UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)

☒

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2019

OR

☐

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from             to             .
Commission File Number 001-33147

Sanchez Midstream Partners LP

(Exact Name of Registrant as Specified in Its Charter)

(713) 783-8000

(Registrant’s Telephone Number, Including Area Code)

Securities registered pursuant to Section 12(b) of the Act:

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

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

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

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

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).    Yes  ☒    No  ☐ 

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

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

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

The aggregate market value of Sanchez Midstream Partners LP common units held by non-affiliates as of June 28, 2019 was approximately $24,442,184 based upon the NYSE American closing price as of such date.  

Common units outstanding on March 13, 2020: 19,975,193 common units.

TABLE OF CONTENTS

COMMONLY USED DEFINED TERMS

As used in this Annual Report on Form 10-K (this “Form 10-K”), unless the context indicates or otherwise requires, the following terms have the following meanings:

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Form 10-K contains “forward-looking statements” as defined by the United States Securities and Exchange Commission (the “SEC”) that are subject to a number of risks and uncertainties, many of which are beyond our control. These statements may include discussions about our business strategy; the ability of our customers to meet their drilling and development plans on a timely basis, or at all, and perform under gathering, processing and other agreements; our financing strategy; our acquisition strategy; our ability to make distributions; our future operating results; the ability of our partners to perform under our joint ventures; our future capital expenditures; and our plans, objectives, expectations, forecasts, outlook and intentions.

All of these types of statements, other than statements of historical fact included in this Form 10-K, are forward-looking statements. These forward-looking statements may be found in Part II, Item 7. and other items within this Form 10-K. In some cases, forward-looking statements can be identified by terminology such as “may,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “continue,” the negative of such terms or other comparable terminology. 

The forward-looking statements contained in this Form 10-K are largely based on our expectations, which reflect estimates and assumptions made by the management of our general partner. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management’s assumptions about future events may prove to be inaccurate.

Important factors that could cause our actual results to differ materially from the expectations reflected in the forward‑looking statements include, among others:

Management cautions all readers that the forward-looking statements contained in this Form 10-K are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in forward-looking statements. The forward-looking statements speak only as of the date made, and other than as required by law, we do not intend to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

PART I

Overview

We are a growth-oriented publicly-traded limited partnership formed in 2005 focused on the acquisition, development and ownership of midstream and other energy-related assets in North America. We have ownership stakes in oil and natural gas gathering systems, natural gas pipelines and natural gas processing facilities, all located in the Western Eagle Ford in South Texas. We also own production assets in Texas and Louisiana. We have entered into a shared services agreement (the “Services Agreement”) with Manager, pursuant to which Manager provides operational services to us including overhead, technical, administrative, marketing, accounting, operation, information systems, financial, compliance, insurance, acquisition, disposition and financing services. Manager owns our general partner and all of our incentive distribution rights. On June 2, 2017, we changed our name to Sanchez Midstream Partners LP from Sanchez Production Partners LP. 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 and associated acreage dedications, provide us with a long range strategic advantage. As of March 13, 2020, Sanchez Energy owned approximately 11.4% 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.

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. To perform the scope of work defined in the Services Agreement, Manager has entered into a shared services agreement with SOG, which also has a shared services agreement in place with Sanchez Energy. We believe that our relationships with Manager and SOG provide us with a cost-effective means of operating our assets. SOG, which was formed in 1972, has a senior management team that averages over 20 years of industry experience. SOG 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 leverage SOG’s extensive expertise and experience to execute on our business strategy.  

Business Strategy

Our primary business objective is to create long-term value by generating stable and predictable cash flows that allow us to make, maintain and grow our cash distributions per common unit over time through the safe and reliable operation of our assets. We plan to achieve this objective by executing the following business strategy:

Our business strategy is subject to risks, please read “Part I, Item 1A. Risk Factors.”

Business Segments

Our business activities are conducted under two operating segments for which we provide information in our consolidated financial statements for the years ended December 31, 2019 and 2018. These two segments are based on the nature of the operations that are undertaken by each segment and are our:

For information about our segments’ revenues, profits and losses and total assets, see Note 18 “Reporting Segments” of our Notes to Consolidated Financial Statements.

Midstream Business

Western Catarina Midstream

In October 2015, we acquired (the “Catarina Transaction”) a gathering system from Sanchez Energy (“Western Catarina Midstream”), which is located on the western portion of Sanchez Energy’s approximately 106,000 net acres in Dimmit, La Salle and Webb counties, Texas (such net acreage is collectively referred to herein as “Sanchez Energy’s Catarina Asset,” and the western portion of such net acreage is individually referred to herein as “Western Catarina”). 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 assets located in the Eagle Ford Shale in South Texas. The gathering lines range in diameter from 4 to 12 inches, with a 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 Bbls per day, approximately 25,000 Bbls 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 crude oil produced by Sanchez Energy at Sanchez Energy’s Catarina Asset. The gathering system has oil interconnects with the Plains All American Pipeline, L.P. header system delivered to the Gardendale terminal, and to all four takeaway pipelines to Corpus Christi, and natural gas interconnects with Southcross Energy Partners, L.P., Kinder Morgan Inc., Energy Transfer Partners, L.P. and Targa Resources Corp.

In conjunction with the Catarina Transaction, we entered into a 15-year firm gas gathering and processing agreement with Sanchez Energy, pursuant to which Sanchez Energy agreed to tender all of its crude 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 outside of the dedicated acreage (the “Gathering Agreement”).

All of the revenues from Western Catarina Midstream are currently earned from Sanchez Energy. During the first five years of the term of the Gathering Agreement (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 was amended to add an incremental infrastructure fee to be paid by Sanchez Energy based on water that was delivered to Western Catarina Midstream through March 31, 2018. Since March 31, 2018, we have agreed with Sanchez Energy to continue adding the incremental infrastructure fee on a month-to-month basis.

During the year ended December 31, 2019, Sanchez Energy transported average daily production through Western Catarina Midstream of approximately 11.1 MBbls/d of oil, 131.7 MMcf/d of natural gas and 5.5 MBbls/d of water. The average age of the Western Catarina Midstream assets is approximately nine years, and such assets have an average expected life of approximately 21 additional years.

Carnero JV

In May 2018, we executed a series of agreements with Targa Resources Corp. (NYSE: TRGP) (“Targa”) and other parties pursuant to which, among other things: (1) the parties merged their respective 50% interests in Carnero Gathering, LLC (“Carnero Gathering”) and Carnero Processing, LLC (“Carnero Processing”) (the “Carnero JV Transaction”) to form an expanded 50 / 50 joint venture in South Texas, Carnero G&P, LLC (“Carnero JV”), (2) Targa contributed 100% of the equity interest in the Silver Oak II Gas Processing Plant located in Bee County, Texas (“Silver Oak II”), to Carnero JV, which expanded the processing capacity of the joint venture from 260 MMcf/d to 460 MMcf/d, (3) Targa contributed certain capacity in the 45 miles of high pressure natural gas gathering pipelines owned by Carnero Gathering that connect Western Catarina Midstream to nearby pipelines and the Raptor Gas Processing Facility (the “Carnero Gathering Line”) to Carnero JV resulting in the joint venture owning all of the capacity in the Carnero Gathering Line, which has a design limit (without compression) of 400 MMcf/d, (4) the Carnero JV received a new dedication from Sanchez Energy and its working interest partners of over 315,000 acres located in the Western Eagle Ford on Sanchez Energy’s acreage in Dimmit, Webb, La Salle, Zavala and Maverick counties, Texas (such acreage is collectively referred to herein as “Sanchez Energy’s Comanche Asset”) pursuant to a new long-term firm gas gathering and processing agreement. The agreement with Sanchez Energy, which was approved by all of the unaffiliated Comanche non-operated working interest owners, establishes commercial terms for the gathering of gas on the Carnero Gathering Line and processing at the Raptor Gas Processing Facility and Silver Oak II. Prior to execution of the agreement, Comanche volumes were gathered and processed on an interruptible basis, with the processing capabilities of the joint ventures limited by the capacity of the 260 MMcf/d cryogenic natural gas processing plant in La Salle County, Texas (the “Raptor Gas Processing Facility.”)

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 upstream 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 a firm transportation service agreement with Sanchez Energy to transport certain quantities of Sanchez Energy’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 had an initial term of one month and renewed automatically on a month-to-month basis. On January 13, 2020, we received written notice of termination from Sanchez Energy terminating the Seco Pipeline Transportation Agreement effective February 12, 2020. During the year ended December 31, 2019, Sanchez Energy transported average daily production through Seco Pipeline of approximately 1.9 MMcf/d of natural gas. The Seco Pipeline has an expected life of approximately 40 years.

Title to Properties

Title to 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, 2019, were approximately 3.0 MMBoe, all of which were classified as proved developed, with 11% being natural gas, 14% being NGLs, and 75% being oil. At December 31, 2019, we owned approximately 44 net producing wells. Our total average proved reserve-to-production ratio is approximately 10 years and our portfolio decline rate is 12% based on our estimated proved reserves at December 31, 2019.

Below is a description of our operations and our oil and natural gas properties by basin at December 31, 2019:

Locations

Of our reserves, 99%  were located in the Eagle Ford Shale on non-operated properties. Production during the year ended December 31, 2019 on these properties was 306.1 MBoe and approximately 2,955.2 MBoe of estimated proved reserves were held at December 31, 2019. All of these reserves were classified as proved developed, with 11% being natural gas, 14% being NGLs, and 75% being oil.

The remaining reserves were located on non-operated properties in Louisiana. During the year ended December 31, 2019, production on Louisiana properties was 2.9 MBoe, and approximately 44.1 MBoe of estimated proved reserves were held at December 31, 2019, all of which were classified as proved developed with 100% being oil.

Operations

We do not currently operate any of our production assets. The Eagle Ford Shale properties are operated by either SOG, Sanchez Energy or Marathon Oil Company and the Louisiana properties are operated by SOG.

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.

Our 2019 estimates of total proved reserves decreased 0.5 MMBoe from 2018 due to production and revisions of previous estimates of 0.3 MMBoe and 0.2 MMBoe, respectively.

As of December 31, 2019, we had no remaining proved undeveloped reserves in our reserves base.

We expect to make minimal capital expenditures related to recompletion of existing wells during the year ending December 31, 2020.

At December 31, 2019 and December 31, 2018, Ryder Scott Co. LP (“Ryder Scott”), an independent oil and natural gas engineering firm, prepared estimates of all our proved reserves. We used these 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 petrophysicists exceeds 20 years, including five to 15 years with a major oil company. The engineering information presented in their 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 13 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 38 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 and approval by the Board.

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:

Existing Wells

The following table sets forth information at December 31, 2019, 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.

We did not convert any proved undeveloped wells into proved producing wells in 2019.

Drilling Activity 

With respect to oil and natural gas wells drilled and completed during the years ended December 31, 2019 and 2018, 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, 2019 or 2018. During the years ended December 31, 2019 and 2018, there were no wells drilled and there were no wells in progress. 

Developed and Undeveloped Acreage 

The following table sets forth information related to our leasehold acreage as of December 31, 2019.

Leases

Most of our reserves are comprised of wellbore rights only. We have a small lease position of less than 150 net acres in Louisiana.

Marketing and Major Customers

Our oil and natural gas production in Texas and Louisiana is marketed by the operators of our properties.

Sanchez Energy accounted for 86% and 71% of our total revenue for the years ended December 31, 2019 and 2018, respectively. We are highly dependent upon Sanchez Energy as our most significant customer, and we expect to derive a substantial portion of our revenue from Sanchez Energy in the foreseeable future. Accordingly, we are indirectly subject to the business risks of Sanchez Energy. Any development that materially and adversely affects Sanchez Energy’s operations or financial condition could have a material adverse impact on us. Additional information regarding our relationship with Sanchez Energy is provided in “Part III, Item 13. Certain Relationships and Related Transactions, and Manager Independence.” For additional information on the risks associated with our relationship with Sanchez Energy, please read “Part I, Item 1A. Risk Factors.”

Markets and Competition

We operate in a competitive environment for acquiring properties, marketing oil, NGLs 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 “Part III, 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:

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. With the approval of the federal Environmental Protection Agency (“EPA”), the individual states can administer some or all of the provisions of RCRA, and some states have adopted their own, more stringent requirements. Drilling fluid, produced water 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, can impose 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 can include the owners or operators 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, including response costs, alternative water supplies, damages to natural resources and 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. Each state also has environmental cleanup laws analogous to CERCLA.

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 practices, including the treatment and disposal or release of hazardous substances, wastes or hydrocarbons were 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 environmental harm.

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 of 1990 amended 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. The Oil Pollution Act imposes ongoing requirements on owners and operators of facilities that handle certain quantities of crude oil, including the preparation of oil spill response plans and proof of financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with a spill. 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 July 2018 completing the final designations. 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 GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, the EPA has used existing Clean Air Act authority to regulate GHGs. For example, the EPA has adopted rules requiring the reporting of GHG emissions from various oil and natural gas operations on an annual basis. In addition, in June 2016, the EPA published New Source Performance Standards (“NSPS”) Subpart

OOOOa standards that require new, modified or reconstructed facilities in the oil and natural gas sector to reduce methane gas and volatile organic compound emissions. However, in June 2017, the EPA published a proposed rule to stay portions of the Subpart OOOOa standards for two years. In September 2018, the EPA issued proposed revisions to the NSPS applicable to new and modified oil and gas sources, which would reduce the monitoring obligations for wells and compressor stations. Further in October 2018, the EPA issued a draft report which includes a template designed to assist with compliance. Until the rules are finalized, the implementation of the 2016 rules remains uncertain. A number of state and regional efforts have also emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions, such as electric power plants, to possess and acquire emission allowances which permit corresponding GHG emissions. Furthermore, the U.S. is currently a party to the Paris Agreement adopted in December 2015 to reduce global GHG emissions. However, in June 2017, President Trump announced that the United States plans to withdraw from the Paris Agreement in accordance with the Agreement’s four-year exit process and to seek negotiations either to reenter the Paris Agreement on different terms or establish a new framework agreement. In August 2017, the U.S. Department of State officially informed the United Nations of the intent of the United States to withdraw from the Paris Agreement and in November 2019 began the formal process of withdrawl.

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 released an Advanced Notice of Proposed Rulemaking seeking public comment on its plans to issue regulations under the Toxic Substances Control Act of 1976 to require companies to disclose information regarding chemicals used in hydraulic fracturing. 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 federal Endangered Species Act (“ESA”) was established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The U.S. Fish and Wildlife Service (“FWS”) may designate critical habitat and suitable habitat areas that it believes are necessary for the survival of a threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions and may materially delay or prohibit land access for development. Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia in September 2011, the FWS was required to make a determination on the listing of more than 250 species as endangered or threatened under the ESA by the end of the agency’s 2017 fiscal year. The designation of previously unprotected species as threatened or endangered in areas where we operate could cause us to incur increased costs arising from species protection measures or could result in limitations on our activities.

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 determine that an individual gathering system is not exempt from FERC regulation and the pipelines associated with such gathering system provide interstate transportation, the rates for, and terms and conditions of, services provided by such gathering system 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 results of operations and cash flows. 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 services, 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 gathering 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 daily civil penalties 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”) through the Pipelines and Hazardous Materials Safety Administration (“PHMSA”), pursuant to the Hazardous Liquid Pipeline Safety Act of 1979, as amended (“HLPSA”) and comparable state statutes with respect to design, installation, inspection, testing, construction, operation, replacement and maintenance of pipeline facilities. HLPSA, as amended, governs he design, installation, testing, construction, operation, replacement and management of crude oil pipeline facilities and also 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 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:

The HLPSA has been amended by the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (“2011 Pipeline Safety Act”) and the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (“2016 Pipeline Safety Act The 2011 Pipeline Safety Act increased the penalties for safety violations, established additional safety requirements for newly constructed pipelines and required studies of safety issues that could result in the adoption of new regulatory requirements by PHMSA for existing pipelines. The 2011 Pipeline Safety Act doubled the maximum administrative fines for safety violations from $100,000 to $200,000 for a single violation and from $1 million to $2 million for a related series of violations, but provided that these maximum penalty caps do not apply to certain civil enforcement actions. Effective April 27, 2017, to account for inflation, those maximum civil penalties were increased to $213,268 per day, with a maximum of $2,132,679 for a series of violations. The 2016 Pipeline Safety Act extended PHMSA’s statutory mandate through 2019. The 2016 Pipeline Safety Act also empowers PHMSA to address imminent hazards by imposing emergency restrictions, prohibitions and safety measures on owners and operators of hazardous liquid pipeline facilities without prior notice or an opportunity for a hearing. PHMSA issued interim regulations in October 2016 to implement the agency’s expanded authority to address unsafe pipeline conditions or practices that pose an imminent hazard to life, property, or the environment.

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 HCAs. 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. On October 1, 2019, PHMSA issued its final rule which will become effective July 1, 2020.  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, 2019, 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

We do not have any employees. 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, (ii) reimbursement for all allocated overhead costs, as well as any direct third-party costs incurred and (iii) for each asset acquisition, disposition or financing, a fee not to exceed 2% of the value of such transaction. 

As of March 13, 2020,  nine (9) employees were employed by SOG with their primary function being to provide services for us, all of which were full-time employees.

None of SOG’s employees are subject to a collective bargaining agreement.

Offices

Our principal executive offices are located at 1000 Main Street, Suite 3000, Houston, Texas 77002. Our telephone number is (713) 783-8000.

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 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.

Item 1A. Risk Factors 

Our business involves a high degree of risk. 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. You should consider and read carefully all of the risks and uncertainties described below, together with all of the other information contained in this Form 10‑K, including the financial statements and the related notes appearing at the end of this Form 10‑K. If any of the following risks, or any risk described elsewhere in this Form 10‑K, were to occur, our business, financial condition or results of operations could be adversely affected. If any of the following risks, or any risk described elsewhere in this Form 10‑K, were to occur, our business, financial condition or results of operations could be adversely affected. The risks below are not the only ones facing the Partnership. Additional risks not currently known to us or that we currently deem immaterial may also adversely affect us. This Form 10‑K also contains forward‑looking statements, estimates and projections that involve risks and uncertainties. Our actual results could differ materially from those anticipated in the forward‑looking statements as a result of specific factors, including the risks described below. Also, please read “Cautionary Note Regarding Forward-Looking Statements.”

The risk factors in this Form 10-K are grouped into the following categories:

Because the majority of our total revenue, including substantially all of our revenue stemming from the operation of our midstream business, is derived from Sanchez Energy, the filing of voluntary petitions for reorganization under Chapter 11 of the United States Bankruptcy Code by Sanchez Energy and certain of its subsidiaries could have a material and adverse impact on us.

Sanchez Energy accounted for approximately 86% of our total revenue and substantially all of our midstream business revenue for the year ended December 31, 2019. We are dependent on Sanchez Energy as our only current customer for utilization of Western Catarina Midstream, and as our primary customer for utilization of our other midstream assets. We expect that a majority of revenues relating to these assets will be derived from Sanchez Energy for the foreseeable future.  

On August 11, 2019, Sanchez Energy Corporation and certain of its subsidiaries filed voluntary petitions for reorganization under Chapter 11 of the United States Bankruptcy code in the United States Bankruptcy Court for the Southern District of Texas, Houston Division, jointly administered Case No. 19-34508 (the “Sanchez Energy Chapter 11 Case”). As a result, we are subject to an increased risk of non-payment, non-performance and/or underutilization of our midstream assets by Sanchez Energy. While Sanchez Energy Corporation has stated it intends to continue to operate in the normal course and intends to interact with its commercial counterparties as usual, no assurances can be given as to the timing or outcome of the bankruptcy process. Through December 31, 2019, we did not experience any significant losses as a result of non-performance. However, as disclosed herein, Sanchez Energy terminated the Seco Pipeline Transportation

Agreement effective on February 12, 2020. Any development that materially and adversely affects Sanchez Energy’s operations or financial condition could have a material and adverse impact on us.

On March 13, 2020, the official committee of unsecured creditors in the Sanchez Energy Chapter 11 Case (the “Unsecured Committee”) filed a motion titled Motion of the Official Committee of Unsecured Creditors for Leave, Standing, and Authority to Prosecute Claims on Behalf of the Debtors’ Estate and for Related Relief (the “March 13 Motion”). The relief sought in the March 13 Motion is to grant the Unsecured Committee derivative standing to prosecute claims that Sanchez Energy allegedly has against the Partnership and others, including, but not limited to, claims to recharacterize or avoid the Catarina Transaction, the Carnero Gathering Transaction (as defined in Note 12 “Investments” of our Notes to Consolidated Financial Statements), and the Carnero Processing Transaction (as defined in Note 12 “Investments” of our Notes to Consolidated Financial Statements). While we do not believe these claims have any merit, if such claims are filed and prosecuted, the cost to defend against such claims and any judgment entered against us could have a material and adverse impact on our business, financial condition and operating results.

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 Sanchez Energy’s 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:

Under the terms of the lease covering Sanchez Energy’s Catarina Asset, 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). The pending Sanchez Energy Chapter 11 Case has resulted in significant delays to the drilling program on Sanchez Energy’s properties, including Sanchez Energy’s Catarina

Asset, and failure to drill the required number of wells could result in forfeiture of acreage not held by production during the current fiscal year. In addition, Sanchez has various drilling obligations under the leases covering Sanchez Energy’s Comanche Asset. If Sanchez Energy fails to meet these drilling obligations, Sanchez Energy could forfeit its acreage under the applicable 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. Declines in commodity prices could have a negative impact on Sanchez Energy’s development and production activity, and if sustained, could lead Sanchez Energy to materially reduce its drilling and completion activities. 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 flows and adversely affect our ability to pay cash distributions to Stonepeak Catarina Holdings LLC (“Stonepeak Catarina”), as the holder of all of our Class C preferred units representing limited partner interests (the “Class C Preferred Units”). Restrictions under our Credit Agreement and our partnership agreement currently prohibit us from paying distributions to our common unitholders.

The Gathering Agreement contains provisions that can reduce the stability in cash flows 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 and NGLs 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 (or through 2020). In addition, the Gathering Agreement also includes a minimum quarterly quantity, which is a total amount of natural gas and NGLs 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. Through December 31, 2019, natural gas volumes from Sanchez Energy have shortened the primary terms of the volume commitments by 197 days, while the minimum oil volume commitment is no longer in effect. 

Under certain circumstances, it is possible that the combined effect of the minimum volume commitment provisions could result in our receiving substantially reduced revenues or cash flows from Sanchez Energy in a given period. In the most extreme circumstances:

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 pay cash distributions to Stonepeak Catarina as the holder of all of our Class C Preferred Units.

Interruptions in operations at our facilities or facilities that Targa operates on behalf of the Carnero JV may adversely affect operations and cash flows available for distribution to Stonepeak Catarina.

Any significant interruption at any of our facilities or the facilities that Targa operates on behalf of the Carnero JV, or in our ability or Targa’s ability on behalf of the Carnero JV, as applicable, to gather, treat or process natural gas, NGLs and oil, would adversely affect operations and cash available for distribution to Stonepeak Catarina as the holder of all of our Class C Preferred Units. Operations at impacted facilities could be partially or completely shut down, temporarily or permanently, as the result of circumstances not within our control, such as:

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.

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 the 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.

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 pay cash distributions to Stonepeak Catarina as the holder of all of our Class C Preferred Units.

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. Decreased levels of production and shrinking margins from lower commodity prices may result in shortages of equipment and skilled labor in the Eagle Ford Shale, as companies seek to deploy their resources in more profitable basins. 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.

Distributions we receive from the Carnero JV may fluctuate from quarter to quarter as Targa, the operator, has certain discretion over the amount and timing of distributions, which could adversely affect our ability to pay cash distributions.

We received approximately $17.2 million in cash from the Carnero JV in the form of distributions during the year ended December 31, 2019. Targa, as the operator of the Carnero JV, has certain rights which permit it to affect the amount and timing of distributions to us. For example, Targa has certain discretion with regard to cash reserves and working capital adjustments that may cause the amount of our distributions to fluctuate from quarter-to-quarter. Fluctuations in the amount and timing of distributions from the Carnero JV could adversely affect our ability to pay cash distributions to Stonepeak Catarina as the holder of all of our Class C Preferred Units.

Our participation in joint ventures exposes us to liability or harm to our reputation resulting from failures by our partner.

In May 2018, we executed a series of agreements with Targa and other parties pursuant to which, among other things: (1) the parties merged their respective 50% interests in Carnero Gathering and Carnero Processing to form an expanded 50 / 50 joint venture in South Texas, Carnero JV, (2) Targa contributed 100% of the equity interest in Silver Oak II to Carnero JV, which expanded the processing capacity of the joint venture from 260 MMcf/d to 460 MMcf/d, (3) Targa contributed certain capacity in the Carnero Gathering Line to Carnero JV resulting in the joint venture owning all of the capacity in the Carnero Gathering Line, which has a design limit (without compression) of 400 MMcf/d, and (4) Carnero JV received a new dedication from Sanchez Energy and its working interest partners of over 315,000 acres located in the Western Eagle Ford on Sanchez Energy’s Comanche Asset pursuant to a new long-term firm gas gathering and processing agreement. We and Targa are jointly and severally liable for all liabilities and obligations of the Carnero JV. 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.

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 prior to and 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 Stonepeak Catarina as the holder of all of our Class C Preferred Units.

If third-party pipelines or other midstream facilities interconnected to our facilities become partially or fully unavailable, our operating margin, cash flows and ability to pay cash distributions 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 flows and ability to pay cash distributions to Stonepeak Catarina as the holder of all of our Class C Preferred Units could be adversely affected.

We do not own the land on which Western Catarina Midstream or the Seco Pipeline is located, which could result in disruptions to our operations.

We do not own the land on which Western Catarina Midstream or the Seco Pipeline is located, 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 or the Seco Pipeline. 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 pay cash distributions to Stonepeak Catarina as the holder of all of our Class C Preferred Units.

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 a right-of-first-offer, Sanchez Energy has agreed to offer us the right to purchase midstream assets that it desires to transfer to any unaffiliated person through 2030. 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. Furthermore, for a variety of reasons, we may decide not to exercise this right when it becomes available.

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-of-first-offer.

Our operations could be disrupted if our or SOG’s information systems are hacked or fail, causing increased expenses and loss of revenue.  

We face various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data systems unusable, threats to the security of our facilities and infrastructure, Sanchez Energy’s facilities and infrastructure or other third-party facilities and infrastructure, such as pipelines. The potential for such security threats has subjected our operations to increased risks that could have a material adverse effect on our business.

Our business is increasingly dependent on technology infrastructure, certain critical financial, accounting and other data processing systems and other communications and information systems, including such systems of SOG that we utilize pursuant to the Services Agreement. These systems include data network and telecommunications, internet access, our website, and various computer hardware equipment and software applications, including those that are critical to the safe operations of our assets. We process transactions on a daily basis and rely upon the proper functioning of computer systems. These systems are subject to damage or interruption from a number of potential sources including natural disasters, software viruses or other malware, power failures, cybersecurity threats to gain unauthorized access to sensitive information, cyber-attacks, which may render data systems unusable, and physical threats to the security of our and SOG’s facilities and infrastructure or third-party facilities and infrastructure. If a key system were hacked or otherwise interfered with by an unauthorized access, or were to fail or experience unscheduled downtime for any reason, even if only for a short period, our financial results could be affected adversely.

Additionally, we rely on information systems across our operations, including the management of processes and transactions. A material disruption to any information systems at our operating locations, or at Sanchez Energy’s or another third-party’s pipelines, terminals or operating locations, may cause disruptions to our operations.

Cyber-attacks against us or others in our industry could result in additional regulations, and U.S. government warnings have indicated that infrastructure assets, including pipelines, may be specifically targeted by certain groups. These attacks include, without limitation, malicious software, ransomware, attempts to gain unauthorized access to data, and other electronic security breaches. These attacks may be perpetrated by state-sponsored groups, “hacktivists”, criminal organizations or private individuals (including employee malfeasance). Current efforts by the federal government and any potential future regulations could lead to increased regulatory compliance costs, insurance coverage cost or capital expenditures. We cannot predict the potential impact to our business or the energy industry resulting from additional regulations.

Further, our business interruption insurance may not compensate us adequately for losses that may occur. We do not carry insurance specifically for cybersecurity events; however, certain of our insurance policies may allow for coverage

of associated damages resulting from such events. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our financial position, results or operations and cash flows. In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient if such an event were to occur.

Market conditions for natural gas, NGLs and oil are highly volatile. A sustained decline in prices for these commodities could adversely affect our revenue, cash flows, profitability and growth.

Prices for natural gas, NGLs and oil fluctuate widely in response to a variety of factors that are beyond our control, such as:

Given that natural gas, NGLs and oil are global commodities, prices can also be significantly influenced by developments in other countries and markets, particularly in key consumption markets like China. For example, the ongoing coronavirus outbreak in China and other locations across the globe has resulted in a meaningful drop in the demand for crude oil and other petroleum products. Ultimately this can lead to a reduction in demand for the services we provide.

Governmental actions may also affect prices for natural gas, NGLs and oil. In the past, prices for natural gas, NGLs and oil have been extremely volatile, and we expect this volatility to continue. NYMEX WTI 12 month strip price for

crude oil was down more than ten percent at the end of fiscal 2019 and the NYMEX Henry Hub 12 month natural gas strip price was down approximately eight percent at the end of fiscal 2019, each when compared with fiscal 2018. Such downward volatility has negatively affected the amount of our net estimated proved reserves and has negatively affected the standardized measure of discounted future net cash flows of our net estimated proved reserves. For the years ended December 31, 2019 and 2018, we did not record impairment on our oil and natural gas properties.

In addition, our revenue, profitability and cash flows depend upon the prices of and demand for natural gas, NGLs and oil, and continued price volatility and low commodity prices, or a sustained drop in prices could negatively affect our financial results and impede our growth. In particular, sustained declines in commodity prices will:

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 cash distributions.

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:

Any of these events can increase 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:

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:

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 cash distributions to Stonepeak Catarina as the holder of all of our Class C Preferred Units.

Future price declines or downward reserve revisions may result in 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 our ability to

borrow funds under our Credit Agreement, which in turn may adversely affect our ability to pay cash distributions to Stonepeak Catarina as the holder of all of our Class C Preferred Units.

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 Texas and Louisiana 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 cash 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 cash distributions to Stonepeak Catarina as the holder of all of our Class C Preferred Units.

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:

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 cash distributions.

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, results of operations and our ability to pay cash distributions to Stonepeak Catarina as the holder of all of our Class C Preferred Units.

Risks Related to Our Midstream and Production Businesses

As a non-operator, our development of successful operations relies extensively on third-parties, including SOG, Sanchez Energy and Targa, which could adversely affect our business, financial condition and results of operations.

We have only participated in wells, leasehold acreage and midstream assets operated by third parties, including SOG, Sanchez Energy and Targa. The success of our business operations depends on the success of such operators. If our operators are not successful in the development, exploitation, production and operating activities relating to our midstream and production businesses, or are unable or unwilling to perform, it could adversely affect our business, financial condition and results of operations.

The insolvency of an operator of any of our properties or assets, the failure of an operator of any of our properties or assets to adequately perform operations or an operator’s breach of applicable agreements could reduce our production and revenue and result in our liability to governmental authorities for compliance with environmental, safety and other regulatory requirements, to the operator’s suppliers and vendors and to royalty owners under oil and gas leases jointly owned with the operator or another insolvent owner.

Our operators will make decisions in connection with their operations (subject to their contractual and legal obligations), which may not be in our best interests and could have a material adverse effect on our business, financial condition and results of operations.

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 (as defined below) 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:

The Credit Agreement will mature on September 30, 2021. 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 4.5. 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 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 September 30, 2021. 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.

Changes in LIBOR reporting practices or the method in which LIBOR is determined may adversely affect the market value of our current or future debt obligations, including obligations under our Credit Agreement.

As of March 13, 2020, we had approximately $144.0 million of debt outstanding under our Credit Agreement that bears interest at variable rates that use the London Interbank Offered Rate (“LIBOR”), as a benchmark rate. On July 27, 2017, the Financial Conduct Authority (the “FCA”), which regulates LIBOR, announced that it intends to stop persuading or compelling banks to submit LIBOR quotations after 2021. It is unclear whether LIBOR will cease to exist or if new methods of calculating LIBOR will be established such that it continues to exist after 2021, or whether any alternative benchmark rate will attain market acceptance as a replacement for LIBOR. It is not possible to predict the further effect of the rules of the FCA, any changes in the methods by which LIBOR is determined or any other reforms to LIBOR that may be enacted in the United Kingdom, the European Union or elsewhere. Any such developments may cause LIBOR to perform differently than in the past, or cease to exist. In addition, any other legal or regulatory changes made by the FCA, the European Commission or any other successor governance or oversight body, or future changes adopted by such body, in the method by which LIBOR is determined or the change from LIBOR to an alternative benchmark rate may result in, among other things, a sudden or prolonged increase or decrease in LIBOR, a delay in the publication of LIBOR, and changes in the rules or methodologies in LIBOR, which may discourage market participants from continuing to administer

or to participate in LIBOR’s determination, and, in certain situations, could result in LIBOR no longer being determined and published.

Under our Credit Agreement, if (a) the administrative agent determines that reasonable means do not exist for ascertaining LIBOR and such circumstances are unlikely to be temporary, (b) the supervisor for the administrator of LIBOR or another governmental authority having jurisdiction over the administrative agent has made a public statement identifying a date after which LIBOR shall no longer be used, or (c) new syndicated loans have started to adopt a new benchmark interest rate, then we will be required to negotiate an amendment to our Credit Agreement with the administrative agent. The use of the alternative benchmark interest rate under any such amendment may result in interest obligations which are more than or do not otherwise correlate over time with the payments that would have been made on such debt if LIBOR was available in its current form. Further, the same costs and risks that may lead to the discontinuation or unavailability of LIBOR may make one or more of the alternative methods impossible or impracticable to determine. At this time, it is not possible to predict the effect of any establishment of any alternative benchmark rate(s) and we cannot predict what alternative benchmark rate(s) will be utilized. Any new benchmark rate will likely not replicate LIBOR exactly, and any changes to benchmark rates may have an uncertain impact on our cost of funds under our Credit Agreement. Any of these proposals or consequences could have a material adverse effect on our financing costs.

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 pay 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 which may diminish our ability to pay cash distributions to Stonepeak Catarina as the holder of all of our Class C Preferred Units. 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. 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 implement restrictions or limitations on our ability to pay cash distributions. For example, our Credit Agreement currently prohibits us from making distributions to our common 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 make or maintain cash distributions to our unitholders in the future, if any, which could materially decrease our ability to pay cash distributions. 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.

Our Credit Agreement restricts us from paying any distributions on our outstanding common units.

We do not have the ability to pay distributions to our common unitholders under our Credit Agreement other than in certain limited circumstances set forth in the Credit Agreement. We have obtained waivers of Credit Agreement limitations in the past and may need to do so in the future.

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 cash distributions.

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 cash 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. For example, our largest customer, Sanchez Energy Corporation, who accounted for 86% and 71% of total revenue for the years ended December 31, 2019 and 2018, respectfully, along with certain of its subsidiaries filed the Sanchez Energy Chapter 11 Case in August of 2019. 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 cash distributions to Stonepeak Catarina as the holder of all of our Class C Preferred Units.

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:

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 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 expected production volumes for 2020, 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 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, and ability to pay cash distributions to Stonepeak Catarina as the holder of all of our Class C Preferred 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 cash distributions to Stonepeak Catarina as the holder of all of our Class C Preferred Units.

Risks Related to Our Cash Distributions

Our partnership agreement prohibits us from making certain distributions until all of the Class C Preferred Units are redeemed and, as a result, our ability to make, maintain and grow cash distributions is dependent on our ability to redeem the Class C Preferred Units.

Under the terms of our partnership agreement, until the first quarter in which no Class C Preferred Units remain outstanding, we are not permitted to declare or make any distributions, redemptions or repurchases in respect of, among other partnership interests, our common units. Beginning January 1, 2021, our partnership agreement provides us with the ability to redeem the Class C Preferred Units without a premium to the liquidation preference of the Class C Preferred Units. If we are unable to access the capital markets on favorable terms or otherwise secure debt or equity financing to redeem the Class C Preferred Units, our ability to redeem the Class C Preferred Units and then to make, maintain and grow cash distributions to unitholders will be materially adversely affected.

Our Credit Agreement restricts us from paying any distributions on our outstanding common units.

We do not have the ability to pay distributions to our common unitholders under our Credit Agreement other than in certain limited circumstances set forth in the Credit Agreement.

If we do not complete expansion projects or make and integrate acquisitions, our future growth may be limited.

Our ability to enhance our financial position depends, in part, 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:

We may not have sufficient available cash from operations to pay our quarterly cash distributions to Stonepeak Catarina 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 and principally depends upon the amount of cash that we generate from our operations, which

will fluctuate from quarter to quarter based on numerous factors described in this Form 10-K, including this Item 1A.“Risk Factors.” These and other factors that affect that amount that we can distribute include:

As a result of these factors, we may not have sufficient available cash to pay a quarterly cash distribution to Stonepeak Catarina as the holder of all of our Class C Preferred Units. 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.

The amount of cash that we may have available for distribution depends primarily upon our operating cash flows and not solely on our profitability.

The amount of cash that we have available for distribution depends primarily upon 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 cash distributions to Stonepeak Catarina as the holder of all of our Class C Preferred Units even when we record net income, and we may pay cash 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 cash 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:

In the past, the prices of oil and natural gas have been extremely volatile, and we expect this volatility to continue.

Our operations require capital expenditures, which will reduce the amount of cash that we may have available for distribution to Stonepeak Catarina as the holder of all of our Class C Preferred Units.

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:

Our capital expenditures will vary from quarter to quarter and will reduce the amount of cash that we may have available for distribution to Stonepeak Catarina as the holder of all of our Class C Preferred Units.

Each quarter we are required to deduct estimated maintenance capital expenditures from operating surplus, which may result in less cash available for distribution 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 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 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. 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 cash distributions to Stonepeak Catarina as the holder of all of our Class C Preferred Units.

Our hedging activities could result in financial losses and involve other risks, which may adversely affect our ability to pay cash 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 2020. 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:

As a result of the Dodd-Frank Wall Street Reform and Consumer Protection Act and other legislation, hedging transactions and many of our contract counterparties have come under increasing governmental oversight and regulations in recent years. Although we cannot predict the ultimate impact of these laws or other proposed laws and the related rulemaking, some of which is ongoing, existing or future regulations may adversely affect the cost and availability of our hedging arrangements, including by causing our counterparties, which include lenders under our Credit Agreement, to curtail or cease their derivative activities.

Acquisitions involve potential risks that could adversely impact our future growth and our ability to pay cash distributions.

Any acquisition involves potential risks, including, among other things:

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 cash distributions to Stonepeak Catarina as the holder of all of our Class C Preferred Units.

Inadequate insurance could have a material adverse impact on our business, financial condition and results of operations.

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 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 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 cash distributions to Stonepeak Catarina as the holder of all of our Class C Preferred Units 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.

We 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, the operators of our facilities and properties or other third parties.  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:

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 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:

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

If at any time our general partner and its controlled affiliates hold more than 80% of any class of outstanding limited partner interests, then our general partner will have the right, which it may assign or transfer in whole or in part to any of its controlled affiliates or to us, but not the obligation to acquire all, but not less than all, of such class of limited partner interests held by unaffiliated persons at a price equal to the greater of (1) the average of the daily closing price of our common units over the 20 trading days preceding the date three days before notice of exercise of the limited call right is first mailed and (2) the highest per-unit price paid by our general partner or any of its controlled affiliates for common units during the 90-day period preceding the date such notice is first mailed.  As a result, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return or a negative return on their investment. Unitholders may also incur tax liability upon a sale of their units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the limited call right. There is no restriction in our partnership agreement that prevents our general partner from causing us to issue additional common units and then exercising its limited call right.

If our general partner exercised its limited call right, the effect would be to take us private and, if the units were subsequently deregistered, we would no longer be subject to the reporting requirements of the Exchange Act.

The standstill in the Board Representation and Standstill Agreement among us, our general partner and Stonepeak Catarina will expire upon the earlier of the occurrence of a material breach of our partnership agreement and the date of which all Class C Preferred Units have been redeemed.

In connection with our August 2019 issuance of Class C Preferred Units to Stonepeak Catarina, an affiliate of Stonepeak Infrastructure Partners (“Stonepeak”), we entered into that certain Amended and Restated Board Representation and Standstill Agreement (the “Representation and Standstill Agreement”), among us, our general partner and Stonepeak Catarina.  The Representation and Standstill Agreement includes a standstill provision pursuant to which Stonepeak Catarina, as the holder of all of our outstanding Class C Preferred Units, agreed that it and its affiliates would refrain from, among other things: (i) acquiring beneficial ownership of additional common units, Class C Preferred Units or other Partnership Interests (as defined in our partnership agreement); (ii) acquiring any debt or assets us or of our subsidiaries; (iii) engaging in any hostile takeover activities with respect to us or our general partner, including any merger, consolidation, recapitalization, business combination, partnership, joint venture, acquisition or similar transaction involving us or our general partner or any of our respective affiliates or properties (excluding Sanchez Energy and its properties); (iv) entering into any transaction the effect of which would be to “short” any of our securities; (v) forming, jointing or participating in any “group” (within the meaning of Section 13(d) of the Exchange Act) with respect to any voting securities of us or our affiliates in respect of any action otherwise prohibited pursuant to the standstill; (vi) calling (or participation in the calling of) a meeting of our partner for the purpose of removing (or approving the removal of) of Sanchez Midstream Partners GP LLC as our general partner and/or electing a successor general partner; (vii) “soliciting” any “proxies” (as such terms are used in the rules and regulation of the SEC) or voting for or in support of (A) the removal of Sanchez Midstream Partners GP LLC as our general partner or (B) the election of any successor general partner, or taking any action the direct effect or purpose of which would be to induce our partners to vote or provide proxies that may be voted in favor of any action contemplated by either of (A) or (B) of this subsection; (viii) seeking to advise of influence any person (within the meaning of Section 13(d)(3) if the Exchange Act) with respect to the voting of any Partnership Interest in connection with the removal (or approving the removal) of Sanchez Midstream Partners GP LLC as our general partner and/or the election of a successor general partner; (ix) issuing, inducing or assisting in the publication of any press release, media report or other publication in connection with the potential or proposed removal of Sanchez Midstream Partners GP LLC as our general partner and/or the election of a successor general partner for the Partnership; (x) advising, assisting or encouraging any third party to do any of the foregoing; or (xi) if Sanchez Midstream Partners GP LLC is removed as our general partner in violation of our partnership agreement, then participating in any way in the management, ownership and/or control of the successor general partner or the successor general partner’s operation of us, other than participation by directors designated to the Board by Stonepeak Catarina in connection with the fulfillment of their duties as directors. 

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:

Our partnership agreement replaces our general partner’s fiduciary duties to our common unitholders 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:

Our partnership agreement restricts the remedies available to our common unitholders 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:

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 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 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 to the fullest extent permitted by applicable law 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 our partnership agreement, which includes 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 the Board. Rather, the Board 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, Stonepeak Catarina, their transferees and persons who acquired such units with the prior approval of the Board, cannot vote on any matter.

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 directors and officers of our general partner in order to control the decisions taken by the Board or such 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.

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:

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 currently 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:

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 the Board 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 as determined for U.S. federal income tax purposes), and no income, gains, losses, deductions or credits recognized by us 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 cash flows 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. In addition, the Treasury Department has issued, and in the future may issue, regulations interpreting those laws that affect publicly traded partnerships. We believe the income that we treat as qualifying satisfies the requirements under current regulations. However, there can be no assurance that there will not be further changes to U.S. federal income tax laws or the Treasury Department’s interpretation of the qualifying income rules in a manner that could impact our ability to qualify as a partnership for U.S. federal income tax purposes in the future.

We are unable to predict whether legislation or other tax-related 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 for certain publicly traded partnerships to be treated as a partnership for U.S. federal income tax purposes. Any such change 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 Credit Agreement and partnership agreement currently prohibit us from paying distributions to our common unitholders. As a result, for the foreseeable future our common unitholders will 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 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 and thus will be borne indirectly by our unitholders.

Pursuant to legislation applicable for partnership tax years beginning after 2017 if the IRS makes audit adjustments to our partnership tax returns, it may assess and collect any taxes (including any applicable penalties or interest) resulting from such audit adjustments directly from us. To the extent possible under these 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 current and former unitholder with respect to an audited and adjusted partnership tax return. Although our general partner may elect to have our current 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 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 its 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 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.

Our ability to deduct business interest expense is limited for U.S. federal income tax purposes to an amount equal to the sum of 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 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.

The Internal Revenue Code 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 suspended by the IRS until regulations or other guidance have been issued. It is not clear when or if such regulations or guidance will be 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. 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. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We prorate our items of income, gain, loss and deduction between transferors and transferees of 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 Treasury regulations allow publicly traded partnerships to use a similar monthly simplifying convention, these regulations do not specifically authorize all aspects of our proration method.  If the IRS were to successfully challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

A unitholder whose common units are the subject of a securities loan (e.g., a loan 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. 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 loaning 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 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, character 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.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties 

A description of our properties is included in “Part I, Item 1. Business,” and is incorporated herein by reference.

The obligations under our Credit Agreement are secured by mortgages on substantially all of our assets. See “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Agreement,” in this Form 10-K for additional information concerning our Credit Agreement.

Item 3. Legal Proceedings 

From time to time we may be the subject of lawsuits and claims arising in the ordinary course of business. Management cannot predict the ultimate outcome of such lawsuits or claims. Management does not currently expect the outcome of any of the known claims or proceedings to individually or in the aggregate have a material adverse effect on our results of operations or financial condition.

To date, no claims relating to the Sanchez Energy Chapter 11 Case have been filed against us. However, on March 13, 2020, the Unsecured Committee filed the March 13 Motion. The relief sought in the March 13 Motion is to grant the Unsecured Committee derivative standing to prosecute claims that Sanchez Energy allegedly has against the Partnership and others, including, but not limited to, claims to recharacterize or avoid the Catarina Transaction, the Carnero Gathering Transaction and the Carnero Processing Transaction. While we do not believe these claims have any merit, if such claims are filed and prosecuted, the cost to defend against such claims and any judgment entered against us could have a material and adverse impact on our business, financial condition and operating results. For additional information about the Sanchez Energy Chapter 11 Case please see https://cases.primeclerk.com/sanchezenergy and dm.epiq11.com/case/sanchez/info.  Information contained on these websites, however, is not incorporated into or otherwise a part of this Form 10-K.

Item 4. Mine Safety Disclosures

Not applicable.

PART II 

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

Our common units are listed on the NYSE American under the symbol “SNMP.”

Holders

The number of unitholders of record of our common units was approximately 53 on March 13, 2020, which does not include beneficial owners whose shares are held by a clearing agency, such as a broker or a bank.

Distributions

Rationale for Our Cash Distribution Policy

Our partnership agreement requires us to distribute all of our available cash quarterly.  Our cash distribution policy reflects a fundamental judgment that our unitholders generally will be better served by our distributing rather than retaining our available cash. However, other than the requirement in our partnership agreement to distribute all of our available cash each quarter, we have no legal obligation to make quarterly cash distributions in any amount, and our general partner has considerable discretion to determine the amount of our available cash each quarter.  Our partnership agreement generally defines “available cash” as cash on hand at the end of a quarter after the payment of expenses, less the amount of cash reserves established by our general partner to provide for the conduct of our business and to comply with applicable law, any of our debt instruments or other agreements or to provide for future distributions to our unitholders for any one or more of the next four quarters.  Our available cash may also include, if our general partner so determines, all or any portion of the cash on hand immediately prior to the date of distribution of available cash for the quarter resulting from working capital borrowings made subsequent to the end of such quarter.  Because we are not subject to an entity-level federal income tax, we expect to have more cash to distribute to our unitholders than would be the case if we were subject to entity-level federal income tax.  If we do not generate sufficient available cash from our operations, we may, but are under no obligation to, borrow funds to pay distributions to our unitholders.

Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy

There is no guarantee that we will make quarterly cash distributions to our unitholders. We do not have a legal or contractual obligation to pay quarterly distributions or any other distributions except as provided in our partnership agreement.  Our cash distribution policy may be changed at any time and is subject to certain restrictions and uncertainties, including the following:

General Partner Interest

Our general partner owns a non-economic general partner interest in us, which does not entitle it to receive cash distributions. However, our general partner may in the future own common units or other equity interests in us and will be entitled to receive distributions on any such interests.

Incentive Distribution Rights

All of the incentive distribution rights are held by Manager.  Incentive distribution rights represent the right to receive increasing percentages (13%, 23% and 35.5%) of quarterly distributions from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved.

For any quarter in which we have distributed cash from operating surplus to our common unitholders in an amount equal to the minimum distribution and distributed cash from surplus to the outstanding common units to eliminate any cumulative arrearages in payment of the minimum quarterly distribution, then we will distribute any additional cash from operating surplus for that quarter among the unitholders and the incentive distribution rights holders in the following manner: