PART
I
Overview
We were formed in 2005 as a Delaware limited liability company until our conversion in 2015 into a Delaware limited partnership. We are a growth-oriented publicly-traded limited partnership focused on the acquisition, development, ownership and operation of midstream and other energy-related assets in North America. The Partnership has ownership stakes in oil and natural gas gathering systems, natural gas pipelines, and a natural gas processing facility, all located in the Western Eagle Ford in South Texas. Our assets include a gathering system on the Western portion of the Catarina asset operated by Sanchez Energy in the Eagle Ford Shale in South Texas (“Western Catarina Midstream”), our wholly owned SECO Pipeline (defined below), a 50% interest in a gathering system that connects to Western Catarina Midstream (the Carnero Gathering Line, defined below), a 50% interest in a cryogenic natural gas processing plant (the Raptor Gas Processing Facility, defined below), and reversionary working interests and other production assets in Texas, Louisiana and Oklahoma.
Our common units are currently listed on the NYSE American under the symbol “SNMP.”
Our Relationship with Sanchez Energy, Manager and SOG
We believe that our relationship with Sanchez Energy provides us with a strategic advantage and will continue to provide us with significant growth opportunities. As of March 6, 2018, Sanchez Energy owned approximately 15.2% of our outstanding common units. Since March 2015, we have completed three midstream asset acquisitions and two working interest acquisitions from Sanchez Energy. Pursuant to a right-of-first-offer, Sanchez Energy has agreed to offer us the right to acquire any midstream assets that it desires to sell. However, Sanchez Energy is under no obligation to sell any assets to us or to accept any offer for its assets that we may choose to make.
We have entered into a shared services agreement with Manager, pursuant to which Manager provides services that we require to operate our business, including overhead, technical, administrative, marketing, accounting, operational, information systems, financial, compliance, insurance, acquisition, disposition and financing services (the “Services Agreement”). Manager in turn has a shared services agreement in place with SOG. SOG also has a shared services agreement in place with Sanchez Energy. We believe that our relationships with Manager and SOG provide us with competitive advantages, including a cost-efficient means of operating our assets. Manager is the sole member of our general partner and has an interest in us through its ownership of all of our incentive distribution rights. Manager and SOG provide services that we require to operate our business, including overhead, technical, administrative, marketing, accounting, operational, information systems, financial, compliance, insurance, acquisition, disposition and financing services. SOG has a senior management team that averages over 20 years of industry experience and employs over 312 full-time employees, including approximately 67 technical staff and engineers. SOG was formed in 1972 and has drilled or participated in over 4,000 wells, directly and through joint ventures, and has successfully built and operated extensive midstream and gathering assets associated with its exploration and production assets. We plan on leveraging SOG’s extensive expertise and experience to execute on our business strategies. While we believe that our relationships with Sanchez Energy, Manager and SOG are a significant strength, they are also a source of potential risks and conflicts. Please read “Item 1A. Risk Factors.”
Business Strategy
Our primary business objective is to create long-term value by generating stable and predictable cash flows that allow us to make and grow our cash distributions per unit over time through the safe and reliable operation of our assets. We plan to achieve this objective by executing the following business strategy:
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Grow our business by acquiring fee-based midstream and other energy-related assets with minimal maintenance capital requirements and low overhead to increase unitholder value;
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Support stable cash flows by aligning our asset base and operations with SOG’s operational platform and Sanchez Energy’s asset base;
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Focus on stable, fixed-fee businesses;
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Grow our business through increased throughput; and
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Maintain financial flexibility and a strong capital structure.
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Our business strategy is subject to risks, please read “Item 1A. Risk Factors.”
Business Segments
Our business activities are conducted by two operating segments for which we provide information in our consolidated financial statements for the years ended December 31, 2017 and 2016. These two segments
are based on the nature of the operations that are undertaken by each segment
and are our:
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midstream business, which includes Western Catarina Midstream, SECO Pipeline (defined below) and our ownership interests in Carnero Processing, LLC (“Carnero Processing”) and Carnero Gathering, LLC (“Carnero Gathering”); and
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production business, which includes non-operated oil and natural gas reserves located in the Eagle Ford Shale in South Texas and in other areas of Texas, Louisiana and Oklahoma.
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For information about our segments’ revenues, profits and losses and total assets, see Note 17. “Reporting Segments” of our Notes to Consolidated Financial Statements.
Midstream Business
Western Catarina Midstream
In October 2015, we acquired from Sanchez Energy a gathering system (“Western Catarina Midstream”), which is located on the western portion of Sanchez Energy’s approximately 106,000 net acres in Dimmit, LaSalle and Webb Counties, Texas (such net acreage collectively “Sanchez Energy’s Catarina Asset” and the western portion of such net acreage “Western Catarina”). The gathering system consists of gathering assets, pipelines, processing units, compression units and other related assets in Western Catarina, which are located in Dimmit and Webb Counties, Texas and service upstream production from the Eagle Ford Shale. Western Catarina Midstream consists of approximately 150 miles of gathering pipelines, four main gathering and processing facilities, including stabilizers, storage tanks, compressors and dehydration units, and other related assets in Western Catarina, which are located in Dimmit and Webb Counties, Texas, and services upstream production from the Eagle Ford Shale. The gathering pipelines range in diameter from 4 to 12 inches, with capacity of 200 MMcf/d for natural gas, and 40 MBbl/d for crude oil and NGLs. There are four main gathering and processing facilities, which include eight stabilizers of 5,000 barrels per day, approximately 25,000 barrels of storage capacity, pressurized storage for NGLs, approximately 18,000 horsepower of compression and approximately 300 MMcf/d of dehydration capacity. The gathering system is currently used solely to support the gathering, processing and transportation of natural gas, NGLs and oil produced by Sanchez Energy at Sanchez Energy’s Catarina Asset. The gathering system has oil interconnects with the Plains All American Pipeline header system delivered to the Gardendale terminal, and to all four takeaway pipelines to Corpus Christi, and it has natural gas interconnects with Southcross Energy Partners, L.P., Kinder Morgan Inc., Energy Transfer Partners, L.P. and Transwestern Pipeline Company, LLC. Pipeline capacity on Western Catarina Midstream can be expanded through small compression projects at a nominal cost, with approximately $1.0 million in capital expenditures planned per year.
In conjunction with the acquisition of Western Catarina Midstream, we entered into the 15-year gas gathering agreement with Sanchez Energy pursuant to which Sanchez Energy agreed to tender all of its crude petroleum, natural gas and other hydrocarbon-based product volumes on approximately 35,000 dedicated acres in Western Catarina for processing and transportation through Western Catarina Midstream, with the potential to tender additional volumes outside of the dedicated acreage (the “Gathering Agreement”).
All of the revenues from Western Catarina Midstream are currently earned from Sanchez Energy. Pursuant to the Gathering Agreement, Sanchez Energy has agreed to tender all of its oil, natural gas and other hydrocarbon-based product volumes on approximately 35,000 dedicated acres in Western Catarina for processing and transportation through Western
Catarina Midstream, with the potential to tender additional volumes from production activities outside of the dedicated acreage. During the first five years of the contract term (or through 2020), Sanchez Energy is required to meet a minimum quarterly volume delivery commitment for oil and natural gas, subject to certain adjustments. In addition, Sanchez Energy is required to pay contractually agreed upon gathering and processing fees for oil and natural gas volumes tendered through Western Catarina Midstream.
In June 2017, the Gathering Agreement with Sanchez Energy was amended to add an incremental infrastructure fee to be paid by SN Catarina based on water that is delivered through the gathering system through March 31, 2018.
During the year ended December 31, 2017, Sanchez Energy transported average daily production through the gathering system of approximately 11.6 MBbl/d of oil, 163.9 MMcf/d of natural gas and 12.2 MBbls/d of water. The average age of the Western Catarina Midstream assets is approximately 7 years, and they have an average expected life of approximately 23 more years.
Carnero Gathering
In July 2016, we acquired from Sanchez Energy a 50% interest in Carnero Gathering,
a joint venture that is 50% owned and operated by Targa Resources Corp. (NYSE: TRGP) (“Targa”), for an initial payment of approximately $37.0 million and the assumption of remaining capital commitments to Carnero Gathering, estimated at approximately $7.4 million as of the acquisition date (the “Carnero Gathering Transaction”). In addition, we are required to pay Sanchez Energy an earnout based on natural gas received above a threshold volume and tariff at Carnero Gathering’s delivery points from Sanchez Energy and other producers. Carnero Gathering owns a total of approximately 45 miles of high pressure natural gas gathering pipelines that currently connect Western Catarina Midstream to nearby pipelines and the Raptor Gas Processing Facility in South Texas (the “Carnero Gathering Line”). Sanchez Energy has entered into a 15-year gathering agreement with Carnero Gathering pursuant to which Sanchez Energy is required to maintain a minimum quarterly volume delivery commitment for the first five years after the Raptor Gas Processing Facility’s in-service date of May 2017.
Carnero Processing
In November 2016, we acquired from Sanchez Energy a 50% interest in Carnero Processing, a joint venture that is 50% owned and operated by Targa, for aggregate cash consideration of approximately $55.5 million and the assumption of remaining capital contribution commitments to Carnero Processing, estimated at approximately $24.5 million as of the date of acquisition.
Carnero Processing owns a 260 MMcf/d cryogenic natural gas processing plant in La Salle County, Texas (the “Raptor Gas Processing Facility”). The Raptor Gas Processing Facility is a strategic asset that we believe will allow us to capture more of the value chain from Sanchez Energy's South Texas production and realize further upside from third party volumes
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SECO Pipeline
In August 2017, we completed construction of a 100% owned and operated 30 mile natural gas pipeline with 400 MMcf/d capacity that is designed and used to transport dry gas from the Raptor Gas Processing Facility to multiple markets in South Texas (the “SECO Pipeline”). The SECO Pipeline provides E&P producers with optionality to southern gas markets and creates the potential to export natural gas to premium priced markets in Mexico. On September 1, 2017, we entered into an agreement with SN Catarina to transport certain quantities of SN Catarina’s natural gas on a firm basis through the SECO Pipeline for $0.22 per MMBtu delivered on or after September 1, 2017 (the “SECO Pipeline Transportation Agreement”). The SECO Pipeline Transportation Agreement continues on a month-to-month basis until terminated by either party. During the year ended December 31, 2017, Sanchez Energy transported average daily production through SECO Pipeline of approximately 61.1 MMcf/d of natural gas.
The SECO Pipeline has an expected life of approximately 40 years.
Title to Properties
Title to the Western Catarina Midstream and the SECO Pipeline assets are either owned in fee or derived from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities, permitting the use of such land for our operations. We have no knowledge of any challenge to the underlying fee title of any material lease, easement, right-of-way, permit or license that is held by us or to the title to any material lease, easement, right-of-way, permit or lease we own, and we believe that we have satisfactory title to all of the material leases, easements, rights-of-way, permits and licenses with respect to all Western Catarina Midstream and SECO Pipeline assets.
Production Business
Our total estimated proved reserves at December 31, 2017, were approximately 5.3 MMBoe, approximately 100% of which were classified as proved developed, with 21% being natural gas, 17% being NGLs, and 62% being oil. At December 31, 2017, we owned approximately 57 net producing wells. Our total average proved reserve-to-production ratio is approximately 9.0 years and our portfolio decline rate is 11% to 20% based on our estimated proved reserves at December 31, 2017.
Below is a description of our operations and our oil and natural gas properties by basin at December 31, 2017:
Locations
Of our reserves, 89% were located in the Eagle Ford Shale on non-operated properties, where production during the year ended December 31, 2017 was 489.9 MBoe and approximately 4,707.7 MBoe of estimated proved reserves were held at December 31, 2017. All of these reserves were classified as proved developed, with 17% being natural gas, 16% being NGLs, and 67% being oil.
The remaining reserves are located on non-operated properties in Oklahoma and Louisiana. During the year ended December 31, 2017, production on Oklahoma properties was 53.4 MBoe, and approximately 472.1 MBoe of estimated proved reserves were held at December 31, 2017, all of which were classified as proved developed, with 69% being natural gas and 31% being NGLs. During the year ended December 31, 2017, production on Louisiana properties was 19.6 MBoe, and approximately 85.6 MBoe of estimated proved reserves were held at December 31, 2017, all of which were classified as proved developed with 100% being oil.
Operations
We no longer operate any of our oil and gas properties. The Eagle Ford Shale properties are operated by SOG and Marathon Oil Company. The Gulf Coast properties are operated primarily by SOG, and the Oklahoma properties are operated primarily by LINN Energy.
Production Divestitures
Texas Production Divestiture
In October 2017, we entered into a purchase and sale agreement to sell specified oil and gas wells, leases and other associated assets and interests located in Texas (the “Texas Production Assets”) for cash consideration of approximately $6.3 million, subject to adjustment for title and environmental defects (the “Texas Production Divestiture”). In addition, the buyer agreed to assume all obligations relating to the assets, including all plugging and abandonment costs relating to the assets, that arise on or after October 1, 2017. The Texas Production Divestiture closed November 13, 2017, and we recorded a gain of approximately $1.4 million on the sale during the fourth quarter of 2017.
Non-Operated Production Divestiture
In July 2017, we entered into an agreement to assign certain non-operated production assets located in Oklahoma, as well as our equity interests in the entities that owned the assets, in exchange for agreeing upon the apportionment of certain shared litigation costs. The assignment was effective as of July 14, 2017.
Oklahoma Production Divestiture
In May 2017, we entered into a purchase and sale agreement to sell all of the Partnership’s equity interests in the entities that owned our remaining Oklahoma production assets for cash consideration of $5.5 million, and assumption by the buyer of all obligations relating to the assets arising after the closing date and all plugging and abandonment costs relating to the assets arising prior to the closing date (the “Oklahoma Production Divestiture”). The Oklahoma Production Divestiture closed July 17, 2017 and we recorded a gain of $2.4 million on the sale during the third quarter of 2017.
Mid-Continent Divestiture
In June 2016, certain wholly-owned subsidiaries of the Partnership entered into an agreement to sell substantially all of our operated oil and natural gas wells, leases and other associated assets and interests in Oklahoma and Kansas (other than those arising under or related to a concession agreement with the Osage Nation) (the “Mid-Continent Divestiture”) for cash consideration of $7,120, effective as of August 1, 2016 (the “Effective Time”). In addition, the buyer agreed to assume all obligations relating to the assets arising after the Effective Time and all plugging and abandonment costs relating to the assets arising prior to the Effective Time. The sale closed on July 15, 2016, and we recorded a $0.2 million loss related to an intangible asset balance comprised of marketing contracts from a 2007 acquisition which were included in the Mid-Continent Divestiture.
Proved Reserves of Natural Gas, NGLs, and Oil
The following table reflects our estimates for proved natural gas, NGLs and oil reserves based on the SEC definitions that were used to prepare our financial statements for the periods presented. The standardized measure values shown in the table are not intended to represent the current market values of our estimated proved reserves.
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Reserve data:
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2017
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2016
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Estimated proved reserves:
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Oil (MMBbl)
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3.3
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3.5
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Natural gas (MMcf)
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6.7
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14.7
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NGLs (MMBbl)
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0.9
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0.9
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Total proved reserves (MMBoe)
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5.3
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6.9
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Estimated proved developed reserves:
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Oil (MMBbl)
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3.3
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3.5
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Natural gas (MMcf)
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6.7
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14.6
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NGLs (MMBbl)
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0.9
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0.9
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Total proved developed reserves (MMBoe)
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5.3
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6.8
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Proved developed reserves as a percent of total reserves
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100%
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100%
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Standardized measure ($ in millions)
⁽ᵃ⁾
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$
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56.7
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$
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49.6
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(a)
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Standardized measure is the present value of estimated future net revenues to be generated from the production of proved reserves. It is determined using SEC-required prices and costs in effect as of the time of estimation without giving effect to non-property related expenses (such as general and administrative expenses or debt service costs) and discounted using an annual discount rate of 10%. Our standardized measure does not include the impact of derivative transactions or future federal income taxes because we are not subject to federal income taxes. Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. The standardized measure shown should not be considered the current market value of our reserves. The 10% discount factor used to calculate present value, which is required, is not necessarily the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate.
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Our 2017 estimates of total proved reserves decreased 1.6 MMBoe from 2016 primarily due to divestitures totaling approximately 1.7 MMBoe, partially offset by an increase of 0.8 MMBoe due to higher commodity prices.
As of December 31, 2017, we have no remaining proved undeveloped reserves (“PUD”) in our reserves base.
We expect to make minimum capital expenditures related to recompletion of existing wells during the year ending December 31, 2018.
At December 31, 2016 and December 31, 2017, Ryder Scott Co. LP (“Ryder Scott”), an independent oil and natural gas engineering firm, prepared estimates of all our proved reserves. We used Ryder Scott’s estimates of our proved reserves to prepare our financial statements. Ryder Scott maintains a degreed staff of highly competent technical personnel. The average experience level of Ryder Scott’s technical staff of engineers, geoscientists and petro physicists exceeds 20 years, including five to 15 years with a major oil company. The engineering information presented in Ryder Scott’s report was overseen by Mr. Eric Nelson, P.E. Mr. Nelson is an experienced reservoir engineer having been a practicing petroleum engineer since 2002. He has more than 12 years of experience in reserves evaluation with Ryder Scott. He has a Bachelor of Science degree in Chemical Engineering from the University of Tulsa and Master of Business Administration degree from the University of Texas. Mr. Nelson is a Registered Professional Engineer in the State of Texas. Our activities with Ryder Scott are coordinated by a reservoir engineer employed by us who has approximately 37 years of experience in the oil and natural gas industry and an engineering degree from the University of Tennessee and a Master of Business Administration from the University of New Orleans. He is a member of the Society of Petroleum Engineers. He has prior reservoir engineering and reserves management experience at Exxon Mobil Corporation, Dominion Resources and Hilcorp Energy. He has extensive experience in managing oil and natural gas reserves processes. He serves as the key technical person reviewing the reserve reports prepared by Ryder Scott prior to review by the audit committee of the board of directors of our general partner and approval by the board of directors of our general partner.
Production and Price History
The following table sets forth information regarding net production of natural gas, NGLs and oil and certain price and cost information for each of the periods indicated:
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For the Year Ended
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December 31,
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2017
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2016
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Variance
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Net production:
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Natural gas (Mcf)
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2,521
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4,327
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(1,806)
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(42)
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%
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Oil production (MBbl)
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414
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331
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83
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25
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%
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NGLs (MBbl)
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102
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81
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21
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26
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%
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Total production (MBoe)
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936
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1,133
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(197)
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(17)
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%
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Average daily production (Boe/d)
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2,565
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3,096
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(531)
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(17)
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%
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Average sales prices:
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Natural gas price per Mcf with hedge settlements
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$
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3.48
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$
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4.00
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$
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(0.52)
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(13)
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%
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Natural gas price per Mcf without hedge settlements
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$
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2.40
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$
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2.40
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$
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—
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—
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%
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Oil price per Bbl with hedge settlements
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$
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64.83
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$
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81.92
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$
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(17.09)
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(21)
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%
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Oil price per Bbl without hedge settlements
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$
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49.32
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$
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40.76
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$
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8.56
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21
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%
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Liquid price per Bbl without hedge settlements
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$
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19.58
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$
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14.41
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$
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5.17
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36
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%
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Total price per Boe with hedge settlements
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$
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40.19
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$
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40.24
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$
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(0.05)
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—
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%
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Total price per Boe without hedge settlements
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$
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30.41
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$
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22.11
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$
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8.30
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38
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%
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Average unit costs per Boe:
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Field operating expenses
(a)
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$
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14.47
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$
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13.67
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$
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0.80
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6
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%
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Lease operating expenses
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$
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12.89
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$
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12.64
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$
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0.25
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2
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%
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Production taxes
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$
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1.58
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$
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1.03
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$
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0.55
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53
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%
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Depreciation, depletion and amortization
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$
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10.17
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$
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5.93
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$
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4.24
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71
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%
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(a)
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Field operating expenses include lease operating expenses (average production costs) and production taxes.
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Existing Wells
The following table sets forth information at December 31, 2017, relating to the existing wells in which we owned a working interest as of that date. Gross wells are the total number of producing wells in which we have an interest, and net wells are the sum of our fractional working interests owned in gross wells.
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Natural Gas
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Oil
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Gross
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Net
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Gross
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Net
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Operated
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—
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—
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—
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—
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Non-operated
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91
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17
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107
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40
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Total
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91
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17
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107
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40
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We did not convert any proved undeveloped wells into proved producing wells in 2017.
Drilling Activity
With respect to oil and natural gas wells drilled and completed during the years ended December 31, 2017 and 2016, the information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that are capable of producing commercial quantities of oil or natural gas, regardless of whether they produce a reasonable rate of return. No exploratory wells were drilled on any of our properties during the years ended December 31, 2017 or 2016. During the year ended December 31, 2017, 1 gross well was drilled, or approximately 0.2
net wells. During the year ended December 31, 2016, 1 gross well was recompleted, or approximately 0.7 net wells. There were no wells in progress at December 31, 2017.
Developed and Undeveloped Acreage
The following table sets forth information related to our leasehold acreage as of December 31, 2017.
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Developed
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Undeveloped
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Acreage
(a)
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Acreage
(b)
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Gross
(c)
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Net
(d)
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Gross
(c)
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Net
(d)
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Total
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2,188
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632
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—
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—
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(a)
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Developed acres are acres pooled within or assigned to productive wells/units.
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(b)
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Undeveloped acres are acres on which wells have not been drilled or acres that have not been pooled into a productive unit.
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(c)
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A gross acre is an acre in which a working interest is either fully or partially leased. The number of gross acres may include minerals not under lease as a result of leasing some but not all joint mineral owners under any given tract.
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(d)
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A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.
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Leases
Most of our reserves are wellbore rights only. We have a small lease position of less than 1,000 net acres in Louisiana.
Marketing and Major Customers
Our oil and natural gas production in the onshore Texas, Oklahoma and Louisiana Gulf Coast region is marketed by the operators of our properties.
Sanchez Energy, whose earned revenues contribute exclusively to our midstream segment, accounted for 63% and 76% of total revenue for the years ended December 31, 2017 and 2016, respectively. Additional information regarding our relationship with Sanchez Energy is provided in Item 13. “Certain Relationships and Related Transactions, and Manager Independence.”
Markets and Competition
We operate in a competitive environment for acquiring properties, marketing oil and natural gas and retaining trained personnel. Many of our competitors have substantially greater financial, technical and personnel resources than us. As a result, our competitors may be able to outbid us for assets, more competitively price their gathering and transportation services and oil and natural gas production, or utilize superior technical resources than our financial or personnel resources permit. Our ability to acquire additional assets will depend on our ability to evaluate and select suitable assets and to consummate transactions in a competitive environment.
The natural gas gathering, compression, treating and transportation business is very competitive. Upon such time that we seek to obtain customers in addition to Sanchez Energy for Western Catarina Midstream, our competitors will include other midstream companies, producers and intrastate and interstate pipelines. Competition for volumes is primarily based on reputation, commercial terms, reliability, service levels, location, available capacity, capital expenditures and fuel efficiencies.
Neither SOG nor any of its related companies are restricted from competing with us. Additional information regarding our relationship with SOG is provided in Item 13. “Certain Relationships and Related Transactions, and Manager Independence.”
Governmental Regulation
Environmental Laws
Our operations are subject to stringent and complex federal, state and local laws and regulations governing environmental protection as well as the discharge of materials into the environment. These laws and regulations may, among other things:
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require the acquisition of various permits before drilling commences;
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restrict the types, quantities and concentrations of various substances, including water and waste, that can be released into the environment;
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limit or prohibit activities on lands lying within wilderness, wetlands and other protected areas; and
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require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells.
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These laws, rules and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible in the absence of such regulations. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. In addition, federal, state and local authorities frequently revise environmental laws and regulations, and any changes that result in more stringent and costly waste handling, disposal and cleanup requirements for the oil and natural gas industry could have a significant impact on our operating costs.
Environmental laws and regulations that could have a material impact on the oil and natural gas industry and our operations include the following:
Waste Handling
The Resource Conservation and Recovery Act (“RCRA”) and comparable state laws regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous wastes and non-hazardous wastes. Under the auspices of the federal Environmental Protection Agency (“EPA”), the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters and most other wastes associated with the exploration, development and production of oil and natural gas are currently regulated under RCRA’s non-hazardous waste provisions. Although we do not believe that the current costs of managing any of our wastes are material under presently applicable laws, any future reclassification of oil and natural gas exploration, development and production wastes as hazardous wastes, could increase our costs to manage and dispose of wastes.
Comprehensive Environmental Response, Compensation and Liability Act
The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the Superfund law, imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the owner or operator of the site where the release occurred, and anyone who disposed of, or arranged for the disposal of, a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.
We currently own, lease or operate numerous properties that have been used for oil and natural gas production for a number of years. Although we believe that operating and waste disposal practices utilized in the past with respect to these properties were typical for the industry at the time, hazardous substances, wastes or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations, including off-site locations, where such substances have been taken for disposal. In addition, these properties have been operated by third parties or by previous
owners or operators whose treatment and disposal of hazardous substances, wastes or hydrocarbons was not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes, remediate contaminated property or perform remedial plugging or pit closure operations to prevent future contamination.
Water Discharges
The Federal Water Pollution Control Act (the “Clean Water Act”), and comparable state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of produced water and other oil and natural gas wastes, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. Federal and state regulatory agencies can impose administrative, civil and criminal penalties, impose investigatory or remedial obligations and issue injunctions limiting or preventing our operations for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.
Oil Pollution Act
The Oil Pollution Act was enacted in 1990 to amend the Clean Water Act in large part due to the Exxon Valdez incident. Under the Oil Pollution Act, the EPA was directed to promulgate regulations which would create a comprehensive prevention, response, liability and compensation program to deal with oil discharged into United States navigable waters. In particular, the regulations developed under the Oil Pollution Act strengthened the requirements that apply to Spill Prevention, Control and Countermeasure Plans. The Oil Pollution Act imposes liability for removal costs and damages resulting from an incident in which oil is discharged into navigable waters and establishes liability for damages for injuries to, or loss of, natural resources.
Air Emissions
The Clean Air Act, and comparable state laws, regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. In October 2015, the EPA finalized rules that lower the National Ambient Air Quality Standard (“NAAQS”) for ozone from 75 parts per billion (“ppb”) to 70 ppb, and the EPA published a final rule in November 2017 stating that 85% of U.S. counties are designated as “attainment/unclassified” but has not issued any non-attainment designations for the remaining 15%. States can also impose air emissions limitations that are more stringent than the federal standards imposed by the EPA. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the Clean Air Act and associated state laws and regulations. Rules restricting air emissions may require a number of modifications to our operations, including the installation of new equipment. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our operating results. However, we believe that our operations will not be materially adversely affected by any such requirements, and the requirements are not expected to be any more burdensome to us than to other similarly situated companies. We believe that our operations are in substantial compliance with federal and state air emission standards.
Climate Change
While the U.S. Congress has from time to time considered legislation to reduce emissions of greenhouse gases (“GHGs”), the prospect for adoption of significant legislation at the federal level to reduce GHG emissions is perceived to be low at this time. Requirements intended to reduce greenhouse gases have been adopted at the federal, regional and state levels. For example, in June 2016, the EPA adopted Subpart OOOOa establishing standards for methane emissions from oil and gas production. However, in June 2017, the EPA published a proposed rule to stay portions of the Subpart OOOOa standards, and until the rule is finalized, future implementation of the 2016 standard is uncertain. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations that limit emissions of GHGs could adversely affect demand for the oil and natural gas that production operators produce, some of whom are our customers, which could thereby reduce demand for our midstream services. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical
effects, such as increased frequency and severity of storms, droughts and floods and other climatic events; if any such effects were to occur, it is uncertain if they would have an adverse effect on our financial condition and operations.
Hydraulic Fracturing
Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and natural gas commissions. However, the EPA has asserted federal regulatory authority over certain hydraulic fracturing practices and has finalized a study of the potential environmental impacts of hydraulic fracturing activities, finding that under certain circumstances, the “water cycle” activities associated with hydraulic fracturing may impact drinking water resources. In 2014, the EPA issued an advanced notice of proposed rulemaking under the Toxic Substances Control Act of 1976 requesting comments related to disclosure for hydraulic fracturing chemicals. Further, the Department of the Interior has released final regulations governing hydraulic fracturing on federal oil and natural gas leases which require lessees to file for approval of well stimulation work before commencement of operations and require well operators to disclose the trade names and purposes of additives used in the fracturing fluids. The states in which we operate have also adopted disclosure requirements related to fracturing fluids. Legislation has been introduced, but not adopted, in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. In addition, some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances. Currently, no states in which we utilize hydraulic fracturing have adopted these regulations. At this time, it is not possible to accurately estimate how potential future laws or regulations addressing hydraulic fracturing would impact our business.
Endangered Species
The Endangered Species Act (“ESA”), and analogous state laws, restrict activities that may affect listed endangered or threatened species or their habitats. If endangered species are located in areas where we operate, our operations or any work performed related to them could be prohibited or delayed or expensive mitigation may be required. While some of our operations may be located in areas that are designated as habitats for endangered or threatened species, we believe that we are in compliance with the ESA. Additional listings under the ESA and similar state laws could result in the imposition of restrictions on our operations and consequently have an adverse effect on our business.
Gathering System Regulation
Regulation of gathering facilities may affect certain aspects of our business and the market for our services. Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated by agencies of the U.S. federal government, primarily the Federal Energy Regulatory Commission (“FERC”). The FERC regulates interstate natural gas transportation rates, terms and conditions of service, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.
The transportation and sale for resale of natural gas in interstate commerce are regulated primarily under the Natural Gas Act (“NGA”), and by regulations and orders promulgated under the NGA by the FERC. In certain limited circumstances, intrastate transportation, gathering, and wholesale sales of natural gas may also be affected directly or indirectly by laws enacted by the U.S. Congress and by FERC regulations.
Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by the FERC under the NGA. We believe that the natural gas pipelines in our gathering systems meet the traditional tests that the FERC has used to establish whether a pipeline is a gathering pipeline not subject to FERC jurisdiction. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services has been the subject of substantial litigation and varying interpretations. In addition, the FERC determines whether facilities are gathering facilities on a case-by-case basis, so the classification and regulation of our natural gas gathering facilities are subject to change based on future determinations by the FERC, the courts, or the U.S. Congress. If the FERC were to consider the status of an individual gathering facility is not exempt from FERC regulation and the pipeline provides interstate transportation, the rates for, and terms and conditions of, services provided by such facility would be subject to regulation by the FERC. Such regulation could decrease revenue, increase operating costs, and, depending upon the facility in question, could adversely affect our results of operations and cash flows. In addition, if any of our facilities were found to have provided services or otherwise
operated in violation of the NGA or the NGPA, this could result in the imposition of civil penalties as well as a requirement to disgorge charges collected for such service in excess of the cost-based rate established by the FERC.
Gathering service, which may occur upstream of transmission service subject to FERC jurisdiction, is regulated by the states. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation. Our purchasing and gathering operations are subject to ratable take and common purchaser statutes in the State of Texas. The ratable take statute generally requires gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, the common purchaser statute generally requires 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. 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 gas.
The Railroad Commission of Texas (“TRRC”) requires gatherers to file reports, obtain permits, make books and records available for audit and provide service on a nondiscriminatory basis. Shippers and producers may file complaints with the TRRC to resolve grievances relating to natural gas gathering access and rate discrimination.
While our systems have not been regulated by the FERC under the NGA, the U.S. Congress may enact legislation or the FERC may adopt regulations that may subject certain of our otherwise non-FERC jurisdictional facilities to further regulation. Changes in law and to FERC policies and regulations may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate pipelines, and we cannot predict what future action FERC will take. We do not believe, however, that any regulatory changes will affect us in a way that materially differs from the way they will affect other natural gas gatherers with which we compete. Failure to comply with those regulations in the future could subject us to civil penalty liability.
The Energy Policy Act of 2005 (“EPAct 2005”), amended the NGA to add an anti-market manipulation provision which makes it unlawful for any entity to engage in prohibited behavior to be prescribed by the FERC, and furthermore provides the FERC with additional civil penalty authority. The EPAct 2005 provided the FERC with the power to assess civil penalties per day for violations of the NGA and the Natural Gas Policy Act (“NGPA”). The civil penalty provisions are applicable to entities that engage in the sale of natural gas for resale in interstate commerce. In Order No. 670, the FERC promulgated rules implementing the anti-market manipulation provision of the EPAct 2005. The rules make it unlawful, in connection with the purchase or sale of natural gas subject to the jurisdiction of the FERC, or the purchase or sale of transportation services subject to the jurisdiction of the FERC, for any entity, directly or indirectly, to: (1) use or employ any device, scheme or artifice to defraud; (2) make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (3) engage in any act or practice that operates as a fraud or deceit upon any person. The anti-market manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of gas pipelines and storage companies that provide interstate services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction.
Pipeline Safety Regulation
We are subject to regulation by the United States Department of Transportation (“DOT”) under the Hazardous Liquid Pipeline Safety Act of 1979 (“HLPSA”) and comparable state statutes with respect to design, installation, inspection, testing, construction, operation, replacement and maintenance of pipeline facilities. HLPSA covers petroleum and petroleum products, including NGLs and condensate, and requires any entity that owns or operates pipeline facilities to comply with such regulations, to permit access to and copying of records and to file certain reports and provide information as required by the U.S. Secretary of Transportation. These regulations include potential fines and penalties for violations. We believe that we are in compliance in all material respects with these HLPSA regulations.
Our natural gas pipelines are subject to regulation by Pipelines and Hazardous Materials Safety Administration (“PHMSA”) pursuant to the Natural Gas Pipeline Safety Act of 1968 (“NGPSA”) and the Pipeline Safety Improvement Act of 2002 (“PSIA”), as reauthorized and amended by the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006 (“PIPES Act”). The NGPSA regulates safety requirements in the design, construction, operation and maintenance
of gas pipeline facilities, while the PSIA establishes mandatory inspections for all U.S. oil and natural gas transmission pipelines in high-consequence areas (“HCAs”).
PHMSA has developed regulations that require pipeline operators to implement integrity management programs, including more frequent inspections and other measures to ensure pipeline safety in HCAs. The regulations require operators, including us, to:
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perform ongoing assessments of pipeline integrity;
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identify and characterize applicable threats to pipeline segments that could impact a HCA;
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improve data collection, integration and analysis;
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repair and remediate pipelines as necessary; and
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implement preventive and mitigating actions.
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The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (“2011 Pipeline Safety Act”) reauthorizes funding for federal pipeline safety programs, increases penalties for safety violations, establishes additional safety requirements for newly constructed pipelines, and requires studies of certain safety issues that could result in the adoption of new regulatory requirements for existing pipelines. The 2011 Pipeline Safety Act, among other things, increases the maximum civil penalty for pipeline safety violations and directs the U.S. Secretary of Transportation to promulgate rules or standards relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation and testing to confirm the material strength of pipe operating above 30% of specified minimum yield strength in HCAs.
PHMSA regularly revises its pipeline safety regulations and has published advanced notices of proposed rulemakings and notices of proposed rulemaking to solicit comments on the need for changes to its natural gas and liquid pipeline safety regulations. In the past few years, PHMSA issued advisory bulletins providing guidance on applicable regulatory requirements, including those that must be followed for the abandonment of a pipeline; aspects of overall pipeline integrity, including the need for corrosion-control systems on buried and insulated pipeline segments, to conduct in-line inspections for all threats, and to ensure in-line inspection tool findings are accurate and verified; the need of owners and operators of natural gas facilities to take appropriate steps to prevent damage to pipeline facilities from accumulated snow or ice; actions pipeline operators should consider taking to ensure the integrity of pipelines in the event of severe flooding or hurricane damage; notice of construction; flow reversal procedures; product changes and conversion; integrity management program evaluation metrics; and incident response plans. Further changes to PHMSA’s rules are expected in the future.
For example, in July 2015, PHMSA issued a notice of proposed rulemaking proposing, among other things, to extend operator qualification requirements to operators of certain natural gas gathering lines and to add a specific timeframe for operators’ notifications of accidents or incidents. In January 2017, PHMSA issued a final rule adding a specific timeframe for operators’ notifications of accidents or incidents but delayed final action on the operator qualification proposals until a later date. The final rule became effective March 24, 2017. In addition, in October 2015, PHMSA issued a notice of proposed rulemaking proposing changes to its hazardous liquid pipeline safety regulations, including to extend: (i) reporting requirements to all onshore or offshore, regulated or unregulated hazardous liquid gathering lines; and (ii) certain integrity management periodic assessment and remediation requirements to regulated onshore gathering lines. On January 13, 2017, PHMSA issued a final rule amending its regulations to impose new reporting requirements for certain unregulated pipelines, including all hazardous liquid gathering lines. The final rule also significantly extends and expands the reach of certain integrity management requirements, regardless of the pipeline’s proximity to a HCA. However, this final rule remains subject to review and approval by the new administration, pursuant to a memorandum issued by the White House to heads of federal agencies. It is unclear whether the final rule will be revised and when it will be implemented. In April 2016, PHMSA issued a notice of proposed rulemaking that would expand integrity management requirements and impose new pressure requirements on currently regulated gas transmission pipelines and would also significantly expand the regulation of gas gathering lines, subjecting previously unregulated pipelines to requirements regarding damage prevention, corrosion control, public education programs, maximum allowable operating pressure limits
and other requirements. PHMSA has not yet finalized these proposed regulations. While we cannot predict the outcome of legislative or regulatory initiatives, such regulatory changes and any legislative changes could have a material effect on our operations, particularly by extending more stringent and comprehensive safety regulations (such as integrity management requirements) to pipelines and gathering lines not previously subject to such requirements. While we expect any legislative or regulatory changes to allow us time to become compliant with new requirements, costs associated with compliance may have a material effect on our operations.
Furthermore, DOT regulations have incorporated by reference the American Petroleum Institute Standard 653 (“API 653”) as the industry standard for the inspection, repair, alteration and reconstruction of storage tanks. API 653 requires regularly scheduled inspection and repair of such tanks. These periodic tank maintenance requirements may result in significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our storage tanks.
States are largely preempted by federal law from regulating pipeline safety for interstate lines but most are certified by the DOT to assume responsibility for enforcing intrastate pipeline regulations and inspection of intrastate pipelines. For example, in Texas the Pipeline Safety Department of the TRRC inspects and enforces the pipeline safety regulations for intrastate pipelines, including gathering lines. States may adopt stricter standards for intrastate pipelines than those imposed by the federal government for interstate lines; however, states vary considerably in their authority and capacity to address pipeline safety. State standards may include more stringent requirements for facility design and management in addition to requirements for pipelines. We do not anticipate any significant difficulty in complying with applicable state laws and regulations. Our pipelines have ongoing inspection and compliance programs designed to keep the facilities in compliance with pipeline safety and pollution control requirements.
We have incorporated all existing requirements into our programs by the required regulatory deadlines and are continually incorporating the new requirements into procedures and budgets. We expect to incur increasing regulatory compliance costs, based on the intensification of the regulatory environment and upcoming changes to regulations as outlined above. In addition to regulatory changes, costs may be incurred when there is an accidental release of a commodity gathered on our system, or a regulatory inspection identifies a deficiency in our required programs.
Other Laws and Regulation
We are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”), and comparable state laws. These laws and the implementing regulations strictly govern the protection of the health and safety of employees. The OSHA hazard communications standard, OSHA Process Safety Management, the EPA community right-to-know regulations under Title III of CERCLA and similar state laws require that we organize and/or disclose information about hazardous materials used or produced in our operations. We believe that we are in substantial compliance with these applicable requirements.
We believe that we are in substantial compliance with existing environmental laws and regulations applicable to our current operations and that our continued compliance with existing requirements should not have a material adverse impact on our financial condition and results of operations. As of December 31, 2017, we had no accrued environmental obligations. We are not aware of any environmental issues or claims that will require material capital expenditures or that will otherwise have a material impact on our financial position or results of operations. However, we cannot predict how future environmental laws and regulations may impact our operations, and therefore, cannot provide assurance that the passage of more stringent laws or regulations in the future will not have a negative impact on our financial condition, results of operations or cash flows.
Employees
Pursuant to the Services Agreement, Manager provides services that we require to operate our business, including overhead, technical, administrative, marketing, accounting, operational, information systems, financial, compliance, insurance and acquisition, disposition and financing services. In connection with providing the services under the Services Agreement, Manager receives compensation consisting of: (i) a quarterly fee equal to 0.375% of the value of our properties other than our assets located in Oklahoma, (ii) reimbursement for all allocated overhead costs as well as any direct third-
party costs incurred and (iii) for each asset acquisition, asset disposition and financing, a fee not to exceed 2% of the value of such transaction.
As of December 31, 2017, 8 employees were employed by SOG with their primary function being to provide services for us, all of which were full-time employees.
None of our or SOG’s employees are subject to a collective bargaining agreement.
Offices
We are headquartered in Houston, Texas.
Available Information
Our internet address is http://www.sanchezmidstream.com. We make our website content available for informational purposes only. It should not be relied upon for investment purposes, nor is it incorporated by reference in this Annual Report on Form 10-K. We make available free of charge on or through our website our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to these reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. The SEC maintains an internet website that contains these reports at http://www.sec.gov. The public may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549. Information concerning the operation of the Public Reference Room may be obtained by calling the SEC at (800) 723-0330.
Item 1A. Risk Factors
Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. The following are some of the important factors that could affect our financial performance or could cause actual results to differ materially from estimates or expectations contained in our forward-looking statements. We may encounter risks in addition to those described below. Additional risks and uncertainties not currently known to us, or that we currently deem to be immaterial, may also impair or adversely affect our business, contracts, financial condition, operating results, cash flows, liquidity and prospects.
The risk factors in this report are grouped into the following categories:
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Risks Related to Our Midstream Business;
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Risks Related to Our Production Business;
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Risks Related to Regulatory Compliance;
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Risks Related to Financing and Credit Environment;
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Risks Related to Our Cash Distributions;
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Risks Related to an Investment in Us and Our Common Units; and
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Risks Related to Our Midstream Business
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Because substantially all of our revenue relating to the operation of our midstream business is derived from Sanchez Energy, any development that materially and adversely affects Sanchez Energy’s operations, financial condition or market reputation could have a material and adverse impact on us.
We are dependent on Sanchez Energy as our only current customer for utilization of Western Catarina Midstream and the SECO Pipeline. Sanchez Energy is the primary customer for utilization of the Carnero Gathering Line and the Raptor Gas Processing Facility. We expect that a majority of revenues relating to these assets will be derived from Sanchez Energy for the foreseeable future. As a result, any event, whether in our area of operations or otherwise, that adversely affects Sanchez Energy’s production, drilling and completion schedule, 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 Sanchez Energy, including, among others:
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the speculative nature of drilling wells;
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a reduction in or slowing of Sanchez Energy’s development program, especially on Sanchez Energy’s Catarina asset, which would directly and adversely impact demand for our gathering and processing services;
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a decline in the price of natural gas, NGLs or oil, which have recently been extremely volatile and have declined rapidly;
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the availability of capital on an economic basis to fund Sanchez Energy’s exploration and development activities;
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Sanchez Energy’s ability to replace reserves;
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Sanchez Energy’s drilling and operating risks, including potential environmental liabilities;
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Sanchez Energy’s ability to finance its operations and development activities;
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transportation capacity constraints and interruptions;
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adverse effects of governmental and environmental regulation; and
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losses from pending or future litigation.
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A reduction in the price of natural gas, NGLs or oil could cause Sanchez Energy to record oil and natural gas property impairments, which would adversely affect its future business and development. Sanchez Energy utilizes the successful efforts method of accounting to account for its oil and natural gas exploration and development activities. Under this method of accounting, a company is required when facts and circumstances indicate that the carrying value may not be recoverable to determine whether the book value of its oil and natural gas properties (excluding unevaluated properties) is less than or equal to the estimated undiscounted future net cash flows using management’s expectations of future oil and natural gas prices. If net capitalized costs exceed estimated undiscounted future net cash flows, the measurement of impairment is based on estimated fair value, using estimated discounted future net cash flows. Sanchez Energy recorded no proved property impairments for the year ended December 31, 2017 and recorded approximately $3.7 million and $700.3 million of proved property impairments for the years ended December 31, 2016 and 2015, respectively. Sanchez Energy could incur additional non-cash impairments to its proved oil and natural gas properties in 2018 if the price of natural gas, NGLs or oil declines. These impairments, along with a substantial and sustained decline in oil and natural gas prices, may materially and adversely affect its future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.
We are subject to the risk of non-payment or non-performance by Sanchez Energy, including with respect to the Gathering Agreement and the SECO Pipeline Transportation Agreement with Sanchez Energy. We cannot predict the extent to which Sanchez Energy’s business would be impacted if conditions in the energy industry were to deteriorate, nor can we estimate the impact that such conditions would have on Sanchez Energy’s ability to execute its drilling and
development program or perform under its agreement with us. Any material non-payment or non-performance by Sanchez Energy would reduce our ability to make distributions to our unitholders.
In addition, due to our relationship with Sanchez Energy, our ability to access the capital markets, or the pricing or other terms of any capital markets transactions, may be adversely affected by any impairment to Sanchez Energy’s financial condition or adverse changes in its credit ratings.
Any material limitation on our ability to access capital as a result of such adverse changes at Sanchez Energy 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 Sanchez Energy could negatively impact our unit price, limiting our ability to raise capital through equity issuances or debt financing, or could negatively affect 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.
Because of the natural decline in production from existing wells, our success depends, in part, on Sanchez Energy’s ability to replace declining production. Any decrease in volumes of natural gas, NGLs and oil that Sanchez Energy produces or any decrease in the number of wells that Sanchez Energy completes could reduce throughput volumes that could adversely affect our business and operating results.
The volumes that support our facilities depend on the level of production from wells connected to our facilities, which may be less than expected and will naturally decline over time. To the extent Sanchez Energy reduces its activity or otherwise ceases to drill and complete wells, especially on its Catarina asset, revenues for our gathering and processing services will be directly and adversely affected. In addition, volumes from completed wells will naturally decline and our cash flows associated with these wells will also decline over time. In order to maintain or increase throughput levels on our facilities, we must obtain new sources of natural gas, NGLs and oil from Sanchez Energy or other third parties. The primary factors affecting our ability to obtain additional sources of natural gas, NGLs and oil include (i) the success of Sanchez Energy’s drilling activity in our areas of operation, (ii) Sanchez Energy’s acquisition of additional acreage and (iii) our ability to obtain additional dedications of acreage from Sanchez Energy or new dedications of acreage from other third parties.
We have no control over Sanchez Energy’s or other producers’ levels of development and completion activity in our areas of operation, the amount of reserves associated with wells connected to our facilities or the rate at which production from a well declines. We have no control over Sanchez Energy or other producers or their development plan decisions, which are affected by, among other things:
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the availability and cost of capital;
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prevailing and projected prices for natural gas, NGLs and oil;
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demand for natural gas, NGLs and oil;
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geologic considerations;
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environmental or other governmental regulations, including the availability and maintenance of drilling permits and the regulation of hydraulic fracturing; and
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the costs of producing natural gas, NGLs and oil and the availability and costs of drilling rigs and other equipment.
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Under the terms of Sanchez Energy’s Catarina lease, Sanchez Energy is subject to annual drilling and development requirements. For example, at the present time, the lease requires Sanchez Energy to drill 50 wells per year (with the ability to bank up to 30 wells from a prior period). If Sanchez Energy fails to meet this minimum drilling commitment, Sanchez Energy would forfeit its acreage under the lease not held by production. Such a forfeiture could impact Sanchez Energy’s ability to develop additional acreage and replace declining production.
Fluctuations in energy prices can also greatly affect the development of reserves. Sanchez Energy could elect to reduce its drilling and completion activity if commodity prices decrease. Declines in commodity prices could have a negative impact on Sanchez Energy’s development and production activity, and if sustained, could lead to a material decrease in such activity. Sustained reductions in development or production activity in our areas of operation could lead to reduced utilization of our services.
Due to these and other factors, even if reserves are known to exist in areas served by our facilities, Sanchez Energy and other producers may choose not to develop, or be prohibited from developing, those reserves. If reductions in development activity result in our inability to maintain the current levels of throughput on our facilities, those reductions could reduce our revenue and cash flow and adversely affect our ability to make cash distributions to our unitholders.
The Gathering Agreement contains provisions that can reduce the cash flow stability that the agreement was designed to achieve.
The Gathering Agreement is designed to generate stable cash flows for us over the life of the minimum volume commitment contract term while also minimizing direct commodity price risk. Under the minimum volume commitment, subject to certain adjustments, Sanchez Energy has agreed to ship a minimum volume of natural gas, NGLs and oil on Western Catarina Midstream or, in some cases, to pay a minimum monetary amount, over certain periods during the term of the minimum volume commitment, which is the first five years of the 15-year term of the Gathering Agreement. In addition, the Gathering Agreement also includes a minimum quarterly quantity, which is a total amount of natural gas, NGLs and oil that Sanchez Energy must flow on Western Catarina Midstream (or an equivalent monetary amount) each quarter during the minimum volume commitment term. If Sanchez Energy’s actual throughput volumes are less than its minimum volume commitment for the applicable period, it must extend the minimum volume commitment term on a nominal volume basis, but to no longer than the original five years (subject to certain exceptions), or, in some cases, make a shortfall payment to us at the end of that contract quarter, as applicable. The amount of the shortfall payment is based on the difference between the actual throughput volume shipped, processed or offset through an extension of the minimum volume commitment term for the applicable period and the minimum volume commitment for the applicable period, multiplied by the applicable fee. To the extent that Sanchez Energy’s actual throughput volumes are above its minimum volume commitment for the applicable period, the Gathering Agreement contains provisions that allow Sanchez Energy to use the excess volumes as a credit to shorten the minimum volume commitment term, but to no less than four years.
Under certain circumstances, it is possible that the combined effect of the minimum volume commitment provisions could result in our receiving no revenues or cash flows from Sanchez Energy in a given period. In the most extreme circumstances:
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we could incur operating expenses with no corresponding revenues from Sanchez Energy; or
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Sanchez Energy could cease shipping throughput volumes at a time when its aggregate minimum volume commitment has been satisfied with previous throughput volume shipments, which could be in as early as four years.
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If either of these circumstances were to occur, it would have a material adverse effect on our results of operations and financial condition and cash flows and our ability to make cash distributions to our unitholders.
We do not intend to obtain independent evaluations of reserves of natural gas, NGLs and oil reserves connected to Western Catarina Midstream on a regular or ongoing basis; therefore, in the future, volumes of natural gas, NGLs and oil on the gathering system could be less than we anticipate.
We have not obtained and do not intend to obtain independent evaluations of the reserves of natural gas, NGLs and oil, including those of Sanchez Energy, connected to Western Catarina Midstream on a regular or ongoing basis. Moreover, even if we did obtain independent evaluations of the reserves of natural gas, NGLs and oil connected to Western Catarina Midstream, such evaluations may prove to be incorrect. Oil and natural gas reserve engineering requires
subjective estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices, future production levels and operating and development costs.
Accordingly, we may not have accurate estimates of total reserves dedicated to some or all of Western Catarina Midstream or the anticipated life of such reserves. If the total reserves or estimated life of the reserves connected to Western Catarina Midstream are less than we anticipate and we are unable to secure additional sources of natural gas, NGLs and oil, it could have a material adverse effect on our business, results of operations and financial condition and our ability to make cash distributions to our unitholders.
Interruptions in operations at our facilities may adversely affect our operations and cash flows available for distribution to our unitholders.
Our operations depend upon the infrastructure that we have developed, constructed or acquired. Any significant interruption at any of our facilities, or in our ability to gather, treat or process natural gas, NGLs and oil, would adversely affect our operations and cash flows available for distribution to our unitholders. Operations at our facilities could be partially or completely shut down, temporarily or permanently, as the result of circumstances not within our control, such as:
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unscheduled turnarounds or catastrophic events at our physical plants or pipeline facilities;
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restrictions imposed by governmental authorities or court proceedings;
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labor difficulties that result in a work stoppage or slowdown;
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a disruption in the supply of resources necessary to operate a facility;
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damage to our facilities resulting from natural gas, NGLs and oil that do not comply with applicable specifications; and
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inadequate transportation or market access to support production volumes, including lack of availability of pipeline capacity.
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All of our midstream assets are located in the Eagle Ford Shale in Texas, making us vulnerable to risks associated with operating in one major geographic area.
All of our midstream assets are located in Eagle Ford Shale in Texas. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, market limitations or interruption of the processing or transportation of natural gas, NGLs or oil.
A shortage of equipment and skilled labor in the Eagle Ford Shale could reduce equipment availability and labor productivity and increase labor and equipment costs, which could have a material adverse effect on our business and results of operations.
Gathering and processing services require special equipment and laborers skilled in multiple disciplines, such as equipment operators, mechanics and engineers, among others. The increased levels of production in the Eagle Ford Shale may result in a shortage of equipment and skilled labor. If we experience shortages of necessary equipment or skilled labor in the future, our labor and equipment costs and overall productivity could be materially and adversely affected. If our equipment or labor prices increase or if we experience materially increased health and benefit costs for employees, our results of operations could be materially and adversely affected.
Our participation in joint ventures exposes us to liability or harm to our reputation resulting from failures by our partner.
In 2016, we purchased from Sanchez Energy a 50% equity interest in each of Carnero Gathering and Carnero Processing, each a joint venture that is 50% owned by Targa and operated by Targa. We and Targa are jointly and severally liable for all liabilities and obligations of Carnero Gathering and Carnero Processing. If Targa fails to perform or is financially unable to bear its portion of required capital contributions or other obligations, including liabilities stemming from claims or lawsuits, we could be required to make additional investments, provide additional services or pay more than our proportionate share of a liability to make up for Targa’s shortfall. Further, if we are unable to adequately address Targa’s performance issues, Sanchez Energy, the main customer on the facilities, may terminate its agreements, which could result in legal liability to us, harm our reputation and reduce cash flows generated from the Carnero Gathering Line and the Raptor Gas Processing Facility.
We may not be able to attract additional third-party volumes, which could limit our ability to grow and would increase our dependence on Sanchez Energy.
Part of our long-term growth strategy includes identifying additional opportunities to offer gathering, processing and transportation services to other third parties. Our ability to increase throughput on our facilities and any related revenue from third parties is subject to numerous factors beyond our control, including competition from third parties and the extent to which we have available capacity when requested by third parties. To the extent that we lack available capacity on our facilities for third-party volumes, we may not be able to compete effectively with third-party gathering or processing systems for additional volumes. In addition, some of our competitors for third-party volumes have greater financial resources and access to larger supplies of oil and natural gas than those available to us, which could allow those competitors to price their services more aggressively than us. Moreover, the underlying lease for the properties on which Western Catarina Midstream is located restricts Western Catarina Midstream to the handling of hydrocarbons produced on the properties covered by the lease.
We may not be able to attract material third-party service opportunities. Our efforts to attract new unaffiliated customers may be adversely affected by (i) our relationship with Sanchez Energy, certain rights that it has under applicable agreements and with respect to Western Catarina Midstream the fact that a substantial portion of the capacity of the facility will be necessary to service Sanchez Energy’s production and development and completion schedule, (ii) the current nature of our facilities, (iii) our desire to provide services pursuant to fee-based contracts and (iv) the existence of current and future dedications to other gatherers by potential third-party customers. As a result, we may not have the capacity or ability to provide services to third parties, or potential third-party customers may prefer to obtain services pursuant to other forms of contractual arrangements under which we would be required to assume direct commodity exposure.
Increased competition from other companies that provide gathering services could have a negative impact on the demand for our services, which could adversely affect our financial results.
Our ability to flow a sufficient volume of throughput after the expiration of the Gathering Agreement to maintain current revenues and cash flows could be adversely affected by the activities of our competitors. Our facilities compete primarily with other gathering and processing systems. Some competitors have greater financial resources than us and may now, or in the future, have access to greater supplies of natural gas, NGLs and oil than we do. Some of these competitors may expand or construct facilities that would create additional competition for the services that we provide to Sanchez Energy or other future customers. In addition, Sanchez Energy or other future customers may develop their own facilities instead of using our midstream assets. Moreover, Sanchez Energy and its affiliates are not limited in their ability to compete with us outside of the dedicated areas.
All of these competitive pressures could make it more difficult for us to retain Sanchez Energy as a customer and/or attract new customers as we seek to expand our business, which could have a material adverse effect on our business, financial condition, results of operations and ability to make cash distributions to our unitholders.
If third-party pipelines or other midstream facilities interconnected to our facilities become partially or fully unavailable, our operating margin, cash flow and ability to make cash distributions to our unitholders could be adversely affected.
Our facilities connect to other pipelines or facilities owned and operated by unaffiliated third parties. The continuing operation of third-party pipelines, compressor stations 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. In addition, if the costs to us to access and transport on these third-party pipelines significantly increase, our profitability could be reduced. If any such increase in costs occurs or if any of these pipelines or other midstream facilities become unable to receive or transport natural gas, NGLs or oil, our operating margin, cash flow and ability to make cash distributions to our unitholders could be adversely affected.
We do not own all of the land on which Western Catarina Midstream is located, which could result in disruptions to our operations.
We do not own all of the land on which Western Catarina gathering Midstream has been constructed, and we are, therefore, subject to the possibility of more onerous terms or increased costs to retain necessary land use if we do not have valid rights-of-way or if such rights-of-way lapse or terminate. We currently have certain rights to construct and operate our pipelines on land owned by third parties for a specific period of time and may need to obtain other rights in the future from third parties and governmental agencies to continue these operations or expand Western Catarina Midstream. Our loss of these rights or inability to obtain additional rights, through our inability to renew or obtain right-of-way contracts or otherwise, could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to you.
Our right-of-first-offer with Sanchez Energy for midstream assets is subject to risks and uncertainty, and thus may not enhance our ability to grow our business.
Pursuant to the purchase agreement entered into in connection with the acquisition of midstream assets in the Western Catarina area from Sanchez Energy, subject to certain exceptions, Sanchez Energy has agreed to provide us the first right to make an offer to purchase midstream assets that it desires to transfer to any unaffiliated person through 2030. The acquisition of additional assets in connection with the exercise of our right-of-first-offer will depend upon, among other things, our ability to agree on the price and other terms of the sale, our ability to obtain financing on acceptable terms for the acquisition of such assets and our ability to acquire such assets on the same or better terms than third parties. We can offer no assurance that we will be able to successfully acquire any assets pursuant to this right.
In addition, Sanchez Energy is under no obligation to accept any offer made by us. Furthermore, for a variety of reasons, we may decide not to exercise this right when it becomes available.
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Risks Related to Our Production Business
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Drilling for and producing oil and natural gas are costly and high-risk activities with many uncertainties that could adversely affect our business, financial condition, results of operation, operating cash flows and any ability to pay distributions to our unitholders.
Drilling activities are subject to many risks, including the risk that commercially productive reservoirs will not be discovered. Drilling for oil and natural gas can be uneconomic, not only from dry holes, but also from productive wells that do not produce sufficient revenues to be commercially viable. In addition, drilling and producing operations may be curtailed, delayed or cancelled as a result of other factors, including:
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the high cost, shortages or delivery delays of drilling rigs, equipment, labor and other services;
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unexpected operational events and drilling conditions;
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adverse weather conditions;
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facility or equipment malfunctions;
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piping, casing or cement failures;
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compliance with environmental and other governmental requirements;
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unusual or unexpected geological formations;
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loss or damage to oilfield drilling and service tools;
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loss of drilling fluid circulation;
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formations with abnormal pressures;
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environmental hazards, such as natural gas leaks, oil spills, compressor incidents, pipeline ruptures and discharges of toxic gases;
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accidents or natural disasters;
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blowouts, craterings and explosions;
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uncontrollable flows of oil, natural gas or well fluids;
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loss or theft of data due to cyber-attacks; and
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Any of these events can cause increased costs or restrict the ability to drill wells and conduct operations. Any delay in the drilling program or significant increase in costs could impact our ability to generate sufficient cash flows to operate our business. Increased costs could include losses from personal injury or loss of life; damage to or destruction or loss of property, natural resources, equipment, and data; pollution; environmental contamination; loss of wells; and regulatory penalties.
Unless we replace the reserves that we produce, our existing reserves will decline, which could adversely affect our production and adversely affect our cash from operations and our ability to pay distributions to our unitholders.
Producing oil and natural gas reservoirs are characterized by declining production rates that vary based on the reservoir characteristics and other factors. The rate of decline of our reserves and production included in our reserve report at the end of the most recently completed fiscal year will change if production from our existing wells declines in a different manner than we have estimated and may change when we make acquisitions and under other circumstances. The rate of decline may also be greater than we have estimated due to decreased capital spending or lack of available capital to make capital expenditures. Our future oil and natural gas reserves and production and, therefore, our cash flows and income, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically acquiring additional recoverable reserves, as we do not intend to drill new wells. We may not be able to develop or acquire additional reserves to replace our current and future production at acceptable costs, which could adversely affect our business, financial condition, results of operations and ability to pay distributions to our unitholders.
Our estimated reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our estimated reserves.
It is not possible to measure underground accumulations of oil and natural gas in an exact way. Oil and natural gas reserve engineering requires subjective estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices, production levels and operating and development costs. Our independent reserve engineers do not independently verify the accuracy and completeness of information and data furnished by us. In
estimating our level of oil and natural gas reserves, we and our independent reserve engineers make certain assumptions that may prove to be incorrect, including assumptions relating to:
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future oil and natural gas prices;
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operating and development costs;
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the effects of regulation;
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the accuracy and reliability of the underlying engineering and geologic data; and
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the availability of funds.
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If these assumptions prove to be incorrect, our estimates of reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of reserves based on risk or recovery and our estimates of the future net cash flows from our reserves could change significantly.
Our standardized measure is calculated using unhedged oil and natural gas prices and is determined in accordance with the rules and regulations of the SEC (except for the impact of income taxes as we are not a taxable entity). Over time, we may make material changes to reserve estimates to take into account changes in our assumptions and the results of actual drilling and production.
The reserve estimates that we make for fields that do not have a lengthy production history are less reliable than estimates for fields with lengthy production histories. A lack of production history may contribute to inaccuracies in our estimates of proved reserves, future production rates and the timing of development expenditures.
The present value of future net cash flows from our estimated proved reserves is not necessarily the same as the current market value of our estimated oil and natural gas reserves.
We base the estimated discounted future net cash flows from our estimated proved reserves on prices and costs in effect on the day of the estimate. However, actual future net cash flows from our oil and natural gas properties also will be affected by factors such as:
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the actual prices that are received for oil and natural gas;
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actual operating costs in producing oil and natural gas;
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the amount and timing of actual production;
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the amount and timing of capital expenditures;
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supply of and demand for oil and natural gas; and
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changes in governmental regulations or taxation.
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The timing of both production and the incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus, their actual present value. In addition, the 10% discount factor used when calculating our discounted future net cash flows in compliance with the Financial Accounting Standard Board’s Accounting Standards may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general. Any material inaccuracies in these reserve estimates or underlying assumptions could materially affect
the quantities and present value of our reserves, which could adversely affect our business, results of operations, financial condition and ability to pay distributions.
Future price declines or downward reserve revisions may result in additional write-downs of our asset carrying values, which could adversely affect our results of operations and limit our ability to borrow funds.
Declines in oil and natural gas prices may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs, or if our estimates of development costs increase or production data factors change, accounting rules may require us to write-down, as a noncash charge to earnings, the carrying value of our properties for impairments. We capitalize costs to acquire, find and develop our oil and natural gas properties under the successful efforts accounting method. We are required to perform impairment tests on our assets periodically and whenever events or circumstances warrant a review of our assets. To the extent such tests indicate a reduction of the estimated useful life or estimated future cash flows of our assets, the carrying value may not be recoverable and therefore would require a write-down. We have incurred impairment charges in the past and may do so again in the future. Any impairment could be substantial and have a material adverse effect on our results of operations in the period incurred and on our ability to borrow funds under our Credit Agreement, which in turn may adversely affect our ability to make cash distributions to our unitholders.
We depend on certain key customers for sales of our oil and natural gas. To the extent these and other customers reduce the volumes of oil or natural gas they purchase from us and are not replaced by new customers, our revenues and cash available for distribution could decline.
Our oil and natural gas production in Oklahoma, as well as the onshore Texas and Louisiana Gulf Coast region, is marketed by the operators of our properties. To the extent these or other customers reduce the volumes of oil and natural gas that they purchase from us and are not replaced by new customers, or the market prices for oil and natural gas decline in our market areas, our revenues and cash available for distribution could decline.
Seasonal weather conditions may adversely affect our ability to conduct production activities.
Oil and natural gas operations are often adversely affected by seasonal weather conditions, primarily during periods of severe weather or rainfall, and during periods of extreme cold. Power outages and other damages resulting from tornados, ice storms, flooding and other strong storms or weather events may prevent wells from being operated in an optimal manner. These weather conditions may reduce oil and natural gas production, which could impact or reduce our future operating cash flows.
Shortages of drilling rigs, supplies, oilfield services, equipment and crews could delay operations and reduce our future operating cash flows and cash available to make future investments or to pay distributions.
Higher oil and natural gas prices generally increase the demand for drilling rigs, supplies, services, equipment and crews, and can lead to shortages of, and increasing costs for, drilling equipment, services and personnel. Shortages of, or increasing costs for, experienced drilling crews and equipment and services could restrict the ability to conduct the operations. Any significant increase in operating costs could reduce our revenues, operating cash flows and cash available to make future investments or to pay distributions.
Our oil and natural gas properties may be exposed to unanticipated water disposal or processing costs.
Where water produced from properties fails to meet the quality requirements of applicable regulatory agencies or wells produce water in excess of the applicable volumetric permit limit, the wells may have to be shut in or upgraded for water handling or treatment. The costs to treat or dispose of this produced water may increase if any of the following occur:
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permits cannot be renewed or obtained from applicable regulatory agencies;
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water of lesser quality or requiring additional treatment is produced;
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the wells produce excess water; or
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new laws and regulations require water to be disposed of or treated in a different manner.
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We may be unable to compete effectively with larger companies in the oil and natural gas industry, which may adversely affect our ability to generate sufficient revenue to allow us to pay distributions to our unitholders.
The oil and natural gas industry is intensely competitive with respect to acquiring productive properties, marketing oil and natural gas and securing equipment and trained personnel, and we compete with other companies that have greater resources. Many of our competitors are major independent oil and natural gas companies and possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to develop and acquire more productive properties than our financial and personnel resources permit. Our ability to acquire additional properties will be dependent on our ability to evaluate, select and finance the acquisition of suitable properties and our ability to consummate transactions in a highly competitive environment. Factors that affect our ability to acquire properties include availability of desirable acquisition targets, staff and resources to identify and evaluate properties and available funds. Many of our larger competitors not only drill for and produce oil and natural gas, but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for oil and natural gas properties and evaluate, bid for and purchase a greater number of properties than our financial or human resources permit. In addition, there is substantial competition for investment capital in the oil and natural gas industry. Our inability to compete effectively with other companies could have a material adverse effect on our business activities, financial condition and results of operations.
Risks Related to Regulatory Compliance
Potential regulatory actions could increase our operating or capital costs and delay our operations or otherwise alter the way we conduct our business.
Our business activities are subject to extensive federal, state, and local regulations. Changes to existing regulations or new regulations may unfavorably impact us, our suppliers or our customers. In the United States, legislation that directly impacts the oil and natural gas industry has been proposed covering areas such as emission reporting and reductions, hydraulic fracturing of wells, the repeal of certain oil and natural gas tax incentives and tax deductions and the treatment and disposal of produced water. The EPA has also ruled that carbon dioxide, methane and other greenhouse gases endanger human health and the environment. This allows the EPA to adopt and implement regulations restricting greenhouse gases under existing provisions of the federal Clean Air Act. In addition, provisions of the Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank Act”), which regulate financial derivatives, may impact our ability to enter into derivatives or require burdensome collateral or reporting requirements. These and other potential regulations could increase our costs, reduce our liquidity, impact our ability to hedge our future oil and natural gas sales, delay our operations or otherwise alter the way that we conduct our business, negatively impacting our financial condition, results of operations and cash flows.
We are subject to federal, state, and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the production and transportation of oil and natural gas. The possibility exists that any new laws, regulations or enforcement policies could be more stringent than existing laws and could significantly increase our compliance costs. If we are not able to recover the resulting costs from insurance or through increased revenues, our ability to pay distributions to our unitholders could be adversely affected.
Our failure to obtain or maintain necessary permits could adversely affect our operations.
Our operations are subject to complex and stringent laws and regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. Failure or delay in obtaining regulatory approvals or leases could have a material adverse effect on our ability to develop our properties. In addition, regulations regarding conservation practices and the protection of correlative rights affect our operations by limiting the quantity of oil and natural gas we may produce and sell.
Increased regulation of hydraulic fracturing could result in reductions or delays in the production of natural gas, NGLs and oil by Sanchez Energy, which could reduce the throughput on our facilities and adversely impact our revenues.
A substantial portion of Sanchez Energy’s production of natural gas, NGLs and oil is being developed from unconventional sources, such as shale formations. These reservoirs require hydraulic fracturing completion processes to release the liquids and natural gas from the rock so it can flow through casing to the surface. Hydraulic fracturing is a well stimulation process that utilizes large volumes of water and sand (or other proppant) combined with fracturing chemical additives that are pumped at high pressure to crack open previously impenetrable rock to release hydrocarbons. Hydraulic fracturing is typically regulated by state oil and gas commissions and similar agencies. Various studies are currently underway by the EPA and other federal and state agencies concerning the potential environmental impacts of hydraulic fracturing activities. For example, the EPA issued an advanced notice of proposed rulemaking under the Toxic Substances Control Act in 2014 requesting comments related to disclosures for hydraulic fracturing chemicals. At the same time, certain environmental groups have suggested that additional laws may be needed to more closely and uniformly regulate the hydraulic fracturing process, and legislation has been proposed by some members of the U.S. Congress to provide for such regulation. We cannot predict whether any such legislation will ever be enacted and if so, what its 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 and process prohibitions that could reduce the volumes of liquids and natural gas that move through our facilities, which in turn could materially adversely affect our revenues and results of operations.
Sanchez Energy may incur significant liability under, or costs and expenditures to comply with, environmental and worker health and safety regulations, which are complex and subject to frequent change.
As an owner, lessee or operator of gathering pipelines and compressor stations, we are subject to various stringent federal, state and local laws and regulations relating to the discharge of materials into, and protection of, the environment. Numerous governmental authorities, such as the EPA and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly response actions. These laws and regulations may impose numerous obligations that are applicable to our and our customer’s operations, including the acquisition of permits to conduct regulated activities, the incurrence of capital or operating expenditures to limit or prevent releases of materials from our or our customers’ operations, the imposition of specific standards addressing worker protection, and the imposition of substantial liabilities and remedial obligations for pollution or contamination resulting from our and our customer’s operations. Failure to comply with these laws, regulations and permits may result in joint and several, strict liability and the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, and the issuance of injunctions limiting or preventing some or all of our operations. Private parties, including the owners of the properties through which our facilities pass and facilities where wastes resulting from our operations are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance, as well as to seek damages for non-compliance, with environmental laws and regulations or for personal injury or property damage. We may not be able to recover all or any of these costs from insurance or Sanchez Energy. In addition, we may experience a delay in obtaining or be unable to obtain required permits, which may interrupt our operations and limit our growth and revenues, which in turn could affect our profitability. There is no assurance that changes in or additions to public policy regarding the protection of the environment will not have a significant impact on our operations and profitability.
The operation of our facilities also poses risks of environmental liability due to leakage, migration, releases or spills from our facilities to surface or subsurface soils, surface water or groundwater. Certain environmental laws impose strict as well as joint and several liability for costs required to remediate and restore sites where hazardous substances, hydrocarbons, or solid wastes have been stored or released. We may be required to remediate contaminated properties currently or formerly operated by us or facilities of third parties that received waste generated by our operations regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. Moreover, public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and stringent environmental legislation and regulations applied to the oil and natural gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability.
We may incur significant costs and liabilities as a result of pipeline integrity management program testing and any related pipeline repair or preventative or remedial measures.
The DOT has adopted regulations requiring pipeline operators to develop integrity management programs for transportation pipelines located where a leak or rupture could do the most harm in HCAs. The regulations require operators to:
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perform ongoing assessments of pipeline integrity;
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identify and characterize applicable threats to pipeline segments that could impact a high consequence area;
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improve data collection, integration and analysis;
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repair and remediate the pipeline as necessary; and
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implement preventive and mitigating actions.
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The 2011 Pipeline Safety Act, among other things, increases the maximum civil penalty for pipeline safety violations and directs the Secretary of Transportation to promulgate rules or standards relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation and testing to confirm the material strength of pipe operating above 30% of specified minimum yield strength in high consequence areas. Should our facilities fail to comply with DOT or comparable state regulations, we could be subject to substantial penalties and fines.
PHMSA has also published advanced notices of proposed rulemaking and notices of proposed rulemaking to solicit comments on the need for changes to its safety regulations as well as advisory bulletins. In April 2016, PHMSA issued a notice of proposed rulemaking that would expand integrity management requirements and impose new pressure requirements on currently regulated gas transmission pipelines and would also significantly expand the regulation of gas gathering lines, subjecting previously unregulated pipelines to requirements regarding damage prevention, corrosion control, public education programs, maximum allowable operating pressure limits and other requirements. In addition, in 2012, PHMSA issued an advisory bulletin providing guidance on the verification of records related to pipeline maximum allowable operating pressure, which could result in additional requirements for the pressure testing of pipelines or the reduction of maximum operating pressures. The adoption of these and other laws or regulations that apply more comprehensive or stringent safety standards could require us to install new or modified safety controls, pursue new capital projects, or conduct maintenance programs on an accelerated basis, all of which could require us to incur increased operational costs that could be significant. While we cannot predict the outcome of legislative or regulatory initiatives, such legislative and regulatory changes could have a material effect on our cash flows. Please read “Item 1. Business—Governmental Regulation—Pipeline Safety Regulation” for more information.
Because we handle oil, natural gas and other petroleum products in our business, we may incur significant costs and liabilities in the future resulting from a failure to comply with new or existing environmental regulations.
The operations of our wells, gathering systems, processing facilities, pipelines and other facilities are subject to stringent and complex federal, state and local environmental laws and regulations. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations. There is an inherent risk that we may incur environmental costs and liabilities due to the nature of our business and the substances we handle. Certain environmental statues, including RCRA, CERCLA and analogous state laws and regulations, impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances have been disposed of or otherwise released. In addition, an accidental release from one of our facilities could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage and fines or penalties for related violations of environmental laws or regulations.
Moreover, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase our compliance costs and the cost of any remediation that may become necessary, and these costs may not be recoverable from insurance.
Risks Related to Financing and Credit Environment
Our Credit Agreement has substantial restrictions and financial covenants and requires periodic borrowing base redeterminations.
We depend on our Credit Agreement for future capital needs. The Credit Agreement restricts our ability to obtain additional financing, make investments, lease equipment, sell assets and engage in business combinations. We are also required to comply with certain financial covenants and ratios. Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of cash flows from our operations and events or circumstances beyond our control, including events and circumstances that may stem from the condition of financial markets and commodity price levels. Our failure to comply with any of the restrictions and covenants under the Credit Agreement could result in an event of default, which could cause all of our existing indebtedness to become immediately due and payable. Each of the following is also an event of default:
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failure to pay any principal when due or any interest, fees or other amount prior to the expiration of certain grace periods;
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a representation or warranty made under the loan documents or in any report or other instrument furnished thereunder is incorrect when made;
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failure to perform or otherwise comply with the covenants in the Credit Agreement or other loan documents, subject, in certain instances, to certain grace periods;
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any event that permits or causes the acceleration of the indebtedness;
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bankruptcy or insolvency events involving us or our subsidiaries;
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certain changes in control as specified in the covenants to the Credit Agreement;
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the entry of, and failure to pay, one or more adverse judgments in excess of $2.5 million or one or more non-monetary judgments that could reasonably be expected to have a material adverse effect and for which enforcement proceedings are brought or that are not stayed pending appeal; and
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specified events relating to our employee benefit plans that could reasonably be expected to result in liabilities in excess of $2.5 million in any year.
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The Credit Agreement will mature on March 31, 2020. We may not be able to renew or replace the facility at similar borrowing costs, terms, covenants, restrictions or borrowing base, or with similar debt issue costs.
The amount available for borrowing at any one time under the Credit Agreement is limited to the separate borrowing bases associated with our oil and natural gas properties and our midstream assets. The borrowing base for the credit available for the upstream oil and natural gas properties is re-determined semi-annually in the second and fourth quarters of the year, and may be re-determined at our request more frequently and by the lenders, in their sole discretion, based on reserve reports as prepared by petroleum engineers, using, among other things, the oil and natural gas pricing prevailing at such time. The borrowing base for the credit available for our midstream properties is equal to the rolling four quarter EBITDA of our midstream operations multiplied by 5.0 initially, 4.75 for the second full quarter after acquiring Western Catarina Midstream and 4.5 thereafter. Outstanding borrowings in excess of our borrowing base must be repaid or we must pledge other oil and natural gas properties as additional collateral. We may elect to pay any borrowing base deficiency in three equal monthly installments such that the deficiency is eliminated in a period of three months. Any increase in our borrowing base must be approved by all of the lenders.
Our Credit Agreement contains a condition to borrowing and a representation that no material adverse effect has occurred, which includes, among other things, a material adverse change in, or material adverse effect on the business, operations, property, liabilities (actual or contingent) or condition (financial or otherwise) of us and our subsidiaries who are guarantors taken as a whole. If a material adverse effect were to occur, we would be prohibited from borrowing under the Credit Agreement and we would be in default under the Credit Agreement, which could cause all of our existing indebtedness to become immediately due and payable.
We will be required to make substantial capital expenditures to increase our asset base. If we are unable to obtain needed capital or financing on satisfactory terms, our ability to make cash distributions may be diminished or our financial leverage could increase.
In order to increase our asset base, we will need to make expansion capital expenditures. If we do not make sufficient or effective expansion capital expenditures, we will be unable to expand our business operations and, as a result, we will be unable to increase our future cash distributions. To fund our expansion capital expenditures and investment capital expenditures, we will be required to use cash from our operations or incur borrowings. Such uses of cash from our operations will reduce cash available for distribution to our unitholders. Alternatively, we may sell additional common units or other securities to fund our capital expenditures. Our ability to obtain bank financing or our ability to access the capital markets for future equity or debt offerings may be limited by our or Sanchez Energy’s financial condition at the time of any such financing or offering and the covenants in our existing debt agreements, as well as by general economic conditions, contingencies and uncertainties that are beyond our control. Even if we are successful in obtaining the necessary funds, the terms of such financings could limit our ability to pay distributions to our unitholders. In addition, incurring additional debt may significantly increase our interest expense and financial leverage, and issuing additional limited partner interests may result in significant unitholder dilution and would increase the aggregate amount of cash required to maintain the then-current distribution rate, which could materially decrease our ability to pay distributions at the prevailing distribution rate. None of our general partner, Sanchez Energy or any of their respective affiliates is committed to providing any direct or indirect support to fund our growth.
We may not be able to extend, replace or refinance our Credit Agreement on terms reasonably acceptable to us, or at all, which could materially and adversely affect our business, liquidity, cash flows and prospects.
Our Credit Agreement matures on March 31, 2020. We may not be able to extend, replace or refinance our existing Credit Agreement on terms reasonably acceptable to us, or at all, with our existing syndicate of banks or with replacement banks. In addition, we may not be able to access other external financial resources sufficient to enable us to repay the debt outstanding under our Credit Agreement upon its maturity. Any of the foregoing could materially and adversely affect our business, liquidity, cash flows and prospects.
Our Credit Agreement may restrict us from paying any distributions on our outstanding units.
We have the ability to pay distributions to unitholders under our Credit Agreement from available cash, including cash from borrowings under the Credit Agreement, as long as no event of default exists and provided that no distribution
to unitholders may be made if the borrowings outstanding, net of available cash, under our Credit Agreement exceed 90% of the borrowing base, after giving effect to the proposed distribution. We have obtained waivers of the Credit Agreement limitation in the past and may need to do so in the future. Our available cash is reduced by any cash reserves established by the board of directors of our general partner for the proper conduct of our business and the payment of fees and expenses. Our ability to pay distributions to our unitholders in any quarter will be solely dependent on our ability to generate sufficient cash from our operations and is subject to the approval of the board of directors of our general partner.
Our ability to access the capital and credit markets to raise capital and borrow on favorable terms will be affected by disruptions in the capital and credit markets, which could adversely affect our operations, our ability to make acquisitions and our ability to pay distributions to our unitholders.
Disruptions in the capital and credit markets could limit our ability to access these markets or significantly increase our cost to borrow. Some lenders may increase interest rates, enact tighter lending standards, refuse to refinance existing debt at maturity on favorable terms or at all and may reduce or cease to provide funding to borrowers. If we are unable to access the capital markets on favorable terms, our ability to make acquisitions and pay distributions could be affected.
We are exposed to credit risk in the ordinary course of our business activities.
We are exposed to risks of loss in the event of nonperformance by our customers, vendors, lenders in our Credit Agreement and counterparties to our hedging arrangements. Some of our customers, vendors, lenders and counterparties may be highly leveraged and subject to their own operating and regulatory risks. Despite our credit review and analysis, we may experience financial losses in our dealings with these and other parties with whom we enter into transactions as a normal part of our business activities. Any nonpayment or nonperformance by our customers, vendors, lenders or counterparties could have a material adverse impact on our business, financial condition, results of operations or ability to pay distributions.
Our future debt levels may limit our flexibility to obtain additional financing and pursue other business opportunities.
We may incur substantial additional indebtedness in the future under our Credit Agreement or otherwise. Our future indebtedness could have important consequences to us, including:
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our ability to obtain additional financing, if necessary, for working capital, maintenance and investment capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;
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covenants and financial tests contained in our existing and future credit and debt instruments may affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities;
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increased cash flows required to make principal and interest payments on our indebtedness could reduce the funds that would otherwise be available to fund operations, capital expenditures, future business development or any distributions to unitholders; and
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our debt level may make us more vulnerable than our competitors with less debt to competitive pressures or a downturn in our business or the economy generally.
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Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future debt, we will be forced to take actions such as reducing any distributions, reducing or delaying business activities, acquisitions, investments and/or capital expenditures, selling assets, restructuring or refinancing our indebtedness, or seeking additional equity capital or bankruptcy protection. We may not be able to affect any of these remedies on satisfactory terms or at all.
Periods of inflation or stagflation, or expectations of inflation or stagflation, could increase our costs and adversely affect our business and operating results.
During periods of inflation or stagflation, our costs of doing business could increase, including increases in the variable interest rates that we pay on amounts we borrow under our Credit Agreement. As we have hedged a large percentage of our future expected production volumes, the cash flows generated by that future hedged production will be capped. If any of our operating, administrative or capital costs were to increase as a result of inflation or any temporary or long-term increase in the cost of goods and services, such a cap could have a material adverse effect on our business, financial condition, results of operations, ability to pay distributions and the market price of our common units.
An increase in interest rates may cause the market price of our common units to decline and may increase our borrowing costs.
Like all equity investments, an investment in our common units is subject to certain risks. In exchange for accepting these risks, investors may expect to receive a higher rate of return than would otherwise be obtainable from lower-risk investments. Accordingly, as interest rates rise, the ability of investors to obtain higher risk-adjusted rates of return by purchasing government-backed debt or other interest-bearing securities may cause a corresponding decline in demand for riskier investments generally, including equity investments such as publicly-traded limited partnership interests. Reduced demand for our common units resulting from investors seeking other more favorable investment opportunities may cause the trading price of our common units to decline.
Higher interest rates may also increase the borrowing costs associated with our Credit Agreement. If our borrowing costs were to increase, our interest payments on our debt may increase, which would reduce the amount of cash available for our operating or capital activities or for any distribution to unitholders.
The swaps regulatory provisions of the Dodd-Frank Act and the rules adopted thereunder and other regulations, including EMIR, may adversely affect our ability to hedge risks associated with our business and our results of operations and cash flows.
The swaps regulatory provisions of the Dodd-Frank Act and the rules of the Commodity Futures Trading Commission (“CFTC”) thereunder now in effect and adopted by the CFTC in the future may adversely affect our ability to manage certain of our risks on a cost effective basis. As mandated by the Dodd-Frank Act, the CFTC has proposed rules to set limits on the positions market participants may hold in certain core futures and futures equivalent contracts, option contracts or swaps for or linked to certain physical commodities, including certain oil and natural gas, subject to exceptions for certain bona fide hedging and other types of transactions. If the position limits in the proposed rules or other similar position limits are imposed, our ability to execute our hedging strategies described above could be compromised.
Under the swaps regulatory provisions of the Dodd-Frank Act and the rules adopted thereunder, we could have to clear on a designated clearing organization and execute on certain markets any swap that we enter into that falls within a class of swaps designated by the CFTC for mandatory clearing unless we qualify for an exception from such requirements as to such swap. The CFTC has designated six classes of interest rate swaps and credit default swaps for mandatory clearing, but has not yet proposed rules designating any class of physical commodity swaps or other class of swaps for mandatory clearing. Although we expect to qualify for the end-user exception from the mandatory clearing and trade execution requirements for the swaps that we enter into to hedge our commercial risks, if we were to fail to qualify for that exception as to a swap we enter into and were required to clear that swap, we would have to post margin with respect to such swap, our cost of entering into and maintaining such swap could increase and we would have less flexibility with respect to that swap than we would enjoy were the swap not cleared. Moreover, the application of the mandatory clearing and trade execution requirements and other swap regulations to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging.
As required by the Dodd-Frank Act, the CFTC and the federal banking regulators have adopted rules requiring certain market participants to collect initial and variation margin with respect to uncleared swaps from their counterparties except as to any uncleared swaps as to which the counterparty qualifies for the end user exception from the mandatory clearing exception. Although those rules do not require initial margin to be collected from non-financial end users of uncleared swaps, an affected market participant must collect from its counterparty to any uncleared swap that is a non-
financial end user, but that does not qualify for the end user exception with respect to that uncleared swap, variation margin with respect to that swap at those times and in those forms and amounts as the market participant determines appropriately addresses the credit risk posed by that counterparty and the risk of that swap. The requirements of those rules relating to initial margin are being phased through September 1, 2020. Were we not to qualify for the end user exception as to any of our uncleared swaps and otherwise have to post initial or variation margin as to our uncleared swaps in the future, our cost of entering into and maintaining swaps would increase. In addition, our counterparties that are subject to the regulations imposing the Basel III capital requirements on them may increase the cost to us of entering into swaps with them or contractually require us to post collateral or greater amounts of collateral
with them in connection with such swaps to offset their increased capital costs or to reduce their capital costs to maintain those swaps on their balance sheets.
The European Market Infrastructure Regulation (“EMIR”) includes regulations related to the trading, reporting, clearing of derivatives and providing margin with respect to derivatives. EMIR may result in increased costs for OTC derivative counterparties and also lead to an increase in the costs of, and demand for, the liquid collateral with respect to any swap to which we are a party and that is governed by EMIR. Therefore, EMIR may impact our ability to maintain or enter into derivatives with certain of our European counterparties.
The Dodd-Frank Act’s swaps regulatory provisions, the related rules described above and the record keeping, reporting and business conduct rules imposed by the Dodd-Frank Act on other swaps market participants, as well as EMIR and the regulations imposing the Basel III capital requirements on certain swaps market participants, could significantly increase the cost of derivative contracts (including through requirements to post margin or other collateral, which could adversely affect our available liquidity), materially alter the terms of the derivative contracts that we enter into, particularly the provisions relating to the our need to provide margin with respect to, or collateralize our obligations under such derivative contracts, reduce the availability of derivatives to protect against certain risks that we encounter, reduce our ability to monetize or restructure our existing derivative contracts and to execute our hedging strategies. If, as a result of the swaps regulatory regime discussed above, we were to reduce our use of swaps to hedge our risks, such as commodity price risks that we encounter in our operations, our results of operations and cash flows may become more volatile and could be otherwise adversely affected.
Risks Related to Our Distributions to Unitholders
If we do not complete expansion projects or make and integrate acquisitions, our future growth may be limited.
A principal focus of our strategy is to increase the quarterly cash distributions that we pay to our unitholders over time. Our ability to increase our distributions depends on our ability to complete expansion projects and make acquisitions that result in an increase in cash generated. We may be unable to complete successful, accretive expansion projects or acquisitions for any of the following reasons:
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an inability to identify attractive expansion projects or acquisition candidates or we are outbid by competitors;
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an inability to obtain necessary rights-of-way or governmental approvals, including from regulatory agencies;
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an inability to successfully integrate the businesses that we develop or acquire;
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an inability to obtain financing for such expansion projects or acquisitions on economically acceptable terms, or at all;
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incorrect assumptions about volumes, reserves, revenues and costs, including synergies and potential growth; or
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an inability to secure adequate customer commitments to use the newly developed or acquired facilities.
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We may not have sufficient available cash from operations to pay our quarterly distributions to unitholders following the establishment of cash reserves and the payment of fees and expenses.
The amount of available cash from which we may pay distributions is defined in both our Credit Agreement and our partnership agreement. The amount of available cash that we distribute is subject to the definition of operating surplus in our partnership agreement. Ultimately, the amount of available cash that we may distribute to our unitholders principally
depends upon the amount of cash that we generate from our operations, which will fluctuate from quarter to quarter based on numerous factors generally described in this caption “Risk Factors.” These and other factors that affect that amount that we can distribute include:
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the amount of revenue generated from our facilities;
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the amount of oil and natural gas that we produce;
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the demand for and the price at which we are able to sell our oil and natural gas production;
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the results of our hedging activity;
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the level of our operating costs;
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the costs that we incur to acquire midstream assets and oil and natural gas properties;
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whether we are able to continue our development activities at economically attractive costs;
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the borrowing base under our Credit Agreement as determined by our lenders;
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the amount of our indebtedness outstanding;
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the level of our interest expense, which depends on the amount of our indebtedness and the interest payable thereon;
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the amount of working capital required to operate our business and our ability to make working capital borrowings under our Credit Agreement;
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fluctuations in our working capital needs;
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the amount of cash reserves established by the board of directors of our general partner for the proper conduct of our business, including the maintenance of our asset base and the payment of future distributions on our common units and incentive distribution rights; and
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the level of our maintenance capital expenditures.
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As a result of these factors, we may not have sufficient available cash to maintain or increase our quarterly distributions. The amount of available cash that we could distribute from our operating surplus in any quarter to our unitholders may fluctuate significantly from quarter to quarter and may be significantly less than any prior distributions that we have previously made. If we do not have sufficient available cash or operating cash flows to maintain or increase quarterly distributions, the market price of our common units may decline substantially.
In order for us to make a distribution from available cash under our Credit Agreement, our outstanding debt balances, net of available cash, must be less than 90% of our borrowing base, as determined by our lenders, after giving effect to the proposed distribution. We have obtained waivers of the Credit Agreement limitation in the past and may need to do so in the future. Our available cash excludes any cash reserves established by the board of directors of our general partner for the proper conduct of our business and the payment of fees and expenses. We are subject to additional future borrowing base redeterminations before our Credit Agreement matures in March 2020 and cannot forecast the level at which our lenders will set our future borrowing base. If our lenders reduce our borrowing base because of any of the numerous factors generally described in this caption “Risk Factors,” our outstanding debt balances, net of available cash, may exceed 90% of the borrowing base, as determined by our lenders, and we may be unable to make quarterly distributions.
The amount of cash that we have available for distribution to our unitholders depends primarily upon our operating cash flows and not our profitability.
The amount of cash that we have available for distribution depends primarily on our operating cash flows, including cash from reserves and working capital (which may include short-term borrowings), and not solely on our profitability, which is affected by non-cash items. As a result, we may be unable to pay distributions even when we record net income, and we may pay distributions during periods when we incur net losses.
Oil and natural gas prices are very volatile. If commodity prices decline significantly for a temporary or prolonged period, our cash from operations may decline and may adversely impact our ability to invest in new midstream facilities, our financial condition and our profitability.
Our revenue, profitability and operating cash flows depend in part upon the prices and demand for oil and natural gas, and a drop in prices can significantly affect our financial results and impede our growth. Changes in oil and natural gas prices have a significant impact on the value of our reserves and on our operating cash flows and may also impact the fees generated by us from our midstream facilities. In particular, declines in commodity prices will directly reduce the value of our reserves, our operating cash flows, our ability to borrow money or raise capital and our ability to pay distributions and may indirectly reduce the cash flows from our midstream facilities. Prices for oil and natural gas may fluctuate widely in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors that are beyond our control, such as:
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the domestic and foreign supply of and demand for oil and natural gas;
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the price and level of foreign imports of oil and natural gas;
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the level of consumer product demand;
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overall domestic and global economic conditions;
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political and economic conditions in oil and natural gas producing countries, including those in West Africa, the Middle East and South America;
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the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;
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the impact of U.S. dollar exchange rates on oil and natural gas prices; technological advances affecting energy consumption;
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domestic and foreign governmental regulations and taxation;
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the impact of energy conservation efforts;
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the costs, proximity and capacity of oil and natural gas pipelines and other transportation facilities;
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the price and availability of alternative fuels; and
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the increase in the supply of natural gas due to the development of natural gas.
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In the past, the prices of oil and natural gas have been extremely volatile, and we expect this volatility to continue. If we raise our distribution level in response to increased operating cash flows during periods of relatively high commodity prices, we may not be able to sustain those distribution levels during periods of lower commodity price levels.
Our operations require capital expenditures, which will reduce any cash available for distribution to our unitholders.
We will need to make capital expenditures to maintain our facilities and infrastructure over the long-term. These expenditures could increase as a result of, among others:
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changes in labor and material costs;
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changes in leasehold and right-of-way costs; and
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government regulations relating to safety, taxation and the environment.
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Our capital expenditures will reduce the amount of cash that we may have available for distribution to our unitholders. In addition, our actual capital expenditures will vary from quarter to quarter.
Each quarter we are required to deduct estimated maintenance capital expenditures from operating surplus, which may result in less cash available for distribution to unitholders than if actual maintenance capital expenditures were deducted.
Our partnership agreement requires us to deduct estimated, rather than actual, maintenance capital expenditures from operating surplus. The amount of estimated maintenance capital expenditures deducted from operating surplus will be subject to review and potential change by the board of directors of our general partner at least once a year. In years when our estimated maintenance capital expenditures are higher than actual maintenance capital expenditures, the amount of cash available for distribution to unitholders will be lower than if actual maintenance capital expenditures were deducted from operating surplus. If we underestimate the appropriate level of estimated maintenance capital expenditures, we may have less cash available for distribution in future periods when actual capital expenditures begin to exceed our previous estimates. Over time, if we do not set aside sufficient cash reserves or have available sufficient sources of financing and make sufficient expenditures to maintain our asset base, we will be unable to pay distributions in full, if at all.
Our hedging activities could result in financial losses or could reduce our income, which may adversely affect our ability to pay distributions.
To achieve more predictable cash flows and to reduce our exposure to adverse fluctuations in the prices of oil and natural gas, our current practice is to hedge, subject to the terms of our Credit Agreement, a significant portion of our expected production volumes for up to five years. As a result, we will continue to have direct commodity price exposure on the unhedged portion of our production volumes. The extent of our commodity price exposure is related largely to the effectiveness and scope of our hedging activities. For example, the derivative instruments that we utilize are generally based on posted market prices, which may differ significantly from the actual oil and natural gas prices that we realize in our operations.
Our actual future production may be significantly higher or lower than we estimated at the time we entered into hedging transactions for such period. If the actual amount is higher than we estimate, we will have greater commodity price exposure than we intended. If the actual amount is lower than the nominal amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flows from our sale or purchase of the underlying physical commodity, which may result in a substantial diminution of our liquidity. As a result of these factors, our hedging activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows. In addition, our hedging activities are subject to the following risks:
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a counterparty may not perform its obligation under the applicable derivative instrument;
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there may be a change in the expected differential between the underlying commodity price in the derivative instrument and the actual price received; and
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the steps that we take to monitor our derivative financial instruments may not detect and prevent violations of our risk management policies and procedures.
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Acquisitions involve potential risks that could adversely impact our future growth and our ability to pay distributions to our unitholders.
Any acquisition involves potential risks, including, among other things:
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the risk of title defects discovered after closing;
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inaccurate assumptions about revenues and costs, including synergies;
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significant increases in our indebtedness and working capital requirements;
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an inability to transition and integrate successfully or timely the businesses we acquire;
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the cost of transition and integration of data systems and processes;
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potential environmental problems and costs;
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the assumptions of unknown liabilities;
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limitations on rights to indemnity from the seller;
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the diversion of management’s attention from other business concerns;
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increased demands on existing personnel and on our organizational structure;
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disputes arising out of acquisitions;
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customer or key employee losses of the acquired businesses; and
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the failure to realize expected growth or profitability.
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The scope and cost of these risks may ultimately be materially greater than estimated at the time of the acquisition. Furthermore, our future acquisition costs may be higher than those we have achieved historically. Any of these factors could adversely impact our future growth and our ability to pay distributions.
Inadequate insurance could have a material adverse impact on our business, financial condition, results of operations and ability to pay distributions.
We ordinarily maintain insurance against certain losses and liabilities arising from our operations; however, insurance against all operational risks is not available to us. In addition, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could therefore occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could have a material adverse impact on our business, financial condition, results of operations and ability to pay distributions.
Risks Inherent in an Investment in Our Common Units
Our general partner and its affiliates will have conflicts of interest with us. They will not owe any fiduciary duties to us or our common unitholders, but instead will owe us and our common unitholders limited contractual duties, and they may favor their own interests to the detriment of us and our other common unitholders.
Manager, an affiliate of SOG, owns and controls our general partner and appoints all but two of the directors of our general partner. Although our general partner has a duty to manage us in a manner that is not adverse 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 Manager and its affiliates. Conflicts of interest will arise between SOG, Manager and their affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these
conflicts of interest, our general partner may favor its own interests and the interests of Manager and its affiliates over our interests and the interests of our unitholders. These conflicts include the following situations, among others:
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Neither our partnership agreement nor any other agreement requires Manager and its affiliates to pursue a business strategy that favors us or utilizes our assets. The directors and officers of Manager and its affiliates have a fiduciary duty to make these decisions in the best interests of the members of Manager and its affiliates, which may be contrary to our interests. Manager and its affiliates may choose to shift the focus of its investment and growth to areas not served by our assets.
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Our general partner is allowed to take into account the interests of parties other than us, such as SOG, Manager and their affiliates, in resolving conflicts of interest.
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Manager and its affiliates may be constrained by the terms of their respective debt instruments from taking actions, or refraining from taking actions, that may be in our best interests.
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Our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing its duties, limit our general partner’s liabilities and restrict the remedies available to our unitholders for actions that, without such limitations, might constitute breaches of fiduciary duty.
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Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.
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Disputes may arise under our commercial agreements with Manager, SOG and their affiliates.
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Our general partner determines the amount and timing of asset purchases and sales, borrowings, issuances of additional partnership units and the creation, reduction or increase of cash reserves, each of which can affect the amount of cash available for distribution to our unitholders.
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Our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which will reduce operating surplus, or an expansion or investment capital expenditure, which will not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders.
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Our general partner determines which costs incurred by it are reimbursable by us, the amount of which is not limited by our partnership agreement.
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Our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make incentive distributions.
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Our partnership agreement permits us to classify up to $20.0 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions to Manager as the holder of the incentive distribution rights.
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Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf.
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Our general partner intends to limit its liability regarding our contractual and other obligations.
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Our general partner and its controlled affiliates may exercise their right to call and purchase all of the common units not owned by them if they own more than 80% of our common units.
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Our general partner controls the enforcement of the obligations that it and its affiliates owe to us, including the obligations of SOG and its affiliates under their commercial agreements with us.
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Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.
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Our general partner may elect to cause us to issue common units to Manager in connection with a resetting of the target distribution levels related to our incentive distribution rights without the approval of the conflicts committee of the board of directors of our general partner or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.
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SOG and its affiliates may compete with us.
SOG and its affiliates may compete with us. As a result, SOG and its affiliates have the ability to acquire and operate assets that directly compete with our assets.
Manager may not allocate corporate opportunities to us.
Pursuant to the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner or any of its affiliates, including Manager 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 does not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any 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 common unitholders.
Our partnership agreement permits our general partner to redeem any partnership interests held by a limited partner who is an ineligible holder.
If our general partner, with the advice of counsel, determines that our not being treated as an association taxable as a corporation or otherwise taxable as an entity for U.S. federal income tax purposes, coupled with the tax status (or lack of proof thereof) of one or more of our limited partners, has, or is reasonably likely to have, a material adverse effect on the maximum applicable rates chargeable to customers by us or our subsidiaries, or we become subject to federal, state or local laws or regulations that create a substantial risk of cancellation or forfeiture of any property that we have an interest in because of the nationality, citizenship or other related status of any limited partner, our general partner may redeem the units held by the limited partner at their current market price. In order to avoid any material adverse effect on rates charged or cancellation or forfeiture of property, our general partner may require each limited partner to furnish information about their U.S. federal income tax status or nationality, citizenship or related status. If a limited partner fails to furnish information about their U.S. federal income tax status or nationality, citizenship or other related status after a request for the information or our general partner determines after receipt of the information that the limited partner is not an eligible holder, our general partner may elect to treat the limited partner as an ineligible holder. An ineligible holder assignee does not have the right to direct the voting of their units and may not receive distributions in kind upon our liquidation.
The market price of our common units may fluctuate significantly, and you could lose all or part of your investment.
The market price of our common units may be influenced by many factors, some of which are beyond our control, including:
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the level of our quarterly distributions;
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our quarterly or annual earnings or those of other companies in our industry;
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announcements by us or our competitors of significant contracts or acquisitions;
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changes in accounting standards, policies, guidance, interpretations or principles;
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general economic conditions, including interest rates and governmental policies impacting interest rates;
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the failure of securities analysts to cover our common units or changes in financial estimates by analysts;
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future sales of our common units; and
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other factors described in this proxy statement/prospectus and the documents incorporated herein.
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Our partnership agreement replaces our general partner’s fiduciary duties to holders of our common units with contractual standards governing its duties.
Our partnership agreement contains provisions that eliminate the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law and replace those duties with several different contractual standards. 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, free of any duties to us and our unitholders other than the implied contractual covenant of good faith and fair dealing, which means that a court will fill gaps under the partnership agreement to enforce the reasonable expectations of the partners, but only where the language in the partnership agreement does not provide for a clear course of action. This provision entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our general partner may make in its individual capacity include:
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how to allocate business opportunities among us and its other affiliates;
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whether to exercise its limited call right;
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whether to seek approval of the resolution of a conflict of interest by the conflicts committee of the board of directors of our general partner; and
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whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement.
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Our partnership agreement restricts the remedies available to holders of our common units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
The effect of eliminating fiduciary standards in our partnership agreement is that the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law will be significantly restricted. For example, our partnership agreement provides that:
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whenever our general partner, the board of directors of our general partner or any committee thereof (including the conflicts committee) makes a determination or takes, or declines to take, any other action in their respective capacities, our general partner, the board of directors of our general partner and any committee thereof (including the conflicts committee), as applicable, is required to make such determination, or take or decline to take such other action, in good faith, and under our partnership agreement, a determination, other action or failure to act by our general partner and any committee thereof (including the conflicts committee) will be deemed to be in good faith unless the general partner, the board of directors of our general partner or any committee thereof (including the conflicts committee) believed that such determination, other action or failure to act was adverse to the interests of the partnership or, with regard to certain determinations by the board of directors of our general partner relating to the conflict transactions described below, the board of directors of our general partner did not believe that the specified standards were met, and, except as specifically provided by our partnership agreement, neither our general partner, the board of directors of our general partner nor any committee thereof (including the conflicts committee) will be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;
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our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as such decisions are made in good faith;
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our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors, as the case may be, acted in bad faith or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and
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our general partner will not be in breach of its obligations under the partnership agreement (including any duties to us or our unitholders) if a transaction with an affiliate or the resolution of a conflict of interest is:
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approved by the conflicts committee of the board of directors of our general partner, although our general partner is not obligated to seek such approval;
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approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner and its affiliates;
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determined by the board of directors of our general partner to be on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or
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determined by the board of directors of our general partner to be fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.
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In connection with a situation involving a transaction with an affiliate or a conflict of interest, any determination by our general partner or the conflicts committee must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the conflicts committee and the board of directors of our general partner determine that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest satisfies either of the standards set forth in the third and fourth sub-bullets above, then it will be presumed that, in making its decision, the board of directors of our general partner acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership challenging such determination, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.
Furthermore, if any limited partner, our general partner or any person holding any beneficial interest in us brings any claims, suits, actions or proceedings (including, but not limited to, those asserting a claim of breach of a fiduciary duty) and such person does not obtain a judgment on the merits that substantially achieves, in substance and amount, the full remedy sought, then such limited partner, our general partner or person holding any beneficial interest in us shall be obligated to reimburse us and our “affiliates,” as defined in Section 1.1 of our partnership agreement (including our general partner, the directors and officers of our general partner, SOG and Manager) for all fees, costs and expenses of every kind and description, including, but not limited to, all reasonable attorney’s fees and other litigation expenses, that the parties may incur in connection with such claim, suit, action or proceeding.
Our partnership agreement includes exclusive forum, venue and jurisdiction provisions and limitations regarding claims, suits, actions or proceedings. By taking ownership of a common unit, a limited partner is irrevocably consenting to these provisions and limitations regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of Delaware courts.
Our partnership agreement is governed by Delaware law. Our partnership agreement includes exclusive forum, venue and jurisdiction provisions designating Delaware courts as the exclusive venue for most claims, suits, actions and proceedings involving us or our officers, directors and employees and limitations regarding claims, suits, actions or proceedings. By taking ownership of a common unit, a limited partner is irrevocably consenting to these provisions and limitations regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of Delaware courts. If a dispute were to arise between a limited partner and us or our officers, directors or employees, the limited partner may be required to pursue its legal remedies in Delaware, which may be an inconvenient or distant location and which is considered to be a more corporate-friendly environment. Furthermore, if any limited partner, our general partner or person holding any beneficial interest in us brings any claims, suits, actions or proceedings (including, but not limited to, those asserting a claim of breach of a fiduciary duty) and such person does not obtain a judgment on the merits that substantially
achieves, in substance and amount, the full remedy sought, then such limited partner, our general partner or person holding any beneficial interest in us shall be obligated to reimburse us and our “affiliates,” as defined in Section 1.1 of our partnership agreement (including our general partner, the directors and officers of our general partner, SOG and Manager) for all fees, costs and expenses of every kind and description, including, but not limited to, all reasonable attorneys’ fees and other litigation expenses, that the parties may incur in connection with such claim, suit, action or proceeding. This provision may have the effect of increasing a unitholder’s cost of asserting a claim and therefore, discourage lawsuits against us and our general partner’s directors and officers. Because fee-shifting provisions such as these are relatively new developments in corporate and partnership law, the enforceability of such provisions are uncertain; in addition, future legislation could restrict or limit this provision of our partnership agreement and its effect of saving us and our affiliates from fees, costs and expenses incurred in connection with claims, actions, suits or proceedings.
Holders of our common units will have limited voting rights and will not be entitled to elect our general partner or its directors.
Our common unitholders have limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s and our general partner’s decisions regarding our business. Common unitholders will have no right on an annual or ongoing basis to elect our general partner or its board of directors. Rather, the board of directors of our general partner will be appointed by Manager. Furthermore, if common unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which our common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price. Our partnership agreement also contains provisions limiting the ability of common unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting our common unitholders’ ability to influence the manner or direction of management.
Our partnership agreement restricts the voting rights of common unitholders owning 20% or more of our common units.
Common unitholders’ voting rights are further restricted by a provision of our partnership agreement providing that any units held by a person that owns 20% 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 our general partner, cannot vote on any matter.
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Our general partner interest or the control of our general partner may be transferred to a third-party without unitholder consent.
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Our general partner is able to transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of any assets it may own without the consent of our common unitholders. Furthermore, there is no restriction in the partnership agreement on the ability of Manager to transfer its membership interest in our general partner to a third party. The new members of our general partner would then be in a position to replace the board of directors and officers of our general partner in order to control the decisions taken by such board of directors and officers.
The incentive distribution rights held by Manager may be transferred to a third party without unitholder consent.
Manager is able to transfer its incentive distribution rights to a third party at any time without the consent of our common unitholders. If Manager transfers its incentive distribution rights to a third party but retains its ownership interest in our general partner, our general partner may not have the same incentive to grow our partnership and increase quarterly distributions to unitholders over time as it would if Manager had retained ownership of the incentive distribution rights. For example, a transfer of incentive distribution rights by Manager could reduce the likelihood of SOG or its affiliates accepting offers made by us relating to assets owned by it or its affiliates, as they would have less of an economic incentive to grow our business, which in turn would impact our ability to grow our asset base.
Following the conversion of the Class B preferred units, you may experience dilution of your common units and we may not have sufficient available cash to enable us to maintain or increase the quarterly distribution amount on our common units.
As of March 6, 2018, there were 31,000,887 Class B preferred units issued and outstanding which are convertible at any time into not less than 31,000,887 common units (plus additional common units resulting from the issuance of paid-in-kind distributions, if any, on such preferred units). Any future conversion of the Class B preferred units would dilute the percentage ownership held by our common unitholders. Additionally, any future conversion of Class B preferred units will result in the payment of distributions on any additional common units issued as a result of such conversion, and we may not have sufficient available cash to maintain or increase the quarterly distribution amount on our common units following the payment of such distributions.
We are able to issue additional units without common unitholder approval, which would dilute unitholder interests.
Our partnership agreement does not limit the number of additional limited partner interests, including limited partner interests that rank senior to our common units that we may issue at any time without the approval of our common unitholders. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:
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our existing limited partners’ proportionate ownership interest in us will decrease;
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the amount of cash available for distribution on each limited partnership interest may decrease;
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because the amount payable to holders of incentive distribution rights is based on a percentage of the total cash available for distribution, the distributions to holders of incentive distribution rights will increase even if the per unit distribution on common units remains the same;
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the ratio of taxable income to distributions may increase;
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the relative voting strength of each previously outstanding limited partner interest may be diminished; and
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the market price of our common units may decline.
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Our general partner intends to limit its liability regarding our obligations.
Our general partner intends to limit its liability under contractual arrangements so that the counterparties to such arrangements have recourse only against our assets and not against our general partner or its assets. Our general partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to our general partner. Our partnership agreement permits our general partner to limit its liability, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our general partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our unitholders.
Manager, or any transferee holding a majority of the incentive distribution rights, may elect to cause us to issue common units to it in connection with a resetting of the minimum quarterly distribution and the target distribution levels related to the incentive distribution rights, without the approval of the conflicts committee of our general partner or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.
The holder or holders of a majority of the incentive distribution rights, which is initially Manager, has the right, at any time when such holders have received incentive distributions at the highest level to which they are entitled (35.5%) for each of the prior four consecutive fiscal quarters (and the amount of each such distribution did not exceed adjusted operating surplus for each such quarter), to reset the minimum quarterly distribution and the initial target distribution levels at higher levels based on our cash distribution at the time of the exercise of the reset election. Following a reset election, the minimum quarterly distribution will be reset to an amount equal to the average cash distribution per unit for the two fiscal quarters immediately preceding the reset election (such amount is referred to as the “reset minimum quarterly distribution”), and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution. Manager has the right to transfer the incentive distribution rights at any
time, in whole or in part, and any transferee holding a majority of the incentive distribution rights will have the same rights as Manager with respect to resetting target distributions.
In the event of a reset of the minimum quarterly distribution and the target distribution levels, the holders of the incentive distribution rights will be entitled to receive, in the aggregate, the number of common units equal to that number of common units which would have entitled the holders to an average aggregate quarterly cash distribution in the prior two quarters equal to the distributions on the incentive distribution rights in the prior two quarters. We anticipate that Manager would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not otherwise be sufficiently accretive to cash distributions per common unit. It is possible, however, that Manager or a transferee could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions that it receives related to its incentive distribution rights and may therefore desire to be issued common units rather than retain the right to receive incentive distribution payments based on target distribution levels that are less certain to be achieved in the then-current business environment. This risk could be elevated if our incentive distribution rights have been transferred to a third party. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued common units to Manager in connection with resetting the target distribution levels.
Your liability may not be limited if a court finds that unitholder action constitutes control of our business.
A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law, and we conduct business in and outside of Delaware. 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. You could be liable for any and all of our obligations as if you were a general partner if a court or government agency were to determine that:
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we were conducting business in a state but had not complied with that particular state’s partnership statute; or
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your right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.
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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 Revised Uniform Limited Partnership Act (the “Delaware Act”), we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Transferees of common units are liable both for the obligations of the transferor to make contributions to the partnership that were known to the transferee at the time of transfer and for those obligations that were unknown if the liabilities could have been determined from the partnership agreement. Neither liabilities to partners on account of their partnership interest nor liabilities that are non-recourse to the partnership are counted for purposes of determining whether a distribution is permitted.
The NYSE American does not require a publicly traded limited partnership like us to comply with certain of its corporate governance requirements.
Because we are a publicly traded limited partnership, the NYSE American does not require us to have a majority of independent directors on our general partner’s board of directors or to establish a compensation committee or a nominating and corporate governance committee. Accordingly, unitholders will not have the same protections afforded to certain corporations that are subject to all of the NYSE American corporate governance requirements.
Tax Risks
Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by states and localities. If the Internal Revenue Service (“IRS”) were to treat us as a corporation for U.S. federal income tax purposes or if we were otherwise subject to a material amount of entity-level taxation, then our cash available for distribution would be substantially reduced.
The anticipated after-tax economic benefit of an investment in our common units depends largely on us being treated as a partnership for U.S. federal income tax purposes. Despite the fact that we are a limited partnership under Delaware law, we will be treated as a corporation for U.S. federal income tax purposes unless we satisfy a “qualifying income” requirement. Based on our current operations, we believe that we satisfy the qualifying income requirement and will continue to be treated as a partnership for U.S. federal income tax purposes. Failure to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to taxation as an entity. We have not requested, and do not plan to request, a ruling from the IRS with respect to our treatment as a partnership for U.S. federal income tax purposes.
If we were treated as a corporation for U.S. federal income tax purposes, we would pay U.S. federal income tax on our taxable income at the corporate income tax rate, and we would also likely pay additional state and local income taxes at varying rates. Distributions to unitholders would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions or credits would flow through to the unitholders. Because a tax would be imposed on us as a corporation, our cash available for distribution to our unitholders would be reduced.
At the state level, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of a material amount of any these taxes in the jurisdictions in which we own assets or conduct business could substantially reduce the cash available for distribution to our unitholders.
If we were treated as a corporation for U.S. federal income tax purposes or otherwise subjected to a material amount of entity-level taxation, there would be a material reduction in the anticipated cash flow and after-tax return to our unitholders likely causing a substantial reduction in the value of 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 U.S. federal, state or local income tax purposes, the minimum quarterly distribution and the target distributions may be adjusted to reflect the impact of that law on us.
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 U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative or legislative changes or differing judicial interpretation at any time. For example, from time to time members of the U.S. Congress have proposed and considered substantive changes to the existing U.S. federal income tax laws that would affect publicly traded partnerships. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible for us to meet the exception to be treated as a partnership for U.S. federal income tax purposes and could negatively impact the value of an investment in our common units.
Our common unitholders’ share of our income will be taxable to them even if they do not receive any cash distributions from us.
Common unitholders are required to pay U.S. federal income and other taxes and, in some cases, state and local income taxes, on their share of our taxable income, whether or not they receive cash distributions from us. Our common unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability due from them with respect to that income.
If the IRS contests the U.S. federal income tax positions we take, the market for our common units may be adversely impacted, and our cash available for distribution to our unitholders might be substantially reduced.
We have not requested a ruling from the IRS with respect to our treatment as a partnership for U.S. federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take, and a court may disagree with some or all of those positions. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will result in a reduction in cash available for distribution to our unitholders and thus will be borne indirectly by our unitholders.
Legislation applicable to partnership tax years beginning after 2017 alters the procedures for auditing partnerships and for assessing and collecting taxes due (including penalties and interest) as a result of a partnership-level U.S. federal income tax audit. If the IRS makes audit adjustments to our partnership tax returns, to the extent possible under the new rules, our general partner may elect to either pay the taxes (including any applicable penalties and interest) directly to the IRS in the year in which the audit is completed, or, if we are eligible, issue a revised information statement to each unitholder and former unitholder with respect to an audited and adjusted partnership tax return. Although our general partner may elect to have our unitholders and former unitholders take such audit adjustment into account and pay any resulting taxes (including applicable penalties or interest) in accordance with their interests in us during the tax year under audit, there can be no assurance that such election will be practical, permissible or effective in all circumstances. If we make payments of taxes and any penalties and interest directly to the IRS in the year in which the audit is completed, our cash available for distribution to our unitholders might be substantially reduced, in which case our current unitholders may bear some or all of the tax liability resulting from such audit adjustment even if the unitholders did not own units in us during the tax year under audit.
Tax gain or loss on the disposition of our common units could be more or less than expected.
If a common unitholder sells common units, the unitholder will recognize gain or loss equal to the difference between the amount realized and the tax basis in those common units. Because distributions in excess of a unitholder’s allocable share of our net taxable income decrease the unitholder’s tax basis in its common units, the amount, if any, of such prior excess distributions with respect to the common units a unitholder sells will, in effect, become taxable income to the unitholder if the unitholder sells such common units at a price greater than its tax basis in those common units, even if the price received is less than its original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation, depletion and intangible drilling cost recapture. In addition, because the amount realized may include a unitholder’s share of our nonrecourse liabilities, a unitholder that sells common units may incur a tax liability in excess of the amount of cash received from the sale.
Unitholders may be subject to limitations on their ability to deduct interest expense we incur.
Pursuant to recently enacted legislation, our ability to deduct business interest expense will be limited for U.S. federal income tax purposes to an amount equal to our business interest income and 30% of our “adjusted taxable income” during the taxable year, computed without regard to any business interest income or expense, and in the case of taxable years beginning before 2022, any deduction allowable for depreciation, amortization, or depletion. Business interest expense that we are not entitled to fully deduct will be allocated to each unitholder as excess business interest and can be carried forward by the unitholder to successive taxable years and used to offset any excess taxable income allocated by us to the unitholder. Any excess business interest expense allocated to a unitholder will reduce the unitholder’s tax basis in its partnership interest in the year of the allocation even if the expense does not give rise to a deduction to the unitholder in that year.
Tax-exempt entities 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, including employee benefit plans and individual retirement accounts (known as IRAs), raises issues unique to them. For example, virtually all of our income allocated to organizations exempt from U.S. federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Tax-exempt entities with multiple unrelated trades or businesses cannot aggregate losses from one unrelated trade or business to offset income from another to reduce total unrelated business taxable income.
As a result, it may not be possible for tax-exempt entities to utilize losses from an investment in us to offset unrelated business taxable income from another unrelated trade or business and vice versa. Tax-exempt entities should consult a tax advisor before investing in our common units.
Non-U.S. unitholders will be subject to U.S. federal income taxes and withholding with respect to income and gain from owning our common units.
Non-U.S. persons are generally taxed and subject to U.S. federal income tax filing requirements on income effectively connected with a U.S. trade or business. Income allocated to our unitholders and, under recently enacted legislation, any gain from the sale of our units will generally be considered to be “effectively connected” with a U.S. trade or business. As a result, distributions to a non-U.S. unitholder will be subject to withholding at the highest applicable effective tax rate and a non-U.S. unitholder who sells or otherwise disposes of a common unit will also be subject to U.S. federal income tax on the gain realized from the sale or disposition of that unit.
Recently enacted legislation also imposes a U.S. federal income tax withholding obligation of 10% of the amount realized upon a non-U.S. person’s sale or exchange of an interest in a partnership that is engaged in a U.S. trade or business. However, application of this withholding rule to dispositions of publicly traded partnership interests has been temporarily suspended by the IRS until regulations or other guidance have been issued. Non-U.S. persons should consult a tax advisor before investing in our common units.
We treat each purchaser of our common units as having the same tax benefits without regard to the common units purchased. The IRS may challenge this treatment, which could adversely affect the value of our common units.
Because we cannot match transferors and transferees of common units, we have adopted depletion, depreciation and amortization positions that may not conform with all aspects of existing U.S. Treasury regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. Our counsel is unable to opine as to the validity of such filing positions. A successful IRS challenge also could affect the timing of these tax benefits or the amount of gain on the sale of common units and could have a negative impact on the value of our common units or result in audits of and adjustments to our unitholders’ tax returns.
We prorate our items of income, gain, loss and deduction between transferors and transferees of common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred.
We prorate our items of income, gain, loss and deduction between transferors and transferees of common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a
particular common unit is transferred. Although recently issued final Treasury regulations allow publicly traded partnerships to use a similar monthly simplifying convention, such tax items must be prorated on a daily basis and these regulations do not specifically authorize all aspects of our proration method. Accordingly, our counsel is unable to opine as to the validity of this method. If the IRS were to successfully change this method or new U.S. Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.
A unitholder whose common units are loaned to a “short seller” to cover a short sale of common units may be considered as having disposed of those common units. If so, the unitholder would no longer be treated for U.S. federal income tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.
Because a unitholder whose common units are loaned to a “short seller” to cover a short sale of common units may be considered as having disposed of the loaned common units, the unitholder may no longer be treated for U.S. federal income tax purposes as a partner with respect to those common 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 common units may not be reportable by the unitholder and any distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Our counsel has not rendered an opinion regarding the treatment of a unitholder whose common units are loaned to a short seller to effect a short sale of common units; therefore, our 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 consult with their tax advisor about whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their common units.
We have adopted certain valuation methodologies in determining a unitholder’s allocations of income, gain, loss and deduction. The IRS may challenge these methodologies or the resulting allocations, and such a challenge could adversely affect the value of our common units.
In determining the items of income, gain, loss and deduction allocable to our unitholders, we must routinely determine the fair market value of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we make many fair market value estimates ourselves using a methodology based on the market value of our common units as a means to determine the fair market value of our assets. The IRS may challenge these valuation methods and the resulting allocations of income, gain, loss and deduction.
A successful IRS challenge to these methods or allocations could adversely affect the timing or amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.
As a result of investing in our common units, our unitholders may become subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire properties.
In addition to U.S. federal income taxes, our unitholders will likely be subject to other taxes, including 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 now or in the future, even if they do not reside in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Furthermore, our unitholders may be subject to penalties for failure to comply with those requirements. It is the responsibility of each unitholder to file all U.S. federal, state and local tax returns that may be required of such unitholder. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in our common units.
Item 1B. Unresolved
Staff Comments
None.
Item 2. Properties
A description of our properties is included in “Item 1. Business,” and is incorporated herein by reference.
Our obligations under our Credit Agreement are secured by mortgages on substantially all of our assets. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Agreement”, in this Annual Report on Form 10-K for additional information concerning our Credit Agreement.
Item 3. Legal Proceedings
We are the subject of legal proceedings and claims arising in the ordinary course of business from time to time. Management cannot predict the ultimate outcome of such legal proceedings and claims. While the legal proceedings and claims are asserted for amounts that may be material should an unfavorable outcome be the result, management does not currently expect that these matters will have a material adverse effect on our financial position or results of operations.
Item 4. Mine Safet
y Disclosures
Not applicable.
PART III
Item 10.
Directors, Executive Officers and Corporate Governance
The following table shows information for members of the board of directors and executive officers of our general partner as of March 6, 2018. All of the directors of our general partner are elected by Manager, as the sole member of our general partner. Members of the board of directors of our general partner hold office until their successors have bene elected or qualified or until the earlier of their death, resignation, removal or disqualification. Executive officers hold office at the discretion of, and may be removed by, the board of directors of our general partner.
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Name
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Age
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Position with Sanchez Midstream Partners LP
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Alan S. Bigman
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50
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Independent Director
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Kirsten A. Hink
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51
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Chief Accounting Officer
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Jack Howell
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31
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Director
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Richard S. Langdon
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67
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Independent Director
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G.M. Byrd Larberg
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65
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Independent Director
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Antonio R. Sanchez, III
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44
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Director; Chairman of the Board
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Eduardo A. Sanchez
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38
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Director
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Patricio D. Sanchez
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37
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Director; President & Chief Operating Officer
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Luke R. Taylor
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40
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Director
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Charles C. Ward
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57
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Chief Financial Officer and Secretary
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Gerald F. Willinger
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50
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Director; Chief Executive Officer
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Alan S. Bigman
was elected as a director of our general partner in March 2015 and was previously a director of Sanchez Production Partners LLC, having been first elected in July 2014. Mr. Bigman is an independent member of the Conflicts Committee of our general partner’s board of directors and is the Chairman of the Audit Committee of our general partner’s board of directors. Mr. Bigman currently serves as an independent non-executive Director and Chairman of the Audit Committee of a $1.5 billion dollar privately held chemicals company. His extensive board experience also includes Basell Polyolefins, an international chemical producer and predecessor of LyondellBasell, where he served as a non-executive Director before his appointment as Chief Financial Officer, and Svyazinvest, then Russia’s largest telecom company, as well as several others. Mr. Bigman’s executive experience includes fourteen years in positions with Access Industries, a privately-held, U.S.-based industrial group, and in senior positions with its portfolio companies. From June 1996 to March 1998, Mr. Bigman was Senior Vice President of Access Industries, overseeing strategic investments. From March 1998 until September 2003, Mr. Bigman served as Vice President and Director of Corporate Finance of Tyumen Oil Company (TNK), a major Russian oil and gas producer and refiner, where he raised over $5 billion to finance the growth of the company from its privatization in 1997 through a sale of a 50% stake to British Petroleum (BP) in 2003, creating TNK-BP, a $20 billion joint venture. From 2003 to 2004, he served as Vice President and Director of Corporate Finance for SUAL, a large Russian aluminum smelter, where he reorganized the finance function and executed strategic merger transactions. From September 2004 until December 2005, Mr. Bigman rejoined Access Industries as Senior Vice President. In January 2006, Mr. Bigman was appointed Chief Financial Officer of Basell Polyolefins, an international chemicals company based in The Netherlands, where he served through 2007 and co-led the acquisition of Lyondell to create one of the largest global chemical companies. In January 2008 Mr. Bigman was appointed Chief Financial Officer of LyondellBasell Industries, the successor company to Basell Polyolefins and Lyondell. LyondellBasell's US operations filed for bankruptcy in January 2009. Mr. Bigman continued to serve as Chief Financial Officer until August 2009, and worked for the company in a project role through March 2010. From 2011 through 2012, he served on a project basis as Director, Capital Markets and M&A of KCAD Deutag, an oilfield services company based in Aberdeen, UK, where he was responsible for reorganizing and staffing the company’s finance, corporate development and tax functions.
Kirsten A. Hink
was elected Chief Accounting Officer of our general partner in May 2015. Mrs. Hink has served as Senior Vice President and Chief Accounting Officer of Sanchez Energy since January 2015, and she previously served as Sanchez Energy’s Vice President and Principal Accounting Officer from March 2012. Prior to joining Sanchez Energy, Mrs. Hink served as the Controller of Vanguard Natural Resources, LLC from January 2011 to February 2012. From January 2010 to December 2010, she served as Assistant Controller of Mariner Energy, Inc. She served as the Chief Accounting
Officer for Edge Petroleum Corporation, or Edge, from July 2008 through December 2009 and the Vice President and Controller for Edge from October 2003 through July 2008. Prior to that time, she served as Controller of Edge from December 31, 2000 to October 2003 and Assistant Controller of Edge from June 2000 to December 2000.
Edge filed for Chapter 11 bankruptcy protection in October 2009. Mrs. Hink is a Certified Public Accountant in the State of Texas.
Jack Howell
was elected as a director of our general partner in October 2015. Mr. Howell has been with Stonepeak Infrastructure Partners (“Stonepeak”) since 2015. Mr. Howell currently serves as a Senior Managing Director at Stonepeak. Prior to joining Stonepeak, he covered the oil and gas sector for Davidson Kempner, a hedge fund that focuses on distressed investments, from 2014 to 2015. Prior to Davidson Kempner, Mr. Howell worked for Denham Capital, an energy-focused private equity firm from 2011 to 2014. Mr. Howell started his career as an Analyst in Credit Suisse’s oil and gas investment banking group from 2009 to 2011.
Richard S. Langdon
was elected as a director of our general partner in March 2015 and was previously a director of Sanchez Production Partners LLC, having been first elected in December 2006. Mr. Langdon is an independent member of the Audit Committee and Conflicts Committee of our general partner’s board of directors. Mr. Langdon is also currently the President and Chief Executive Officer of Badlands Energy, Inc., a privately held exploration and production company, and its publicly traded predecessor entity, Gasco Energy, Inc., since May 2013. Mr. Langdon has also served as a Director of Badlands Energy, Inc. and its predecessor, Gasco Energy, Inc., since 2003. Badlands Energy filed for Chapter 11 bankruptcy in August 2017. In addition to his current Badlands Energy titles, Mr. Langdon is also serving as Debtor-in-Possession for Badlands Energy, Inc. Mr. Langdon also currently serves on the board of directors, as chairman of the audit committee and as a member of the compensation committee of Gulfslope Energy, Inc., which capacities he has served in since March 2014. Mr. Langdon was the President and Chief Executive Officer of KMD Operating Company LLC (“KMD Operating”), a privately held production company, from November 2011 until December 2015 and Matris Exploration Company L.P., a privately held production company, from July 2004 until the merger of Matris Exploration into KMD Operating in November 2011, which merger was effective January 2011. Mr. Langdon also served as President and Chief Executive Officer of Sigma Energy Ventures, LLC, a privately held production company, from November 2007 until November 2013. From 1997 until 2002, Mr. Langdon served as Executive Vice President and Chief Financial Officer of EEX Corporation, a publicly traded exploration and production company that merged with Newfield Exploration Company in 2002. Prior to that, he held various positions with the Pennzoil Companies from 1991 to 1996, including Executive Vice President—International Marketing—Pennzoil Products Company; Senior Vice President—Business Development—Pennzoil Company; and Senior Vice President—Commercial & Control—Pennzoil Exploration & Production Company.
G. M. Byrd Larberg
was elected as a director of our general partner in March 2015. He was previously a director of Sanchez Production Partners LLC, having been first elected in July 2014. Mr. Larberg is an independent member of the Audit Committee of our general partner’s board of directors and is the Chairman of the Conflicts Committee of our general partner’s board of directors. Mr. Larberg also serves as a member of the board of directors of Horizon Energy, a private Exploration Company with both Domestic and International focus, which position he has held since late 2016. From 2010 to 2012, Mr. Larberg served as a member of the board of directors of Risco Resources, a small independent exploration company headquartered in Jakarta, Indonesia, which was sold in 2012. Mr. Larberg served as a member of the board of directors of 3GIG, an exploration-focused software firm headquartered in Houston, Texas, from 2008 to 2013 and now serves as an advisor to the board. He is active on the board of the Houston Metropolitan YMCA, as past chairman of the board. He was a board member of Meridian Resources, a Houston-based exploration company, from 2007 until it was acquired by Alta Mesa in 2010. Mr. Larberg began his career at Shell Exploration and Production Company as a geologist in 1976. Over the next twenty-one years, he held various leadership positions within Shell, and served as Vice President of Exploration and Production, Africa and Latin America for Pecten International, an affiliate of Shell Oil Company, from 1993 to 1996. Mr. Larberg left Shell and joined Burlington Resources in 1998. From 1998 to 2006, Mr. Larberg held several key positions at Burlington Resources, beginning as Vice President of Exploration for Burlington Resources International. In 2000, Mr. Larberg was elected Executive Vice President and Chief Operating Officer of Burlington Resources International, a position he held until 2003, when he moved to the corporate office as Vice President of Geosciences. In this capacity, he was responsible for technical excellence for the Geology and Geophysical programs across the company, G&G technology business development, and management of the company-wide exploration portfolio. Mr. Larberg retired from Burlington Resources in April 2006 following the company’s purchase by ConocoPhillips. Mr. Larberg was a director of Duma Hydrocarb Energy Corporation, a publicly traded production company, for a brief period in 2014. He occasionally consults in the areas of technical and portfolio management for exploration companies, including Pemex, Maersk, ONGC and Ecopetrol, Repsol and OMX.
Antonio R. Sanchez, III
was elected as a director of our general partner in March 2015 and was previously a director of Sanchez Production Partners LLC, having been first elected in August 2013. Mr. Sanchez, III is Chairman of our general partner’s board of directors. He has served as the Chief Executive Officer of Sanchez Energy, a publicly traded exploration and production company, and has been a member of Sanchez Energy’s board of directors since its formation in August 2011. He has been directly involved in the oil and gas industry for over 12 years. Mr. Sanchez, III is also the Co-President of SOG, which he joined in October 2001. He was the President of SEP Management I, LLC and was a Managing Director of Sanchez Energy Partners I, LP until their dissolution in December 2016. In his capacities as a director and officer of these companies, Mr. Sanchez, III has managed all aspects of their daily operations, including exploration, production, finance, capital markets activities, engineering and land management. From 1997 to 1999, Mr. Sanchez, III was an investment banker specializing in mergers and acquisitions with J.P. Morgan Securities Inc. From 1999 to 2001, Mr. Sanchez, III worked in a variety of positions, including sales and marketing, product development and investor relations, at Zix Corporation, a publicly traded encryption technology company (NASDAQ: ZIXI). Mr. Sanchez, III was also a member of the board of directors of Zix Corporation from May 2003 to June 2014.
Eduardo A.
Sanchez
was elected as a director of our general partner in June 2015. Mr. Sanchez served as president of Sanchez Energy Corporation from October 2015 to November 2017, President and Chief Executive Officer of Sanchez Resources, LLC from February 2010 until November 2017, co-president of SOG from July 2014 to November 2017, and chief executive officer of Sanchez Oil & Gas Mexico Holdings, LLC from August 2015 to December 2017. Prior to his work at Sanchez Resources, LLC, Mr. Sanchez worked at Commonwealth Associates, Inc. focusing on private equity and debt placements in small and midsize market capitalization businesses including those in the energy sector.
Patricio D. Sanchez
was elected President & Chief Operating Officer of our general partner in March 2017, Chief Operating Officer of our general partner in May 2015 and a director in June 2015. Mr. Sanchez has served as co-president of SOG since June 2014 and prior to that from April 2010 to June 2014 as Executive Vice President. Mr. Sanchez has served as an Executive Vice President of Sanchez Energy Corporation since November 2016. Mr. Sanchez has also been the managing member of Santerra Holdings, LLC, an oil and gas production company, since February 2012. Mr. Sanchez has managed many aspects of these companies’ daily operations, including exploration, production, finance, capital markets activities, engineering and land management.
Luke R. Taylor
was elected as a director of our general partner in October 2015. Mr. Taylor has served as a Senior Managing Director with Stonepeak since August 2011 and has served as a member of Stonepeak’s investment committee since 2015. Mr. Taylor sits on the boards of the following private companies: Golar Power, which develops, owns and operates integrated LNG-based transportation and downstream solutions, Ironclad Energy Partners, which develops, owns and operates energy generation and utility infrastructure assets, and Tidewater Holdings, which is an inland barge and terminal operator in the Pacific Northwest. Mr. Taylor is a former director of Paradigm Energy Partners, Orion Holdings and Northstar Renewable Power. Prior to joining Stonepeak, Mr. Taylor was a Senior Vice President with Macquarie Capital based in New York from August 2005 to May 2011.
Charles C. Ward
was elected Chief Financial Officer & Secretary of our general partner in March 2015. He previously served as Chief Financial Officer and Treasurer of Sanchez Production Partners LLC from March 2008 until its conversion to a limited partnership in March 2015 and Secretary from July 2014 until March 2015. Mr. Ward also served as a Vice President of Constellation Energy Commodities Group, Inc. from November 2005 until December 2008. Prior to that time, he was a Vice President of Enron Creditors Recovery Corp. from March 2002 to November 2005.
Gerald F. Willinger
was elected as a director of our general partner in March 2015 and was previously a director of Sanchez Production Partners LLC, having been first elected in August 2013. Mr. Willinger was elected Interim Chief Executive Officer of our general partner in April 2015 and Chief Executive Officer in December 2015. Mr. Willinger has served as a Managing Director of Sanchez Capital Advisors, LLC since February 2010. Mr. Willinger was also a co-founder, officer and director of Sanchez Resources from February 2010 to November 2017 when Sanchez Resources was acquired by Sanchez Energy Corporation. From 1998 to 2000, Mr. Willinger was an investment banker with Goldman, Sachs & Co. Mr. Willinger served in various private equity investment management roles at MidOcean Partners, LLC and its predecessor entity, DB Capital Partners, LLC, from 2000 to 2003 and at the Cypress Group, LLC from 2003 to 2006. Prior to joining Sanchez Capital Advisors, LLC, Mr. Willinger was a Senior Analyst for Silver Point Capital, LLC, a credit-opportunity fund, from 2006 to 2009.
Messrs. Howell and Taylor were elected to the board of directors of our general partner in October 2015 pursuant to a board representation and standstill agreement entered into in connection with our issuance of Class B preferred units to Stonepeak Catarina Holdings LLC. Pursuant to the agreement, we and our general partner agreed to permit Stonepeak to designate two persons to serve on our general partner’s board of directors. The right to designate one board member will immediately terminate on such date as Stonepeak no longer owns at least 25% of the outstanding Class B preferred units issued to it; and the right to designate the second board member will immediately terminate on such date as no Class B preferred units are outstanding. Stonepeak also has the right to appoint the three independent members to the board of directors if all of the Class B preferred units have not been redeemed by December 31, 2021, with such right continuing until all Class B preferred units have been redeemed.
Messrs. Antonio R. Sanchez, III, Eduardo A. Sanchez and Patricio D. Sanchez are brothers.
Qualifications of Board of Directors
The sole member of our general partner elects all of the persons to our general partner’s board of directors, except for two persons who are appointed by holders of our Class B preferred units. The following sets forth the specific experience, qualifications, attributes and skills that led the sole member of our general partner to conclude that the persons appointed by it should serve as directors:
Mr. Bigman brings considerable financial, managerial, transaction and corporate governance experience to the board of directors of our general partner. During his career, he has held management positions of increasing responsibility in major energy corporations throughout the world where he has successfully lead financings, financial restructurings, mergers and acquisitions involving companies focused on various aspects of the hydrocarbon value chain. With respect to energy finance, as Vice President and Director of Corporate Finance for TNK, a leading Russian oil and gas producer, he raised capital to finance the growth of the company from its privatization in 1997 through a sale of a 50% stake to British Petroleum (BP) in 2003, creating TNK-BP, a $20 billion joint venture. In the area of corporate governance, Mr. Bigman served on the board of directors of Basell Polyolefins, where he was a member of the audit and compensation committees, which is beneficial for our board operations. He has also served on several international boards, including the board of Svyazinvest, Russia’s largest telecommunications holding company, and JKX Oil and Gas, a UK public company focused on international oil and gas assets.
Mr. Langdon brings to the board of directors of our general partner considerable financial and managerial experience in the energy industry as well as his entrepreneurial abilities, which are valuable to us. He has served as the Chief Financial Officer of EEX Corporation, a publicly traded production company that merged with Newfield Exploration. He has also held significant commercial positions with the Pennzoil Companies, including roles in business development and marketing. He was also the founder and owner of two privately held oil and gas companies. Mr. Langdon has extensive experience in finance and accounting that adds significant value to the board’s oversight role of our financial reporting. He has prior public company board and audit committee experience, which is beneficial for our board operations, and served as the chairman of the audit committee of Gasco Energy, Inc., a publicly traded production company until he was named Gasco’s President and Chief Executive Officer.
Mr. Larberg brings to the board of directors of our general partner significant technical, operational and financial management experience in the oil and natural gas industry. His background provides a unique perspective on the dynamics of the oil and natural gas production industry. He has considerable governance experience, having previously served on the boards of several other companies. Taken together, this wealth of experience is invaluable to our board as we look to grow the Partnership.
Mr. Sanchez, III brings to the board of directors of our general partner substantial oil and gas/energy industry experience in both public and private entities. In his current capacity as Chief Executive Officer of Sanchez Energy, he brings the perspective of leading a quickly growing, publicly-traded upstream company focused on asset value maximization and the creation of shareholder value. In his current capacity as Co-President of SOG, he brings particular expertise in operating multiple oil and natural gas entities through a shared service model.
Mr. Eduardo Sanchez brings to the board of directors of our general partner substantial oil and gas/energy industry experience in both public and private entities. Through his past experience as the President of Sanchez Energy and co-
president of SOG, he brings the perspective of leading a quickly growing publicly-traded upstream company focused on asset value maximization and the creation of shareholder value and particular expertise in operating multiple oil and natural gas entities through a shard service model.
Mr. Patricio Sanchez brings to the board of directors of our general partner substantial oil and gas/energy industry experience in both public and private entities. As an Executive Vice President at Sanchez Energy, he brings the perspective of leading a quickly growing, publicly-traded upstream company focused on asset value maximization and the creation of shareholder value. In his current capacity as Co-President of SOG, he brings particular expertise in operating multiple oil and gas entities through a shared service model.
Mr. Willinger brings to the board of directors of our general partner substantial experience in risk management, finance and negotiated transactions in the energy industry. He has a valuable perspective on master limited partnerships, which provides the board with unique insights into master limited partnership management and growth opportunities. In addition, he brings an expansive network of both private and public capital providers, which is useful for the board when evaluating possible capital sources.
The following sets forth the specific experience, qualifications, attributes and skills that led the holders of our Class B preferred units to conclude that the persons appointed by them should serve as directors:
Mr. Howell brings to the board of directors of our general partner extensive oil and gas investing experience, along with experience in oil and gas transaction financings and mergers and acquisitions.
Mr. Taylor brings to the board of directors of our general partner significant investment experience in energy and infrastructure companies, along with experience in finance and mergers and acquisitions.
Committees of the Board of Directors
The board of directors of our general partner has two standing committees: an audit committee and a conflicts committee. We do not have a compensation committee, but rather the board of directors of our general partner approves equity grants to directors, officers, employees and service providers.
Audit Committee
As described in the audit committee charter, the audit committee is directly responsible for the appointment, compensation, retention and oversight of the work of the independent public accountants to audit our financial statements, including assessing the independent auditor’s qualifications and independence, and establishes the scope of, and oversees, the annual audit. The committee also approves any other services provided by public accounting firms. The board of directors of our general partner has delegated to the audit committee the review and approval of our decision to enter into derivative transactions and our exemption from the swap clearing and swap execution requirements of the Dodd-Frank Act. The audit committee provides assistance to the board in fulfilling its oversight responsibility to the unitholders, the investment community and others relating to the integrity of our financial statements, our compliance with legal and regulatory requirements, the independent auditor’s qualifications and independence and the performance of our internal audit function. The audit committee oversees our system of disclosure controls and procedures and system of internal controls regarding financial, accounting, legal compliance and ethics that management and the board of directors of our general partner established. In doing so, it is the responsibility of the audit committee to maintain free and open communication between the committee and our independent auditors, the internal accounting function and our management.
Messrs. Bigman (chair), Langdon and Larberg are members of the audit committee. The board of directors of our general partner has determined that Mr. Bigman is an “audit committee financial expert” as that term is defined in the applicable rules of the SEC and that he is “independent” as defined in applicable NYSE American listing standards.
Conflicts Committee
Under our partnership agreement, the board of directors of our general partner has appointed a conflicts committee composed of the independent directors, G. M. Byrd Larberg, chairman, Alan Bigman and Richard Langdon, to review
specific matters that the board of directors of our general partner believes may involve conflicts of interest. The conflicts committee will determine if the resolution of a conflict of interest is fair and reasonable to us. The members of the conflicts committee may not be security holders, officers or employees of our general partner, directors, officers, or employees of affiliates of the general partner or holders of any ownership interest in us other than common units or other publicly traded units and must meet the independence standards established by the NYSE American, the Exchange Act and other federal securities laws. Any matter approved by the conflicts committee is conclusively deemed to be fair and reasonable to us, approved by all of our partners and not a breach by our general partner of any duties that it may owe us or our unitholders.
Other
We maintain on our website, http://www.sanchezmidstream.com, a copy of the charters of the Audit Committee of the board of directors of our general partner, as well as copies of the Corporate Governance Guidelines and Code of Business Conduct and Ethics that are applicable to us and our general partner. Copies of these documents are also available in print upon request of the Corporate Secretary of our general partner. We intend to post any changes to or waivers of our Code of Business Conduct and Ethics for the executive officers of our general partner on our website.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Exchange Act requires the directors and executive officers of our general partner, and persons who own more than 10% of a registered class of our equity securities, to file initial reports of ownership of our equity securities and reports of changes in ownership of our equity securities with the SEC. Such persons are also required by SEC regulation to furnish us with copies of all Section 16(a) forms that they file.
Based solely on our review of the copies of such forms furnished to us and written representations from the directors and executive officer of our general partner, we believe that during 2017 all Section 16(a) reporting persons complied with all applicable filing requirements in a timely manner, except that Form 4s were filed late on December 1, 2017 by each of Messrs. Sanchez, III, Sanchez E., Sanchez P. and Willinger, a Form 4 filed late on May 10, 2017 by Gerald F. Willinger, a Form 4 filed late on May 3, 2017 by Antonio R. Sanchez, III, a Form 4 filed late on April 26, 2017 by Eduardo A. Sanchez and a Form 4 filed late on April 18, 2017 by Patricio D. Sanchez.
Certifications
The NYSE American requires the Chief Executive Officer of each listed company to certify annually that he is not aware of any violation by a listed company of the NYSE American’s corporate governance listing standards, qualifying the certification to the extent necessary. In accordance with the rules of the NYSE American, we last provided such a certification on April 10, 2017. The certifications of the Chief Executive Officer and Chief Financial Officer of our general partners required by Sections 302 and 906 of the Sarbanes-Oxley Act have been included as exhibits to this Annual Report on Form 10-K.
Item 11. Executiv
e Compensation
Our general partner has the sole responsibility for conducting our business and for managing our operations, and its board of directors and executive officers make decisions on our behalf. The executive officers of our general partner are employed by SOG and manage the day-to-day affairs of our business.
Summary Compensation Table
The following table sets forth the compensation of our named executive officers (which are the chief executive officer and the two next most highly compensated officers of our general partner) for 2017 and 2016:
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Cash
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Unit
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All Other
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Name and Principal Position
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Year
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Salary
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Bonus
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Awards
(a)
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Compensation
(b)
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Total
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Gerald F. Willinger
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2017
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$
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600,000
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$
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—
|
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$
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1,299,982
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$
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192,756
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$
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2,092,738
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Chief Executive Officer
(c)
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2016
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$
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600,000
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$
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—
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$
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99,991
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$
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68,590
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$
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768,581
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Patricio D. Sanchez
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2017
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$
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400,000
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$
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—
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$
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899,985
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$
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68,152
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$
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1,368,137
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President & Chief Operating Officer
(c)(d)
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2016
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$
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400,000
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$
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—
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$
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99,991
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$
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51,748
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$
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551,739
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Charles C. Ward
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2017
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$
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275,000
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$
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—
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$
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499,992
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$
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17,134
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$
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792,126
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Chief Financial Officer and Secretary
(c)
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2016
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$
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275,000
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$
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—
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$
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—
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$
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1,380,689
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$
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1,655,689
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(a)
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For 2016, Messrs. Willinger and Sanchez were each issued 9,661 units under the Plan for director compensation with a grant date fair value of $99,991, based on the $10.35 price per common unit on April 19, 2016, which was the closing price as reported on the NYSE American on the day before the date of grant. For 2017, Messrs. Willinger and Sanchez were each issued 6,369 units under the Plan for director compensation with a grant date fair value of $99,993, based on the $15.70 price per common unit on March 31, 2017, which was the closing price as reported on the NYSE American on the day before the date of grant. On March 21, 2017, the board of directors of our general partner awarded executive bonuses for services rendered in 2017, which were paid in the form of restricted units under the Plan to vest one year after the date of grant. Messrs. Willinger, Sanchez and Ward received 82,191, 54,794 and 34,246 restricted units, respectively, with a grant date fair value per common unit of $1,199,989, $799,992, and $499,992, respectively, based on a price per common unit of $14.60, which was the closing price on the date of grant as reported on the NYSE American.
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(b)
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The amount in this column reflects the amount of matching contributions made under our 401k plan, parking cost paid for our executive officers, the aggregate incremental cost of the personal use of aircraft made available by SOG, and allocated to the Partnership and the cost of life insurance for our executive officers. Mr. Ward also received cash a cash severance payment in January 2016 of $1,363,375 relating to the termination of his employment agreement. For Messrs. Willinger and Sanchez, the amounts for 2017 and 2016 also include $44,500 and $50,500, respectively, in director compensation paid in cash. For Messrs. Willinger and Sanchez, the amounts for 2017 include the aggregate incremental cost of the personal use of aircraft made available by SOG and allocated the Partnership of $129,866 and $22,404, respectively.
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(c)
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Our named executive officers are eligible to participate in benefit plans such as medical, dental, life, and disability insurance, 401k and flexible spending accounts on the same terms as all employees or service providers.
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(d)
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Mr. Sanchez was elected Chief Operating Officer in May 2015 and President & Chief Operating Officer in March 2017.
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None of the executive officers of our general partner have employment agreements.
Outstanding Equity Awards at Fiscal Year-End 2017
The following table sets forth the outstanding equity awards and their market value using the closing price of our common units on NYSE American at December 31, 2017 for the named executive officers:
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Number of
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Fair Market
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Units Not
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Value of Units
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Name
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Vested
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Not Vested
⁽ᵃ⁾
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Gerald F. Willinger
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93,426
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(b)
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$
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1,324,698
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Patricio D. Sanchez
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66,029
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(b)
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$
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924,701
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Charles C. Ward
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39,246
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(b)
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$
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555,492
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(a)
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Amounts are based on the closing price of our common units of $11.10 as reported on the NYSE American on December 31, 2017.
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(b)
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Reflects restricted units granted under the Plan on December 1, 2015 and March 21, 2017, which units vest pro-rata over a three-year period and on their first anniversary, respectively. Except in connection with a change in control (as defined in the Plan) or in the discretion of the board of directors of our general partner, any unvested restricted units will be forfeited upon such time as the holder is no longer an officer, employee, consultant or director of us, our general partner, any of their affiliates or any other person performing bona fide services for us.
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Compensation of Directors
The board of directors of our general partner has approved the following compensation program for its directors:
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a cash retainer of $10,000, payable quarterly on the last day of each fiscal quarter;
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·
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an equity grant of $100,000 of fully vested common units on March 31 of each year;
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·
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a $1,500 fee for each meeting of the board of directors of our general partner and $1,000 for each substantive meeting of the Audit Committee and $3,500 for each substantive meeting of the Conflicts Committee attended by a member thereof;
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·
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a cash retainer of $3,500 for the chair of the Audit Committee and $2,500 for the chair of the Conflicts Committee, each payable quarterly on the last day of each fiscal quarter; and
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·
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eligibility for independent directors to participate in health benefits generally available to all employees and reimbursement for up to $500,000 of life insurance.
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The following table sets forth a summary of the 2017 compensation for the directors of our general partner’s board of directors, except for Messrs. Willinger and Patricio Sanchez whose director compensation is included above under “—Summary Compensation Table”:
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Director Compensation
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Fees Earned or Paid
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Unit
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All Other
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Name
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in Cash
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Awards
(a)
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Compensation
(e)
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Total
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Alan S. Bigman
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$
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68,500
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$
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99,993
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$
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20,152
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$
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188,645
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Jack Howell
(b)
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$
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—
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$
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—
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$
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—
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$
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—
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Richard S. Langdon
(c)
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$
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104,500
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$
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99,993
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$
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—
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$
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204,493
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G. M. Byrd Larberg
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$
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64,500
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$
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99,993
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$
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—
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$
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164,493
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Antonio R. Sanchez, III
(d)
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$
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43,000
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$
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99,993
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$
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—
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$
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142,993
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Eduardo A. Sanchez
(d)
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$
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43,000
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$
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99,993
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$
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—
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$
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142,993
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Luke R. Taylor
(b)
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$
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—
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$
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—
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$
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—
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$
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—
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(a)
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The amounts shown in this column represent the aggregate grant date fair value of the units granted under the Plan, computed in accordance with FASB ASC Topic 718, based on the $15.70 closing price per common unit as reported on the NYSE American on March 31, 2017, the day before the date of grant for all directors.
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(b)
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As the designated directors appointed by Stonepeak, Messrs. Howell and Taylor waived any director fees to which they were otherwise entitled.
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(c)
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Fees earned or paid in cash includes the last of three annual payments of $50,000, which occurred on April 5, 2017.
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(d)
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Mr. Antonio R. Sanchez, III and Mr. Eduardo A. Sanchez also each hold 11,235 outstanding unvested equity awards with a fair market value of $124,709 as of December 31, 2017, based on an $11.10 per unit closing price as reported by the NYSE American on such date.
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(e)
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All other compensation includes amounts for health insurance premium fees paid by us for the director.
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Item 12. Securit
y Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters
The following table sets forth the beneficial ownership of our units, as of March 6, 2018, held by:
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·
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each unitholder known by us to beneficially own more than 5% of our outstanding units;
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·
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each of the directors of our general partner’s board of directors;
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·
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each of our general partner’s named executive officers (as such term is defined by the SEC); and
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·
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the directors and executive officers of our general partner as a group.
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The amounts and percentage of common units and Class B preferred units beneficially owned are reported on the basis of the SEC rules governing the determination of beneficial ownership of securities. Under the SEC rules, a person is deemed to be a “beneficial owner” of a security if that person has or shares “voting power,” which includes the power to
vote or to direct the voting of such security, and/or “investment power,” which includes the power to dispose of or to direct the disposition of such security. A person is also deemed to be a beneficial owner of any securities of which that person has a right to acquire beneficial ownership within 60 days. Under these rules, more than one person may be deemed a beneficial owner of the same securities, and a person may be deemed a beneficial owner of securities as to which he has no economic interest.
Percentage of total units beneficially owned is based on 14,965,134 common units and 31,000,887 Class B preferred units outstanding as of March 6, 2018, the number of common units beneficially owned and the number of Class B preferred units beneficially owned is based upon ownership as of March 6, 2018, except with respect to the amounts reported on filings on Schedule 13G or 13D, which amounts are based upon holdings as of March 1, 2018 unless otherwise specified therein. Except as indicated by footnote, to our knowledge the persons named in the table below have sole voting and investment power with respect to all units shown as beneficially owned by them, subject to community property laws where applicable.
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Percentage of
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Common Units Beneficially
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Class B Preferred Units
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Total Units
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Owned
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Beneficially Owned
(1)
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Beneficially
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Name and address of Beneficial Owner
(2)
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Number
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Percentage
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Number
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Percentage
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Owned
(1)
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Stonepeak Catarina Holdings, LLC
(3)
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393,291
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2.6
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%
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31,000,887
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100
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%
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68.3
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%
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Goldman Sachs Asset Management, L.P.
(4)
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1,145,389
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7.7
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%
|
—
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|
—
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|
2.5
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%
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SN UR Holdings, LLC
(5)
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2,272,727
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15.2
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%
|
—
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|
—
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|
4.9
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%
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Alan S. Bigman
(6)
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21,293
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|
*
|
|
—
|
|
—
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|
*
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Kirsten A. Hink
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12,500
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|
*
|
|
—
|
|
—
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|
*
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Jack Howell
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|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
Richard S. Langdon
|
|
26,866
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|
*
|
|
—
|
|
—
|
|
*
|
|
G. M. Byrd Larberg
|
|
21,293
|
|
*
|
|
—
|
|
—
|
|
*
|
|
Antonio R. Sanchez, III
(7)
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333,465
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|
2.2
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%
|
—
|
|
—
|
|
*
|
|
Eduardo A. Sanchez
|
|
304,990
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|
2.0
|
%
|
—
|
|
—
|
|
*
|
|
Patricio D. Sanchez
|
|
361,005
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|
2.4
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%
|
—
|
|
—
|
|
*
|
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Luke R. Taylor
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
Charles C. Ward
|
|
101,378
|
|
*
|
|
—
|
|
—
|
|
*
|
|
Gerald F. Willinger
|
|
214,925
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|
1.4
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%
|
—
|
|
—
|
|
*
|
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All directors and executive officers as a group (11 persons)
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1,397,715
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|
9.3
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%
|
—
|
|
—
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|
3.2
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%
|
*
Less than 1%
|
(1)
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The holder of Class B preferred units has the right to convert such units into our common units at any time.
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(2)
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Unless otherwise set forth below, the address of all of all beneficial owners is c/o Sanchez Midstream Partners LP, 1000 Main Street, Suite 3000, Houston, Texas 77002.
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(3)
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Ownership data as reported on Schedule 13D/A filed on May 31, 2017 by Stonepeak Catarina Holdings LLC, Stonepeak Catarina Upper Holdings LLC, Stonepeak Infrastructure Fund (Orion Aiv) LP, Stonepeak Associates LLC, Stonepeak GP Holdings LP, Stonepeak GP Investors LLC, Stonepeak GP Investors Manager LLC, Michael Dorrell and Trent Vichie. The principal business address of each reporting person is 717 Fifth Avenue, 25th Floor, New York, New York 10022.The filing lists each filing person as having shared voting and dispositive power over the common units and the Class B preferred units.
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(4)
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Ownership data as reported on Schedule 13G filed on January 31, 2018 by Goldman Sachs Asset Management, L.P. and GS Investment Strategies, LLC. The principal business address of the reporting person is Goldman Sachs Asset Management, 200 West Street, New York, NY 10282. The filing lists each filing person as having shared voting and dispositive power over the common units.
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(5)
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Ownership data as reported on Schedule 13G filed on November 28, 2016 by SN UR Holdings, LLC and Sanchez Energy Corporation. The principal business address of each filing reporting person is 1000 Main Street, Suite 3000, Houston, Texas 77002. The filing lists each filing person as having shared voting and dispositive power over the common units.
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(6)
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Of these common units, 800 are held by Mr. Bigman’s children.
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(7)
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Mr. Antonio R. Sanchez III owns 325,951 common units. Mr. Sanchez is a co-manager of SOG, which owns 35,320 common units and of which Mr. Sanchez shares voting and dispositive power.
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Equity Compensation Plan Information
The following table reflects our equity compensation plan information for our only equity compensation plan, the Sanchez Midstream Partners LP Long-Term Inventive Plan (the “Plan”), as of December 31, 2017:
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|
|
|
|
|
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|
|
Number of
|
|
|
|
|
|
|
|
|
Securities
|
|
|
|
|
Number of securities
|
|
|
|
to be issued upon
|
|
Weighted-average
|
|
remaining available
|
|
|
|
exercise of
|
|
exercise price of
|
|
for future
|
|
|
|
outstanding options,
|
|
outstanding options,
|
|
issuance under equity
|
|
|
|
warrants, and rights
|
|
warrants, and rights
|
|
compensation plans
|
|
Plan Category
|
|
|
|
|
|
|
|
|
Equity compensation plans approved by security holders
|
|
—
|
|
$
|
—
|
|
1,599,135
|
|
Equity compensation plans not approved by security holders
|
|
—
|
|
$
|
—
|
|
—
|
|
Total
|
|
—
|
|
$
|
—
|
|
1,599,135
|
|
Item 13. Certain Relationship
s and Related Transactions, and Director Independence
Manager
We are controlled by our general partner, Sanchez Midstream Partners GP LLC. The sole member of our general partner is Manager, which has no officers. The sole manager and member of Manager is SP Capital Holdings, LLC, which has no officers. The co-managers of SP Capital Holdings, LLC are Antonio R. Sanchez, III, Eduardo A. Sanchez, Patricio D. Sanchez and their father, Antonio R. Sanchez, Jr. SP Capital Holdings, LLC is owned by Antonio R. Sanchez, III (26%), Eduardo A. Sanchez (26%), and Patricio D. Sanchez (26%), along with their sister, Ana Lee Sanchez Jacobs (18%), and Antonio R. Sanchez, Jr (4%).
In May 2014, we entered into the Services Agreement with Manager pursuant to which Manager provides services that we require to operate our business, including overhead, technical, administrative, marketing, accounting, operational, information systems, financial, compliance, insurance, acquisition, disposition and financing services. In connection with providing the services under the Services Agreement, Manager receives compensation consisting of: (i) a quarterly fee equal to 0.375% of the value of our properties other than our assets located in Oklahoma, (ii) reimbursement for all allocated overhead costs as well as any direct third-party costs incurred and (iii) for each asset acquisition, asset disposition and financing, a fee not to exceed 2% of the value of such transaction. Each of these fees, not including the reimbursement of costs, will be paid in cash unless Manager elects for such fee to be paid in our equity. For the fees earned during the year ended December 31, 2017, Manager elected to receive 707,527 of our common units, valued at $8.8 million, in lieu of cash. During the years ended December 31, 2017 and 2016, we incurred costs of approximately $8.8 million and $7.5 million, respectively, under the Services Agreement.
In connection with our conversion from a limited liability company to a limited partnership in March 2015, all of our incentive distribution rights were granted to Manager. Pursuant to the terms of our partnership agreement, if, for any quarter, we have distributed cash from operating surplus to our common unitholders in an amount equal to the minimum quarterly distribution, then we will make additional distributions from operating surplus for that quarter among our common unitholders and Manager (as the holder of our incentive distribution rights) in the following manner:
|
·
|
|
first, 100% to all common unitholders, pro rata, until each unitholder receives a total of $0.575 per unit for that quarter;
|
|
·
|
|
second, 87.0% to all common unitholders, pro rata, and 13.0% to the holders of our incentive distribution rights, until each unitholder receives a total of $0.625 per unit for that quarter;
|
|
·
|
|
third, 77.0% to all common unitholders, pro rata, and 23.0% to the holders of our incentive distribution rights, until each unitholder receives a total of $0.875 per unit for that quarter; and
|
|
·
|
|
thereafter, 64.5% to all common unitholders, pro rata, and 35.5% to the holders of our incentive distribution rights.
|
No incentive distribution payments have been made since their date of issuance.
Manager’s right to receive incentive distributions is reduced by a percentage equal to the number of common units held by Sanchez Energy and its affiliates resulting from the common unit issuance made to SN UR Holdings, LLC, a subsidiary of Sanchez Energy, in November 2016, divided by all common units outstanding as of the time of distribution.
SOG
SOG provides services to us through a contractual relationship with SP Holdings. Antonio R. Sanchez, III and Patricio D. Sanchez are Co-Presidents of SOG; Antonio R. Sanchez, Jr. is the Chief Executive Officer and sole director of SOG; Ana Lee Sanchez Jacobs is an Executive Vice President of SOG; and Gerald F. Willinger is an Executive Vice President of SOG. The controlling owners of SOG are Antonio R. Sanchez, Jr. and Santig, Ltd. The general partner of Santig, Ltd. is Sanchez Management Corporation, which is owned 100% by Antonio R. Sanchez, Jr. Antonio R. Sanchez, Jr. is Chairman and President of Sanchez Management Corporation and Antonio R. Sanchez, III is Executive Vice President of Sanchez Management Corporation.
In May 2014, we entered into a Contract Operating Agreement with SOG (the “Operating Agreement”) pursuant to which SOG either provides services to operate, develop and produce our oil and natural gas properties or engages a third-party operator to do so, other than with respect to our properties in the Mid-Continent region. In connection with providing services under the Operating Agreement, SOG will be reimbursed for all direct charges under COPAS. Aside from reimbursed costs, no amounts have been paid to SOG under the Operating Agreement during the years ended December 31, 2017 and 2016.
In May 2014, we and certain of our subsidiaries entered into a Geophysical Seismic Data Use License Agreement with SOG (the “License Agreement”) pursuant to which SOG provides us with a non-exclusive, royalty-free license to use seismic, geophysical and geological information relating to our oil and natural gas properties that is proprietary to SOG and not restricted by agreements that SOG has with landowners or seismic data vendors. No amounts are payable under the License Agreement.
Sanchez Energy
Since January 1, 2015, we have completed three midstream acquisitions and two working interest acquisitions from Sanchez Energy, and acquired a Lease Option from Sanchez Energy (defined below), which was subsequently terminated. Antonio R. Sanchez, Jr., the father of Antonio R. Sanchez, III, Eduardo A. Sanchez and Patricio D. Sanchez, is a director and Executive Chairman of the board of directors of Sanchez Energy, Antonio R. Sanchez, III, is a director and Chief Executive Officer of Sanchez Energy, Eduardo A. Sanchez is the former President of Sanchez Energy and Patricio D. Sanchez is an Executive Vice President of Sanchez Energy. The employees of SOG, including Kirsten A. Hink, our Chief Accounting Officer, provide common services to both us and Sanchez Energy. The beneficial ownership of Sanchez Energy’s common stock as of March 5, 2018 by Antonio R. Sanchez, Jr., Antonio R. Sanchez, III, Eduardo A. Sanchez and Patricio D. Sanchez was 6.8%, 3.0%, 1.4% and 1.2%, respectively.
We entered into the Gathering Agreement with Sanchez Energy in October 2015. For the years ended December 31, 2017 and 2016, Sanchez Energy paid us approximately $52.8 million and $50.1 million, respectively, pursuant to the terms of the Gathering Agreement. On June 30, 2017, the Gathering Agreement was amended to add an incremental infrastructure fee to be paid by SN Catarina based on water that is delivered through the gathering system through March 31, 2018.
As part of the Carnero Gathering Transaction that closed in July 2016, we are required to pay Sanchez Energy an earnout based on natural gas received above a threshold volume and tariff at Carnero Gathering’s delivery points from Sanchez Energy and other producers. For the years ended December 31, 2017 and 2016, we did not make an earnout payment to Sanchez Energy. However, we had a payable of $0.1 million to Sanchez Energy at year end December 31, 2017 related to the earnout.
In October 2016, we and a wholly-owned subsidiary of Sanchez Energy, entered into a lease option purchase agreement pursuant to which Sanchez Energy’s subsidiary sold and conveyed to us an option to acquire a ground lease to which Sanchez Energy’s subsidiary was a party for a tract of land leased from the Calhoun Port Authority in Point Comfort, Texas (the “Lease Option”). In addition, if Sanchez Energy or any of its affiliates entered into an option to engage in the construction of or participation in a Project (as defined below) and/or received the benefit of an acreage dedication from an affiliate of Sanchez Energy relating to a Project, then such option and/or acreage dedication would also be assigned to us, if we exercise the Lease Option. We were to pay Sanchez Energy’s subsidiary $1.00 if the Lease Option was exercised, along with $250,000 if we or any other person affiliated with us elected to construct, own or operate a marine storage terminal on or within five miles of the Port Comfort lease or participated as an investor in the same, within five miles thereof (a “Project”), or Sanchez Energy or its affiliates conveyed an acreage dedication to or an option regarding a Project. On September 11, 2017, Sanchez Energy, Sanchez Energy’s subsidiary and we entered into an agreement that terminated the Lease Option.
We completed the Carnero Processing Transaction in November 2016. Additionally, in conjunction with our public offering of common units in November 2016, the Partnership entered into a Common Unit Purchase Agreement with SN UR Holdings, LLC (the “Purchaser”), a wholly-owned subsidiary of Sanchez Energy, whereby we issued to the Purchaser 2,272,727 common units for proceeds of approximately $25.0 million.
In September 2017, we entered into the SECO Pipeline Transportation Agreement. For the year ended December 31, 2017, SN Catarina paid us approximately $0.9 million pursuant to the terms of that agreement.
Class B Preferred Unit Issuance
Under our partnership agreement, in the event that we did not raise at least $75.0 million through the issuance of additional common units prior to September 30, 2016 (with the conversion of our Class A preferred units counting toward such amount) or if any Class A preferred units remained outstanding after March 31, 2016, the cash portion of the distribution rate on our Class B preferred units would increase by 4.0% per annum until consummation of such issuance or conversion, as applicable. We did not raise at least $75.0 million through the issuance of additional common units prior to September 30, 2016 and, therefore, the increased distribution rate was utilized for the quarter ended September 30, 2016. We issued common units in November 2016, which satisfied the equity raise requirement to decrease quarterly distributions to their original level starting with the quarter ended December 31, 2016.
As a result of the common unit issuance in November 2016, and in accordance with our partnership agreement, in December 2016, we issued an additional 9,851,996 Class B preferred units to Stonepeak. Stonepeak disagreed with our calculation of the additional Class B preferred units due under our partnership agreement and
in January 2017, we and Stonepeak entered into a settlement agreement to settle the disputed calculation. Pursuant to the settlement agreement, and in accordance with Section 5.4 of our partnership agreement, we issued 1,704,446 Class B preferred units to Stonepeak in a privately negotiated transaction as consideration for the Settlement Agreement, with the “Class B Preferred Unit Price” under our partnership agreement being established at $11.29 per Class B preferred unit.
In October 2015, as amended in January 2017, we entered into a registration rights agreement with Stonepeak pursuant to which we agreed to register, upon Stonepeak’s request, the resale of the common units issuable upon conversion of the Class B preferred units along with any other common units held by Stonepeak. In addition, we and our general partner entered into a board representation and standstill agreement with Stonepeak pursuant to which we and our general partner have agreed to permit Stonepeak to designate two persons to serve on the board of directors of our general partner.
Item 14. Principa
l Accounting Fees and Services
We engaged our principal accountant, KPMG LLP (“KPMG”), to audit our financial statements and perform other professional services for the fiscal years ended December 31, 2017 and 2016.
Audit Fees
. The aggregate fees billed for the financial statement audit or services provided in connection with statutory or regulatory filings for the years ended December 31, 2017 and 2016 were $816,000 and $712,000, respectively.
Audit-Related Fees
. The aggregate fees billed for audit-related fees for the years ended December 31, 2017 and 2016 were $215,000 and $215,000, respectively.
Tax Fees
. There were no tax fees billed by KPMG for the years ended December 31, 2017 and 2016.
All Other Fees
. There aggregate fees billed for other fees for the year ended December 31, 2017 was $36,000. There were no other fees billed by KPMG for the year ended December 31, 2016.
Audit Committee Pre-Approval Policies and Practices
The audit committee of our general partner’s board of directors must pre-approve any audit and permissible non-audit services performed by our independent registered public accounting firm. In addition, the audit committee has oversight responsibility to ensure that the independent registered public accounting firm is not engaged to perform certain enumerated non-audit services, including, but not limited to, bookkeeping, financial information system design and implementation, appraisal or valuation services, internal audit outsourcing services and legal services. The audit committee has adopted an audit and non-audit services pre-approval policy, which sets forth the procedures and the conditions pursuant to which services proposed to be performed by the independent registered public accounting firm must be approved. Pursuant to the policy, all services must be reviewed and approved and the chairman of the audit committee has been delegated the authority to specifically pre-approve services, which pre-approval is subsequently reviewed with the committee. All of the services described as Audit Fees, Audit-Related Fees, Tax Fees and All Other Fees were approved by the audit committee.