
Devon’s sponsorship. We expect our relationship with Devon will continue to provide us with significant business opportunities. Devon is one of the largest independent oil and gas producers in North America. Devon has a significant interest in promoting the success of our business, due to its 64.0% direct ownership interest in ENLC and 23.1% direct ownership interest in ENLK as of December 31, 2017. Approximately 46.8% of our gross operating margin for the year ended December 31, 2017 was attributable to commercial contracts with Devon.
Strategically-located assets. The majority of our assets are strategically located in economically advantageous regions with the potential for increasing throughput volume and cash flow generation. Our asset portfolio includes gathering, transmission, fractionation, and processing systems that are located in the areas in which producer activity is focused on crude oil, condensate and NGLs, as well as natural gas. We have established platforms in Texas, Oklahoma and Louisiana, and we are focused on growing our operations in Central Oklahoma, the Permian Basin and southern Louisiana through organic development and acquisitions.
Stable cash flows. Approximately 94% of our gross operating margin for the year ended December 31, 2017 was generated from fee-based contract arrangements with minimal direct commodity price exposure. In addition, our cash flows are generated across a variety of products, services and geographic locations and through transactions with a strong portfolio of customers with investment-grade credit ratings. We have approximately six years remaining on fixed-fee gathering and processing agreements with a subsidiary of Devon pursuant to which we provide gathering, treating, compression, dehydration, stabilization, processing and fractionation services, as applicable, for natural gas delivered by Devon to our gathering and processing systems in the Barnett and Cana-Woodford Shales. These agreements provide us with dedication of all of the natural gas owned or controlled by Devon and produced from or attributable to existing and future wells located on certain oil, natural gas and mineral leases covering lands within the
acreage dedications, excluding properties previously dedicated to other natural gas gathering systems not owned and operated by Devon. These agreements also include minimum volume commitments (“MVCs”) that will remain in effect up to January 1, 2019. Additionally, our EnLink Oklahoma T.O. assets are supported by Devon with acreage dedications and MVCs for gathering and processing on Devon’s STACK acreage through 2021. For additional information, please read “Our Contractual Relationship with Devon.” We will continue to focus on contract structures that reduce volatility and support long-term stability of cash flows.
Integrated midstream services. We span the energy value chain by providing natural gas, NGL, crude oil and condensate services across a diverse customer base. These services include gathering, compressing, treating, processing, transporting, storing and selling natural gas, fractionating, transporting, storing, exporting and selling NGLs, and gathering, transporting, stabilizing, storing and trans-loading crude oil and condensate. We believe our ability to provide all of these services gives us an advantage in competing for new opportunities because we can provide substantially all services that producers, marketers and others require to move natural gas, NGLs, crude oil and condensate from the wellhead to the market on a cost-effective basis.
Experienced management team. Our management team has deep experience in the energy industry and has a proven track record of creating value through the development, acquisition, optimization and integration of midstream assets. We believe this team provides us with a strong foundation for evaluating growth opportunities and operating our assets in a safe, reliable and efficient manner.
We believe that we will leverage our competitive strengths to successfully implement our strategy; however, our business involves numerous risks and uncertainties that may prevent us from achieving our primary business objectives. For a more complete description of the risks associated with our business, please see “Item 1A. Risk Factors.”
Our Contractual Relationship with Devon
The following table includes our long-term, fixed-fee contracts with Devon:
Remaining Contract Term (Years)
Year Contract Entered Into
Gathering MVC (MMcf/d)
Processing MVC (MMcf/d)
Remaining MVC Term (Years)
Annual Rate Escalators
Bridgeport gathering and processing contract
Johnson County gathering contract
Cana gathering and processing contract
EnLink Oklahoma T.O. gathering and processing contract (1)
The gathering MVCs and processing MVCs under this contract escalate on a quarterly basis over the life of the five-year commitment, beginning with an average commitment of 37 MMcf/d during 2016 and ending with an average commitment of 230 MMcf/d during 2020.
In addition, we entered into to a five-year transportation MVC, which was executed in June 2014 and expires in July 2019, with Devon related to VEX. The MVC under the VEX contract averaged 25,000 Bbls/d during the first year and will average 30,000 Bbls/d for years two through five.
Recent Growth Developments
Central Oklahoma Plants. In 2017, we completed construction of two new cryogenic gas processing plants, which included the Chisholm II plant completed in April 2017 and the Chisholm III plant completed in December 2017. Each plant provides 200 MMcf/d of processing capacity and is connected to new and existing gathering pipeline and compression assets in the STACK play in Oklahoma. The new capacity is supported by new and existing long-term contracts.
In addition, we are constructing an additional 200 MMcf/d gas processing plant, referred to as the “Thunderbird plant” to expand our Central Oklahoma processing capacity. We expect to begin operations on the Thunderbird plant during the first quarter of 2019.
In June 2017, we entered into a long-term, fee-based arrangement with Oneok Partners (“Oneok”) under which Oneok transports NGLs from our Chisholm processing facility to the Gulf Coast and our Cajun-Sibon system. The agreement allows us to retain control of volumes and preferentially fill our Cajun-Sibon system.
Black Coyote Crude Oil Gathering System. In the fourth quarter of 2017, we began construction of a new crude oil gathering system that we refer to as “Black Coyote,” which will expand our operations in the core of the STACK play in Central Oklahoma. Black Coyote is being built primarily on acreage dedicated from Devon, which will be the main shipper on the system. The system is expected to be operational in the first quarter of 2018.
Lobo Natural Gas Gathering and Processing Facilities. The Lobo facilities are part of our joint venture (the “Delaware Basin JV”) with an affiliate of NGP Natural Resources XI, LP (“NGP”) and are supported by long-term contracts. In the first quarter of 2017, we completed the expansion of a 75-mile gathering system for our Lobo II processing facility. In the second quarter of 2017, we completed the construction of an expansion of the Lobo II processing facility, which provided an additional 60 MMcf/d of processing capacity to the existing 95 MMcf/d provided by the Lobo processing facilities. Furthermore, we are constructing an additional expansion of the Lobo II processing facility, which will increase capacity by 15 MMcf/d and is expected to be completed during the first half of 2018. In 2018, we will also expand our gas processing capacity at our Lobo facilities by 200 MMcf/d through the construction of the Lobo III cryogenic gas processing plant, which is expected to be operational around the second half of 2018.
Greater Chickadee Crude Oil Gathering System. In March 2017, we completed construction and began operations of a crude oil gathering system in Upton and Midland counties, Texas in the Permian Basin, which we refer to as “Greater Chickadee.” Greater Chickadee includes over 185 miles of high- and low-pressure pipelines that transport crude oil volumes to several major market outlets and other key hub centers in the Midland, Texas area and is supported by long-term contracts. Greater Chickadee also includes multiple central tank batteries, together with pump, truck injection and storage stations to maximize shipping and delivery options for our producer customers.
Marathon Petroleum Joint Venture. In April 2017, we completed construction and began operating a new NGL pipeline, which is part of our 50/50 joint venture with a subsidiary of Marathon Petroleum Company (“Marathon Petroleum”). This joint venture, Ascension Pipeline Company, LLC (the “Ascension JV”), is a bolt-on project to our Cajun-Sibon NGL system and is supported by long-term, fee-based contracts with Marathon Petroleum.
Sale of Non-Core Assets
In March 2017, we completed the sale of our ownership interest in HEP for net proceeds of $189.7 million. For the year ended December 31, 2016, we recorded an impairment loss of $20.1 million to reduce the carrying value of our investment to the expected sales price. Upon the sale of HEP in March 2017, we recorded an additional loss of $3.4 million for the year ended December 31, 2017 based on the adjusted sales price at closing.
Acquisitions, Organic Growth and Asset Sales in 2015 and 2016
In January 2015, we acquired 100% of the voting equity interests of LPC Crude Oil Marketing LLC (“LPC”), which has crude oil gathering, transportation and marketing operations in the Permian Basin, for approximately $108.1 million.
In March 2015, we acquired 100% of the voting equity interests in Coronado Midstream Holdings LLC (“Coronado”), which owns natural gas gathering and processing facilities in the Permian Basin, for approximately $600.3 million.
In April 2015, we acquired VEX, located in the Eagle Ford Shale in South Texas, together with 100% of the voting equity interests (the “VEX interests”) in certain entities, from Devon in a drop down transaction (the “VEX Drop Down”) for $166.7 million in cash and approximately $9.0 million in common units. Additionally, we assumed $40.0 million in construction costs related to VEX.
In October 2015, we acquired 100% of the voting equity interests in a subsidiary of Matador Resources Company (“Matador”), which has gathering and processing operations in the Delaware Basin, for approximately $141.3 million.
Prior to November 2015, we co-owned the Deadwood natural gas processing plant with a subsidiary of Apache Corporation (“Apache”). In November 2015, we acquired Apache’s 50% ownership interest in the Deadwood natural gas processing facility for approximately $40.1 million. We now own 100% of the Deadwood processing plant.
In 2015, we completed the EMH Drop Downs.
In January 2016, ENLK and ENLC acquired an 83.9% and 16.1% interest, respectively, in EnLink Oklahoma T.O. for aggregate consideration of approximately $1.4 billion. The EnLink Oklahoma T.O. assets serve gathering and processing needs in the growing STACK and CNOW plays in Central Oklahoma and are supported by long-term, fixed-fee contracts with acreage dedications that, at the time of acquisition, had a weighted-average term of approximately 15 years.
In April 2016, we completed construction of the 100 MMcf/d Riptide processing plant in the Permian Basin.
In August 2016, we formed the Delaware Basin JV with NGP to operate and expand our natural gas, natural gas liquids and crude oil midstream assets in the Delaware Basin. The Delaware Basin JV is owned 50.1% by us and 49.9% by NGP.
In October 2016, we completed construction of the initial phase of the 60 MMcf/d Lobo II processing facilities.
In November 2016, we formed the Cedar Cove JV with Kinder Morgan, Inc., which consists of gathering and compression assets in Blaine County, Oklahoma, located in the heart of the STACK play. The gathering system has a capacity of 25 MMcf/d with over 50,000 gross acres of dedications and ties into our existing Oklahoma assets. All gas gathered by the Cedar Cove JV is processed at our Central Oklahoma processing system. We hold a 30% ownership interest of the Cedar Cove JV, and Kinder Morgan, Inc. holds the remaining 70% ownership interest.
In December 2016, we sold the North Texas Pipeline (the “NTPL”), a 140-mile natural gas transportation pipeline, for $84.6 million. We maintain capacity on the NTPL at competitive rates and at levels sufficient to support current and expected operations. As a result of the sale, we recorded a loss of $13.4 million for the year ended December 31, 2016.
Our assets consist of gathering systems, transmission pipelines, processing facilities, fractionation facilities, stabilization facilities, storage facilities and ancillary assets. Except as stated otherwise, the following tables provide information about our assets as of and for the year ended December 31, 2017:
December 31, 2017
Gathering and Transmission Pipelines
Approximate Length (Miles)
Compression (HP) (1)
Estimated Capacity (2)
Average Throughput (3)
Bridgeport rich and lean gathering systems
Johnson County gathering system
Silver Creek gathering system
Acacia transmission system
North Texas assets
MEGA System gathering facilities
Lobo gathering system (4)
Permian Basin assets (4)
Central Oklahoma gathering system
Northridge gathering system
Louisiana gas gathering and transmission system
Total Gas Pipelines
NGL, Crude Oil and Condensate Pipelines
Cajun-Sibon pipeline system
Ascension pipeline (5)
Crude and condensate assets:
Ohio River Valley (6)
Victoria Express Pipeline
Permian gathering (7)
Total NGL, Crude Oil and Condensate Pipelines
Includes power generation units.
Estimated capacity for gas pipelines is MMcf/d. A volume capacity of 100 MMcf/d correlates to an approximate energy content of 100,000 MMBtu/d. Estimated capacity for liquids and crude and condensate pipelines is Bbls/d.
Average throughput for gas pipelines is MMBtu/d. Average throughput for NGL, crude and condensate pipelines is Bbls/d.
Includes gross mileage, compression, capacity and throughput for the Delaware Basin JV, which is owned 50.1% by us. Estimated capacity on our Lobo gathering system includes only the Delaware Basin JV’s compression capacity and does not include gas compressed by third parties on our system.
Includes gross mileage, capacity and throughput for the Ascension JV, which is owned 50% by us.
Estimated capacity is comprised of trucking capacity only.
Estimated capacity is comprised of 68,500 Bbls/d of pipeline capacity and 50,000 Bbls/d of trucking capacity.
December 31, 2017
Processing Capacity (MMcf/d)
Average Throughput (MMBtu/d)
Bridgeport processing facility
Silver Creek processing system
North Texas assets
MEGA system processing facilities
Lobo processing facilities
Permian Basin assets
Central Oklahoma processing facilities
Northridge processing facility
Louisiana gas processing facilities
Total Processing Facilities
December 31, 2017
Estimated NGL Fractionation Capacity (MBbls/d)
Average Throughput (Bbls/d)
Plaquemine fractionation facility (1)
Plaquemine processing plant
Eunice fractionation facility
Riverside fractionation facility (1)
Bridgeport processing facility (2)
Mesquite terminal (2)
Gulf Coast Fractionators (3)
Total Fractionation Facilities
The Plaquemine fractionation facility produces purity ethane and propane for sale to markets via pipeline, while butane and heavier products are sent to the Riverside fractionation facility for further processing. The Plaquemine fractionation facility and the Riverside fractionation facility have an aggregate fractionation capacity of 110 MBbls/d.
We have two fractionation facilities with capacity of 15 MBbls/d each. Our Mesquite terminal in the Permian Basin and our Bridgeport processing plant in North Texas provide operational flexibility for the related processing plants but are not the primary fractionation facilities for the NGLs produced by the processing plants. Under our current contracts, we do not earn fractionation fees for operating these facilities, so throughput volumes through these facilities are not captured on a routine basis and are not significant to our gross operating margins.
Volumes shown reflect only our contractual right to the benefits and burdens of a 38.75% economic interest in Gulf Coast Fractionators held by Devon.
Estimated Storage Capacity (1)
Belle Rose gas storage facility
Sorrento gas storage facility
Total gas storage
Napoleonville NGL storage facility
Crude oil storage:
Total crude oil storage
Estimated capacity for gas storage is Bcf, and includes linefill capacity necessary to operate storage facilities. Estimated capacity for NGL and crude oil storage is MMBbls.
Texas Assets. Our Texas assets include transmission pipelines, processing facilities and gathering systems in the Barnett Shale in North Texas and the Permian Basin in West Texas.
Acacia Transmission System. The Acacia transmission system is a pipeline that connects production from the Barnett Shale to markets in North Texas accessed by Atmos Energy, Brazos Electric, Enbridge Energy Partners, Energy Transfer Partners, Enterprise Product Partners and GDF Suez. Devon is the Acacia transmission system’s only customer with approximately six years remaining on a fixed-fee transportation agreement that covers transmission services and includes annual rate escalators.
Processing and Fractionation Facilities. Our processing facilities in Texas include 10 gas processing plants and consist of the following:
North Texas Assets. Our North Texas processing systems include the following:
Bridgeport processing facility. Our Bridgeport natural gas processing facility, located in Wise County, Texas, approximately 40 miles northwest of Fort Worth, Texas, is one of the largest processing plants in the U.S. with seven cryogenic turboexpander plants. Devon is the Bridgeport facility’s largest customer, providing substantially all of the natural gas processed for the year ended December 31, 2017. We currently have approximately six years remaining on a fixed-fee processing agreement with Devon pursuant to which we provide processing services for natural gas delivered by Devon to the Bridgeport processing facility. This contractual arrangement includes an MVC from Devon of 650 MMcf/d of natural gas delivered to the Bridgeport processing facility that will remain in effect up to January 1, 2019.
Silver Creek processing system. Our Silver Creek processing system, located in Weatherford, Azle and Fort Worth, Texas, includes three processing plants: the Azle plant, the Silver Creek plant and the Goforth plant, which account for 50 MMcf/d, 200 MMcf/d and 30 MMcf/d of processing capacity, respectively.
Permian Basin Assets. Our Permian Basin processing facilities consist of the following:
MEGA system processing facilities. Our Permian Basin processing plants are located in Midland, Martin, and Glasscock counties, Texas and operate as a connected system. These assets consist of the Bearkat processing facility with a capacity of 75 MMcf/d, the Deadwood processing facility with a capacity of 58 MMcf/d, the Midmar processing facilities with a capacity of 175 MMcf/d and the Riptide processing facility with a capacity of 100 MMcf/d (collectively, the “Midland Energy Gathering Area” or “MEGA system”).
Lobo processing facilities. Our Lobo natural gas processing facilities are located in Loving County, Texas and include two processing plants, the Lobo I plant and the Lobo II plant, which account for 35 MMcf/d and 120 MMcf/d of processing capacity, respectively. The Lobo processing facilities and the connected gathering system are owned by the Delaware Basin JV.
Gathering Systems. Our gathering systems in Texas are connected to our North Texas or Permian Basin processing assets.
North Texas Assets. Our North Texas gathering systems include the following:
Bridgeport rich gathering system. A substantial majority of the natural gas gathered on the Bridgeport rich gas gathering system is delivered to the Bridgeport processing facility. Devon is the largest customer on the Bridgeport rich gathering system contributing substantially all of the natural gas gathered for the year ended December 31, 2017. As described above, we currently have approximately six years remaining on a fixed-fee gathering agreement with Devon pursuant to which we provide gathering services on the Bridgeport system. The agreement includes an MVC from Devon that will remain in effect up to January 1, 2019, with a combined 850 MMcf/d of natural gas to be delivered for gathering into the Bridgeport rich and Bridgeport lean gathering systems.
Bridgeport lean gathering system. Natural gas gathered on the Bridgeport lean gathering system is all attributable to Devon and is delivered to the Acacia transmission system and to intrastate pipelines without processing. As described above, we are party to a fixed-fee gathering and processing agreement with Devon that covers gathering services on the Bridgeport system.
Johnson County gathering system. Natural gas gathered on this system is primarily attributable to Devon and is delivered to intrastate pipelines without processing. We currently have approximately six years remaining on a fixed-fee gathering agreement pursuant to which we provide gathering services on the Johnson County gathering system. This contractual arrangement includes an MVC from Devon that will remain in effect up to January 1, 2019, with 125 MMcf/d of natural gas to be delivered for gathering into the Johnson County gathering system.
Silver Creek gathering system. Our Silver Creek gathering system is located primarily in Hood, Parker and Johnson counties, Texas, and connects to the Silver Creek processing system.
Permian Basin assets. Our Permian Basin gathering systems include the following:
MEGA system gathering facilities. This gathering system in the Permian Basin serves as an interconnected system of pipelines and compressors to deliver gas from wellheads in the Permian Basin to the MEGA system processing facilities.
Lobo gathering system. The rich natural gas gathering system consists of gathering pipeline and compression assets in the Delaware Basin primarily in Texas, with a minor portion in New Mexico. The Lobo gathering system is owned by the Delaware Basin JV.
Oklahoma Assets. Our Oklahoma assets consist of processing facilities and gathering systems in southern and Central Oklahoma.
Oklahoma processing system. Our processing facilities include the following:
Central Oklahoma processing facilities. The Central Oklahoma plants include the Chisholm plants, the Battle Ridge plant and the Cana processing facilities (collectively, the “Central Oklahoma processing system”), which account for 520 MMcf/d, 85 MMcf/d and 400 MMcf/d of processing capacity, respectively. The residue natural gas from the Cana processing facility is delivered to Enable Midstream Partners and ONEOK. The unprocessed NGLs from the Chisholm facilities are transported by ONEOK to NGL transmission lines, which then transport the NGLs to our fractionators in Louisiana. Devon is the primary customer of the Cana processing facilities and has approximately six years remaining on a fixed-fee gathering and processing agreement with us pursuant to which we provide processing services for natural gas delivered by Devon to
the Cana processing facility. In addition, contractual arrangements related to the Central Oklahoma processing system that contain an MVC include the following:
Our contractual arrangement with Devon includes an MVC that will remain in effect until October 2020. For 2018, the MVC dictates that approximately 145 MMcf/d of natural gas will be delivered to the Chisholm plant processing facility. The MVC escalates quarterly, resulting in approximately 230 MMcf/d to be delivered in 2020.
We have another contractual arrangement with Devon that includes an MVC that will remain in effect up to January 1, 2019 with 330 MMcf/d of natural gas to be delivered to the Cana processing facility.
Northridge processing facility. Our Northridge processing plant is located in Hughes County in the Arkoma-Woodford Shale in southeastern Oklahoma. The residue natural gas from the Northridge processing facility is delivered to Centerpoint, Enable Midstream Partners and MPLX.
Oklahoma gathering system. Our Oklahoma gathering systems include the following:
Central Oklahoma gathering system. The Central Oklahoma gathering system serves the STACK and CNOW plays. Contractual arrangements related to the Central Oklahoma gathering system that contain an MVC include the following:
Our contractual arrangement with Devon includes an MVC that will remain in effect until October 2020. For 2018, the MVC dictates that approximately 153 MMcf/d of natural gas will be handled through the Chisholm gathering system. The MVC escalates quarterly, resulting in approximately 230 MMcf/d to be delivered in 2020.
We have another contractual arrangement with Devon that includes an MVC that will remain in effect up to January 1, 2019, with 330 MMcf/d of natural gas to be handled through the Cana gathering system.
Northridge gathering system. Our Northridge gathering system is located in the Arkoma-Woodford Shale in Southeastern Oklahoma.
Louisiana Assets. Our Louisiana assets consist of gas and NGL transmission pipelines, processing facilities, gathering systems and gas and NGL storage.
Louisiana Gas Pipeline and Processing Systems. The Louisiana gas pipeline system includes gathering and transmission systems, processing facilities and underground gas storage.
Gas Transmission and Gathering Systems. Our transmission system consists of a portfolio of large capacity interconnections with the Gulf Coast pipeline grid that provides customers with supply access to multiple domestic production basins for redelivery to major industrial market consumption located primarily in the Mississippi River Corridor between Baton Rouge and New Orleans. Our natural gas transmission services are supplemented by fully integrated, high deliverability salt dome storage capacity strategically located in the natural gas consumption corridor. In combination with our transmission system, our gathering systems provide a fully integrated wellhead to burner tip value chain that includes local gathering, processing and treating services to Louisiana producers.
Gas Processing and Storage Facilities. Our processing facilities in Louisiana include five gas processing plants, of which three are currently operational.
Plaquemine Processing Plant. The Plaquemine processing plant has 225 MMcf/d of processing capacity and is connected to the Plaquemine fractionation facility.
Gibson Processing Plant. The Gibson processing plant has 110 MMcf/d of processing capacity and is located in Gibson, Louisiana. The processing plant is connected to our Louisiana gathering system.
Pelican Processing Plant. The Pelican processing plant complex is located in Patterson, Louisiana and has a designed capacity of 600 MMcf/d of natural gas. The Pelican processing plant is connected with continental shelf and deepwater production and has downstream connections to the ANR Pipeline. This plant has an interconnection with the Louisiana gas pipeline system allowing us to process natural gas from this system at our Pelican processing plant when markets are favorable.
Blue Water Gas Processing Plant. We operate and own a 64.29% interest in the Blue Water gas processing plant. The Blue Water gas processing plant is located in Crowley, Louisiana and is connected to the Blue Water pipeline system. Our share of the plant’s capacity is approximately 193 MMcf/d. The plant is not expected to operate in the future unless fractionation spreads are favorable and volumes are sufficient to run the plant.
Eunice Processing Plant. The Eunice processing plant is located in south central Louisiana and has a capacity of 475 MMcf/d of natural gas. In August 2013, we shut down the Eunice processing plant due to adverse economics driven by low NGL prices and low processing volumes, which we do not see improving in the near term based on forecasted prices.
Sabine Pass Processing Plant. The Sabine Pass processing plant is located east of the Sabine River at Johnson's Bayou, Louisiana and has a processing capacity of 300 MMcf/d of natural gas. In 2013, we shut down the Sabine Pass processing plant and do not anticipate reopening the plant based on current market conditions.
Belle Rose Gas Storage Facility. The Belle Rose storage facility is located in Assumption Parish, Louisiana. This facility was placed in service in May 2016 and is designed for injecting pipeline quality gas into storage or withdrawing stored gas for delivery by pipeline.
Sorrento Gas Storage Facility. The storage facility is located in Assumption Parish, Louisiana. This facility is designed for injecting pipeline quality gas into storage or withdrawing stored gas for delivery by pipeline.
Louisiana Liquids Pipeline System. Our Louisiana liquids pipeline system includes NGL transport lines, fractionation assets and underground NGL storage.
Cajun-Sibon Pipeline System. The Cajun-Sibon pipeline system transports unfractionated NGLs from areas such as the Liberty, Texas interconnects near Mont Belvieu and from our Gibson and Pelican processing plants in South Louisiana to either the Riverside or Eunice fractionators or to third-party fractionators when necessary.
Ascension Pipeline. The Ascension JV is an NGL pipeline that connects our Riverside fractionator to Marathon Petroleum’s Garyville refinery and is owned 50% by Marathon Petroleum.
Fractionation Facilities. There are four fractionation facilities located in Louisiana that are connected to our processing facilities, and to Mont Belvieu and other hubs through our Cajun-Sibon pipeline system.
Plaquemine Fractionation Facility. The Plaquemine fractionator is located at our Plaquemine gas processing plant complex and is connected to our Cajun-Sibon pipeline. The Plaquemine fractionation facility produces purity ethane and propane for sale to markets via pipeline, while butane and heavier products are sent to our Riverside facility for further processing. The Plaquemine fractionator, collectively with the Riverside Fractionation Facility, has an approximate capacity of 110,000 Bbls/d of raw-make NGL products.
Plaquemine Gas Processing Plant. In addition to the Plaquemine fractionation facility, the adjacent Plaquemine Gas Processing Plant also has an on-site fractionator.
Eunice Fractionation Facility. The Eunice fractionation facility is located in south central Louisiana. Liquids are delivered to the Eunice fractionation facility by the Cajun-Sibon pipeline. The Eunice fractionation facility is directly connected to the southeast propane market and to a third-party storage facility.
Riverside Fractionation Facility. The Riverside fractionator and loading facility is located on the Mississippi River upriver from Geismar, Louisiana. Liquids are delivered to the Riverside fractionator by the Cajun-Sibon pipeline system from the Eunice and Pelican processing plants or by third-party truck and rail assets. The loading/unloading facility has the capacity to transload 15,000 Bbls/d of crude oil and condensate from rail cars to barges.
Napoleonville Storage Facility. The Napoleonville NGL storage facility is connected to the Riverside facility and is comprised of two existing caverns. The caverns are currently operated in butane service, and space is leased to customers for a fee.
Crude and Condensate. Our Crude and Condensate assets consist of crude oil and condensate pipelines, above ground storage and a trucking fleet.
Ohio River Valley. Our ORV operations are an integrated network of assets comprised of a 5,000-barrel-per-hour crude oil and condensate barge loading terminal on the Ohio River, a 20-spot crude oil and condensate rail loading terminal on the Ohio Central Railroad network, crude oil and condensate pipelines in Ohio and West Virginia, above ground crude oil storage, a trucking fleet comprised of both semi and straight trucks, trailers for hauling NGL volumes and seven existing brine disposal wells. Additionally, our ORV operations include eight condensate stabilization and natural gas compression stations that are supported by long-term, fee-based contracts with multiple producers.
Permian Crude and Condensate. Our Permian Crude and Condensate assets have crude oil gathering, transportation and marketing operations in the Permian Basin. These assets include trucking and crude gathering pipelines acquired in the LPC acquisition and the Greater Chickadee gathering system, which was placed into service in March 2017 and delivers crude oil for customers to Enterprise Product Partners L.P.’s crude oil terminal in West Texas. Greater Chickadee also includes multiple central tank batteries, with pump, truck injection and storage stations to maximize shipping and delivery options for producers.
Black Coyote Crude Oil Gathering System. We are expanding our operations in the core of the STACK play in Central Oklahoma with the construction of the Black Coyote crude oil gathering system. Black Coyote is primarily being built on dedicated acreage from Devon, which will be the main shipper on the system. The system is expected to be operational in the first quarter of 2018.
Victoria Express Pipeline. VEX includes a multi-grade crude oil pipeline with terminals in Cuero and the Port of Victoria Terminal and barge docks. The Cuero truck unloading terminal at the origin of the VEX system contains eight unloading bays and above-ground storage capacity for receipt from and delivery to the VEX pipeline. The VEX pipeline terminates at the Port of Victoria Terminal, which has an eight-bay truck unloading dock and above-ground storage capacity. The Port of Victoria Terminal delivers to two barge loading docks at the Port of Victoria. We have an agreement with Devon, which includes an MVC of 30,000 Bbls/d, that will remain in effect until July 2019.
Corporate. Our Corporate assets primarily consist of a contractual right to the benefits and burdens associated with Devon’s 38.75% ownership interest in GCF and a 30% ownership interest in the Cedar Cove JV.
Gulf Coast Fractionators. We are entitled to receive the economic benefits and burdens of the 38.75% interest in GCF held by Devon, with the remaining interests owned 22.5% by Phillips 66 and 38.75% by Targa Resources Partners. GCF owns an NGL fractionator located on the Gulf Coast at Mont Belvieu, Texas. Phillips 66 is the operator of the fractionator. GCF receives raw mix NGLs from customers, fractionates the raw mix and redelivers the finished products to the customers for a fee.
Cedar Cove JV. On November 9, 2016, we formed a joint venture with Kinder Morgan, Inc. consisting of gathering and compression assets in Blaine County, Oklahoma, which tie into our existing Oklahoma assets. All gas gathered by the Cedar Cove JV is processed by our Central Oklahoma processing facilities. We own 30% of the Cedar Cove JV.
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.
Storage. Demand for natural gas, NGLs and crude oil fluctuate daily and seasonally, while production and pipeline deliveries are relatively constant in the short term. Storage of products during periods of low demand helps to ensure that sufficient supplies are available during periods of high demand. Natural gas and NGLs are stored in large volumes in underground facilities and in smaller volumes in tanks above and below ground, while crude oil is typically stored in tanks above ground.
Crude oil and condensate terminals. Crude oil and condensate rail terminals are an integral part of ensuring the movement of new crude oil and condensate production from the developing shale plays in the United States and Canada. In general, the crude oil and condensate rail loading terminals are used to load rail cars and transport the commodity out of developing basins into market rich areas of the country where crude oil and condensate rail unloading terminals are used to unload rail cars and store crude oil and condensate volumes for third parties until the crude oil and condensate is redelivered to premium market delivery points via pipelines, trucks or rail.
Balancing Supply and Demand
When we purchase natural gas, crude oil and condensate, we establish a margin normally by selling it for physical delivery to third-party users. We can also use over-the-counter derivative instruments or enter into future delivery obligations under futures contracts on the New York Mercantile Exchange (“NYMEX”) related to our natural gas purchases. Through these transactions, we seek to maintain a position that is balanced between (1) purchases and (2) sales or future delivery obligations. Our policy is not to acquire and hold natural gas futures contracts or derivative products for the purpose of speculating on price changes.
The business of providing gathering, transmission, processing and marketing services for natural gas, NGLs, crude oil and condensate is highly competitive. We face strong competition in obtaining natural gas, NGLs, crude oil and condensate supplies and in the marketing and transportation of natural gas, NGLs, crude oil and condensate. Our competitors include major integrated and independent exploration and production companies, natural gas producers, interstate and intrastate pipelines, other natural gas, NGLs and crude oil and condensate gatherers and natural gas processors. Competition for natural gas and crude oil and condensate supplies is primarily based on geographic location of facilities in relation to production or markets, the reputation, efficiency and reliability of the gatherer and the pricing arrangements offered by the gatherer. For areas where acreage is not dedicated to us, we will compete with similar enterprises in providing additional gathering and processing
services in its respective areas of operation, 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, we have numerous competitors, including marketing affiliates of interstate pipelines, major integrated oil and gas companies, and local and national natural gas producers, gatherers, brokers and marketers of widely varying sizes, financial resources and experience. Local utilities and distributors of natural gas are, in some cases, engaged directly and through affiliates in marketing activities that compete with our marketing operations.
We face strong competition for acquisitions and development of new projects from both established and start-up companies. Competition increases the cost to acquire existing facilities or businesses and results in fewer commitments and lower returns for new pipelines or other development projects. Our competitors may have greater financial resources than we possess or may be willing to accept lower returns or greater risks. Our competition differs by region and by the nature of the business or the project involved.
Natural Gas, NGL, Crude Oil and Condensate Supply
Our gathering and transmission pipelines have connections with major intrastate and interstate pipelines, which we believe have ample natural gas and NGL supplies in excess of the volumes required for the operation of these systems. We evaluate well and reservoir data that is either publicly available or furnished by producers or other service providers in connection with the construction and acquisition of our gathering systems and assets to determine the availability of natural gas, NGLs, crude oil and condensate supply for our systems and assets and/or obtain an MVC from the producer that results in a rate of return on investment. We do not routinely obtain independent evaluations of reserves dedicated to our systems and assets due to the cost and relatively limited benefit of such evaluations. Accordingly, we do not have estimates of total reserves dedicated to our systems and assets or the anticipated life of such producing reserves.
Credit Risk and Significant Customers
We are subject to risk of loss resulting from nonpayment or nonperformance by our customers and other counterparties, such as our lenders and hedging counterparties. We diligently attempt to ensure that we issue credit to only credit-worthy customers. However, our purchase and resale of crude oil, condensate, NGLs and natural gas exposes us to significant credit risk, as the margin on any sale is generally a very small percentage of the total sales price. Therefore, a credit loss can be very large relative to our overall profitability. A substantial portion of our throughput volumes come from customers that have investment-grade ratings. However, lower commodity prices in future periods may result in a reduction in our customers’ liquidity and ability to make payments or perform on their obligations to us. Some of our customers have filed for bankruptcy protection, and their debts and payments to us are subject to laws governing bankruptcy.
For the years ended December 31, 2017, 2016 and 2015, Devon represented 14.4%, 18.5% and 16.6%, respectively, of our consolidated revenues, and Dow Hydrocarbons & Resources LLC (“Dow Hydrocarbons”) represented 11.2%, 10.8% and 11.7%, respectively, of our consolidated revenues. No other customer represented greater than 10.0% of our revenue. Our operations are dependent on the volume of natural gas that Devon provides to us under commercial agreements, which constitutes a substantial portion of our natural gas supply. The loss of Devon or Dow Hydrocarbons as a customer could have a material impact on our results of operations if we were not able to sell our products to another customer with similar margins because the gross operating margins received from transactions with Devon and Dow Hydrocarbons are material to our total gross operating margin.
Natural Gas Pipeline Regulation. We own 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”). FERC regulates the rates and terms and conditions of service on interstate natural gas pipelines, as well as the certification, construction, modification, expansion and abandonment of facilities.
The rates and terms and conditions for our 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. Proposed rate increases and changes to our tariffs are subject to FERC approval. Pursuant to FERC’s jurisdiction over rates, existing rates may be challenged by complaint or by FERC on its own initiative, and proposed new or changed rates may be challenged by protest. If protested, a rate increase may be suspended for up to five months and collected, subject to refund. If, upon completion of an investigation, FERC finds that
the new or changed rate is unlawful, it is authorized to require the pipeline to refund revenues collected in excess of the just and reasonable rate during the term of the investigation.
The rates charged by our FERC regulated natural gas pipelines may also be affected by the ongoing uncertainty regarding FERC’s current income tax allowance policy. In July 2016, the United States Court of Appeals for the District of Columbia Circuit issued its opinion in United Airlines, Inc., et al.v. FERC, finding that FERC had acted arbitrarily and capriciously when it failed to demonstrate that permitting an interstate petroleum products pipeline organized as a limited partnership to include an income tax allowance in the cost of service underlying its rates in addition to the discounted cash flow return on equity would not result in the pipeline double-recovering its investors’ income taxes. The court vacated FERC’s order and remanded to FERC to consider mechanisms for demonstrating that there is no double recovery as a result of the income tax allowance. On December 15, 2016, FERC issued a Notice of Inquiry seeking comment on how to address any double recovery resulting from its income tax allowance policy. FERC is currently considering whether, and if so, to what extent, pipelines owned by pass-through entities such as MLPs may include income tax allowance in rates to compensate for the income tax liability of investors.
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 state a material fact necessary to make the statements made not misleading (in light of the circumstances under which the statements were made); or (3) engage in any act, practice or course of business that operates (or would operate) as a fraud or deceit upon any person. The EPAct 2005 also amends the NGA and the Natural Gas Policy Act of 1978 (“NGPA”) to give FERC authority to impose civil penalties for violations of these statutes up to $1.0 million per day per violation for violations occurring after August 8, 2005. The maximum penalty authority established by the statute has been adjusted to $1.2 million per day per violation and will continue to be adjusted periodically for inflation. Should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.
Certain of our intrastate natural gas pipelines also transport gas in interstate commerce and, thus, the rates, terms and conditions of such services are subject to FERC jurisdiction under Section 311 of the NGPA (“Section 311”). Pipelines providing transportation service under Section 311 are required to provide services on an open and nondiscriminatory basis, and the maximum rates for interstate transportation services provided by such pipelines must be “fair and equitable.” Such rates are generally subject to review every five years by FERC or by an appropriate state agency.
In addition to Section 311 regulation, our intrastate natural gas pipeline operations are subject to regulation by various state agencies. Most state agencies possess the authority to review and authorize natural gas transportation transactions and the construction, acquisition, abandonment and interconnection of physical facilities for intrastate pipelines. State agencies also may regulate transportation rates, service terms and conditions and contract pricing.
Liquids Pipeline Regulation. We own certain liquids and crude oil pipelines that are regulated by FERC as common carrier interstate pipelines under the Interstate Commerce Act (“ICA”), the Energy Policy Act of 1992 and related rules and orders.
FERC regulation requires that interstate liquids pipeline rates and terms and conditions of service, including rates for transportation of crude oil, condensate and NGLs, be filed with FERC and that these rates and terms and conditions of service be “just and reasonable” and not unduly discriminatory or unduly preferential.
Rates of interstate liquids pipelines are currently regulated by FERC primarily through an annual indexing methodology, under which pipelines increase or decrease their rates in accordance with an index adjustment specified by FERC. This adjustment is subject to review every five years. For the five-year period beginning on July 1, 2016, FERC established an annual index adjustment equal to the change in the producer price index for finished goods plus 1.23%. On October 20, 2016, however, FERC issued an Advance Notice of Proposed Rulemaking indicating that FERC is considering a new policy that would deny proposed index increases for pipelines under certain circumstances where revenues exceed cost-of-service by a certain percentage or where the proposed index increases exceed certain annual cost changes reported to FERC. Under current FERC regulations, liquids pipelines can request a rate increase that exceeds the rate obtained through application of the indexing methodology by using a cost-of-service approach, but only after the pipeline establishes that a substantial divergence exists between the actual costs experienced by the pipeline and the rates resulting from application of the indexing
methodology. The rates charged by our 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 our ability to set rates based on our costs or could order us to reduce our rates and pay reparations to complaining shippers for up to two years prior to the date of the complaint. FERC also has the authority to change our terms and conditions of service if it determines that they are unjust and unreasonable or unduly discriminatory or preferential.
As we acquire, construct and operate new liquids assets and expand our liquids transportation business, the classification and regulation of our liquids transportation services, including services that our marketing companies provide on our FERC-regulated liquids pipelines, are subject to ongoing assessment and change based on the services we provide and determinations by FERC and the courts. Such changes may subject additional services we provide to regulation by FERC.
Intrastate NGL and other petroleum pipelines are not generally subject to rate regulation by FERC, but they are subject to regulation by various agencies in the respective states where they are located. While such regulatory regimes vary, state agencies typically require intrastate NGL and petroleum pipelines to file their rates with the agencies and permit shippers to challenge existing rates or proposed rate increases.
Gathering Pipeline Regulation. Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of FERC under the NGA. We own a number of natural gas pipelines that we believe meet the traditional tests FERC has used to establish that a pipeline is a gathering pipeline and therefore not subject to FERC jurisdiction. The distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of substantial, ongoing litigation, however, so the classification and regulation of our gathering facilities are subject to change. Application of FERC jurisdiction to our gathering facilities could increase our operating costs, decrease our rates and adversely affect our business. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory requirements and complaint-based rate regulation.
In addition, we are subject to some state ratable take and common purchaser statutes. The ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply.
Natural Gas Storage Regulation. In December 2016, the DOT’s Pipeline and Hazardous Materials Safety Administration (“PHMSA”) issued an interim final rule (“IFR”) that addresses safety issues related to downhole facilities located at both intrastate and interstate underground storage facilities. The IFR incorporates by reference two of the American Petroleum Institute’s Recommended Practice standards and mandates certain reporting requirements for operators of underground natural gas storage facilities. Under the IFR, all intrastate transportation related underground natural gas storage facilities will become subject to minimum federal safety standards and be inspected by PHMSA or by a state entity that has chosen to expand its authority to regulate these facilities under a certification filed with PHMSA. The IFR became effective on January 18, 2017, with a compliance deadline of January 18, 2018. PHMSA subsequently determined, however, that it will not issue enforcement citations to any operators for violations of provisions of the IFR that had previously been non-mandatory provisions of American Petroleum Institute Recommended Practices 1170 and 1171 until one year after PHMSA issues a final rule. On October 19, 2017, PHMSA formally reopened the comment period on the IFR in response to a petition for reconsideration. This matter remains ongoing and subject to future PHMSA determinations. We are in compliance with this IFR.
Certain of our field injection and withdrawal wells and water disposal wells are subject to the jurisdiction of the Railroad Commission of Texas (“TRRC”). TRRC regulations require that we report the volumes of natural gas and water disposal associated with the operations of such wells on a monthly and annual basis, respectively. Results of periodic mechanical integrity tests must also be reported to the TRRC. In addition, our underground gas storage caverns in Louisiana are subject to the jurisdiction of the Louisiana Department of Natural Resources (“LDNR”). In recent years, LDNR has put in place more comprehensive regulations governing underground hydrocarbon storage in salt caverns.
We also operate brine disposal wells that are regulated as Class II wells under the federal Safe Drinking Water Act (“SDWA”). The SDWA imposes requirements on owners and operators of Class II wells through the EPA’s Underground Injection Control program, including construction, operating, monitoring and testing, reporting and closure requirements. Our brine disposal wells are also subject to comparable state laws and regulations. For more information, see “Environmental Matters” below.
Sales of Natural Gas and NGLs. The prices at which we sell natural gas and NGLs currently are not subject to federal regulation and, for the most part, are not subject to state regulation. Our natural gas and NGL sales are, however, affected by the availability, terms, cost and regulation of pipeline transportation.
Employee Safety. We are subject to the requirements of the Occupational Safety and Health Act (“OSHA”), and comparable state laws that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our operations are in substantial compliance with the OSHA requirements including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances.
Pipeline Safety Regulations. Our pipelines are subject to regulation by PHMSA pursuant to the Natural Gas Pipeline Safety Act of 1968 (“NGPSA”) and the Pipeline Safety Improvement Act of 2002 (“PSIA”). The NGPSA regulates safety requirements in the design, construction, operation and maintenance of gas pipeline facilities. The PSIA established mandatory inspections for all U.S. crude oil and natural gas transportation pipelines and some gathering lines in high-consequence areas (“HCAs”), which include, among other things, areas of high population density or that serve as sources of drinking water. PHMSA has developed regulations implementing the PSIA that require transportation pipeline operators to implement integrity management programs, including more frequent inspections and other measures to ensure pipeline safety in HCAs. More recently, the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 increased penalties for safety violations, established additional safety requirements for newly constructed pipelines and required studies of certain safety issues that could result in the adoption of new regulatory requirements for existing pipelines, and in June 2016, the President of the United States signed the Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (the “PIPES Act”), which reauthorizes PHMSA’s oil and gas pipeline programs through 2019.
In April 2016, PHMSA published a notice of proposed rulemaking (“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. Furthermore, this NPRM would require that records or other data relied on to determine operating pressures must be traceable, verifiable and complete. Locating such records and, in the absence of any such records, verifying maximum pressures through physical testing or modifying or replacing facilities, could significantly increase our costs. Additionally, failure to locate such records or verify maximum pressures could result in the reduction of allowable operating pressures, which would reduce available capacity on our pipelines. PHMSA, however, has yet to finalize this rulemaking, and the contents and timing of any final rule are currently uncertain.
In addition, in January 2017, PHMSA finalized new hazardous liquid pipeline safety regulations that would have extended certain regulatory reporting requirements to all hazardous liquid gathering (including oil) pipelines. The final rule also would have required additional event-driven and periodic inspections, required the use of leak detection systems on all hazardous liquid pipelines, modified repair criteria, and required certain pipelines to eventually accommodate in-line inspection tools. The effective date of this final rule is currently uncertain due to a regulatory freeze implemented by the Trump administration on January 20, 2017.
On January 23, 2017, PHMSA published in the Federal Register amendments to the pipeline safety regulations to address requirements of the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 and to update and clarify certain regulatory requirements regarding notifications of accidents and incidents. The final rule also adds provisions for cost recovery for design reviews of certain new projects, provides for renewal of existing special permits, and incorporates certain standards for in-line inspections and stress corrosion cracking assessments.
At the state level, several states have passed legislation or promulgated rules dealing with pipeline safety. We believe that our pipeline operations are in substantial compliance with applicable PHMSA and state requirements; however, due to the possibility of new or amended laws and regulations or reinterpretation of existing laws and regulations, there can be no
assurance that future compliance with PHMSA or state requirements will not have a material adverse effect on our financial condition, results of operations or cash flows.
On November 2, 2015, PHMSA issued a Notice of Probable Violation and Proposed Compliance Order (the “NOPV”) asserting that we have 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. On January 18, 2018, we received a letter from PHMSA withdrawing the NOPV and indicating that the case was closed effective as of January 18, 2018.
General. Our operations involve processing and pipeline services for delivery of hydrocarbons (natural gas, NGLs, crude oil and condensates) from point-of-origin at crude oil and gas wellheads operated by our suppliers to our end-use market customers. Our facilities include natural gas processing and fractionation plants, natural gas and NGL storage caverns, brine disposal wells, pipelines and associated facilities, fractionation and storage units for NGLs, and transportation and delivery of hydrocarbons. As with all companies in our industrial sector, our operations are subject to stringent and complex federal, state and local laws and regulations relating to the discharge of hazardous substances or solid wastes into the environment or otherwise relating to protection of the environment. Compliance with existing and anticipated environmental laws and regulations increases our overall costs of doing business, including costs of planning, constructing, and operating plants, pipelines, and other facilities, as well as capital expenditures necessary to maintain or upgrade equipment and facilities. Similar costs are likely upon changes in laws or regulations and upon any future acquisition of operating assets.
Any failure to comply with applicable environmental laws and regulations, including those relating to equipment failures, and obtaining required governmental approvals and permits, may result in the assessment of administrative, civil or criminal penalties, imposition of investigatory or remedial activities and, in certain, less common circumstances, issuance of temporary or permanent injunctions or construction or operation bans or delays. As part of the regular evaluation of our operations, we routinely review and update governmental approvals as necessary.
The continuing trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. Moreover, risks of process upsets, accidental releases or spills are associated with possible future operations, and we cannot assure you that we will not incur significant costs and liabilities, including those relating to claims for damage to the environment, property and persons as a result of any such upsets, releases or spills. We may be unable to pass on current or future environmental costs to our customers. A discharge or release of hydrocarbons, hazardous substances or solid wastes into the environment could, to the extent losses related to the event are not insured, subject us to substantial expense, including both the cost to comply with applicable laws and regulations and to pay fines or penalties that may be assessed and the cost related to claims made by neighboring landowners and other third parties for personal injury or damage to natural resources or property. We attempt to anticipate future regulatory requirements that might be imposed and plan accordingly to comply with changing environmental laws and regulations and to minimize costs with respect to more stringent future laws and regulations or more rigorous enforcement of existing laws and regulations.
Hazardous Substances and Solid Waste. Environmental laws and regulations that relate to the release of hazardous substances or solid wastes into soils, sediments, groundwater and surface water and/or include measures to prevent and control pollution may pose significant costs to our industrial sector. These laws and regulations generally regulate the generation, storage, treatment, transportation and disposal of solid wastes and hazardous substances and may require investigatory and corrective actions at facilities where such waste or substance may have been released or disposed. For instance, the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the federal “Superfund” law, and comparable state laws impose liability without regard to fault or the legality of the original conduct on certain classes of persons that contributed to a release of a “hazardous substance” into the environment. Potentially responsible parties include the owner or operator of the site where a release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at an off-site location, such as a landfill. Under CERCLA, these persons may be subject to joint and several liability for the costs of cleaning up and restoring sites where hazardous substances have been released into the environment and for damages to natural resources. CERCLA also authorizes the U.S. Environmental Protection Agency (“EPA”) and, in some cases, third parties, to take actions in response to threats to public health or the environment and to seek recovery of costs they incur from the potentially responsible classes of persons. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by
hazardous substances or solid wastes released into the environment. Although petroleum, natural gas and NGLs are excluded from CERCLA’s definition of a “hazardous substance,” in the course of ordinary operations, we may generate wastes that may fall within the definition of a “hazardous substance.” In addition, there are other laws and regulations that can create liability for releases of petroleum, natural gas or NGLs. Moreover, we may be responsible under CERCLA or other laws for all or part of the costs required to clean up sites at which such substances have been disposed. We have not received any notification that we may be potentially responsible for cleanup costs under CERCLA or any analogous federal, state, or local law.
We also generate, and may in the future generate, both hazardous and nonhazardous solid wastes that are subject to requirements of the federal Resource Conservation and Recovery Act (“RCRA”) and/or comparable state statutes. From time to time, the EPA and state regulatory agencies have considered the adoption of stricter disposal standards for nonhazardous wastes, including crude oil, condensate and natural gas wastes. Moreover, it is possible that some wastes generated by us that are currently exempted from the definition of hazardous waste may in the future lose this exemption and be designated as “hazardous wastes,” resulting in the wastes being subject to more rigorous and costly management and disposal requirements. Additionally, the Toxic Substances Control Act (“TSCA”) and analogous state laws impose requirements on the use, storage and disposal of various chemicals and chemical substances. In June 2017, the EPA finalized three rulemakings to update its implementation of TSCA. Two of the new rules establish the EPA’s process and criteria for identifying high priority chemicals for risk evaluation and determining whether these high priority chemicals present an unreasonable risk to health or the environment. The third rule requires industry reporting of chemicals manufactured or processed in the U.S. over the past 10 years. Changes in applicable laws or regulations may result in an increase in our capital expenditures or plant operating expenses or otherwise impose limits or restrictions on our production and operations.
We currently own or lease, have in the past owned or leased, and in the future may own or lease, properties that have been used over the years for brine disposal operations, crude oil and condensate transportation, natural gas gathering, treating or processing and for NGL fractionation, transportation or storage. Solid waste disposal practices within the NGL industry and other oil and natural gas related industries have improved over the years with the passage and implementation of various environmental laws and regulations. Nevertheless, some hydrocarbons and other solid wastes may have been released on or under various properties owned, leased or operated by us during the operating history of those properties. In addition, a number of these properties may have been operated by third parties over whose operations and hydrocarbon and waste management practices we had no control. These properties and wastes disposed thereon may be subject to the SWDA, CERCLA, RCRA, TSCA and analogous state laws. Under these laws, we could be required, alone or in participation with others, to remove or remediate previously disposed wastes or property contamination, if present, including groundwater contamination, or to take action to prevent future contamination.
Air Emissions. Our current and future operations are subject to the federal Clean Air Act and regulations promulgated thereunder and under comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including our facilities, and impose various control, monitoring, and reporting requirements. Pursuant to these laws and regulations, we may be required to obtain environmental agency pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in an increase in existing air emissions, obtain and comply with the terms of air permits, which include various emission and operational limitations, or use specific emission control technologies to limit emissions. We likely will be required to incur certain capital expenditures in the future for air pollution control equipment in connection with maintaining or obtaining governmental approvals addressing air emission-related issues. Failure to comply with applicable air statutes or regulations may lead to the assessment of administrative, civil or criminal penalties and may result in the limitation or cessation of construction or operation of certain air emission sources or require us to incur additional capital expenditures. Although we can give no assurances, we believe such requirements will not have a material adverse effect on our financial condition, results of operations or cash flows, and the requirements are not expected to be more burdensome to us than to any similarly situated company.
In addition, the EPA included Wise County, the location of our Bridgeport facility, in its January 2012 revision to the Dallas-Fort Worth ozone nonattainment area for the 2008 revised ozone national ambient air quality standard (“NAAQS”). As a result of this moderate nonattainment 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. In October 2015, the EPA lowered the NAAQS for ozone from 75 to 70 parts per billion for both the 8-hour primary and secondary standards. This new standard is being challenged in a pending appeal before the U.S. Court of Appeals for the D.C. Circuit, but
if the standard is implemented, it could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits, and result in potentially significant expenditures for pollution control equipment.
Effective May 15, 2012, the EPA promulgated rules under the Clean Air Act that established new air emission controls for oil and natural gas production, pipelines and processing operations under the New Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutants (“NESHAPs”) programs. These rules require the control of emissions through reduced emission (or “green”) completions and establish specific new requirements regarding emissions from wet seal and reciprocating compressors, pneumatic controllers, and storage vessels at production facilities, gathering systems, boosting facilities, and onshore natural gas processing plants. In addition, the rules revised existing requirements for VOC emissions from equipment leaks at onshore natural gas processing plants by lowering the leak definition for valves from 10,000 parts per million to 500 parts per million and requiring the monitoring of connectors, pumps, pressure relief devices and open-ended lines. These rules required a number of modifications to our assets and operations. In October 2012, several challenges to the EPA’s NSPS and NESHAPs rules for the industry were filed by various parties, including environmental groups and industry associations. In a January 16, 2013 unopposed motion to hold this litigation in abeyance, the EPA indicated that it may reconsider some aspects of the rules. The case remains in abeyance. The EPA has since revised certain aspects of the rules 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 announced its intention to reconsider those regulations in April 2017 and has sought to stay its requirements. However, the rule remains in effect. In June 2016, the EPA also finalized a rule regarding alternative criteria for aggregating multiple small surface sites into a single source for air quality permitting purposes. This rule could cause small facilities within one-quarter mile of one another to be deemed a major source on an aggregate basis, thereby triggering more stringent air permitting processes and requirements across the oil and gas industry. On November 10, 2016, the EPA issued a final Information Collection Request (“ICR”) that requires numerous oil and gas companies to provide information regarding methane emissions from existing oil and gas facilities, a step used to provide a basis for future rulemaking. The EPA withdrew this ICR in March 2017. The Obama Administration indicated that other federal agencies, including the Bureau of Land Management (“BLM”), 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. Certain provisions of the BLM rule went into effect in January 2017, while others were scheduled to go into effect in January 2018. In December 2017, BLM published a final rule delaying the 2018 provisions until 2019. As a result of this continued regulatory focus and other factors, additional GHG regulation of the oil and gas industry remains possible. Compliance with such rules could result in additional costs, including increased capital expenditures and operating costs for us and for other companies in our industry. While we are not able at this time to estimate such additional costs, as is the case with similarly situated entities in the industry, they could be significant for us. Compliance with such rules, as well as any new state rules, may also make it more difficult for our suppliers and customers to operate, thereby reducing the volume of natural gas transported through our pipelines, which may adversely affect our business. However, the status of recent and future rules and rulemaking initiatives under the Trump Administration remains uncertain.
Climate Change. In December 2009, the EPA determined that emissions of certain gases, commonly referred to as “greenhouse gases,” present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA adopted regulations under existing provisions of the federal Clean Air Act that require Prevention of Significant Deterioration (“PSD”) pre-construction permits and Title V operating permits for greenhouse gas emissions from certain large stationary sources. Under these regulations, facilities required to obtain PSD permits must meet “best available control technology” standards for their greenhouse gas emissions established by the states or, in some cases, by the EPA on a case by case basis. The EPA has also adopted rules requiring the monitoring and reporting of greenhouse gas emissions from specified sources in the United States, including, among others, certain onshore oil and natural gas processing and fractionating facilities. The EPA announced its intention to reconsider those regulations in April 2017 and has sought to stay its requirements. However, the rule remains in effect. In addition, efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues. Because regulation of greenhouse gas emissions is relatively new, further regulatory, legislative and judicial developments are likely to occur. Such developments in greenhouse gas initiatives may affect us and other companies operating in the oil and gas industry. In addition to these developments, recent judicial decisions have allowed certain tort claims alleging property damage to proceed against greenhouse gas emissions sources, which may increase our litigation risk for such claims. In addition, in 2015,
the United States participated in the United Nations Conference on Climate Change, which led to the creation of the Paris Agreement. The Paris Agreement entered into force November 4, 2016, and requires countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals every five years beginning in 2020. In June 2017, the Trump Administration announced its intent to withdraw from the Paris Agreement. Pursuant to the terms of the Paris Agreement, the earliest date the United States can withdraw is November 2020. Due to the uncertainties surrounding the regulation of and other risks associated with greenhouse gas emissions, we cannot predict the financial impact of related developments on us.
Federal or state legislative or regulatory initiatives that regulate or restrict emissions of greenhouse gases in areas in which we conduct business could adversely affect the availability of, or demand for, the products we store, transport and process, and, depending on the particular program adopted, could increase the costs of our operations, including costs to operate and maintain our facilities, install new emission controls on our facilities, acquire allowances to authorize our greenhouse gas emissions, pay any taxes related to our greenhouse gas emissions and/or administer and manage a greenhouse gas emissions program. We may be unable to recover any such lost revenues or increased costs in the rates we charge our customers, and any such recovery may depend on events beyond our control, including the outcome of future rate proceedings before FERC or state regulatory agencies and the provisions of any final legislation or regulations. Reductions in our revenues or increases in our expenses as a result of climate control initiatives could have adverse effects on our business, financial condition, results of operations or cash flows.
Due to their location, our operations along the Gulf Coast are vulnerable to operational and structural damages resulting from hurricanes and other severe weather systems, while inland operations include areas subject to tornadoes. Our insurance may not cover all associated losses. We are taking steps to mitigate physical risks from storms, but no assurance can be given that future storms will not have a material adverse effect on our business.
Hydraulic Fracturing and Wastewater. The Federal Water Pollution Control Act, also known as the Clean Water Act, and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including NGL-related wastes, into state waters or waters of the United States. In June 2015, the EPA and the U.S. Army Corps of Engineers 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. In November 2017, the EPA and the U.S. Army Corps of Engineers proposed the addition of an applicability date to the 2015 Clean Water Rule that would be two years after the date of a final rule. This change, if adopted, would effectively prevent the rule from coming back into effect immediately if the stay is lifted. Regulations promulgated pursuant to the Clean Water Act require that entities that discharge into federal and state waters obtain National Pollutant Discharge Elimination System (“NPDES”) permits and/or state permits authorizing these discharges. The Clean Water Act and analogous state laws assess administrative, civil and criminal penalties for discharges of unauthorized pollutants into the water and impose substantial liability for the costs of removing spills from such waters. In addition, the Clean Water Act and analogous state laws require that individual permits or coverage under general permits be obtained by covered facilities for discharges of storm water runoff. We believe that we are in substantial compliance with Clean Water Act permitting requirements as well as the conditions imposed by our permits and that continued compliance with such existing permit conditions will not have a material effect on our financial condition, results of operations or cash flows.
In December 2016, the EPA released the final results of its comprehensive research study on the potential adverse impacts that hydraulic fracturing may have on drinking water resources. The EPA concluded that hydraulic fracturing activities can impact drinking water resources under some circumstances, including large volume spills and inadequate mechanical integrity of wells. The results of the EPA’s study could spur action toward federal legislation and regulation of hydraulic fracturing or similar production operations. We operate brine disposal wells that are regulated as Class II wells under the SDWA. The SDWA imposes requirements on owners and operators of Class II wells through the EPA’s Underground Injection Control program, including construction, operating, monitoring and testing, reporting and closure requirements. Our brine disposal wells are also subject to comparable state laws and regulations, which in some cases are more stringent than requirements under the SDWA, such as the Ohio Department of Natural Resources rules that took effect October 1, 2012. These rules set new, more stringent standards for the permitting and operating of brine disposal wells, including extensive review of geologic data and use of state-of-the-art technology. The Ohio Department of Natural Resources also imposes requirements on the transportation and disposal of brine. Compliance with current and future laws and regulations regarding our brine disposal wells may impose substantial costs and restrictions on our brine disposal operations, as well as adversely affect demand for our brine disposal services. State and federal regulatory agencies recently have focused on a possible connection between the operation of injection wells used for oil and gas waste waters and an observed increase in minor seismic activity and tremors. When caused by human activity, such events are called induced seismicity. In a few instances, operators of injection wells in the vicinity of minor seismic events
have reduced injection volumes or suspended operations, often voluntarily. A 2012 report published by the National Academy of Sciences concluded that only a very small fraction of the tens of thousands of injection wells have been suspected to be, or have been, the likely cause of induced seismicity. However, some state regulatory agencies have modified their regulations to account for induced seismicity. For example, TRRC rules allow the TRRC to modify, suspend, or terminate a permit based on a determination that the permitted activity is likely to be contributing to seismic activity. In the state of Ohio, the Ohio Department of Natural Resources (“ODNR”) requires a seismic study prior to the authorization of any new disposal well. In addition, the ODNR has instituted a continuous monitoring network of seismographs and is able to curtail injected volumes regionally based upon seismic activity detected. The Oklahoma Corporation Commission (“OCC”) has also taken steps to focus on induced seismicity, including increasing the frequency of required recordkeeping for wells that dispose into certain formations and considering seismic information in permitting decisions. For instance, on August 3, 2015, the OCC adopted a plan calling for mandatory reductions in oil and gas wastewater disposal well volumes, the implementation of which has involved reductions of injection or shut-ins of disposal wells. The OCC also recently released well completion seismicity guidelines in December 2016 for operators in the STACK play that call for hydraulic fracturing operations to be suspended following earthquakes of certain magnitudes in the vicinity. Regulatory agencies are continuing to study possible linkage between injection activity and induced seismicity. To the extent these studies result in additional regulation of injection wells, such regulations could impose additional regulations, costs and restrictions on our brine disposal operations.
It is common for our customers or suppliers to recover natural gas from deep shale formations through the use of hydraulic fracturing, combined with sophisticated horizontal drilling. Hydraulic fracturing is an important and commonly used process in the completion of wells by oil and gas producers. Hydraulic fracturing involves the injection of water, sand and chemical additives under pressure into rock formations to stimulate gas production. Due to public concerns raised regarding potential impacts of hydraulic fracturing on groundwater quality, legislative and regulatory efforts at the federal level and in some states and localities have been initiated to require or make more stringent the permitting and other regulatory requirements for hydraulic fracturing operations of our customers and suppliers. There are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. On December 13, 2016, the EPA released a study of the potential adverse effects that hydraulic fracturing may have on water quality and public health, concluding that there is scientific evidence that hydraulic fracturing activities potentially can impact drinking water resources in the United States under some circumstances. This study or similar studies could spur initiatives to further regulate hydraulic fracturing. In June 2016, the EPA finalized rules prohibiting discharges of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. The EPA has also issued an advance notice of proposed rulemaking under the Toxic Substances Control Act to gather information regarding the potential regulation of chemical substances and mixtures used in oil and gas exploration and production. Also, effective June 24, 2015, BLM adopted rules regarding well stimulation, chemical disclosures, water management, and other requirements for hydraulic fracturing on federal and American Indian lands; however, a federal district court invalidated these BLM rules in June 2016, but the rules were reinstated on appeal by the U.S. Court of Appeals for the Tenth Circuit in September 2017. While this appeal was pending, BLM proposed a rulemaking in July 2017 to rescind these rules in their entirety. BLM has yet to finalize this rulemaking. Additional regulatory burdens in the future, whether federal, state or local, could increase the cost of or restrict the ability of our customers or suppliers to perform hydraulic fracturing. As a result, any increased federal, state or local regulation could reduce the volumes of natural gas that our customers move through our gathering systems which would materially adversely affect our financial condition, results of operations or cash flows.
Endangered Species and Migratory Birds. The Endangered Species Act (“ESA”), Migratory Bird Treaty Act (“MBTA”), and similar state and local laws restrict activities that may affect endangered or threatened species or their habitats or migratory birds. Some of our pipelines may be located in areas that are designated as habitats for endangered or threatened species, potentially exposing us to liability for impacts on an individual member of a species or to habitat. The ESA can also make it more difficult to secure a federal permit for a new pipeline.
We occupy approximately 157,600 square feet of space at our executive offices in Dallas, Texas under a lease expiring in February 2030. We also occupy office space of approximately 56,000 square feet in Midland, Texas and 32,000 square feet in Houston, Texas under long-term leases.
As of December 31, 2017, we (through our subsidiaries) employed 1,494 full-time employees. Of these employees, 330 were general and administrative, engineering, accounting and commercial personnel, and the remainder were operational employees. We are not party to any collective bargaining agreements and we have not had any significant labor disputes in the past. We believe that we have good relations with our employees.
Item 1A. Risk Factors
The following risk factors and all other information contained in this report should be considered carefully when evaluating us. These risk factors could affect our actual results. Other risks and uncertainties, in addition to those that are described below, may also impair our business operations. If any of the following risks occur, our business, financial condition, results of operations or cash flows (including our ability to make distributions to our 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. 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.
We are dependent on Devon for a substantial portion of the natural gas that we gather, process and transport. The expiration of five-year MVCs from Devon in 2019 and 2020 could result in a material decline in our operating results and cash available for distribution because the volumes of natural gas that we gathered, processed and transported for Devon during 2017 have been below the MVC levels under certain of our contracts.
We are dependent on Devon for a substantial portion of our natural gas supply. For the year ended December 31, 2017, Devon represented approximately 46.8% of our gross operating margin. In order to minimize volumetric exposure, in March 2014, we obtained five-year MVCs from Devon at the Bridgeport processing facility, Bridgeport and East Johnson County gathering systems and the Central Oklahoma gathering system, and these MVCs expire on January 1, 2019. We also have a five-year MVC from Devon attributable to VEX, and this MVC expires on July 31, 2019. If the volumes of natural gas and crude oil that we gather and transport on our systems are below the MVC levels after the contracts expire, we could experience a material decline in our operating revenues and cash flow. For the year ended December 31, 2017, we recognized $59.2 million, $13.8 million and $8.9 million in MVC shortfall revenue from Devon attributable to our Texas, Oklahoma and Crude and Condensate segments, respectively, because volumes were below the minimum level. For the year ended December 31, 2016, we recognized $26.4 million, $10.8 million and $9.0 million in MVC shortfall revenue from Devon attributable to our Texas, Oklahoma and Crude and Condensate segments, respectively. For the year ended December 31, 2015, we recognized $3.8 million, $20.1 million, and $0.5 million in MVC shortfall revenue from Devon attributable to our Texas, Oklahoma and Crude and Condensate segments, respectively.
Because we are substantially dependent on Devon as one of our primary customers and through its indirect control of our general partner, any development that materially and adversely affects Devon’s operations, financial condition or market reputation could have a material and adverse impact on us. Material adverse changes at Devon could restrict our access to capital, make it more expensive to access the capital markets or increase the costs of our borrowings.
We are substantially dependent on Devon as one of our primary customers and through its indirect control of our general partner, and we expect to derive a significant portion of our gross operating margin from Devon for the foreseeable future. As a result, any event, whether in our area of operations or otherwise, that adversely affects Devon’s production, financial condition, leverage, market reputation, liquidity, results of operations or cash flows may adversely affect our revenues and cash available for distribution. Accordingly, we are indirectly subject to the business risks of Devon, some of which are the following:
potential changes in the supply of and demand for oil, natural gas and NGLs and related products and services;
risks relating to Devon’s exploration and drilling programs, including potential environmental liabilities;
adverse effects of governmental and environmental regulation; and
general economic and financial market conditions.
Further, we are subject to the risk of non-payment or non-performance by Devon, including with respect to our gathering and processing agreements. We cannot predict the extent to which Devon’s business will be impacted by pricing conditions in the energy industry, nor can we estimate the impact such conditions would have on Devon’s ability to perform under our gathering and processing agreements. Additionally, due to our relationship with Devon, our ability to access the capital markets, or the pricing or other terms of any capital markets transactions, may be adversely affected by any impairments to Devon’s financial condition or adverse changes in its credit ratings. S&P Global Ratings (“S&P”) and Moody’s Investors Services (“Moody’s”) have currently assigned to Devon a BBB and Ba1 credit rating, respectively. Any material limitations on our ability to access capital as a result of such adverse changes at Devon could limit our ability to obtain future financing under favorable terms, or at all, or could result in increased financing costs in the future. Similarly, material adverse changes at Devon could negatively impact our unit price, limiting our ability to raise capital through equity issuances or debt financing or our
ability to engage in, expand or pursue our business activities and could also prevent us from engaging in certain transactions that might otherwise be considered beneficial to us.
Please see “Item 1A. Risk Factors” in Devon’s Annual Report on Form 10-K for the year ended December 31, 2017 for a full discussion of the risks associated with Devon’s business.
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 our general partner 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 our general partner and result in less than favorable treatment of us and our unitholders.
Adverse developments in our gathering, transmission, processing, crude oil, condensate, natural gas and NGL services businesses would reduce our ability to make distributions to our unitholders.
We rely exclusively on the revenues generated from our gathering, transmission, processing, fractionation, crude oil, natural gas, condensate and NGL services businesses, and as a result, our financial condition depends upon prices of, and continued demand for, natural gas, NGLs, crude oil and condensate. An adverse development in one of these businesses may have a significant impact on our financial condition and our ability to make distributions to our unitholders.
A significant portion of our operations are located in the Barnett Shale, making us vulnerable to risks associated with having revenue-producing operations concentrated in a limited number of geographic areas.
Our revenue-producing operations are geographically concentrated in the Barnett Shale, causing us to be exposed to risks associated with regional factors. Specifically, our operations in the Barnett Shale accounted for approximately 11.9% of our consolidated revenues and approximately 34.1% of our consolidated gross operating margin for the year ended December 31, 2017. The concentration of our operations in this region also increases exposure to unexpected events that may occur in this region such as natural disasters or labor difficulties. Any one of these events has the potential to have a relatively significant impact on our operations and growth plans, decrease cash flows, increase operating and capital costs and prevent development within originally anticipated time frames. Any of these risks could have a material adverse effect on our financial condition, results of operations or cash flows.
We must continually compete for crude oil, condensate, natural gas and NGL supplies, and any decrease in supplies of such commodities could adversely affect our financial condition, results of operations or cash flows.
In order to maintain or increase throughput levels in our gathering systems and asset utilization rates at our processing plants and fractionators, we must continually contract for new product supplies. We may not be able to obtain additional contracts for crude oil, condensate, natural gas and NGL supplies. The primary factors affecting our ability to connect new wells to our gathering facilities include our success in contracting for existing supplies that are not committed to other systems and the level of drilling activity near our gathering systems. If we are unable to maintain or increase the volumes on our systems by accessing new supplies to offset the natural decline in reserves, our business and financial results could be materially, adversely affected. In addition, our future growth will depend in part upon whether we can contract for additional supplies at a greater rate than the rate of natural decline in our current supplies.
Fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new crude oil, condensate and natural gas reserves. During 2015 and 2016, we saw suppressed drilling activity due to low commodity prices. Although drilling activity has improved during 2017 in some of the most economic basins, we could see downward pressure on future drilling activity in these basins if commodity prices decline below current levels, which may 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 our systems and assets. Additional governmental regulation of, or delays in issuance of permits for, the offshore exploration and production industry may negatively impact current and future volumes from offshore pipelines supplying our processing plants. We have no control over producers and depend on them to maintain sufficient levels of drilling activity. A continued decrease in the level of drilling activity or a material decrease
in production in our principal geographic areas for a prolonged period, as a result of unfavorable commodity prices or otherwise, likely would have a material adverse effect on our financial condition, results of operations and cash flows.
Any decrease in the volumes that we gather, process, fractionate or transport would adversely affect our financial condition, results of operations or cash flows.
Our financial performance depends to a large extent on the volumes of natural gas, crude oil, condensate and NGLs gathered, processed, fractionated and transported on our assets. Decreases in the volumes of natural gas, crude oil, condensate and NGLs we gather, process, fractionate or transport would directly and adversely affect our financial condition. These volumes can be influenced by factors beyond our control, including:
environmental or other governmental regulations;
increases in storage levels of natural gas, NGLs, crude oil and condensate;
increased use of alternative energy sources;
decreased demand for natural gas, NGLs, crude oil and condensate;
continued fluctuations in commodity prices, including the prices of natural gas, NGLs, crude oil and condensate;
availability of supply connected to our systems; and
availability and adequacy of infrastructure to gather and process supply into and out of our systems.
The volumes of natural gas, crude oil, condensate and NGLs gathered, processed, fractionated and transported on our assets also depend on the production from the regions that supply our systems. Supply of natural gas, crude oil, condensate and NGLs can be affected by many of the factors listed above, including commodity prices and weather. In order to maintain or increase throughput levels on our systems, we must obtain new sources of natural gas, crude oil, condensate and NGLs. The primary factors affecting our ability to obtain non-dedicated sources of natural gas, crude oil, condensate and NGLs include (i) the level of successful leasing, permitting and drilling activity in our areas of operation, (ii) our ability to compete for volumes from new wells and (iii) our ability to compete successfully for volumes from sources connected to other pipelines. We have no control over the level of drilling activity in our areas of operation, the amount of reserves associated with wells connected to our systems or the rate at which production from a well declines. In addition, we have no control over producers or their drilling or production decisions, which are affected by, among other things, the availability and cost of capital, levels of reserves, availability of drilling rigs and other costs of production and equipment.
An impairment of goodwill, long-lived assets, including intangible assets and equity method investments, could reduce our earnings.
GAAP requires us to test goodwill and intangible assets with indefinite useful lives for impairment on an annual basis or when events or circumstances occur indicating that goodwill might be impaired. Long-lived assets, including intangible assets with finite useful lives, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. For the investments we account for under the equity method, the impairment test considers whether the fair value of the unconsolidated affiliate investment as a whole, not the underlying net assets, has declined and whether that decline is other than temporary. If we determine that an impairment is indicated, we would be required to take an immediate non-cash charge to earnings with a correlative effect on equity and balance sheet leverage as measured by debt to total capitalization. For the year ended December 31, 2015, we recognized impairments on property and equipment of $12.1 million, an intangible asset impairment of $223.1 million and a goodwill impairment of $1,328.2 million. In the first quarter of 2016, we recognized an additional goodwill impairment of $566.3 million. For the year ended December 31, 2017, we recognized impairments on property and equipment of $17.1 million. Additional impairment of the value of our existing goodwill and intangible assets could have a significant negative impact on our future operating results.
Our construction of new assets may be more expensive than anticipated, may not result in revenue increases and may be subject to regulatory, environmental, political, legal and economic risks that could adversely affect our financial condition, results of operations or cash flows.
The construction of additions or modifications to our existing systems and the construction of new midstream assets involves numerous regulatory, environmental, political and legal uncertainties beyond our control including potential protests or legal actions by interested third parties, and may require the expenditure of significant amounts of capital. Financing may not be
available on economically acceptable terms or at all. If we undertake these projects, we may not be able to complete them on schedule, at the budgeted cost or at all. Moreover, our revenues may not increase due to the successful construction of a particular project. For instance, if we expand a pipeline or construct a new pipeline, the construction may occur over an extended period of time, and we may not receive any material increases in revenues promptly following completion of a project or at all. Moreover, we may construct facilities to capture anticipated future production growth in a region in which such growth does not materialize. As a result, new facilities may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our financial condition, results of operations or cash flows. In addition, the construction of additions to our existing gathering and processing assets will generally require us to obtain new rights-of-way and permits prior to constructing new pipelines or facilities. We may be unable to timely obtain such rights-of-way or permits to connect new product supplies to our existing gathering lines or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for us to obtain new rights-of-way or to expand or renew existing rights-of-way. If the cost of renewing or obtaining new rights-of-way increases, our cash flows could be adversely affected.
Construction of our major development projects subjects us to risks of construction delays, cost over-runs, limitations on our growth and negative effects on our financial condition, results of operations or cash flows.
We are engaged in the planning and construction of several major development projects, some of which will take a number of months before commercial operation. These projects are complex and subject to a number of factors beyond our control, including delays from vendors, suppliers and third-party landowners, the permitting process, changes in laws, unavailability of materials, labor disruptions, environmental hazards, financing, accidents, weather and other factors. Any delay in the completion of these projects could have a material adverse effect on our financial condition, results of operations or cash flows. The construction of pipelines and gathering and processing and fractionation facilities requires the expenditure of significant amounts of capital, which may exceed our estimated costs. Estimating the timing and expenditures related to these development projects is very complex and subject to variables that can significantly increase expected costs. Should the actual costs of these projects exceed our estimates, our liquidity and capital position could be adversely affected. This level of development activity requires significant effort from our management and technical personnel and places additional requirements on our financial resources. We may not have the ability to attract and/or retain the necessary number of personnel with the skills required to bring complicated projects to successful conclusions.
Our operations are dependent on our rights and ability to receive or renew the required permits and other approvals from governmental authorities and other third parties.
Performance of our operations requires that we obtain and maintain numerous environmental and land use permits and other approvals authorizing our business activities. A decision by a governmental authority or other third party to deny, delay or restrictively condition the issuance of a new or renewed permit or other approval, or to revoke or substantially modify an existing permit or other approval, could have a material adverse effect on our ability to initiate or continue operations at the affected location or facility. Expansion of our existing operations is also predicated on securing the necessary environmental or land use permits and other approvals, which we may not receive in a timely manner or at all.
In order to obtain permits and renewals of permits and other approvals in the future, we may be required to prepare and present data to governmental authorities pertaining to the potential adverse impact that any proposed activities may have on the environment, individually or in the aggregate, including on public and Indian lands. Certain approval procedures may require preparation of archaeological surveys, endangered species studies and other studies to assess the environmental impact of new sites or the expansion of existing sites. Compliance with these regulatory requirements is expensive and significantly lengthens the time needed to develop a site or pipeline alignment. Also, obtaining or renewing required permits or other approvals is sometimes delayed or prevented due to community opposition and other factors beyond our control. The denial of a permit or other approvals essential to our operations or the imposition of restrictive conditions with which it is not practicable or feasible to comply could impact our operations or prevent our ability to expand our operations or obtain rights-of-way. Significant opposition to a permit or other approvals by neighboring property owners, members of the public or non-governmental organizations, or other third parties or delays in the environmental review and permitting process also could impact our operations or prevent our ability to expand our operations or obtain rights-of-way.
We conduct a portion of our operations through joint ventures, which subjects us to additional risks that could have a material adverse effect on the success of these operations, our financial position, results of operations or cash flows.
We participate in several joint ventures, and we may enter into other joint venture arrangements in the future. The nature of a joint venture requires us to share control with unaffiliated third parties. If our joint venture partners do not fulfill their contractual and other obligations, the affected joint venture may be unable to operate according to its business plan, and we may be required to increase our level of commitment. If we do not timely meet our financial commitments or otherwise comply with
our joint venture agreements, our ownership of and rights with respect to the applicable joint venture may be reduced or otherwise adversely affected. Differences in views among joint venture participants could also result in delays in business decisions or otherwise, failures to agree on major issues, operational inefficiencies and impasses, litigation or other issues. Third parties may also seek to hold us liable for the joint ventures’ liabilities. These issues or any other difficulties that cause a joint venture to deviate from its original business plan could have a material adverse effect on our financial condition, results of operations or cash flows.
Any reductions in our credit ratings could increase our financing costs, the cost of maintaining certain contractual relationships and reduce our cash available for distribution.
We cannot guarantee that our credit ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. S&P and Moody’s have currently assigned to ENLK a BBB- and Ba1 credit rating, respectively. Any future downgrade could increase the cost of borrowings under our credit facility. Any downgrade could also lead to higher borrowing costs for future borrowings and, if below investment grade, could require:
additional or more restrictive covenants that impose operating and financial restrictions on us and our subsidiaries;
our subsidiaries to guarantee such debt and certain other debt;
us and our subsidiaries to provide collateral to secure such debt; and
us or our subsidiaries to post cash collateral or letters of credit under our hedging arrangements or in order to purchase commodities or obtain trade credit.
Any increase in our financing costs or additional or more restrictive covenants resulting from a credit rating downgrade could adversely affect our ability to finance future operations and make cash distributions to unitholders. If a credit rating downgrade and the resultant collateral requirement were to occur at a time when we were experiencing significant working capital requirements or otherwise lacked liquidity, our results of operations and our ability to make cash distributions to unitholders could be adversely affected.
We typically do not obtain independent evaluations of hydrocarbon reserves; therefore, volumes we service in the future could be less than we anticipate.
We typically do not obtain, on a regular basis, independent evaluations of hydrocarbon reserves connected to our gathering systems or that we otherwise service due to the unwillingness of producers to provide reserve information as well as the cost of such evaluations. Accordingly, we do not have independent estimates of total reserves serviced by our assets or the anticipated life of such reserves. If the total reserves or estimated life of the reserves is less than we anticipate and we are unable to secure additional sources, then the volumes transported on our gathering systems or that we otherwise service in the future could be less than anticipated. A decline in the volumes could have a material adverse effect on our financial condition, results of operations or cash flows.
We may not be successful in balancing our purchases and sales.
We are a party to certain long-term gas, NGL and condensate sales commitments that we satisfy through supplies purchased under long-term gas, NGL and condensate purchase agreements. When we enter into those arrangements, our sales obligations generally match our purchase obligations. However, over time, the supplies that we have under contract may decline due to reduced drilling or other causes, and we may be required to satisfy the sales obligations by purchasing additional gas at prices that may exceed the prices received under the sales commitments. In addition, a producer could fail to deliver contracted volumes or deliver in excess of contracted volumes, or a consumer could purchase more or less than contracted volumes. Any of these actions could cause our purchases and sales not to be balanced. If our purchases and sales are not balanced, we will face increased exposure to commodity price risks and could have increased volatility in our operating income.
We have made commitments to purchase natural gas in production areas based on production-area indices and to sell the natural gas into market areas based on market-area indices, pay the costs to transport the natural gas between the two points and capture the difference between the indices as margin. Changes in the index prices relative to each other (also referred to as basis spread) can significantly affect our margins or even result in losses. For example, we are a party to one contract associated with our North Texas operations with a term to July 2019 to supply approximately 150,000 MMBtu/d of gas. We buy gas for this contract on several different production-area indices and sell the gas into a different market area index. We realize a loss on the delivery of gas under this contract each month based on current prices. As of December 31, 2017, the balance sheet reflected a liability of $26.9 million related to this performance obligation based on forecasted discounted cash obligations in excess of
market under this gas delivery contract. Reduced supplies and narrower basis spreads in recent periods have increased the losses on this contract, and greater losses on this contract could occur in future periods if these conditions persist or become worse.
Our profitability is dependent upon prices and market demand for crude oil, condensate, natural gas and NGLs that are beyond our control and have been volatile. A depressed commodity price environment could result in financial losses and reduce our cash available for distribution.
We are subject to significant risks due to fluctuations in commodity prices. We are directly exposed to these risks primarily in the gas processing and NGL fractionation components of our business. For the year ended December 31, 2017, approximately 3.4% of our total gross operating margin was generated under percent of liquids contracts and percent of proceeds contracts, with most of these contracts relating to our processing plants in the Permian Basin. Under percent of liquids contracts, we receive a fee in the form of a percentage of the liquids recovered, and the producer bears all the cost of the natural gas shrink. Accordingly, our revenues under percent of liquids contracts are directly impacted by the market price of NGLs. Gross operating margin under percent of proceeds contracts is impacted only by the value of the natural gas or liquids produced with margins higher during periods of higher natural gas and liquids prices.
We also realize gross operating margins under processing margin contracts. For the year ended December 31, 2017, approximately 1.3% of our total gross operating margin was generated under processing margin contracts. We have a number of processing margin contracts for activities at our Plaquemine and Pelican processing plants. Under this type of contract, we pay the producer for the full amount of inlet gas to the plant, and we make a margin based on the difference between the value of liquids recovered from the processed natural gas as compared to the value of the natural gas volumes lost (“shrink”) and the cost of fuel used in processing. The shrink and fuel losses are referred to as plant thermal reduction (“PTR”). Our margins from these contracts can be greatly reduced or eliminated during periods of high natural gas prices relative to liquids prices.
We are also indirectly exposed to commodity prices due to the negative impacts of low commodity prices on production and the development of production of crude oil, condensate, natural gas and NGLs connected to or near our assets and on our margins for transportation between certain market centers. Low prices for these products have reduced the demand for our services and volumes on our systems, and continued low prices may reduce such demand even further.
Although the majority of our NGL fractionation business is under fee-based arrangements, a portion of our business is exposed to commodity price risk because we realize a margin due to product upgrades associated with our Louisiana fractionation business. For the year ended December 31, 2017, gross operating margin realized associated with product upgrades represented approximately 1.3% of our gross operating margin.
The prices of crude oil, condensate, natural gas and NGLs were volatile during 2017. Crude oil and weighted average NGL prices increased 15% and 21%, while natural gas prices decreased 11%, from January 1, 2017 to December 31, 2017, respectively. We expect this volatility to continue. For example, crude oil prices (based on the NYMEX futures daily close prices for the prompt month) in 2017 ranged from a high of $60.42 per Bbl in December 2017 to a low of $42.53 per Bbl in June 2017. Weighted average NGL prices in 2017 (based on the Oil Price Information Service (“OPIS”) Napoleonville daily average spot liquids prices) ranged from a high of $0.78 per gallon in February 2017 to a low of $0.41 per gallon in January 2017. Natural gas prices (based on Gas Daily Henry Hub closing prices) during 2017 ranged from a high of $3.42 per MMBtu in May 2017 to a low of $2.56 per MMBtu in February 2017.
The markets and prices for crude oil, condensate, natural gas and NGLs depend upon factors beyond our control that make it difficult to predict future commodity price movements with any certainty. These factors include the supply and demand for crude oil, condensate, natural gas and NGLs, which fluctuate with changes in market and economic conditions and other factors, including:
the impact of weather on the supply and demand for crude oil and natural gas;
the level of domestic crude oil, condensate and natural gas production;
technology, including improved production techniques (particularly with respect to shale development);
the level of domestic industrial and manufacturing activity;
the availability of imported crude oil, natural gas and NGLs;
international demand for crude oil and NGLs;
actions taken by foreign crude oil and gas producing nations;
the continued threat of terrorism and the impact of military action and civil unrest;
the availability of local, intrastate and interstate transportation systems;
the availability of downstream NGL fractionation facilities;
the availability and marketing of competitive fuels;
the impact of energy conservation efforts; and
the extent of governmental regulation and taxation, including the regulation of hydraulic fracturing and “greenhouse gases.”
Changes in commodity prices also indirectly impact our profitability by influencing drilling activity and well operations, and thus the volume of gas, crude oil and condensate we gather and process and NGLs we fractionate. Volatility in commodity prices may cause our gross operating margin and cash flows to vary widely from period to period. Our hedging strategies may not be sufficient to offset price volatility risk and, in any event, do not cover all of our throughput volumes. Moreover, hedges are subject to inherent risks, which we describe in “Item 7A. Quantitative and Qualitative Disclosure about Market Risk.” Our use of derivative financial instruments does not eliminate our exposure to fluctuations in commodity prices and interest rates and has (in the past) resulted and could (in the future) result in financial losses or reductions in our income.
If third-party pipelines or other midstream facilities interconnected to our gathering or transportation systems become partially or fully unavailable, or if the volumes we gather, process or transport do not meet the quality requirements of the pipelines or facilities to which we connect, our gross operating margin and cash flow could be adversely affected.
Our gathering, processing and transportation assets connect to other pipelines or facilities owned and operated by unaffiliated third parties. The continuing operation of, and our continuing access to, such third-party pipelines, processing facilities and other midstream facilities is not within our control. These pipelines, plants and other midstream facilities may become unavailable because of testing, turnarounds, line repair, maintenance, reduced operating pressure, lack of operating capacity, regulatory requirements and curtailments of receipt or deliveries due to insufficient capacity or because of damage from severe weather conditions or other operational issues. Further, these pipelines and facilities connected to our assets impose product quality specifications. We may be unable to access such facilities or transport product along interconnected pipelines if the volumes we gather or transport do not meet their product quality requirements. In addition, if our costs to access and transport on these third-party pipelines significantly increase, our profitability could be reduced. If any such increase in costs occurs, if any of these pipelines or other midstream facilities become unable to receive, transport or process product, or if the volumes we gather or transport do not meet the product quality requirements of such pipelines or facilities, our operating margin and cash flow could be adversely affected.
Our debt levels could limit our flexibility and adversely affect our financial health or limit our flexibility to obtain financing and to pursue other business opportunities.
We continue to have the ability to incur debt, subject to limitations in our credit facility. Our level of indebtedness could have important consequences to us, including the following:
our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;
our funds available for operations, future business opportunities and distributions to unitholders will be reduced by that portion of our cash flows required to make interest payments on our debt;
our debt level will make us more vulnerable to general adverse economic and industry conditions;
our ability to plan for, or react to, changes in our business and the industry in which we operate; and
our risk that we may default on our debt obligations.
In addition, our ability to make scheduled payments or to refinance our obligations depends on our successful financial and operating performance, which will be affected by prevailing economic, financial and industry conditions, many of which are beyond our control. If our cash flow and capital resources are insufficient to fund our debt service obligations, we may be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets, restructuring or refinancing our debt or seeking additional equity capital. We may not be able to effect any of these actions on satisfactory terms or at all.
The terms of our credit facility and indentures may restrict our current and future operations, particularly our ability to respond to changes in business or to take certain actions.
Our credit facility agreement and the indentures governing our senior notes contain, and any future indebtedness we incur will likely contain, a number of restrictive covenants that impose significant operating and financial restrictions, including restrictions on our ability to engage in acts that may be in our best long-term interest. One or more of these agreements include covenants that, among other things, restrict our ability to:
incur subsidiary indebtedness;
engage in transactions with our affiliates;
consolidate, merge or sell substantially all of our assets;
enter into sale and lease back transactions; and
change business activities we conduct.
In addition, our credit facility requires us to satisfy and maintain a specified financial ratio. Our ability to meet that financial ratio can be affected by events beyond our control, and we cannot assure you that we will continue to meet that ratio.
Our ability to comply with the covenants and restrictions contained in our credit facility and indentures may be affected by events beyond our control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. A breach of any of these covenants could result in an event of default under our 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 our credit facility or indentures is accelerated, there can be no assurance that we will have sufficient assets to repay the indebtedness. The operating and financial restrictions and covenants in these debt agreements and any future financing agreements may adversely affect our ability to finance future operations or capital needs or to engage in other business activities.
A default under ENLC’s credit facility could have an adverse effect on the price of our common units and could result in a change of control of our general partner.
ENLC has entered into a credit facility that is secured by, among other things, a first priority lien on 88,528,451 of our common units and the 100% membership interest in our general partner indirectly held by ENLC. Although we are not a party to this credit facility, if a default under such credit facility were to occur, the lenders could foreclose on the pledged equity interests. Any such foreclosure on our common units could have an adverse effect on the market price of our common units. In addition, any foreclosure on ENLC’s interest in the general partner would allow the new owner of our general partner to replace the board of directors and officers of our general partner with its own designees and to control the decisions taken by the board of directors and officers. Moreover, any change of control of our general partner would permit the lenders under our credit facility to declare all amounts thereunder immediately due and payable, and if any such event occurs, we may be required to refinance our debt on unfavorable terms, which could negatively impact our results of operations and our ability to make distributions to our unitholders.
Increases in interest rates could adversely impact the price of our common units, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions.
Interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our unit price is impacted by our 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 our units, and a rising interest rate environment could have an adverse impact on the price of our common units, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions at our intended levels or at all.
We are vulnerable to operational, regulatory and other risks due to our significant assets in South Louisiana and the Texas Gulf Coast, including the effects of adverse weather conditions such as hurricanes.
Our operations and revenues could be significantly impacted by conditions in South Louisiana and the Texas Gulf Coast because we have significant assets located in these two areas. Our concentration of activity in Louisiana and the Texas Gulf Coast makes us more vulnerable than many of our competitors to the risks associated with these areas, including:
adverse weather conditions, including hurricanes and tropical storms;
delays or decreases in production, the availability of equipment, facilities or services; and
changes in the regulatory environment.
Because a significant portion of our operations could experience the same condition at the same time, these conditions could have a relatively greater impact on our results of operations than they might have on other midstream companies that have operations in more diversified geographic areas.
Our business is subject to a number of weather-related risks. These weather conditions can cause significant damage and disruption to our operations and adversely impact our financial condition, results of operations or cash flows.
Virtually all of our operations are exposed to potential natural disasters, including hurricanes, tornadoes, storms, floods, fires, severe temperatures and earthquakes. In particular, South Louisiana and the Texas Gulf Coast experience hurricanes and other extreme weather conditions on a frequent basis. The location of our significant assets and concentration of activity in these regions make us particularly vulnerable to weather risks in these areas.
High winds, storm surge, flooding and other natural disasters can cause significant damage and curtail our operations for extended periods during and after such weather conditions, which may result in decreased revenues and otherwise adversely impact our financial condition, results of operations or cash flow. These interruptions could involve significant damage to people, property or the environment, and repair time and costs could be extensive. Any such event that interrupts the revenues generated by our operations, or which causes us to make significant expenditures not covered by insurance, could reduce our cash available for paying distributions to our partners and, accordingly, adversely affect our financial condition and the market price of our securities.
In addition, we rely on the volumes of natural gas, crude oil, condensate and NGLs gathered, processed, fractionated and transported on our assets. These volumes are influenced by the production from the regions that supply our systems. Adverse weather conditions can cause direct or indirect disruptions to the operations of, and otherwise negatively affect, producers, suppliers, customers and other third parties to which our assets are connected, even if our assets are not damaged. As a result, our financial condition, results of operations and cash flows could be adversely affected.
We may also suffer reputational damage as a result of a natural disaster or other similar event. The occurrence of such an event, or a series of such events, especially if one or more of them occurs in a highly populated or sensitive area, could negatively impact public perception of our operations and/or make it more difficult for us to obtain the approvals, permits, licenses, rights-of-way or real property interests we need in order to operate our assets or complete planned growth projects.
A reduction in demand for NGL products by the petrochemical, refining or other industries or by the fuel markets could materially adversely affect our financial condition, results of operations or cash flows.
The NGL products we produce have a variety of applications, including as heating fuels, petrochemical feedstocks and refining blend stocks. A reduction in demand for NGL products, whether because of general or industry specific economic conditions, new government regulations, global competition, reduced demand by consumers for products made with NGL products (for example, reduced petrochemical demand observed due to lower activity in the automobile and construction industries), increased competition from petroleum-based feedstocks due to pricing differences, mild winter weather for some NGL applications or other reasons could result in a decline in the volume of NGL products we handle or reduce the fees we charge for our services. Our NGL products and the demand for these products are affected as follows:
Ethane. Ethane is typically supplied as purity ethane or as part of ethane-propane mix. Ethane is primarily used in the petrochemical industry as feedstock for ethylene, one of the basic building blocks for a wide range of plastics and other chemical products. Although ethane is typically extracted as part of the mixed NGL stream at gas processing plants, if natural gas prices increase significantly in relation to NGL product prices or if the demand for ethylene falls,
it may be more profitable for natural gas processors to leave the ethane in the natural gas stream. Such “ethane rejection” reduces the volume of NGLs delivered for fractionation and marketing.
Propane. Propane is used as a petrochemical feedstock in the production of ethylene and propylene, as a heating, engine and industrial fuel, and in agricultural applications such as crop drying. Changes in demand for ethylene and propylene could adversely affect demand for propane. The demand for propane as a heating fuel is significantly affected by weather conditions. The volume of propane sold is at its highest during the six-month peak heating season of October through March. Demand for our propane may be reduced during periods of warmer-than-normal weather.
Normal Butane. Normal butane is used in the production of isobutane, as a refined product blending component, as a fuel gas, and in the production of ethylene and propylene. Changes in the composition of refined products resulting from governmental regulation, changes in feedstocks, products and economics, demand for heating fuel and for ethylene and propylene could adversely affect demand for normal butane.
Isobutane. Isobutane is predominantly used in refineries to produce alkylates to enhance octane levels. Accordingly, any action that reduces demand for motor gasoline or demand for isobutane to produce alkylates for octane enhancement might reduce demand for isobutane.
Natural Gasoline. Natural gasoline is used as a blending component for certain refined products and as a feedstock used in the production of ethylene and propylene. Changes in the mandated composition resulting from governmental regulation of motor gasoline and in demand for ethylene and propylene could adversely affect demand for natural gasoline.
NGLs and products produced from NGLs are sold in competitive global markets. Any reduced demand for ethane, propane, normal butane, isobutane or natural gasoline in the markets we access for any of the reasons stated above could adversely affect demand for the services we provide as well as NGL prices, which would negatively impact our financial condition, results of operations or cash flows.
We expect to encounter significant competition in any new geographic areas into which we seek to expand, and our ability to enter such markets may be limited.
If we expand our operations into new geographic areas, we expect to encounter significant competition for natural gas, condensate, NGLs and crude oil supplies and markets. Competitors in these new markets will include companies larger than us, which have both lower cost of capital and greater geographic coverage, as well as smaller companies, which have lower total cost structures. As a result, we may not be able to successfully develop greenfield or acquire assets located in new geographic areas and our results of operations could be adversely affected.
We do not own most of the land on which our pipelines, compression and plant facilities are located, which could disrupt our operations.
We do not own most of the land on which our pipelines, compression and plant facilities are located, and we are therefore subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid rights-of-way or leases or if such rights-of-way or leases lapse or terminate. We sometimes obtain the rights to land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew right-of-way contracts, leases or otherwise, could cause us to cease operations on the affected land, increase costs related to continuing operations elsewhere and reduce our revenue.
We offer pipeline, truck, rail and barge services. Significant delays, inclement weather or increased costs affecting these transportation methods could materially affect our results of operations.
We offer pipeline, truck, rail and barge services. The costs of conducting these services could be negatively affected by factors outside of our control, including rail service interruptions, new laws and regulations, rate increases, tariffs, rising fuel costs or capacity constraints. Inclement weather, including hurricanes, tornadoes, snow, ice and other weather events, can negatively impact our distribution network. In addition, rail, truck or barge accidents involving the transportation of hazardous materials could result in significant environmental penalties and remediation, claims arising from personal injury and property damage.
We could experience increased severity or frequency of trucking accidents and other claims, which could materially affect our results of operations.
Potential liability associated with accidents in the trucking industry is severe and occurrences are unpredictable. A material increase in the frequency or severity of accidents or workers’ compensation claims or the unfavorable development of existing claims could materially adversely affect our results of operations. In the event that accidents occur, we may be unable to obtain desired contractual indemnities, and our insurance may be inadequate in certain cases. The occurrence of an event not fully insured or indemnified against, or the failure or inability of a customer or insurer to meet its indemnification or insurance obligations, could result in substantial losses.
Changes in trucking regulations may increase our costs and negatively impact our results of operations.
Our trucking services are subject to regulation as motor carriers by the DOT and by various state agencies, whose regulations include certain permit requirements of state highway and safety authorities. These regulatory authorities exercise broad powers over our trucking operations, generally governing such matters as the authorization to engage in motor carrier operations, safety, equipment testing and specifications and insurance requirements. There are additional regulations specifically relating to the trucking industry, including testing and specification of equipment and product handling requirements. The trucking industry is subject to possible regulatory and legislative changes that may impact our operations and affect the economics of the industry by requiring changes in operating practices or by changing the demand for or the cost of providing trucking services. Some of these possible changes include increasingly stringent fuel emission limits, changes in the regulations that govern the amount of time a driver may drive or work in any specific period, limits on vehicle weight and size and other matters, including safety requirements.
If we do not make acquisitions on economically acceptable terms or efficiently and effectively integrate the acquired assets with our asset base, our future growth will be limited.
Our ability to grow depends, in part, on our ability to make acquisitions that result in an increase in cash generated from operations on a per unit basis. If we are unable to make accretive acquisitions either because we are (1) unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them, (2) unable to obtain financing for these acquisitions on economically acceptable terms or at all or (3) outbid by competitors, then our future growth and our ability to increase distributions will be limited.
From time to time, we may evaluate and seek to acquire assets or businesses that we believe complement our existing business and related assets. We may acquire assets or businesses that we plan to use in a manner materially different from their prior owner’s use. Any acquisition involves potential risks, including:
the inability to integrate the operations of recently acquired businesses or assets, especially if the assets acquired are in a new business segment or geographic area;
the diversion of management’s attention from other business concerns;
the failure to realize expected volumes, revenues, profitability or growth;
the failure to realize any expected synergies and cost savings;
the coordination of geographically disparate organizations, systems and facilities;
the assumption of unknown liabilities;
the loss of customers or key employees from the acquired businesses;
a significant increase in our indebtedness; and
potential environmental or regulatory liabilities and title problems.
Management’s assessment of these risks is inexact and may not reveal or resolve all existing or potential problems associated with an acquisition. Realization of any of these risks could adversely affect our operations and cash flows. If we consummate any future acquisition, our capitalization and results of operations may change significantly, and you will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources.
We may not be able to retain existing customers or acquire new customers, which would reduce our revenues and limit our future profitability.
The renewal or replacement of existing contracts with our customers at rates sufficient to maintain current revenues and cash flows depends on a number of factors beyond our control, including the price of, and demand for, crude oil, condensate, NGLs and natural gas in the markets we serve and competition from other midstream service providers. Our competitors include companies larger than we are, which could have both a lower cost of capital and a greater geographic coverage, as well as companies smaller than we are, which could have lower total cost structures. In addition, competition is increasing in some markets that have been overbuilt, resulting in an excess of midstream energy infrastructure capacity, or where new market entrants are willing to provide services at a discount in order to establish relationships and gain a foothold. The inability of our management to renew or replace our current contracts as they expire and to respond appropriately to changing market conditions could have a negative effect on our profitability.
In particular, our ability to renew or replace our existing contracts with industrial end-users and utilities impacts our profitability. For the year ended December 31, 2017, approximately 53.9% of our sales of gas transported using our physical facilities were to industrial end-users and utilities. As a consequence of the increase in competition in the industry and volatility of natural gas prices, industrial end-users and utilities may be reluctant to enter into long-term purchase contracts. Many industrial end-users purchase natural gas from more than one natural gas company and have the ability to change providers at any time. Some of these industrial end-users also have the ability to switch between gas and alternate fuels in response to relative price fluctuations in the market. Because there are numerous companies of greatly varying size and financial capacity that compete with us in marketing natural gas, we often compete in the industrial end-user and utilities markets primarily on the basis of price.
We are exposed to the credit risk of our customers and counterparties, and a general increase in the nonpayment and nonperformance by our customers could have an adverse effect on our financial condition, results of operations or cash flows.
Risks of nonpayment and nonperformance by our customers are a major concern in our business. We are subject to risks of loss resulting from nonpayment or nonperformance by our customers and other counterparties, such as our lenders and hedging counterparties. Any increase in the nonpayment and nonperformance by our customers could adversely affect our results of operations and reduce our ability to make distributions to our unitholders. Additionally, equity values for many of our customers continue to be low. The combination of a reduction in cash flow from lower commodity prices, a reduction in borrowing bases under reserve-based credit facilities and the lack of availability of debt or equity financing may result in a significant reduction in our customers’ liquidity and ability to make payment or perform on their obligations to us. Furthermore, some of our customers may be highly leveraged and subject to their own operating and regulatory risks, which increases the risk that they may default on their obligations to us.
Increased federal, state and local legislation and regulatory initiatives, as well as government reviews relating to hydraulic fracturing could result in increased costs and reductions or delays in natural gas production by our customers, which could adversely impact our revenues.
A portion of our suppliers’ and customers’ natural gas production is developed from unconventional sources, such as deep gas shales, that require hydraulic fracturing as part of the completion process. State legislatures and agencies have enacted legislation and promulgated rules to regulate hydraulic fracturing, require disclosure of hydraulic fracturing chemicals, temporarily or permanently ban hydraulic fracturing and impose additional permit requirements and operational restrictions in certain jurisdictions or in environmentally sensitive areas. EPA and the BLM have also issued rules, conducted studies and made proposals that, if implemented, could either restrict the practice of hydraulic fracturing or subject the process to further regulation. For instance, the EPA has issued final regulations under the federal Clean Air Act establishing performance standards, including standards for the capture of air emissions released during hydraulic fracturing, and adopted rules prohibiting the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. Although the EPA has announced its intention to reconsider the regulations relating to the capture of air emissions in April 2017 and has sought to stay its requirements, the rule remains in effect along with the restriction on discharges to publicly owned wastewater treatment plants. The BLM also adopted new rules, effective on January 17, 2017, to reduce venting, flaring and leaks during oil and natural gas production activities on onshore federal and Indian leases. Certain provisions of the BLM rule went into effect in January 2017, while others were scheduled to go into effect in January 2018. In December 2017, BLM published a final rule delaying the 2018 provisions until 2019. State and federal regulatory agencies also have recently focused on a possible connection between the operation of injection wells used for oil and gas waste waters and an observed increase in induced seismicity, which has resulted in some regulation at the state level. For instance, in December 2016 the Oklahoma Corporation Commission released well completion seismicity guidelines for operators in the STACK play that call for hydraulic
fracturing operations to be suspended following earthquakes of certain magnitudes in the vicinity. As regulatory agencies continue to study induced seismicity, additional legislative and regulatory initiatives could affect our customers’ injection well operations as well as our brine disposal operations.
We cannot predict whether any additional legislation or regulations will be enacted and, if so, what the provisions would be. If additional levels of regulation and permits were required through the adoption of new laws and regulations at the federal or state level, that could lead to delays, increased operating costs and process prohibitions for our suppliers and customers that could reduce the volumes of natural gas that move through our gathering systems which could materially adversely affect our revenue and results of operations.
Transportation on certain of our natural gas pipelines is subject to federal and state rate and service regulation, which could limit the revenues we collect from our customers and adversely affect the cash available for distribution to our unitholders. The imposition of regulation on our currently unregulated natural gas pipelines also could increase our operating costs and adversely affect the cash available for distribution to our unitholders.
The rates, terms and conditions of service under which we transport natural gas in our pipeline systems in interstate commerce are subject to regulation by FERC under the NGA and Section 311 of the NGPA and the rules and regulations promulgated under those statutes. Under the NGA, FERC regulation requires that interstate natural gas pipeline rates be filed with FERC and that these rates be “just and reasonable,” not unduly preferential and not unduly discriminatory, although negotiated or settlement rates may be accepted in certain circumstances. Interested persons may challenge proposed new or changed rates, and FERC is authorized to suspend the effectiveness of such rates pending an investigation or hearing. FERC may also investigate, upon complaint or on its own motion, rates that are already in effect and may order a pipeline to change its rates prospectively. Accordingly, action by FERC could adversely affect our ability to establish rates that cover operating costs and allow for a reasonable return. An adverse determination in any future rate proceeding brought by or against us could have a material adverse effect on our business, financial condition, results of operations, and cash available for distribution. Under the NGPA, we are required to justify our rates for interstate transportation service on a cost-of-service basis every five years. In addition, our intrastate natural gas pipeline operations are subject to regulation by various agencies of the states in which they are located. Should FERC or any of these state agencies determine that our rates for transportation service should be lowered, our business could be adversely affected.
The rates charged by our natural gas pipelines may also be affected by the ongoing uncertainty regarding FERC’s income tax allowance policy as a result of ongoing proceedings at FERC related to third parties or general FERC policies. The ultimate outcome of these proceedings, which may not be definitively resolved for some time, is not certain and could result in changes to FERC’s general treatment of income tax allowances in the cost of service or to the discounted cash flow return on equity. Additionally, recently enacted legislation commonly referred to as the Tax Cuts and Jobs Act (the “Tax Cuts and Jobs Act”) includes a reduction in the highest marginal U.S. federal corporate income tax rate from 35% to 21%, effective for taxable years beginning on or after January 1, 2018. At this time, it is uncertain how and when FERC will require this reduction in corporate tax rates to be reflected in the income tax allowance of regulated entities for rate-making purposes. Depending upon the resolution of these issues, the cost of service rates of our interstate natural gas pipelines could be affected to the extent FERC proposes new rates or changes to our existing rates or if our rates are subject to compliance or challenged by FERC.
Our natural gas gathering and processing activities generally are exempt from FERC regulation under the Natural Gas Act. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of substantial, ongoing litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC and the courts. Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels since FERC has less extensively regulated the gathering activities of interstate pipeline transmission companies and a number of such companies have transferred gathering facilities to unregulated affiliates. Application of FERC jurisdiction to our gathering facilities could increase our operating costs, decrease our rates and adversely affect our business. Our gathering operations also may be or become subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.
If we fail to comply with all the applicable FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines. Under the EPAct 2005, FERC has civil penalty authority to impose penalties for current violations of the NGA or NGPA of up to $1.0 million per day for each violation. The maximum penalty authority established by statute has been adjusted to $1.2 million and will continue to be adjusted periodically for inflation. FERC also has the power to order disgorgement of profits from transactions deemed to violate the NGA and EPAct 2005.
Other state and local regulations also affect our business. We are subject to some ratable take and common purchaser statutes in the states where we operate. Ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes have the effect of restricting our right as an owner of gathering facilities to decide with whom we contract to purchase or transport natural gas. Federal law leaves any economic regulation of natural gas gathering to the states, and some of the states in which we operate have adopted complaint-based or other limited economic regulation of natural gas gathering activities. States in which we operate that have adopted some form of complaint-based regulation, like Texas, generally allow natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering access and rate discrimination.
Transportation on our liquids pipelines is subject to federal and state rate and service regulation, which could limit the revenues we collect from our customers and adversely affect the cash available for distribution to our unitholders. The imposition of regulation on our currently unregulated liquids pipeline operations also could increase our operating costs and adversely affect the cash available for distribution to our unitholders.
Our interstate liquids transportation pipelines are subject to regulation by FERC under the ICA, the Energy Policy Act of 1992 and the rules and regulations promulgated under those laws. If, upon completion of an investigation, FERC finds that new or changed rates are unlawful, it is authorized to require the pipeline to refund revenues collected in excess of the just and reasonable rates during the term of the investigation. FERC may also investigate, upon complaint or on its own motion, rates that are already in effect and may order a carrier to change its rates prospectively if it determines that the rates are unjust and unreasonable or unduly discriminatory or preferential. Under certain circumstances, FERC could limit our recovery of costs or could require us to reduce our rates and the payment of reparations to complaining shippers for up to two years prior to the date of the complaint. In particular, ongoing uncertainty surrounding FERC’s current income tax allowance policy could affect our rates going forward, as could proposed 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, all of which could have a material impact on our business. Such changes, if accepted, could decrease our rates and adversely affect our business.
As we acquire, construct and operate new liquids assets and expand our liquids transportation business, the classification and regulation of our liquids transportation services, including services that our marketing companies provide on our FERC-regulated liquids pipelines, are subject to ongoing assessment and change based on the services we provide and determinations by FERC and the courts. Such changes may subject additional services we provide to regulation by FERC, which could increase our operating costs, decrease our rates and adversely affect our business.
We may incur significant costs and liabilities resulting from compliance with pipeline safety regulations.
The pipelines we own and operate are subject to stringent and complex regulation related to pipeline safety and integrity management. For instance, the Department of Transportation, through PHMSA, has established a series of rules that require pipeline operators to develop and implement integrity management programs for hazardous liquid (including oil) pipeline segments that, in the event of a leak or rupture, could affect HCAs. PHMSA also recently proposed rules 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, we cannot predict the cost of such requirements, but they could be significant. Moreover, violations of pipeline safety regulations can result in the imposition of significant penalties.
Several states have also passed legislation or promulgated rules to address pipeline safety. Compliance with pipeline integrity laws and other pipeline safety regulations issued by state agencies such as the TRRC could result in substantial expenditures for testing, repairs and replacement. For example, TRRC regulations require periodic testing of all intrastate pipelines meeting certain size and location requirements. Our costs relating to compliance with the required testing under the TRRC regulations were approximately $2.3 million, $3.3 million and $3.3 million for the years ended December 31, 2017, 2016 and 2015, respectively. If our pipelines fail to meet the safety standards mandated by the TRRC or PHMSA regulations, then we may be required to repair or replace sections of such pipelines or operate the pipelines at a reduced operating pressure, the cost of which actions cannot be estimated at this time.
Due to the possibility of new or amended laws and regulations or reinterpretation of existing laws and regulations, there can be no assurance that future compliance with PHMSA or state requirements will not have a material adverse effect on our results of operations or financial positions. Moreover, because certain of our operations are located around urban or more
populated areas, such as the Barnett Shale, we may incur additional expenses from compliance with municipal and other local or state regulations that impose various obligations including, among other things, regulating the locations of our facilities; limiting the noise, odor, or light levels of our facilities; and requiring certain other improvements, including to the appearance of our facilities, that result in increased costs for our facilities. We are also subject to claims by neighboring landowners for nuisance related to the construction and operation of our facilities, which could subject us to damages for declines in neighboring property values due to our construction and operation activities.
Failure to comply with existing or new environmental laws or regulations or an accidental release of hazardous substances, hydrocarbons or wastes into the environment may cause us to incur significant costs and liabilities.
Many of the operations and activities of our pipelines, gathering systems, processing plants, fractionators, brine disposal operations and other facilities are subject to significant federal, state and local environmental laws and regulations, the violation of which can result in administrative, civil and criminal penalties, including civil fines, injunctions or both. The obligations imposed by these laws and regulations include obligations related to air emissions and discharge of pollutants from our pipelines and other facilities and the cleanup of hazardous substances and other wastes that are or may have been released at properties currently or previously owned or operated by us or locations to which we have sent wastes for treatment or disposal. These laws impose strict, joint and several liability for the remediation of contaminated areas. Private parties, including the owners of properties near our facilities or upon or through which our gathering systems traverse, may also have the right to pursue legal actions to enforce compliance and to seek damages for non-compliance with environmental laws for releases of contaminants or for personal injury or property damage.
Our business may be adversely affected by increased costs due to stricter pollution control requirements or liabilities resulting from non-compliance with required operating or other regulatory permits. New environmental laws or regulations, including, for example, legislation relating to the control of greenhouse gas emissions, or changes in existing environmental laws or regulations might adversely affect our products and activities, including processing, storage and transportation, as well as waste management and air emissions. Federal and state agencies could also impose additional safety requirements, any of which could affect our profitability. Changes in laws or regulations could also limit our production or the operation of our assets or adversely affect our ability to comply with applicable legal requirements or the demand for crude oil, brine disposal services or natural gas, which could adversely affect our business and our profitability.
Recent rules under the Clean Air Act imposing more stringent requirements on the oil and gas industry could cause our customers and us to incur increased capital expenditures and operating costs as well as reduce the demand for our services.
We are subject to stringent and complex regulation under the federal Clean Air Act, implementing regulations, and state and local equivalents, including regulations related to controls for oil and natural gas production, pipelines, and processing operations. For instance, the EPA finalized new rules, effective August 2, 2016, to regulate emissions of methane and volatile organic compounds from new and modified sources in the oil and gas sector. The EPA announced its intention to reconsider those regulations in April 2017 and has sought to stay its requirements. However, the rule remains in effect. The EPA also finalized a rule regarding the alternative criteria for aggregating multiple small surface sites into a single source for air quality permitting purposes. This rule could cause small facilities, on an aggregate basis, to be deemed a major source if within one quarter-mile of one another, thereby triggering more stringent air permitting processes and requirements across the oil and gas industry. In addition, on November 10, 2016, the EPA issued a final Information Collection Request (“ICR”) that requires numerous oil and gas companies to provide information regarding methane emissions from existing oil and gas facilities, a step used to provide a basis for future rulemaking. The EPA withdrew this ICR in March of 2017. The BLM also adopted new rules on November 15, 2016, effective January 17, 2017, to reduce venting, flaring, and leaks during oil and natural gas production activities on onshore federal and Indian leases. Certain provisions of the BLM rule went into effect in January 2017, while others were scheduled to go into effect in January 2018. In December 2017, BLM published a final rule delaying the 2018 provisions until 2019.
Additional regulation of GHG emissions from the oil and gas industry remains a possibility. These regulations could require a number of modifications to our operations, and our natural gas exploration and production suppliers’ and customers’ operations, including the installation of new equipment, which could result in significant costs, including increased capital expenditures and operating costs. The incurrence of such expenditures and costs by our suppliers and customers could result in reduced production by those suppliers and customers and thus translate into reduced demand for our services. Responding to rule challenges, the EPA has since revised certain aspects of its April 2012 rules and has indicated that it may reconsider other aspects of the rules.
Climate change legislation and regulatory initiatives could result in increased operating costs and reduced demand for the natural gas and NGL services we provide.
The United States Congress has from time to time considered adopting legislation to reduce emissions of GHGs, and there has been a wide-ranging policy debate, both nationally and internationally, regarding the impact of these gases and possible means for their regulation. In addition, efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues. In 2015, the United States participated in the United Nations Conference on Climate Change, which led to the adoption of the Paris Agreement. The Paris Agreement became effective November 4, 2016 and requires countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals, every five years beginning in 2020. Although the Trump Administration has announced its intent to withdraw from the Paris Agreement, the earliest effective date of this withdrawal pursuant to the terms of the Paris Agreement is November 2020. At the federal regulatory level, both the EPA and the BLM have adopted regulations for the control of methane emissions, which also include leak detection and repair requirements, from the oil and gas industry.
In addition, many states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and NGL fractionation plants, to acquire and surrender emission allowances with the number of allowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved.
Although it is not possible at this time to predict whether future legislation or new regulations may be adopted to address greenhouse gas emissions or how such measures would impact our business, the adoption of legislation or regulations imposing reporting or permitting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur additional costs to reduce emissions of GHGs associated with our operations, could adversely affect our performance of operations in the absence of any permits that may be required to regulate emission of GHGs or could adversely affect demand for the natural gas we gather, process or otherwise handle in connection with our services.
The ESA and MBTA govern our operations and additional restrictions may be imposed in the future, which could have an adverse impact on our operations.
The ESA and analogous state laws restrict activities that may affect endangered or threatened species or their habitats. Similar protections are offered to migratory birds under the MBTA. The U.S. Fish and Wildlife Service and state agencies may designate critical or suitable habitat areas that they believe are necessary for the survival of threatened or endangered species, which could materially restrict use of or access to federal, state and private lands. Some of our operations may be located in areas that are designated as habitats for endangered or threatened species or that may attract migratory birds. In these areas, we may be obligated to develop and implement plans to avoid potential adverse impacts to protected species, and we may be prohibited from conducting operations in certain locations or during certain seasons, such as breeding and nesting seasons, when our operations could have an adverse effect on the species. It is also possible that a federal or state agency could order a complete halt to our activities in certain locations if it is determined that such activities may have a serious adverse effect on a protected species. In addition, the U.S. Fish and Wildlife Service and state agencies regularly review species that are listing candidates, and designations of additional endangered or threatened species, or critical or suitable habitat, under the ESA could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas.
Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. The occurrence of a significant accident or other event that is not fully insured could adversely affect our operations and financial condition.
Our operations are subject to the many hazards inherent in the gathering, compressing, processing, transporting, fractionating, disposing and storage of natural gas, NGLs, condensate, crude oil and brine, including:
damage to pipelines, facilities, storage caverns, equipment and surrounding properties caused by hurricanes, floods, sink holes, fires and other natural disasters and acts of terrorism;
inadvertent damage to our assets from construction or farm equipment;
leaks of natural gas, NGLs, crude oil, condensate and other hydrocarbons;
rail accidents, barge accidents and truck accidents;
These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage and may result in curtailment or suspension of our related operations. We are not fully insured against all risks incident to our business. In accordance with typical industry practice, we have appropriate levels of business interruption and property insurance on our underground pipeline systems. We are not insured against all environmental accidents that might occur. If a significant accident or event occurs that is not fully insured, it could adversely affect our operations and financial condition.
The adoption of derivatives legislation by the United States Congress and promulgation of related regulations could have an adverse effect on our ability to hedge risks associated with our business.
Comprehensive financial reform legislation was signed into law by the President on July 21, 2010. The legislation calls for the Commodities Futures Trading Commission (“CFTC”) to regulate certain markets for derivative products, including over-the-counter (“OTC”) derivatives. The CFTC has issued several new relevant regulations and other rulemakings are pending at the CFTC, the product of which would be rules that implement the mandates in the new legislation to cause significant portions of derivatives markets to clear through clearinghouses. While some of these rules have been finalized, some have not and, as a result, the final form and timing of the implementation of the new regulatory regime affecting commodity derivatives remains uncertain.
In particular, on October 18, 2011, the CFTC adopted final rules under the Dodd-Frank Act establishing position limits for certain energy commodity futures and options contracts and economically equivalent swaps, futures and options. The position limit levels set the maximum amount of covered contracts that a trader may own or control separately or in combination, net long or short. The final rules also contained limited exemptions from position limits which would be phased in over time for certain bona fide hedging transactions and positions. The CFTC’s original position limits rule was challenged in court by two industry associations and was vacated and remanded by a federal district court. However, the CFTC proposed and revised new rules in November 2013 and December 2016, respectively, that would place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. The CFTC has sought comment on the position limits rule as reproposed, but these new position limit rules are not yet final and the impact of those provisions on us is uncertain at this time. The CFTC has withdrawn its appeal of the court order vacating the original position limits rule.
The legislation and new regulations may also require counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. The new legislation and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures and to generate sufficient cash flow to pay quarterly distributions at current levels or at all. Our revenues could be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material, adverse effect on us, our financial condition and our results of operations.
Our use of derivative financial instruments does not eliminate our exposure to fluctuations in commodity prices and interest rates and has in the past and could in the future result in financial losses or reduce our income.
Our operations expose us to fluctuations in commodity prices, and our credit facility exposes us to fluctuations in interest rates. We use over-the-counter price and basis swaps with other natural gas merchants and financial institutions. Use of these instruments is intended to reduce our exposure to short-term volatility in commodity prices. As of December 31, 2017, we have hedged only portions of our expected exposures to commodity price risk. In addition, to the extent we hedge our commodity price risk using swap instruments, we will forego the benefits of favorable changes in commodity prices. Although we do not currently have any financial instruments to eliminate our exposure to interest rate fluctuations, we may use financial instruments in the future to offset our exposure to interest rate fluctuations.
Even though monitored by management, our hedging activities may fail to protect us and could reduce our earnings and cash flow. Our hedging activity may be ineffective or adversely affect cash flow and earnings because, among other factors:
hedging can be expensive, particularly during periods of volatile prices;
our counterparty in the hedging transaction may default on its obligation to pay or otherwise fail to perform; and
available hedges may not correspond directly with the risks against which we seek protection. For example:
the duration of a hedge may not match the duration of the risk against which we seek protection;
variations in the index we use to price a commodity hedge may not adequately correlate with variations in the index we use to sell the physical commodity (known as basis risk); and
we may not produce or process sufficient volumes to cover swap arrangements we enter into for a given period. If our actual volumes are lower than the volumes we estimated when entering into a swap for the period, we might be forced to satisfy all or a portion of our derivative obligation without the benefit of cash flow from our sale or purchase of the underlying physical commodity, which could adversely affect our liquidity.
A failure in our computer systems or a terrorist or cyber-attack on us, or third parties with whom we have a relationship, may adversely affect our ability to operate our business.
We are reliant on technology to conduct our business. Our business is dependent upon our operational and financial computer systems to process the data necessary to conduct almost all aspects of our business, including operating our pipelines, truck fleet and storage facilities, recording and reporting commercial and financial transactions and receiving and making payments. Any failure of our computer systems, or those of our customers, suppliers or others with whom we do business, could materially disrupt our ability to operate our business. Unknown entities or groups have mounted so-called “cyber-attacks” on businesses to disable or disrupt computer systems, disrupt operations and steal funds or data. Cyber-attacks could also result in the loss of confidential or proprietary data or security breaches of other information technology systems that could disrupt our operations and critical business functions. In addition, our pipeline systems may be targets of terrorist activities that could disrupt our ability to conduct our business and have a material adverse effect on our business and results of operations. Strategic targets, such as energy-related assets, may be at greater risk of future terrorist or cyber-attacks than other targets in the United States. Our insurance may not protect us against such occurrences. Any such terrorist or cyber-attack that affects us or our customers, suppliers or others with whom we do business, could have a material adverse effect on our business, cause us to incur a material financial loss, subject us to possible legal claims and liability and/or damage our reputation.
Moreover, as the sophistication of cyber attacks continues to evolve, we may be required to expend significant additional resources to further enhance our digital security or to remediate vulnerabilities. In addition, cyber-attacks against us or others in our industry could result in additional regulations, which could lead to increased regulatory compliance costs, insurance coverage cost or capital expenditures. We cannot predict the potential impact to our business or the energy industry resulting from additional regulations.
Our success depends on key members of our management, the loss or replacement of whom could disrupt our business operations.
We depend on the continued employment and performance of the officers of our general partner and key operational personnel. If any of these officers or other key personnel resign or become unable to continue in their present roles and are not adequately replaced, our business operations could be materially adversely affected. We do not maintain any “key man” life insurance for any officers.
Failure to attract and retain an appropriately qualified workforce could reduce labor productivity and increase labor costs, which could have a material adverse effect on our business and results of operations.
Gathering and compression services require laborers skilled in multiple disciplines, such as equipment operators, mechanics and engineers, among others. Our business is dependent on our ability to recruit, retain and motivate employees. Certain circumstances, such as an aging workforce without appropriate replacements, a mismatch of existing skill sets to future needs, competition for skilled labor or the unavailability of contract resources, may lead to operating challenges such as a lack of resources, loss of knowledge or a lengthy time period associated with skill development. Our costs, including costs for contractors to replace employees, productivity costs and safety costs, may rise. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to the new employees, or the future availability and cost of contract labor may adversely affect our ability to manage and operate our business. If we are unable to successfully attract and retain an appropriately qualified workforce, our results of operations could be negatively affected.
Subsidence and coastal erosion could damage our pipelines along the Gulf Coast and offshore and the facilities of our customers, which could adversely affect our operations and financial condition.
Our pipeline operations along the Gulf Coast and offshore could be impacted by subsidence and coastal erosion. Such processes could cause serious damage to our pipelines, which could affect our ability to provide transportation services. Additionally, such processes could impact our customers who operate along the Gulf Coast, and they may be unable to utilize our services. Subsidence and coastal erosion could also expose our operations to increased risks associated with severe weather conditions, such as hurricanes, flooding and rising sea levels. As a result, we may incur significant costs to repair and preserve our pipeline infrastructure. Such costs could adversely affect our financial condition, results of operation or cash flows.
Our assets were constructed over many decades using varying construction and coating techniques, which may cause our inspection, maintenance or repair costs to increase in the future. In addition, there could be service interruptions due to unknown events or conditions or increased downtime associated with our pipelines that could have a material adverse effect on our financial condition, results of operations or cash flows.
Our pipelines were constructed over many decades. Pipelines are generally long-lived assets, and pipeline construction and coating techniques have varied over time and can vary for individual pipelines. Depending on the construction era and quality, some assets will require more frequent inspections or repairs, which could result in increased maintenance or repair expenditures in the future. Any significant increase in these expenditures could adversely affect our financial condition, results of operations or cash flows.
Risk Inherent in an Investment in the Partnership
Cash distributions are not guaranteed and may fluctuate with our performance and the establishment of financial reserves.
Because distributions on our units are dependent on the amount of cash we generate, distributions may fluctuate based on our performance. The actual amount of cash that is available to be distributed each quarter will depend on numerous factors, some of which are beyond our control and the control of our general partner. Cash distributions are dependent primarily on cash flow, including cash flow from financial reserves and working capital borrowings, and not solely on profitability, which is affected by non-cash items. Therefore, cash distributions might be made during periods when we record losses and might not be made during periods when we record profits.
We may not have sufficient available cash from operating surplus each quarter to enable us to make cash distributions at our current distribution rate under our cash distribution policy. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:
the fees we charge and the margins we realize for our services;
the prices of, levels of production of and demand for crude oil, natural gas, condensate and NGLs;
the volume of natural gas we gather, compress, process, transport and sell, the volume of NGLs we process or fractionate and sell, the volume of crude oil we handle at our crude terminals, the volume of crude oil we gather, transport, purchase and sell, the volume of condensate we stabilize and transport and the volumes of brine we dispose;
the relationship between natural gas and NGL prices;
cash settlements of hedging positions;
the level of competition from other midstream energy companies;
the level of our operating and maintenance and general and administrative costs; and
prevailing economic conditions.
In addition, the actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including:
the level of capital expenditures we make;
our ability to make borrowings under our credit facility to pay distributions;
the cost of acquisitions;
our debt service requirements and other liabilities;
fluctuations in our working capital needs;
general and administrative expenses;
restrictions on distributions contained in our debt agreements; and
the amount of cash reserves established by our general partner for the proper conduct of our business.
Because of these factors, we may not be able, or may not have sufficient available cash to pay distributions to unitholders each quarter. Furthermore, you should also be aware that the amount of cash we have available for distribution depends primarily upon our cash flows, including cash flow from financial reserves and borrowings under our credit facility, and is not solely a function of profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses and may not make cash distributions during periods when we record net income.
Devon, through its control of ENLC, controls our general partner, which has sole responsibility for conducting our business and managing our operations. Devon, ENLC and our general partner have conflicts of interest with, and may favor Devon’s interests to the detriment of, our unitholders.
Devon, through its control of ENLC, controls our general partner and indirectly has the power to appoint all of the officers and directors of our general partner. Although our general partner has a fiduciary duty to manage us in a manner that is beneficial to us and our unitholders, the directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner that is beneficial to its owner, ENLC, in which Devon owns the manager and a 64.0% limited liability company interest as of December 31, 2017. Conflicts of interest may arise in the future among Devon, ENLC and its affiliates, including our general partner, on the one hand, and our partnership and our unitholders, on the other hand. As a result of these conflicts, our general partner may favor its own interests and those of its affiliates, including Devon and ENLC, over our interests. These conflicts include, among others, the following situations:
Conflicts Relating to Control
our partnership agreement limits our general partner’s liability and reduces its fiduciary duties, while also restricting the remedies available to our unitholders for actions that might, without these limitations, constitute breaches of fiduciary duty by our general partner;
in resolving conflicts of interest, our general partner is allowed to take into account the interests of parties in addition to unitholders, which has the effect of limiting its fiduciary duties to the unitholders;
our general partner’s affiliates may engage in limited competition with us;
Conflicts Relating to Costs
our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, issuance of additional limited partner interests and reserves;
our general partner determines which costs incurred by it and its affiliates are reimbursable by us; and
our general partner is not restricted from causing us to pay it or its affiliates for any services rendered on terms that are fair and reasonable to us or entering into additional contractual arrangements with any of these entities on our behalf.
Our unitholders will have limited voting rights and will not be entitled to elect our general partner or the board of directors of our general partner, which could reduce the price at which our common units will trade.
Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business, and therefore limited ability to influence management’s decisions regarding our business. Unitholders did not elect our general partner or the board of directors of our general partner and have no right to elect our general partner or the board of directors of our general partner on an annual or other continuing basis. The board of directors of our general partner, including its independent directors, is chosen indirectly by ENLC, subject, in certain circumstances, to the designation rights of certain of our investors with respect to one director. In addition, the partnership agreement 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 with the performance of our general partner, they have little ability to remove our general partner.
Our unitholders have little ability to remove our general partner because the general partner and its affiliates own a significant amount of our outstanding units. 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 general partner. Affiliates of the general partner controlled approximately 52.3% of all the outstanding units as of February 14, 2018.
Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.
Unitholders’ voting rights are further restricted by the partnership agreement, which provides that any units held by a person that owns 20.0% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of the general partner, cannot be voted on any matter.
Cost reimbursements due to our general partner and its affiliates for services provided, which will be determined by our general partner, could be substantial and would reduce the cash available for distribution to our unitholders.
Prior to making any distributions on the units, we reimburse our general partner and its affiliates, including officers and directors of our general partner, for all expenses they incur on our behalf. These expenses will include all costs incurred by our general partner and its affiliates in the discharge of their duties to our partnership, including costs for rendering corporate staff and support services to us, if any. There is no limit on the amount of expenses for which our manager and its affiliates may be reimbursed. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us. In addition, to the extent our general partner incurs obligations on behalf of us, we are obligated to reimburse or indemnify our general partner. If we are unable or unwilling to reimburse or indemnify our general partner, our general partner 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.
The control of our general partner may be transferred to a third party without unitholder consent.
The general partner may transfer its general partner interest in us to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, there is no restriction in the partnership agreement on the ability of (i) ENLC to transfer all or a portion of its ownership interest in the general partner to a third party or (ii) Devon to transfer all or a portion of its ownership interest in ENLC and/or ENLC’s manager to a third party. The new owner of the general partner or ENLC’s manager, as the case may be, would then be in a position to replace the board of directors and officers of the general partner with its own choices and to control the decisions taken by the board of directors and officers.
Our general partner’s absolute discretion in determining the level of cash reserves may adversely affect our ability to make cash distributions to our unitholders.
Our partnership agreement requires our general partner to deduct from operating surplus cash reserves that in its reasonable discretion are necessary to fund our future operating expenditures. In addition, the partnership agreement permits our general partner to reduce available cash by establishing cash reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party or to provide funds for future distributions to partners. These cash reserves will affect the amount of cash available for distribution to our unitholders.
Our partnership agreement replaces the fiduciary duties otherwise owed to our unitholders by our general partner with contractual standards governing its duties and restricts the remedies available to our unitholders for actions that might otherwise constitute a breach of fiduciary duty by our general partner.
Our partnership agreement contains provisions that eliminate and replace the fiduciary standards that our general partner would otherwise be held to by state fiduciary duty law. For example, our partnership agreement permits our general partner to make a number of decisions, in its individual capacity, as opposed to in its capacity as our general partner, or otherwise, free of fiduciary duties to our unitholders. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting our unitholders. Examples of decisions that our general partner may make in its individual capacity include:
how to allocate business opportunities among us and its other affiliates;
whether to exercise its call right;
whether or not to consent to any merger or consolidation of us or any amendment to our partnership agreement; and
whether or not the general partner should elect to seek the approval of the conflicts committee or the unitholders, or neither, of any conflicted transaction.
The partnership agreement also restricts the remedies available to our unitholders for actions that would otherwise constitute breaches of our general partner’s fiduciary duties. By purchasing any of our common units, a unitholder is treated as having consented to the provisions in our partnership agreement, including the provisions discussed above.
We may issue additional units, including units that are senior to our common units and pari passu, with our Series C Preferred Units, without our unitholders’ approval, which would dilute our unitholders’ ownership interests.
We may issue an unlimited number of limited partner interests of any type without the approval of our unitholders. These additional limited partner interests may include any securities in parity with the Series C Preferred Units without any vote of the holders of the Series C Preferred Units (except where the cumulative distributions on the Series C Preferred Units or any parity securities are in arrears and in certain other circumstances) and without the approval of our common unitholders. The issuance of additional limited partner interests or other equity securities of equal or senior rank will have the following effects:
our existing unitholders’ proportionate ownership interest in us will decrease;
the amount of cash available for distribution on each unit may decrease;
the relative voting strength of each previously outstanding unit may be diminished; and
the market price of the common units may decline.
Additionally, although holders of the Series C Preferred Units are entitled to limited voting rights, with respect to certain matters the Series C Preferred Units generally vote separately as a class along with all other series of our parity securities that we may issue with respect to which like voting rights have been conferred and are exercisable. As a result, the voting rights of holders of Series C Preferred Units may be significantly diluted, and the holders of such other series of parity securities that we may issue may be able to control or significantly influence the outcome of any vote. The issuance of additional units on parity with or senior to the Series C Preferred Units would dilute the interests of the holders of the Series C Preferred Units, and any issuance of equity securities of any class or series that ranks on parity with the Series C Preferred Units as to the payment of distributions and amounts payable upon a liquidation event or additional indebtedness could affect our ability to pay distributions on, redeem or pay the liquidation preference on the Series C Preferred Units.
Future issuances and sales of parity securities, or the perception that such issuances and sales could occur, may cause prevailing market prices for the Series C Preferred Units and our common units to decline and may adversely affect our ability to raise additional capital in the financial markets at times and prices favorable to us.
Furthermore, the payment of distributions on any additional units may increase the risk that we will not be able to make distributions at our prior per unit distribution levels. To the extent new units are senior to our common units, their issuance will increase the uncertainty of the payment of distributions on our common units.
If we do not pay distributions on our Series B Preferred Units and Series C Preferred Units, we will be unable to pay distributions on our common units until all unpaid Series B Preferred Units and Series C Preferred Unit distributions have been paid, and our common unitholders are not entitled to receive distributions for such prior period.
The Series B Preferred Units and Series C Preferred Units rank senior to our common units with respect to distribution rights and rights upon liquidation. If we do not pay the required distributions on our Series B Preferred Units and Series C Preferred Units, we will be unable to pay distributions on our common units. Additionally, because distributions to our Series B Preferred Units and Series C Preferred Unitholders are cumulative, we will have to pay all unpaid accumulated preferred distributions before we can pay any distributions to our common unitholders. Also, because distributions to our common unitholders are not cumulative, if we do not pay distributions on our common units with respect to any quarter, our common unitholders will not be entitled to receive distributions covering any prior periods.
In addition, in the event of our liquidation, winding-up or dissolution, the holders of the Series B Preferred Units and Series C Preferred Units would have the right to receive proceeds from any such transaction before the holders of our common units. The payment of these liquidation preferences could result in common unitholders not receiving any consideration if we were to liquidate, dissolve or wind up, either voluntarily or involuntarily. Additionally, the existence of these liquidation preferences
may reduce the value of our common units, make it harder for us to sell common units in offerings in the future, or prevent or delay a change of control. The preferences and privileges of the Series B Preferred Units and Series C Preferred Units could adversely affect the market price for our common units, or could make it more difficult for us to sell our common units in the future.
In connection with the January 2016 issuance of the Series B Preferred Units, we entered into an agreement with TPG VII Management, LLC (“TPG”), an affiliate of Enfield Holdings, L.P., the holder of our Series B Preferred Units (“Enfield”), pursuant to which we granted them the right to appoint one member to the board of directors of our general partner. In addition, Enfield has the right to vote, under certain conditions, on an as-converted basis with our common unitholders on matters submitted to a unitholder vote. Also, as long as any Series B Preferred Units are outstanding, subject to certain exceptions, the affirmative vote or consent of the holders of at least a majority of the outstanding Series B Preferred Units, voting together as a separate class, will be necessary for, among other things: (i) any action to be taken that adversely affects any of the rights, preferences or privileges of the Series B Preferred Units, (ii) amending the terms of the Series B Preferred Units, (iii) the issuance of any limited partner interests that are senior or in parity in right of distribution or in liquidation to the Series B Preferred Units, subject to certain exceptions, and (iv) the ability to incur funded indebtedness for borrowed money if, immediately after the incurrence thereof and giving pro forma effect to the use of proceeds thereof, the consolidated leverage ratio (as defined in the credit agreement governing our credit facility) would exceed (a) 5.50 to 1.00 if such indebtedness is not incurred during an acquisition period (as defined in the credit agreement governing our credit facility) or (b) 6.00 to 1.00 such indebtedness is incurred during an acquisition period. These restrictions may adversely affect our ability to finance future operations or capital needs or to engage in other business activities.
Furthermore, the Series B Preferred Units are convertible into common units (i) in full or in part, at any time, at Enfield’s option or (ii) in full, at our option, in certain circumstances. Please read “Item 8. Financial Statements and Supplementary Data-Note 8(c)” for additional information concerning the Series B Preferred Units. Such conversion may cause substantial dilution to holders of the common units.
Our general partner has a limited call right that may require our unitholders to sell their common units at an undesirable time or price.
If at any time our general partner and its affiliates own more than 80.0% of the common units, our general partner 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 the common units held by unaffiliated persons at a price equal to the greater of (1) their then-current market price and (2) the highest per-unit price paid by our general partner 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, our unitholders may be required to sell their common units at an undesirable time or price and may therefore not receive any return on their investment. Existing unitholders may also incur a tax liability upon a sale of their units. Our general partner 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 partnership agreement that prevents our general partner from issuing additional common units and exercising its call right. If our general partner exercised its call right, the effect would be to take us private. As of December 31, 2017, ENLC and its affiliates, including Devon, owned 52.4% of our outstanding common units.
ENLC or its affiliates, including our largest holder Devon, may sell units in the public or private markets, and such sales could have an adverse impact on the trading price of the common units.
As of December 31, 2017, ENLC and its affiliates, including our largest holder Devon, held an aggregate of 183,189,051 units. The sale of any or all of these units in the public or private markets could have an adverse impact on the price of common units or on any trading market on which common units are held.
The price of our common units may fluctuate significantly, which could cause our unitholders to lose all or part of their investment.
As of December 31, 2017, only approximately 47.6% of our common units were held by public unitholders. The lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of our common units and limit the number of investors who are able to buy our common units. The market price of our common units may be influenced by many factors, some of which are beyond our control, including:
the quarterly distributions paid by us with respect to our common units;
our quarterly or annual earnings or those of other companies in our industry;
the loss of Devon as a customer;
announcements by us or our competitors of significant contracts or acquisitions;
changes in accounting standards, policies, guidance, interpretations or principles;
general economic conditions;
the failure of securities analysts to cover our common units or changes in financial estimates by analysts;
future sales of our common units; and
other factors described in these “Risk Factors.”
Our unitholders may not have limited liability if a court finds that unitholder action constitutes control of our business.
Our unitholders could be held liable for our obligations to the same extent as a general partner if a court determined that the right or the exercise of the right by our unitholders to remove or replace our general partner, to approve amendments to our partnership agreement, or to take other action under our partnership agreement constituted participation in the “control” of our business, to the extent that a person who has transacted business with the Partnership reasonably believes, based on our unitholders’ conduct, that our unitholders are a general partner. Our general partner generally has unlimited liability for the obligations of our partnership, such as its debts and environmental liabilities, except for those contractual obligations of our partnership that are expressly made without recourse to our general partner. In addition, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act (the “Delaware Act”) provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of that section may be liable to the limited partnership for the amount of the distribution for a period of three years from the date of the distribution. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business.
The NYSE does not require a publicly traded limited partnership like us to comply with certain of its corporate governance requirements.
Our common units are listed on the NYSE. Because we are a publicly traded limited partnership, the NYSE exempts us from the following corporate governance requirements:
the requirement that a majority of the board consist of independent directors;
the requirement that the board of directors have a nominating or corporate governance committee, composed entirely of independent directors, that is responsible for identifying individuals qualified to become board members, consistent with criteria approved by the board, selection of board nominees for the next annual meeting of equity holders, development of corporate governance guidelines and oversight of the evaluation of the board and management;
the requirement that we have a compensation committee of the board, composed entirely of independent directors, that is responsible for reviewing and approving corporate goals and objectives relevant to chief executive officer compensation, evaluation of the chief executive officer’s performance in light of the goals and objectives, determination and approval of the chief executive officer’s compensation, making recommendations to the board with respect to compensation of other executive officers and incentive compensation and equity-based plans that are subject to board approval and producing a report on executive compensation to be included in an annual proxy statement or Form 10-K filed with the SEC;
the requirement that we conduct an annual performance evaluation of the nominating, corporate governance and compensation committees; and
the requirement that we have written charters for the nominating, corporate governance and compensation committees addressing the committees’ responsibilities and annual performance evaluations.
For so long as we remain a publicly traded limited partnership, we will not be required to have a majority of independent directors or nominating, corporate governance or compensation committees. Accordingly, unitholders will not have the same protections afforded to certain corporations that are subject to all of the NYSE corporate governance requirements.
Unitholders may have liability to repay distributions that were wrongfully distributed to them.
Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Act, a limited partnership cannot make a distribution to its limited partners if, after the
distribution, all liabilities, other than liabilities to unitholders on account of their limited partner interests and liabilities for which the recourse of creditors is limited to specific property of the limited partnership, would exceed the fair value of the assets of the limited partnership. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the non-recourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act will be liable to the limited partnership for the amount of the distribution for three years.
Tax Risks to Our Unitholders
Our tax treatment and our being subject to entity level taxation by individual states depends on our status as a partnership for federal income tax purposes. If the IRS treats us as a corporation or we become subject to entity level taxation for state tax purposes, it would substantially reduce the amount of cash available for distribution to our unitholders.
The anticipated after-tax economic benefit of an investment in us depends largely on our being treated as a partnership for federal income tax purposes.
If we were treated as a corporation for federal income tax purposes, we would pay additional tax on our income at corporate rates of up to 21% for taxable years beginning on or after January 1, 2018 (under the law as of the date of this report), and 35% to the extent we were treated as a corporation in any taxable years ending prior to January 1, 2018, and we would probably pay state income taxes as well. In addition, distributions to unitholders would generally be taxed again as corporate distributions, and none of our income, gains, losses or deductions would flow through to unitholders. Because a tax would be imposed upon us as a corporation, the cash available for distribution to unitholders would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders and thus would likely result in a material reduction in the value of the common units.
In addition, recently enacted legislation applicable to partnership tax years beginning after 2017 changes the audit procedures for large partnerships and in certain circumstances would permit the IRS to assess and collect taxes (including any applicable penalties and interest) resulting from partnership-level federal income tax audits directly from us in the year in which the audit is completed. If we are required to make payments of taxes, penalties and interest resulting from audit adjustments, our cash available for distribution to our unitholders might be substantially reduced.
Moreover, changes in current state law may subject us to entity-level taxation by individual states. Because of widespread state budget deficits, several states are evaluating ways to subject partnerships to entity level taxation through the imposition of state income, franchise and other forms of taxation. For example, we are required to pay Texas franchise tax at a maximum effective rate of 0.75% of our taxable margin apportioned to Texas in the prior year. If additional state tax were to be imposed on us, the cash available for distribution to unitholders could be reduced and/or the value of an investment in our common units would be adversely impacted.
Our partnership agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state, or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts will be decreased to reflect the impact of that law on us. No such adjustments have been made to date, but there can be no assurance that no such adjustments will be made in the future.
If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the costs of any contest could reduce the cash available for distribution to our unitholders.
We have not requested any ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from our counsel’s conclusions expressed in this Annual Report or from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take. A court may not agree with all of our counsel’s conclusions or the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the prices at which our common units trade. In addition, our costs of any contest with the IRS will be borne by us and therefore indirectly by our unitholders and our general partner since such costs will reduce the amount of cash available for distribution by us.
If the IRS makes audit adjustments to our income tax returns for tax years beginning after 2017, it may collect any resulting taxes (including any applicable penalties and interest) directly from us, in which case we may require our unitholders and former unitholders to reimburse us for such taxes (including any applicable penalties or interest) or, if we are required to bear such payment, our cash available for distribution to our unitholders might be substantially reduced.
If the IRS makes audit adjustments to income tax returns for tax years beginning after 2017, it may assess and collect taxes (including any applicable penalties and interest) directly from us. We will generally have the ability to shift any such tax liability to our general partner and our unitholders in accordance with their interests in us during the year under audit, but there can be no assurance that we will be able to do so (and will choose to do so) under all circumstances, or that we will be able to (or choose to) effect corresponding shifts in state income or similar tax liability resulting from the IRS adjustment in states in which we do business in the year under audit or in the adjustment year. If we make payments of taxes, penalties and interest resulting from audit adjustments, we may require our unitholders and former unitholders to reimburse us for such taxes (including any applicable penalties or interest) or, if we are required to bear such payment, our cash available for distribution to our unitholders might be substantially reduced. In addition, because payment would be due for the taxable year in which the audit is completed, unitholders during that taxable year would bear the expense of the adjustment even if they were not unitholders during that taxable year.
Unitholders may be required to pay taxes on their share of our taxable income even if they do not receive any cash distributions from us. A unitholder’s share of our taxable income, and its relationship to any distributions we make, may be affected by a variety of factors, including our economic performance, transactions in which we engage or changes in law, and may be substantially different from any estimate we make in connection with a unit offering.
A unitholder’s allocable share of our taxable income will be taxable to it, which may require the unitholder to pay federal income taxes and, in some cases, state and local income taxes, even if the unitholder receives cash distributions from us that are less than the actual tax liability that results from that income or no cash distributions at all.
Further, a unitholder’s share of our taxable income, and its relationship to any distributions we make, may be affected by a variety of factors, including our economic performance, which may be affected by numerous business, economic, regulatory, legislative, competitive and political uncertainties beyond our control, and certain transactions in which we might engage. For example, we may engage in transactions that produce substantial taxable income allocations to some or all of our unitholders without a corresponding increase in cash distributions to our unitholders, such as a sale or exchange of assets, the proceeds of which are reinvested in our business or used to reduce our debt, or an actual or deemed satisfaction of our indebtedness for an amount less than the adjusted issue price of the debt. A unitholder’s ratio of its share of taxable income to the cash received by it may also be affected by changes in law. For instance, under the recently enacted tax reform law known as the Tax Cuts and Jobs Act, the net interest expense deductions of certain business entities, including us, are limited to 30% of such entity’s “adjusted taxable income,” which is generally taxable income with certain modifications. If the limit applies, a unitholder’s taxable income allocations will be more (or its net loss allocations will be less) than would have been the case absent the limitation.
From time to time, in connection with an offering of our units, we may state an estimate of the ratio of federal taxable income to cash distributions that a purchaser of units in that offering may receive in a given period. These estimates depend in part on factors that are unique to the offering with respect to which the estimate is stated, so the expected ratio applicable to other units will be different, and in many cases less favorable, than these estimates. Moreover, even in the case of units purchased in the offering to which the estimate relates, the estimate may be incorrect due to the uncertainties described above, challenges by the IRS to tax reporting positions which we adopt, or other factors. The actual ratio of taxable income to cash distributions could be higher or lower than expected, and any differences could be material and could materially affect the value of the common units.
Tax gain or loss on the disposition of our common units could be different than expected.
Unitholders who sell common units will recognize gain or loss equal to the difference between the amount realized and their tax basis in those common units. Because distributions in excess of the unitholder’s allocable share of total net taxable income decrease the unitholder’s tax basis in his or her units, the amount, if any, of such prior excess distributions with respect to the units sold by the unitholder, will, in effect, become taxable income to the unitholder if the common unit is sold at a price greater than the tax basis in that common unit, even if the price received is less than the original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income to the unitholder due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our non-recourse liabilities, a unitholder who sells units may incur a tax liability in excess of the amount of cash received from the sale.
Tax-exempt entities and foreign persons face unique tax issues from owning common units that may result in adverse tax consequences to them.
Investment in common units by tax-exempt entities, such as individual retirement accounts (known as IRAs), pension plans, and non-U.S. persons, raises issues unique to them. For example, virtually all of our income allocated to organizations exempt from federal income tax, including individual retirement accounts and other qualified retirement plans, will be unrelated business income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes, at the highest applicable effective tax rate, and non-U.S. persons will be required to file federal income tax returns and generally pay tax on their share of our taxable income. If you are a tax-exempt entity or a foreign person, you should consult your tax advisor before investing in our common units.
Under the recently enacted Tax Cuts and Jobs Act, if a unitholder sells or otherwise disposes of a common unit, the transferee is required to withhold 10% of the amount realized by the transferor unless the transferor certifies that it is not a foreign person, and we are required to deduct and withhold from the transferee amounts that should have been withheld by the transferee but were not withheld. However, the Department of the Treasury and the IRS have determined that this withholding requirement should not apply to any disposition of a publicly traded interest in a publicly traded partnership (such as us) until regulations or other guidance have been issued clarifying the application of this withholding requirement to dispositions of such interests. Accordingly, while this new withholding requirement does not currently apply to interests in us, there can be no assurance that such requirement will not apply in the future.
We will treat each purchase of common units as having the same tax benefits without regard to the specific units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.
Because we cannot match transferors and transferees of common units and because of other reasons, we will take depreciation and amortization positions that may not conform to all aspects of existing Treasury regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to unitholders. It also could affect the timing of these tax benefits or the amount of gain from the sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to the tax returns of unitholders.
Treatment of distributions on our Series C Preferred Units as guaranteed payments for the use of capital creates a different tax treatment for the holders of Series C Preferred Units than the holders of our common units.
The tax treatment of distributions on our Series C Preferred Units is uncertain. We will treat the holders of Series C Preferred Units as partners for tax purposes and will treat distributions on the Series C Preferred Units as guaranteed payments for the use of capital that will generally be taxable to the holders of Series C Preferred Units as ordinary income. Although a holder of Series C Preferred Units could recognize taxable income from the accrual of such a guaranteed payment even in the absence of a contemporaneous distribution, we anticipate accruing and making the guaranteed payment distributions semi-annually on the 15th day of June and December through and including December 15, 2022 and, thereafter, quarterly on the 15th day of March, June, September and December of each year. Because the guaranteed payment for each unit must accrue as income to a holder during the taxable year of the accrual, the guaranteed payment attributable to the period beginning December 15 and ending December 31 will accrue as income to the holder of record of a Series C Preferred Unit on December 31 for such period, regardless of whether such holder continues to own the Series C Preferred Unit at the time the actual distribution is made. Otherwise, the holders of Series C Preferred Units are generally not anticipated to share in our items of income, gain, loss or deduction, nor will we allocate any share of our nonrecourse liabilities to the holders of Series C Preferred Units. If the Series C Preferred Units were treated as indebtedness for tax purposes, rather than as guaranteed payments for the use of capital, distributions likely would be treated as payments of interest by us to the holders of Series C Preferred Units.
Investment in the Series C Preferred Units by tax-exempt investors, such as employee benefit plans and individual retirement accounts (“IRAs”), and non-U.S. persons raises issues unique to them. Although the issue is not free from doubt, we will treat distributions to non-U.S. holders of Series C Preferred Units as “effectively connected income” subject to withholding taxes. If the amount of withholding exceeds the amount of U.S. federal income tax actually due, non-U.S. holders of Series C Preferred Units may be required to file U.S. federal income tax returns in order to seek a refund of such excess. The treatment of guaranteed payments for the use of capital to tax-exempt investors is not certain and such payments may be treated as unrelated business taxable income for federal income tax purposes. If you are a tax-exempt entity or a non-U.S. person, you should consult your tax advisor with respect to the consequences of owning our Series C Preferred Units.
The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.
The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units, may be modified by administrative, legislative or judicial interpretation at any time. For example, from time to time, the President and members of Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships, including elimination of partnership tax treatment for publicly traded partnerships. Any modification to the federal income tax laws and interpretations thereof may or may not be retroactively applied and could make it more difficult or impossible for us to meet the requirements that must be satisfied in order for us to be treated as a partnership for federal income tax purposes.
We are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units. Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal income tax purposes, the minimum quarterly distribution and the target distribution levels will be adjusted to reflect the impact of that law on us.
We will adopt certain valuation methodologies and monthly conventions for federal income tax purposes that may result in a shift of income, gain, loss and deduction between our general partner and our unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.
When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and our general partner, which may be unfavorable to such unitholders. Moreover, under our valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of taxable income, gain, loss and deduction between our general partner and certain of our unitholders.
A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of taxable gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.
Entity level taxes on income from our C corporation subsidiary will reduce cash available for distribution, and a unitholder’s share of dividend and interest income from such subsidiary will constitute portfolio income that cannot be offset by the unitholder’s share of other losses or deductions.
A portion of our taxable income is earned through a C corporation subsidiary. Such C corporation subsidiary is subject to federal income tax on its taxable income at the corporate tax rate, which is currently a maximum of 21%, and will likely pay state (and possibly local) income tax at varying rates, on its taxable income. Any such entity level taxes will reduce the cash available for distribution to our unitholders. Distributions from such C corporation subsidiary will generally be taxed again to unitholders as dividend income to the extent of current and accumulated earnings and profits of such subsidiary. Currently, the maximum federal income tax rate applicable to such dividend income which is allocable to individuals is 20% plus an unearned income Medicare tax of 3.8%. An individual unitholder’s share of dividend and interest income from our C corporation subsidiary would constitute portfolio income that could not be offset by the unitholder’s share of our other losses or deductions.
As a result of investing in our common units, you will likely be subject to state and local taxes and return filing or withholding requirements in jurisdictions where you do not live.
In addition to federal income taxes, you will likely be subject to other taxes such as state and local income taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property. You will likely be required to file state and local tax returns and pay state and local income taxes in some or all of the various jurisdictions in which we do business or own property and you may be subject to penalties for failure to comply with those requirements. We own property or conduct business in a number of states, most of which currently impose a state income tax on individuals. Most of these states also impose an income tax on corporations and other entities. As we make acquisitions or expand our business, we may do business or own property in other states that impose an
income tax. It is our unitholders’ responsibility to file all federal, state, local, and foreign tax returns. Under the tax laws of some states where we will conduct business, we may be required to withhold a percentage from amounts to be distributed to a unitholder who is not a resident of that state. Our counsel has not rendered an opinion on the state, local, or foreign tax consequences of owning our common units.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The U.S. Treasury Department and the IRS recently issued final Treasury Regulations pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders although such tax items must be prorated on a daily basis. However, these Treasury Regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to successfully challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.
A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.
Because a unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of the loaned units, he may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Our counsel has not rendered an opinion regarding the treatment of a unitholder where common units are loaned to a short seller to cover a short sale of common units; therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.
Compliance with and changes in tax law could adversely affect our performance.
We are subject to extensive tax laws and regulations, including federal and state income taxes and transactional taxes such as excise, sales/use, payroll, franchise and ad valorem taxes. New tax laws and regulations and changes in existing tax laws and regulations are continuously being enacted that could result in increased tax expenditures in the future. Many of these tax liabilities are subject to audits by the respective taxing authority. These audits may result in additional taxes as well as interest and penalties.
Item 1B. Unresolved Staff Comments
We do not have any unresolved staff comments.
Item 2. Properties
A description of our properties is contained in “Item 1. Business.”
Title to Properties
Substantially all of our pipelines are constructed on rights-of-way granted by the apparent record owners of the property. Lands over which pipeline rights-of-way have been obtained may be subject to prior liens that have not been subordinated to the right-of-way grants. We have obtained, where necessary, easement agreements from public authorities and railroad companies to cross over or under, or to lay facilities in or along, watercourses, county roads, municipal streets, railroad properties and state highways, as applicable. In some cases, property on which our pipeline was built was purchased in fee. Our processing plants are located on land that we lease or own in fee.
We believe that we have satisfactory title to all of our rights-of-way and land assets. Title to these assets may be subject to encumbrances or defects. We believe that none of such encumbrances or defects should materially detract from the value of our assets or from our interest in these assets or should materially interfere with their use in the operation of the business.
Item 3. Legal Proceedings
Our operations are subject to a variety of risks and disputes normally incident to our business. As a result, at any given time we may be a defendant in various legal proceedings and litigation arising in the ordinary course of business, including litigation on disputes related to contracts, property use or damage and personal injury. We may continue to see claims brought by landowners, such as nuisance claims and other claims based on property rights. Except as otherwise set forth herein, we do not believe that any pending or threatened claim or dispute is material to our financial condition, results of operations or cash flows. We maintain insurance policies with insurers in amounts and with coverage and deductibles that our general partner believes are reasonable and prudent. However, we cannot assure you that this insurance will be adequate to protect us from all material expenses related to potential future claims for personal and property damage or that these levels of insurance will be available in the future at economical prices.
At times, our subsidiaries acquire pipeline easements and other property rights by exercising rights of eminent domain and common carrier. As a result, from time to time we or our subsidiaries are party to lawsuits under which a court will determine the value of pipeline easements or other property interests obtained by our subsidiaries by condemnation. Damage awards in these suits should reflect the value of the property interest acquired and the diminution in the value of the remaining property owned by the landowner. However, some landowners have alleged unique damage theories to inflate their damage claims or assert valuation methodologies that could result in damage awards in excess of the amounts anticipated. Although it is not possible to predict the ultimate outcomes of these matters, we do not expect that awards in these matters will have a material adverse impact on our consolidated financial condition, results of operations or cash flows.
We (or our subsidiaries) are defending lawsuits filed by owners of property located near processing facilities or compression facilities that we own or operate as part of our systems. The suits generally allege that the facilities create a private nuisance and have damaged the value of surrounding property. Claims of this nature have arisen as a result of the industrial development of natural gas gathering, processing and treating facilities in urban and occupied rural areas.
We own and operate a high-pressure pipeline and underground natural gas and NGL storage reservoirs and associated facilities near Bayou Corne, Louisiana. In August 2012, a large sinkhole formed in the vicinity of this pipeline and underground storage reservoirs, resulting in damage to certain of our facilities. In order to recover our losses from responsible parties, we sued the operator of a failed cavern in the area, and its insurers, as well as other parties we alleged to have contributed to the formation of the sinkhole seeking recovery for these losses. We also filed a claim with our insurers, which our insurers denied. We disputed the denial and sued our insurers, and we subsequently reached settlements regarding the entirety of our claims in both lawsuits. In August 2014, we received a partial settlement with respect to our claims in the amount of $6.1 million. We secured additional settlement payments during 2017, which resulted in the recognition of “Gain on litigation settlement” of $26.0 million on the consolidated statement of operations for the year ended December 31, 2017.
Item 4. Mine Safety Disclosures
Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities
Our common units are listed on the NYSE under the symbol “ENLK.” On February 14, 2018, there were approximately 27,474 record holders and beneficial owners (held in street name) of our common units. For equity compensation plan information, see discussion under “Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters—Equity Compensation Plan Information.”
The following table shows the high and low closing sales prices per common unit, as reported by the NYSE and cash distributions declared per common unit for the periods indicated:
Declared Per Unit
Quarter Ended December 31
Quarter Ended September 30
Quarter Ended June 30
Quarter Ended March 31
Quarter Ended December 31
Quarter Ended September 30
Quarter Ended June 30
Quarter Ended March 31
Unless restricted by the terms of our credit facility, within 45 days after the end of each quarter, we will distribute all of our available cash, as defined in our partnership agreement, to common unitholders of record on the applicable record date. Our available cash consists generally of all cash on hand at the end of the fiscal quarter plus all cash on hand on the date of determination resulting from working capital borrowings made after the end of the fiscal quarter, less reserves that our general partner determines are necessary to:
provide for the proper conduct of our business;
comply with applicable law, our debt instruments or other agreements; and
provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters.
Under our existing credit facility, we may be limited from making certain distributions if an event of default exists. Please read “Item 8. Financial Statements and Supplementary Data—Note 6” for additional information concerning our credit facility.
Our general partner has broad discretion to establish cash reserves that it determines are necessary or appropriate to properly conduct our business. These can include cash reserves for future capital and maintenance expenditures, reserves to stabilize distributions of cash to the unitholders and our general partner, reserves to reduce debt or, as necessary, reserves to comply with the terms of any of our agreements or obligations. Our distributions are made to our general partner based on its ownership interest with the remaining interest to unitholders, subject to the payment of incentive distributions to our general partner if certain target cash distribution levels to common unitholders are achieved. Incentive distributions to our general partner increase to 13.0%, 23.0% and 48.0% based on incremental distribution thresholds as set forth in our partnership agreement.
The following graph sets forth the cumulative total stockholder return for our common units, the Standard & Poor’s 500 Stock Index, Alerian MLP Index and a peer group of publicly traded limited partnerships in the midstream natural gas, natural gas liquids, propane, and pipeline industries for the year ended December 31, 2017. The chart assumes that $100 was invested on March 10, 2014, with distributions reinvested. The peer group includes MPLX, Energy Transfer Equity, L.P., Targa Resources, Inc. and Western Gas Equity Partners, L.P.
Item 6. Selected Financial Data
The historical financial statements included in this report reflect (1) for periods prior to March 7, 2014, the assets, liabilities and operations of EnLink Midstream Holdings, LP Predecessor (the “Predecessor”), the predecessor to Midstream Holdings, which is the historical predecessor of the Partnership and (2) for periods on or after March 7, 2014, the results of operations of the Partnership after giving effect to the Business Combination discussed under “Item 1. Business—General.” The Predecessor was comprised of all of the U.S. midstream assets and operations of Devon prior to the Business Combination, including its 38.75% interest in GCF. However, in connection with the Business Combination, only the Predecessor’s systems serving the Barnett, Cana-Woodford and Arkoma-Woodford Shales in Texas and Oklahoma, as well as the economic benefits and burdens of the 38.75% interest in GCF, were contributed to Midstream Holdings, effective as of March 7, 2014.
The following table presents our selected historical financial and operating data for the periods indicated. Financial and operating data for the years ended December 31, 2017, 2016, 2015 and 2014 reflect acquisitions and dispositions for periods subsequent to the applicable transaction date. The selected historical financial data should be read together with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements and accompanying notes in “Item 8. Financial Statements and Supplementary Data.”
EnLink Midstream Partners, LP
Year Ended December 31,
(In millions, except per unit data)
Product sales—related parties
Midstream services—related parties
Gain (loss) on derivative activity
Operating costs and expenses:
Cost of sales (1)
Operating expenses (2)
General and administrative (3)
(Gain) loss on disposition of assets
Depreciation and amortization
Gain on litigation settlement
Total operating costs and expenses
Operating income (loss)
Other income (expense):
Interest expense, net of interest income
Gain on extinguishment of debt
Income (loss) from unconsolidated affiliates
Other income (expense)
Total other income (expense)
Income (loss) from continuing operations before non-controlling interest and income taxes
Income tax (provision) benefit
Net income (loss) from continuing operations
Income (loss) from discontinued operations, net of tax
Income from discontinued operations attributable to non-controlling interest, net of tax
Discontinued operations, net of tax
Net income (loss)
Less: Net income (loss) from continuing operations attributable to the non-controlling interest
Net income (loss) attributable to EnLink Midstream Partners, LP
Predecessor interest in net income
General partner interest in net income
Limited partners’ interest in net income (loss) attributable to EnLink Midstream Partners, LP
Class C partners’ interest in net loss attributable to EnLink Midstream Partners, LP
Series B preferred interest in net income attributable to EnLink Midstream Partners, LP
Series C preferred interest in net income attributable to EnLink Midstream Partners, LP
Net income (loss) attributable to EnLink Midstream Partners, LP per limited partners' unit:
Basic and diluted common unit
Distributions declared per limited partner unit
Includes related party cost of sales of $211.0 million, $150.1 million, $141.3 million, $354.3 million and $1,588.2 million for the years ended December 31, 2017, 2016, 2015, 2014 and 2013, respectively.
Includes related party operating expense of $0.6 million, $0.5 million, $0.5 million, $5.9 million and $36.2 million for the years ended December 31, 2017, 2016, 2015, 2014 and 2013, respectively.
Includes related party general and administrative expenses of $11.6 million and $45.1 million for the years ended December 31, 2014 and 2013, respectively. Related party general and administrative expenses, if any, subsequent to December 31, 2014, were not material.
Prior to March 7, 2014, our financial results only included the assets, liabilities and operations of our Predecessor. Beginning on March 7, 2014, our financial results also consolidated the assets, liabilities and operations of the legacy business of the Partnership prior to giving effect to the Business Combination.
EnLink Midstream Partners, LP
Year Ended December 31,
(In millions, except per unit data)
Balance Sheet Data (end of period):
Property and equipment, net
Long-term debt (including current maturities)
Partners' equity including non-controlling interest