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, 2016

OR

☐

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

Sanchez Production Partners LP

(Exact Name of Registrant as Specified in Its Charter)

 

Telephone Number: (713) 783-8000

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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post such files).    Yes  ☒    No  ☐ 

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

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

 

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

Aggregate market value of Sanchez Production Partners LP Common Units, without par value, held by non-affiliates as of June 30, 2016 was approximately $40,730,955 based upon NYSE MKT closing price.

 

Common Units outstanding on March 23, 2017: 14,153,061 common units.

 

 

 

TABLE OF CONTENTS

 

 

 

 

 

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K contains “forward-looking statements” as defined by the Securities and Exchange Commission (“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;

acquisition strategy;

financing strategy;

ability to make, maintain and grow distributions;

the ability of our customers to meet their drilling and development plans on a timely basis or at all and perform under gathering and processing agreements;

future operating results;

future capital expenditures; and

plans, objectives, expectations, forecasts, outlook and intentions.

All of these types of statements, other than statements of historical fact included in this Annual Report on Form 10-K, are forward-looking statements. 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 Annual Report on Form 10-K are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe that 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. Management cautions all readers that the forward-looking statements contained in this Annual Report on 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 the forward-looking statements due to factors listed in the “Risk Factors” section and elsewhere in this Annual Report on Form 10-K. 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.

 

 

 

COMMONLY USED DEFINED TERMS

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

“Sanchez Production Partners,” “the Partnership,” “we,” “us,” “our” or like terms refer collectively to Sanchez Production Partners LP, its consolidated subsidiaries and, where the context provides, the entities in which we have a 50% ownership interest.  Such terms also refer to Sanchez Production Partners LLC, our predecessor-in-interest prior to our conversion from a limited liability company to a limited partnership.

“Bbl” means a barrel of 42 U.S. gallons of oil.

“Bcf” means one billion cubic feet of natural gas.

“Boe” means one barrel of oil equivalent, calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Bbl of oil.

“Boe/d” means one Boe per day.

“Manager” refers to SP Holdings, LLC.

“MBbl” means one thousand barrels of crude oil or other liquid hydrocarbons.

“MBbl/d” means one thousand barrels of crude oil or other liquid hydrocarbons per day. 

“MBoe” means one thousand Boe.

“Mcf” means one thousand cubic feet of natural gas.

“MMBbl” means one million barrels of crude oil or other liquid hydrocarbons.

“MMBoe” means one million Boe.

“MMBtu” means one million British thermal units.

“MMcf” means one million cubic feet of natural gas. 

“MMcf/d” means one million cubic feet of natural gas per day.

“NGLs” means natural gas liquids.

“our general partner” refers to Sanchez Production Partners GP LLC, our general partner.

“Sanchez Energy” refers to Sanchez Energy Corporation (NYSE: SN) and its consolidated subsidiaries.

“SOG” refers to Sanchez Oil & Gas Corporation, an entity that provides operational support to us.

“SP Holdings” refers to SP Holdings, LLC, the sole member of our general partner.

 

PART I

Overview

We were formed in 2005 as a Delaware limited liability company until our conversion in 2015 into a Delaware limited partnership.  We are focused on the acquisition, development, ownership and operation of midstream and other

production assets in North America.  We currently own a gathering system in the Eagle Ford Shale (the “Western Catarina gathering system”), a 50% interest in a gathering system that connects to the Western Catarina gathering system, a 50% interest in a cryogenic natural gas processing plant, reversionary working interests and other production assets in Texas, Louisiana, Oklahoma and Kansas.  

We have entered into a shared services agreement (the “Services Agreement”) with Manager pursuant to which Manager provides services that we require to operate our business, including overhead, technical, administrative, marketing, accounting, operational, information systems, financial, compliance, insurance, professionals and acquisition, disposition and financing services. 

Our common units are currently listed on the NYSE MKT under the symbol “SPP.”

Our Relationship with Sanchez Energy, Manager and SOG

We believe that our relationship with Sanchez Energy provides us with a strategic advantage and will continue to provide us with significant growth opportunities. As of March 23, 2017, Sanchez Energy owns approximately 17% of our outstanding common units.  Since March 2015, we have completed three midstream asset acquisitions and two working interest acquisitions from Sanchez Energy.  Pursuant to a right-of-first-offer, Sanchez Energy has agreed to offer us the right to acquire any midstream assets that it desires to sell.  However, Sanchez Energy is under no obligation to sell any assets to us or to accept any offer for its assets that we may choose to make.

We have a shared services agreement in place with Manager, which in turn has a shared services agreement in place with SOG.  SOG also has a shared services agreement in place with Sanchez Energy.  We believe that our relationships with Manager and SOG provide us with competitive advantages, including a cost-efficient means of operating our assets.  Manager is the sole member of our general partner and has an interest in us through its ownership of all of our incentive distribution rights.  Manager and SOG provide services that we require to operate our business, including overhead, technical, administrative, marketing, accounting, operational, information systems, financial, compliance, insurance, acquisition, disposition and financing services.  SOG has a senior management team that averages over 20 years of industry experience and employs over 200 full-time employees, including approximately 50 technical staff and engineers.  SOG also provides us a dedicated business development team that screens approximately 150 acquisition opportunities per year.  SOG was formed in 1972 and has drilled or participated in over 3,000 wells, directly and through joint ventures, and has successfully built and operated extensive midstream and gathering assets associated with its exploration and production assets.  Since Sanchez Energy’s initial public offering in December 2011, SOG has been responsible for executing on approximately $2.2 billion in total drilling and completion budgets and has assisted in closing approximately $3.4 billion in acquisitions.  Since its inception, SOG has cultivated relationships with mineral and surface rights owners in and around South Texas and other oil and natural gas basins in North America and has compiled an extensive technological database, including more than 8,500 square miles of 3D seismic data, more than 450,000 well logs, greater than 15,000 wells of electronic documents, as well as a fully integrated suite of the latest interpretive geological software.  We plan on leveraging SOG’s extensive expertise and experience to execute on our business strategies.  While we believe that our relationships with Sanchez Energy, Manager and SOG are a significant strength, they are also a source of potential risks and conflicts.  Please read “Item 1A.  Risk Factors.”

Business Strategy

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

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

Business Segments

Our business activities are conducted by two operating segments for which we provide information in our consolidated financial statements for the years ended December 31, 2016 and 2015.  These two segments are our:

midstream business, which includes the Western Catarina gathering system and our ownership interests in Carnero Processing and Carnero Gathering; and

production business, which includes oil and natural gas reserves located in the Eagle Ford Shale in South Texas and in other areas of Texas and Louisiana, as well as properties in the Mid-Continent region. 

For information about our segments’ revenues, profits and losses and total assets, see Note 17. “Reporting Segments” of our Notes to Consolidated Financial Statements.

Midstream Business

Western Catarina Gathering System

In October 2015, we acquired the Western Catarina gathering system from Sanchez Energy.   The system consists of gathering assets, pipelines, processing units, compression units and other related assets in Western Catarina, which are located in Dimmit and Webb Counties, Texas and service upstream production from the Eagle Ford Shale.  The Western Catarina gathering system consists of approximately 150 miles of gathering pipelines, four main gathering and processing facilities, including stabilizers, storage tanks, compressors and dehydration units, and other related assets in Western Catarina, which are located in Dimmit and Webb Counties, Texas, and services upstream production from the Eagle Ford Shale.  The gathering pipelines range in diameter from 4 to 12 inches, with capacity of 40 MBbl/d for crude oil and NGLs, and 200 MMcf/d for natural gas.  There are four main gathering and processing facilities, which include eight stabilizers of 5,000 barrels per day, approximately 25,000 barrels of storage capacity, NGL pressurized storage, 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 crude oil, NGLs and natural gas produced by Sanchez Energy at Western Catarina.  The gathering system has crude oil interconnects with the Plains All American Pipeline header system delivered to the Gardendale terminal, and to all four takeaway pipelines to Corpus Christi, and it has natural gas interconnects with Southcross Energy Partners, L.P., Kinder Morgan, Energy Transfer Partners, L.P. and Transwestern Pipeline Company, LLC.  Pipeline capacity on the Western Catarina gathering system can be expanded through small compression projects at a nominal cost, with approximately $1.0 million in capital expenditures planned per year.

All of the revenues from the Western Catarina gathering system are currently earned from Sanchez Energy.  Pursuant to a 15-year gathering agreement, Sanchez Energy has agreed to tender all of its crude petroleum, natural gas and other hydrocarbon-based product volumes on approximately 35,000 dedicated acres in the Western Catarina area of the Eagle Ford Shale in South Texas for processing and transportation through the Western Catarina gathering system, with the potential to tender additional volumes from production activities outside of the dedicated acreage.  During the first five years of the contract term (or through 2020), Sanchez Energy is required to meet a minimum quarterly volume delivery commitment for crude oil and natural gas, subject to certain adjustments.  In addition, Sanchez Energy is required to pay contractually agreed upon gathering and processing fees for crude oil and natural gas volumes tendered through the Western Catarina gathering system.

During the fiscal year ended December 31, 2016, Sanchez Energy transported average daily production through the gathering system of approximately 13.3 MBbl/d of crude oil and 181.5 MMcf/d of natural gas.  The average age of the Western Catarina gathering system assets is approximately 6 years, and they have an expected life of approximately 24 more years.

Carnero Gathering System

In July 2016, we purchased from Sanchez Energy a 50% interest in Carnero Gathering, LLC (“Carnero Gathering”), a joint venture that is 50% owned by Targa Resources Corp. (NYSE: TRGP) (“Targa”), for an initial payment of approximately $37.0 million and the assumption by us of remaining capital commitments to Carnero Gathering, estimated at approximately $7.4 million as of that date.  In addition, we are required to pay Sanchez Energy an earnout based on natural gas received above a threshold volume and tariff at Carnero Gathering’s delivery points from Sanchez Energy and other producers.  Carnero Gathering owns a total of approximately 45 miles (a portion of which remains under construction) of high pressure natural gas gathering pipelines that currently connect the Western Catarina gathering system to nearby pipelines in South Texas (the “Carnero gathering system”).  The Carnero gathering system is designed to directly connect to a cryogenic natural gas processing plant discussed below. Sanchez Energy has entered into a 15-year gathering agreement with Carnero Gathering pursuant to which Sanchez Energy is required to maintain a minimum quarterly volume delivery commitment for the first five years after the Raptor Plant (as defined below) discussed below is operational.

Carnero Processing

In November 2016, we completed the acquisition of 50% of the outstanding membership interests in Carnero Processing, LLC (“Carnero Processing”) from Sanchez Energy for aggregate cash consideration of approximately $55.5 million and the assumption of approximately $24.5 million of remaining capital contribution commitments as of that date. Carnero Processing is developing a 200MMcf/d cryogenic natural gas processing plant that is being constructed in La Salle County, Texas, which is expected to be completed in April 2017 (the “Raptor Plant”).  Carnero Processing is planning to expand the Raptor Plant to 260 MMcf/d.  The Raptor Plant is a strategic asset that we believe will allow us to capture more of the value chain from Sanchez Energy's South Texas production and realize further upside from third party volumes.

Title to Properties

Title to the Western Catarina gathering system assets falls into two categories: parcels that are owned in fee and parcels in which our interest is derived from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities, permitting the use of such land for our operations.  Portions of the land on which portions of the Western Catarina gathering system are located are owned by us in fee title, and we believe that we have satisfactory title to these lands.  The remaining land on which the Western Catarina gathering system is located are held by us pursuant to surface leases between us, as lessee, and the fee owner of the lands, as lessors.  Our predecessors leased or owned these lands for many years without any material challenge known to us relating to the title to the land upon which the assets are located, and we believe that we have satisfactory leasehold estates or fee ownership in such lands.  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 that have, and we believe that we have satisfactory title to all of the material leases, easements, rights-of-way, permits and licenses with respect to the Western Catarina gathering system.

Production Business

Our total estimated proved reserves at December 31, 2016, were approximately 6.9 MMBoe, approximately 100% of which were classified as proved developed, with 35% being natural gas, 14% being NGLs, and 51% being oil. At December 31, 2016, we owned approximately 840 net producing wells. Our total average proved reserve-to-production ratio is approximately 5.2 years and our portfolio decline rate is 12% to 21% based on our estimated proved reserves at December 31, 2016.

Below is a description of our operations and our oil and natural gas properties by basin at December 31, 2016:

Locations

We have oil and natural gas properties in three regions in the United States:

Eagle Ford Shale, where production during the year ended December 31, 2016 was 0.3 MMBoe and approximately 4.2 MMBoe of estimated proved reserves were held at December 31, 2016, all of which were classified as proved developed, with 71% being oil, 15% being natural gas and 14% being NGLs;

Mid-Continent region, primarily Oklahoma, where production during the year ended December 31, 2016 was 0.6 MMBoe and had approximately 1.7 MMBoe of estimated proved reserves were held at December 31, 2016, all of which were classified as proved developed with 77% being natural gas, 13% being NGLs  and 10% being oil; and

Texas and Louisiana Gulf Coast, where we had approximately 1.0 MMBoe of estimated proved reserves at December 31, 2016, all of which were classified as proved developed, with 54% being natural gas, 34% being oil and 12% being NGLs. 

Operations

We do not operate any of our oil and gas properties, except in the Cherokee Basin in the Mid-Continent region, which is currently being marketed for sale.  The Eagle Ford Shale properties are operated by SOG and Marathon Oil Company. The Texas Gulf Coast properties are operated primarily by SOG.

Production Acquisition

In November 2016, we completed the acquisition of working interests in 23 producing Eagle Ford Shale wellbores located in Dimmit and Zavala counties in South Texas together with escalating working interests in an additional 11 producing wellbores located in the Palmetto Field in Gonzales County, Texas (together, the “Production Acquisition”) for aggregate cash consideration of $25.6 million after $1.4 million in normal and customary closing adjustments from SN Cotulla Assets, LLC and SN Palmetto, LLC, each a wholly-owned subsidiary of Sanchez Energy.

Proved Oil, Natural Gas and Natural Gas Liquids Reserves

The following table reflects our estimates of proved oil, natural gas and NGLs 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 oil and NGLs.

 

Our 2016 estimates of total proved reserves decreased 4.7 MMBoe from 2015 due to a 5.3 MMBoe decrease in undeveloped gas reserves in the Cherokee Basin.  The Cherokee Basin decrease was due to a combination of factors including the sale of properties (1.0 MMBoe decrease) and the decrease in proved developed non-producing and proved

undeveloped (“PUD”) reserves (4.3 MMBoe decrease).  Offsetting the decrease was the acquisition of Eagle Ford Shale properties, which increased reserves by 1.3 MMboe. 

As of December 31, 2016, we have no remaining PUDs in our reserves base.

 

The table below details the activity in our PUD locations from December 31, 2015 to December 31, 2016:

 

Excluding acquisitions, we expect to make capital expenditures related to recompletion of existing wells of approximately $0.2 million during the year ending December 31, 2017. During the year ended December 31, 2016, four PUDs were removed from the future drilling schedule due to capital priorities shifting to acquisition opportunities.

At December 31, 2016, Ryder Scott Co. LP (“Ryder Scott”), an independent oil and natural gas engineering firm, prepared estimates of all our proved reserves. At December 31, 2015, Netherland, Sewell & Associates, Inc. (“NSAI”), an independent oil and natural gas engineering firm, and Ryder Scott prepared estimates of all our proved reserves. We used NSAI’s and Ryder Scott’s estimates of our proved reserves to prepare our financial statements. NSAI and Ryder Scott maintain a degreed staff of highly competent technical personnel. The average experience level of NSAI’s technical staff of engineers, geoscientists and petro physicists exceeds 20 years, including five to 15 years with a major oil company. The engineering information presented in Ryder Scott’s report was overseen by Michael F. Stell, P.E. Mr. Stell is an experienced reservoir engineer having been a practicing petroleum engineer since 1981. He has more than 24 years of experience in reserves evaluation with Ryder Scott. He has a Bachelor of Science degree in Chemical Engineering from Purdue University and Master of Science degree in Chemical Engineering from University of California - Berkeley. Mr. Stell is a Registered Professional Engineer in the State of Texas. Our technical staff of engineers and geosciences professionals has an average experience level that exceeds 28 years. Our activities with NSAI and Ryder Scott are coordinated by a reservoir engineer employed by us who has approximately 36 years of experience in the oil and natural gas industry and an engineering degree from the University of Tennessee and a masters 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 NSAI and Ryder Scott prior to review by the audit committee of the board of directors of our general partner and approval by the board of directors of our general partner.

Production and Price History

The following table sets forth information regarding net production of oil, natural gas and natural gas liquids and certain price and cost information for each of the periods indicated:

Existing Wells

The following table sets forth information at December 31, 2016, 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 2016.

 

Drilling Activity

The following sets forth information with respect to oil and natural gas wells drilled and completed by us during the years ended December 31, 2016 and 2015. 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, 2016 or 2015.  During the year ended December 31, 2016, we recompleted 1 gross well, or approximately 0.7 net wells.  During the year ended December 31, 2015, we drilled 1 gross productive development well.  There were no wells in progress at December 31, 2016.

 

 

Developed and Undeveloped Acreage

The following table sets forth information as of December 31, 2016 related to our leasehold acreage.

 

Leases

Our leases are concentrated in Oklahoma (88%), Texas (8%), Kansas (2%) and Louisiana (2%). We have approximately 827 leases in the Cherokee Basin on 124,287 gross acres, or approximately 120,845 net acres. Our acreage includes areas leased under a concession agreement that we have with the Osage Nation in Osage County, Oklahoma, which provides us with the exclusive right to lease for coalbed methane on up to 560,000 acres within Osage County and the exclusive right for a period of 90 days after drilling a coalbed methane well on any such acreage to lease for oil and natural gas on such acreage. Generally, we have the right each year to elect to license up to a certain amount of acreage under the concession agreement for such year for a specified license payment, and a license must be obtained before we then lease the acreage. During the term of the concession agreement, however, we have the exclusive right to lease the acreage covered thereunder for coalbed methane unless we notify the Osage Nation in writing that we have no intention to lease any particular acreage. Our concession agreement with the Osage Nation requires drilling and completing a specified number of wells between 2005 and 2020, which we had achieved as of December 31, 2012, the most recent drilling target. We believe that the Osage Nation has granted at least two concessions for the drilling of conventional oil and natural gas on acreage which overlaps certain of the acreage covered by our earlier granted concession, and it has taken the position that we are not entitled to conventional oil and natural gas leases under the terms of our concession agreement where we have not drilled a coalbed methane well first.

The typical oil and natural gas lease agreement covering our other Cherokee Basin properties provides for the payment of royalties to the mineral owner for all oil and natural gas produced from any wells drilled on or pooled with the leased property. In the Cherokee Basin, depending on the location of a particular well, the total lease burden on our operated properties is generally 20%, generally corresponding to an 80% net revenue interest to us, and on our non-operated properties is generally a 40% net revenue interest. We have approximately 46 leases with a gross acreage position of 3,150 acres, or approximately 737 net acres in the Central Kansas Uplift. We have no leasehold rights associated with our 83 well bores in the Woodford Shale. We have approximately 55 leases in Louisiana with a gross acreage position of 2,343 acres, or approximately 466 net acres. We have approximately 240 leases in Texas with a gross acreage position of 10,665 acres, or 5,179 net acres.

Under the oil and natural gas lease agreements covering our productive wells, such leases have generally been perpetuated beyond their stated lease term and generally will not expire unless and until associated production ceases. Such leases are said to be “held by production” and do not require us to make lease payments beyond the royalty amount stipulated by each lease. The area held by production from a particular well is typically held by lease or applied to a pooled unit for such well or as specified under state law. Barring establishment of commercial production, most of our leases not currently held by production will expire. Approximately 14% of our total net undeveloped acreage of 6,185 acres is held under leases that have remaining primary terms expiring in 2017. Of these expiration amounts in 2017, approximately 95% apply to our concession agreement with the Osage Nation. If these leases do expire, we have the exclusive right to

acquire a new coalbed methane lease on any expired acreage under our concession agreement with the Osage Nation until its expiration in 2020 or any earlier termination according to its terms and conditions. The remaining expiring acreage is primarily located in Texas.

Marketing and Major Customers

We manage our oil and natural gas marketing efforts and actively monitor our credit exposure to our major customers. We currently sell our natural gas produced in the Cherokee Basin to Macquarie Cook Energy LLC; Keystone Gas Corporation; Scissortail Energy, LLC; Cotton Valley Compression, L.L.C.; Cherokee Basin Pipeline, LLC and ONEOK Energy Services Company, L.P. Our oil production in the Cherokee Basin is primarily purchased by Sunoco Partners Marketing and Terminals L.P. and Coffeyville Resources Refining and Marketing, LLC. Our natural gas production in the Woodford Shale and our oil production in the Central Kansas Uplift is marketed by the operators of our properties.  Our oil and natural gas production in the onshore Texas and Louisiana Gulf Coast region is marketed by the operators of our properties.

For the years ended December 31, 2016 and 2015, two customers accounted for 10% or more of our total revenue.  Sanchez Energy, whose earned revenues contribute exclusively to our midstream segment, accounted for 76% and 17% of total revenue for the years ended December 31, 2016 and 2015, respectively. During that same time period, Macquarie Cook Energy, LLC, whose earned revenues contribute exclusively to our production segment, accounted for approximately 6% and 17% of our total revenue, respectively. 

Markets and Competition

We operate in a competitive environment for acquiring properties, marketing oil and natural gas and retaining trained personnel.  Many of our competitors have substantially greater financial, technical and personnel resources than us.  As a result, our competitors may be able to outbid us for assets, more competitively price their gathering and transportation services and oil and natural gas production, or utilize superior technical resources than our financial or personnel resources permit.  Our ability to acquire additional assets will depend on our ability to evaluate and select suitable assets and to consummate transactions in a competitive environment.

The natural gas gathering, compression, treating and transportation business is very competitive.  Upon such time that we seek to obtain other customers besides Sanchez Energy for the Western Catarina gathering system, 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.

We are also affected by competition for drilling rigs, completion rigs and the availability of related equipment. In the past, the oil and natural gas industry has experienced shortages of drilling and completion rigs, equipment, pipe and personnel, which has delayed development drilling activities and has caused significant increases in the prices for this equipment and personnel. We are unable to predict when, or if, such shortages may occur or how they would affect our development and drilling program. To date, however, we have not experienced such shortages. In addition, over the past several years, our field employees have been working with teams of drilling and completion contractors and have developed relationships that should enable us to mitigate the risks associated with equipment availability.

Neither SOG nor any of its related companies are restricted from competing with us.

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:

 

require the acquisition of various permits before drilling commences;

restrict the types, quantities and concentrations of various substances, including water and waste, that can be released into the environment;

limit or prohibit activities on lands lying within wilderness, wetlands and other protected areas; and

require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells.

These laws, rules and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible in the absence of such regulations.  The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability.  In addition, federal, state and local authorities frequently revise environmental laws and regulations, and any changes that result in more stringent and costly waste handling, disposal and cleanup requirements for the oil and natural gas industry could have a significant impact on our operating costs.

Environmental laws and regulations that could have a material impact on the oil and natural gas industry and our operations include the following:

Waste Handling

The Resource Conservation and Recovery Act (“RCRA”) and comparable state laws regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous wastes and non-hazardous wastes.  Under the auspices of the federal Environmental Protection Agency (“EPA”), the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements.  Drilling fluids, produced waters and most other wastes associated with the exploration, development and production of oil and natural gas are currently regulated under RCRA’s non-hazardous waste provisions.  Although we do not believe that the current costs of managing any of our wastes are material under presently applicable laws, any future reclassification of oil and natural gas exploration, development and production wastes as hazardous wastes, could increase our costs to manage and dispose of wastes.

Comprehensive Environmental Response, Compensation and Liability Act

The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the Superfund law, imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment.  These persons include the owner or operator of the site where the release occurred, and anyone who disposed of, or arranged for the disposal of, a hazardous substance released at the site.  Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies.  In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

We currently own, lease or operate numerous properties that have been used for oil and natural gas production for a number of years.  Although we believe that operating and waste disposal practices utilized in the past with respect to these properties were typical for the industry at the time, hazardous substances, wastes or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations, including off-site locations, where such substances have been taken for disposal.  In addition, these properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes or hydrocarbons was not under our control.  These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws.  Under such laws, we could be required to remove previously disposed substances and wastes, remediate contaminated property or perform remedial plugging or pit closure operations to prevent future contamination.

Water Discharges

The Federal Water Pollution Control Act (the “Clean Water Act”), and comparable state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of produced water and other oil and natural gas wastes, into waters of the United States.  The discharge of pollutants into regulated waters is prohibited,

except in accordance with the terms of a permit issued by the EPA or an analogous state agency.  Federal and state regulatory agencies can impose administrative, civil and criminal penalties, impose investigatory or remedial obligations and issue injunctions limiting or preventing our operations for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.

Oil Pollution Act

The Oil Pollution Act was enacted in 1990 to amend the Clean Water Act in large part due to the Exxon Valdez incident.  Under the Oil Pollution Act, the EPA was directed to promulgate regulations which would create a comprehensive prevention, response, liability and compensation program to deal with oil discharged into United States navigable waters.  In particular, the regulations developed under the Oil Pollution Act strengthened the requirements that apply to Spill Prevention, Control and Countermeasure Plans.  The Oil Pollution Act imposes liability for removal costs and damages resulting from an incident in which oil is discharged into navigable waters and establishes liability for damages for injuries to, or loss of, natural resources.

Air Emissions

The Clean Air Act, and comparable state laws, regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements.  In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources.  In October 2015, finalized rules that lower the National Ambient Air Quality Standard (“NAAQS”) for ozone from 75 parts per billion (“ppb”) to 70 ppb.  In addition, in May 2016, the EPA issued rules which define what are called “stationary sources” to resolve how sources of emissions from the crude oil and natural gas sector should be aggregated under Clean Air Act permit programs.  Compliance with these or other new legal requirements could, among other things, require installation of new emission controls on some of our equipment, result in longer permitting timelines , and significantly increase our capital expenditures and operating costs, which could adversely impact our business. States can also impose air emissions limitations that are more stringent than the federal standards imposed by the EPA.  Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the Clean Air Act and associated state laws and regulations.  Rules restricting air emissions may require a number of modifications to our operations, including the installation of new equipment.  Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our operating results.  However, we believe that our operations will not be materially adversely affected by any such requirements, and the requirements are not expected to be any more burdensome to us than to other similarly situated companies.  We believe that our operations are in substantial compliance with federal and state air emission standards.

Climate Change

While the U.S. Congress has from time to time considered legislation to reduce emissions of greenhouse gases (“GHGs”), the prospect for adoption of significant legislation at the federal level to reduce GHG emissions is perceived to be low at this time. In May 2016, the EPA issued new regulations that set methane emission standards for new and modified oil and natural gas production and natural gas processing and transmission facilities to reduce methane emissions from the oil and natural gas sector by up to 45 percent from 2012 levels by 2025. Furthermore, in August 2015, the EPA issued final rules outlining the Clean Power Plan (“CPP”), which was developed in accordance with the Administration’s Climate Action Plan announced the previous year. Under the CPP, carbon pollution from power plants must be reduced over 30% below 2005 levels by 2030. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations that limit emissions of GHGs could adversely affect demand for the oil and natural gas that production operators produce, some of whom are our customers, which could thereby reduce demand for our midstream services. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events; if any such effects were to occur, it is uncertain if they would have an adverse effect on our financial condition and operations.

Hydraulic Fracturing

Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production.  The process is typically regulated by state oil and natural gas commissions.  However, the EPA has asserted federal regulatory authority over certain hydraulic fracturing practices and has finalized a study of the potential environmental impacts of hydraulic fracturing activities, finding that under certain circumstances, the “water cycle” activities associated with hydraulic fracturing may impact drinking water resources.  In 2014, the EPA issued an advanced notice of proposed rulemaking under the Toxic Substances Control Act of 1976 requesting comments related to disclosure for hydraulic fracturing chemicals.  Further, the Department of the Interior has released final regulations governing hydraulic fracturing on federal and Native American oil and natural gas leases which require lessees to file for approval of well stimulation work before commencement of operations and require well operators to disclose the trade names and purposes of additives used in the fracturing fluids.  The states in which we operate have also adopted disclosure requirements related to fracturing fluids.  Legislation has been introduced, but not adopted, in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process.  In addition, some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances.  Currently, no states in which we utilize hydraulic fracturing have adopted these regulations.  At this time, it is not possible to accurately estimate how potential future laws or regulations addressing hydraulic fracturing would impact our business.

Endangered Species

The Endangered Species Act (“ESA”), and analogous state laws, restrict activities that may affect listed endangered or threatened species or their habitats.  If endangered species are located in areas where we operate, our operations or any work performed related to them could be prohibited or delayed or expensive mitigation may be required.  While some of our operations may be located in areas that are designated as habitats for endangered or threatened species, we believe that we are in compliance with the ESA.  In addition, as a result of a settlement approved by the U.S. District Court for the District of Columbia on September 9, 2011, the U.S. Fish and Wildlife Service is required to review and consider the listing of numerous species as endangered under the ESA by no later than the completion of the agency’s 2017 fiscal year.  Additional listings under the ESA and similar state laws could result in the imposition of restrictions on our operations and consequently have an adverse effect on our business.

Gathering System Regulation

Regulation of gathering facilities may affect certain aspects of our business and the market for our services. Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated by agencies of the U.S. federal government, primarily the Federal Energy Regulatory Commission (“FERC”). The FERC regulates interstate natural gas transportation rates, terms and conditions of service, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.

The transportation and sale for resale of natural gas in interstate commerce is regulated primarily under the Natural Gas Act (“NGA”), and by regulations and orders promulgated under the NGA by the FERC. In certain limited circumstances, intrastate transportation, gathering, and wholesale sales of natural gas may also be affected directly or indirectly by laws enacted by the U.S. Congress and by FERC regulations.

Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by the FERC under the NGA. We believe that the natural gas pipelines in our gathering systems meet the traditional tests that the FERC has used to establish whether a pipeline is a gathering pipeline not subject to FERC jurisdiction. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services has been the subject of substantial litigation and varying interpretations.  In addition, the FERC determines whether facilities are gathering facilities on a case-by-case basis, so the classification and regulation of our natural gas gathering facilities are subject to change based on future determinations by the FERC, the courts, or the U.S. Congress. If the FERC were to consider the status of an individual gathering facility is not exempt from FERC regulation and the pipeline provides interstate transportation, the rates for, and terms and conditions of, services provided by such facility would be subject to regulation by the FERC. Such regulation could decrease revenue, increase operating costs, and, depending upon the facility in question, could adversely affect our

results of operations and cash flows. In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the NGA or the NGPA, this could result in the imposition of civil penalties as well as a requirement to disgorge charges collected for such service in excess of the cost-based rate established by the FERC.

Gathering service, which may occur upstream of transmission service subject to FERC jurisdiction, is regulated by the states. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation. Our purchasing and gathering operations are subject to ratable take and common purchaser statutes in the State of Texas.  The ratable take statute generally requires gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling.  Similarly, the common purchaser statute generally requires gatherers to purchase without undue discrimination as to source of supply or producer.  These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply.  These statutes have the effect of restricting our right as an owner of gathering facilities to decide with whom we contract to purchase or transport gas.

The Railroad Commission of Texas (“TRRC”) requires gatherers to file reports, obtain permits, make books and records available for audit and provide service on a nondiscriminatory basis.  Shippers and producers may file complaints with the TRRC to resolve grievances relating to natural gas gathering access and rate discrimination.

While our systems have not been regulated by the FERC under the NGA, the U.S. Congress may enact legislation or the FERC may adopt regulations that may subject certain of our otherwise non-FERC jurisdictional facilities to further regulation. Changes in law and to FERC policies and regulations may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate pipelines, and we cannot predict what future action FERC will take. We do not believe, however, that any regulatory changes will affect us in a way that materially differs from the way they will affect other natural gas gatherers with which we compete. Failure to comply with those regulations in the future could subject us to civil penalty liability.

The Energy Policy Act of 2005 (“EPAct 2005”), amended the NGA to add an anti-market manipulation provision which makes it unlawful for any entity to engage in prohibited behavior to be prescribed by the FERC, and furthermore provides the FERC with additional civil penalty authority. The EPAct 2005 provided the FERC with the power to assess civil penalties of up to $1,000,000 per day for violations of the NGA and the Natural Gas Policy Act (“NGPA”).  Effective August 1, 2016, the maximum penalty increased to $1,973,970 to account for inflation.  The civil penalty provisions are applicable to entities that engage in the sale of natural gas for resale in interstate commerce. In Order No. 670, the FERC promulgated rules implementing the anti-market manipulation provision of the EPAct 2005. The rules make it unlawful, in connection with the purchase or sale of natural gas subject to the jurisdiction of the FERC, or the purchase or sale of transportation services subject to the jurisdiction of the FERC, for any entity, directly or indirectly, to: (1) use or employ any device, scheme or artifice to defraud; (2) make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (3) engage in any act or practice that operates as a fraud or deceit upon any person. The anti-market manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of gas pipelines and storage companies that provide interstate services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction.

Pipeline Safety Regulation

We are subject to regulation by the United States Department of Transportation (“DOT”) under the Hazardous Liquid Pipeline Safety Act of 1979 (“HLPSA”) and comparable state statutes with respect to design, installation, inspection, testing, construction, operation, replacement and maintenance of pipeline facilities. HLPSA covers petroleum and petroleum products, including NGLs and condensate, and requires any entity that owns or operates pipeline facilities to comply with such regulations, to permit access to and copying of records and to file certain reports and provide information as required by the U.S. Secretary of Transportation. These regulations include potential fines and penalties for violations. We believe that we are in compliance in all material respects with these HLPSA regulations.

Our natural gas pipelines are subject to regulation by Pipelines and Hazardous Materials Safety Administration (“PHMSA”) pursuant to the Natural Gas Pipeline Safety Act of 1968 (“NGPSA”) and the Pipeline Safety Improvement Act of 2002 (“PSIA”), as reauthorized and amended by the Pipeline Inspection, Protection, Enforcement and Safety Act

of 2006 (“PIPES Act”). The NGPSA regulates safety requirements in the design, construction, operation and maintenance of gas pipeline facilities, while the PSIA establishes mandatory inspections for all U.S. oil and natural gas transmission pipelines in high-consequence areas (“HCAs”).

PHMSA has developed regulations that require pipeline operators to implement integrity management programs, including more frequent inspections and other measures to ensure pipeline safety in HCAs. The regulations require operators, including us, to:

perform ongoing assessments of pipeline integrity; 

identify and characterize applicable threats to pipeline segments that could impact a HCA;  

improve data collection, integration and analysis; 

repair and remediate pipelines as necessary; and 

implement preventive and mitigating actions. 

The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (“2011 Pipeline Safety Act”) reauthorizes funding for federal pipeline safety programs, increases penalties for safety violations, establishes additional safety requirements for newly constructed pipelines, and requires studies of certain safety issues that could result in the adoption of new regulatory requirements for existing pipelines. The 2011 Pipeline Safety Act, among other things, increases the maximum civil penalty for pipeline safety violations and directs the U.S. Secretary of Transportation to promulgate rules or standards relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation and testing to confirm the material strength of pipe operating above 30% of specified minimum yield strength in HCAs.  In October 2013, PHMSA finalized rules that increased the maximum administrative civil penalties for violation of the pipeline safety laws and regulations after January 2012 to $200,000 per violation per day, with a maximum of $2,000,000 for a series of violations.  Effective August 1, 2016, these penalties were adjusted for inflation and increased to $205,638 per day, with a maximum of $2,056,380 for a series of violations.

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 January 2015, the EPA unveiled a plan to cut methane emissions from the oil and natural gas sector by 40 to 45 percent by 2025, using 2012 methane emissions as a baseline. To implement that plan, in June 2016, the EPA issued a final rule amending new source performance standards for the oil and natural gas source category by setting standards for both methane and volatile organic compounds for certain equipment, processes, and activities across the source category, including equipment and processes at natural gas gathering facilities.  Also as part of that plan, the EPA called for PHMSA to propose new standards and programs to reduce methane leaks from natural gas transportation and distribution lines. 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 will be effective March 24, 2017.  In addition, in October 2015, PHMSA issued a notice of proposed rulemaking proposing changes to its hazardous liquid pipeline safety regulations, including to extend: (i) reporting requirements to all onshore or offshore, regulated or unregulated hazardous liquid gathering lines; and (ii) certain

integrity management periodic assessment and remediation requirements to regulated onshore gathering lines.    On January 13, 2017, PHMSA issued a final rule amending its regulations to impose new reporting requirements for certain unregulated pipelines, including all hazardous liquid gathering lines. The final rule also significantly extends and expands the reach of certain integrity management requirements, regardless of the pipeline’s proximity to a HCA. However, this final rule remains subject to review and approval by the new administration, pursuant to a memorandum issued by the White House to heads of federal agencies. It is unclear whether the final rule will be revised and when it will be implemented. In April 2016, PHMSA issued a notice of proposed rulemaking that would expand integrity management requirements and impose new pressure requirements on currently regulated gas transmission pipelines and would also significantly expand the regulation of gas gathering lines, subjecting previously unregulated pipelines to requirements regarding damage prevention, corrosion control, public education programs, maximum allowable operating pressure limits and other requirements. PHMSA has not yet finalized these proposed regulations.  While we cannot predict the outcome of legislative or regulatory initiatives, such regulatory changes and any legislative changes could have a material effect on our operations, particularly by extending more stringent and comprehensive safety regulations (such as integrity management requirements) to pipelines and gathering lines not previously subject to such requirements. While we expect any legislative or regulatory changes to allow us time to become compliant with new requirements, costs associated with compliance may have a material effect on our operations.

Furthermore, DOT regulations have incorporated by reference the American Petroleum Institute Standard 653 (“API 653”) as the industry standard for the inspection, repair, alteration and reconstruction of storage tanks.  API 653 requires regularly scheduled inspection and repair of such tanks.  These periodic tank maintenance requirements may result in significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our storage tanks.

States are largely preempted by federal law from regulating pipeline safety for interstate lines but most are certified by the DOT to assume responsibility for enforcing intrastate pipeline regulations and inspection of intrastate pipelines. For example, in Texas the Pipeline Safety Department of the TRRC inspects and enforces the pipeline safety regulations for intrastate pipelines, including gathering lines. States may adopt stricter standards for intrastate pipelines than those imposed by the federal government for interstate lines; however, states vary considerably in their authority and capacity to address pipeline safety. State standards may include more stringent requirements for facility design and management in addition to requirements for pipelines. We do not anticipate any significant difficulty in complying with applicable state laws and regulations. Our pipelines have ongoing inspection and compliance programs designed to keep the facilities in compliance with pipeline safety and pollution control requirements.

We have incorporated all existing requirements into our programs by the required regulatory deadlines and are continually incorporating the new requirements into procedures and budgets. We expect to incur increasing regulatory compliance costs, based on the intensification of the regulatory environment and upcoming changes to regulations as outlined above. In addition to regulatory changes, costs may be incurred when there is an accidental release of a commodity gathered on our system, or a regulatory inspection identifies a deficiency in our required programs.

Other Laws and Regulation

We are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”), and comparable state laws.  These laws and the implementing regulations strictly govern the protection of the health and safety of employees.  The OSHA hazard communications standard, OSHA Process Safety Management, the EPA community right-to-know regulations under Title III of CERCLA and similar state laws require that we organize and/or disclose information about hazardous materials used or produced in our operations.  We believe that we are in substantial compliance with these applicable requirements.

Our operations in Texas are subject to the rules and regulations of the TRRC, Oil & Gas Division.  Our operations in Louisiana are subject to the rules and regulations of the Louisiana Department of Natural Resources, Office of Conservation.  We believe that we are in substantial compliance with these rules and regulations.

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, 2016, we had no accrued environmental

obligations.  We are not aware of any environmental issues or claims that will require material capital expenditures or that will otherwise have a material impact on our financial position or results of operations.  However, we cannot predict how future environmental laws and regulations may impact our operations, and therefore, cannot provide assurance that the passage of more stringent laws or regulations in the future will not have a negative impact on our financial condition, results of operations or cash flows.

Employees

Pursuant to the Services Agreement, Manager provides services that we require to operate our business, including overhead, technical, administrative, marketing, accounting, operational, information systems, financial, compliance, insurance and acquisition, disposition and financing services.  In connection with providing the services under the Services Agreement, Manager receives compensation consisting of:  (i) a quarterly fee equal to 0.375% of the value of our properties other than our assets located in the Mid-Continent region, (ii) reimbursement for all allocated overhead costs as well as any direct third-party costs incurred and (iii) for each asset acquisition, asset disposition and financing, a fee not to exceed 2% of the value of such transaction. 

As of February 14, 2017, 33 employees were employed by SOG with their primary function being to provide services for us, all of which are full-time employees.

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

Offices

We are headquartered in Houston, Texas.  We also own and maintain field offices in Coffeyville, Kansas and Skiatook, Oklahoma in connection with the operation of our Mid-Continent region properties.

Available Information

Our internet address is http://www.sanchezpp.com. We make our website content available for informational purposes only. It should not be relied upon for investment purposes, nor is it incorporated by reference in this Annual Report on Form 10-K. We make available free of charge on or through our website our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to these reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. The SEC maintains an internet website that contains these reports at http://www.sec.gov. The public may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549. Information concerning the operation of the Public Reference Room may be obtained by calling the SEC at (800) 723-0330.

Item 1A. Risk Factors 

Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. The following are some of the important factors that could affect our financial performance or could cause actual results to differ materially from estimates or expectations contained in our forward-looking statements. We may encounter risks in addition to those described below. Additional risks and uncertainties not currently known to us, or that we currently deem to be immaterial, may also impair or adversely affect our business, contracts, financial condition, operating results, cash flows, liquidity and prospects.

The risk factors in this report are grouped into the following categories:

Risks Related to Our Midstream Business; 

Risks Related to Our Production Business;

Risks Related to Regulatory Compliance;

Risks Related to Financing and Credit Environment;

Risks Related to Our Cash Distributions; 

Risks Related to an Investment in Us and Our Common Units; and 

Tax Risks.

Because all of our revenue relating to the operation of the Western Catarina gathering system, a substantial amount of the revenue that Carnero Gathering generates from the Carnero Gathering system and a substantial amount of the revenue that Carnero Processing expects to generate from the Raptor Plant upon completion are expected to be derived from Sanchez Energy, any development that materially and adversely affects Sanchez Energy’s operations, financial condition or market reputation could have a material and adverse impact on us.

We are substantially dependent on Sanchez Energy as our only current customer for utilization of the Western Catarina gathering system, and Sanchez Energy is the primary customer for utilization of the Carnero gathering system and the Raptor Plant, and we expect that a substantial majority of revenues relating to the Western Catarina gathering system, the Carnero gathering system and Raptor Plant, upon completion, will be derived from Sanchez Energy for the foreseeable future.  As a result, any event, whether in our area of operations or otherwise, that adversely affects Sanchez Energy’s production, drilling and completion schedule, financial condition, leverage, market reputation, liquidity, results of operations or cash flows may adversely affect our revenues and cash available for distribution.  Accordingly, we are indirectly subject to the business risks of Sanchez Energy, including, among others:

the speculative nature of drilling wells;

a reduction in or slowing of Sanchez Energy’s development program, especially on Sanchez Energy’s Catarina asset, which would directly and adversely impact demand for our gathering and processing services;

a decline in natural gas, NGLs and oil prices, which have recently been extremely volatile and have declined rapidly;

the availability of capital on an economic basis to fund Sanchez Energy’s exploration and development activities;

Sanchez Energy’s ability to replace reserves;

Sanchez Energy’s drilling and operating risks, including potential environmental liabilities;

Sanchez Energy’s ability to finance its operations and development activities;

transportation capacity constraints and interruptions;

adverse effects of governmental and environmental regulation; and

losses from pending or future litigation.

In addition, recent lower oil, natural gas and NGL prices have caused and may further cause Sanchez Energy to record ceiling limitation impairments, which would adversely affect its future business and development.  Sanchez Energy utilizes the full cost method of accounting to account for its oil and natural gas exploration and development activities.  Under this method of accounting, a company is required on a quarterly basis to determine whether the book value of its oil and natural gas properties (excluding unevaluated properties) is less than or equal to the “ceiling,” based upon the expected after-tax present value (discounted at 10%) of the future net cash flows from the proved reserves.  Any excess of the net book value of the oil and natural gas properties over the ceiling must be recognized as a non-cash impairment expense.  Sanchez Energy recorded a full cost ceiling test impairment before income taxes of approximately $169 million and $1,365 million for the years ended December 31, 2016 and 2015, respectively.  Sanchez Energy could incur additional non-cash impairments to its full cost pool in 2017 if average prices decline.  These impairments, along with a substantial

and sustained decline in oil and natural gas prices, may materially and adversely affect its future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.

We are subject to the risk of non-payment or non-performance by Sanchez Energy, including with respect to the Western Catarina gathering and processing agreement.  We cannot predict the extent to which Sanchez Energy’s business would be impacted if conditions in the energy industry were to deteriorate, nor can we estimate the impact that such conditions would have on Sanchez Energy’s ability to execute its drilling and development program or perform under the gathering and processing agreement.  Any material non-payment or non-performance by Sanchez Energy would reduce our ability to make distributions to our unitholders.

In addition, due to our relationship with Sanchez Energy, our ability to access the capital markets, or the pricing or other terms of any capital markets transactions, may be adversely affected by any impairment to Sanchez Energy’s financial condition or adverse changes in its credit ratings.

Any material limitation on our ability to access capital as a result of such adverse changes at Sanchez Energy could limit our ability to obtain future financing under favorable terms, or at all, or could result in increased financing costs in the future.  Similarly, material adverse changes at Sanchez Energy could negatively impact our unit price, limiting our ability to raise capital through equity issuances or debt financing, or could negatively affect our ability to engage in, expand or pursue our business activities, and could also prevent us from engaging in certain transactions that might otherwise be considered beneficial to us.

Because of the natural decline in production from existing wells, our success depends, in part, on Sanchez Energy’s ability to replace declining production.  Any decrease in volumes of natural gas, NGLs and oil that Sanchez Energy produces or any decrease in the number of wells that Sanchez Energy completes could adversely affect our business and operating results.

The volumes that support our facilities depend on the level of production from wells connected to our facilities, which may be less than expected and will naturally decline over time.  To the extent Sanchez Energy reduces its activity or otherwise ceases to drill and complete wells, especially on its Catarina asset, revenues for our gathering and processing services will be directly and adversely affected.  In addition, volumes from completed wells will naturally decline and our cash flows associated with these wells will also decline over time.  In order to maintain or increase throughput levels on our facilities, we must obtain new sources of natural gas, NGLs and oil from Sanchez Energy or other third parties.  The primary factors affecting our ability to obtain additional sources of natural gas, NGLs and oil include (i) the success of Sanchez Energy’s drilling activity in our areas of operation, (ii) Sanchez Energy’s acquisition of additional acreage and (iii) our ability to obtain additional dedications of acreage from Sanchez Energy or new dedications of acreage from other third parties.

We have no control over Sanchez Energy’s or other producers’ levels of development and completion activity in our areas of operation, the amount of reserves associated with wells connected to our facilities or the rate at which production from a well declines.  We have no control over Sanchez Energy or other producers or their development plan decisions, which are affected by, among other things:

the availability and cost of capital;

prevailing and projected prices for natural gas, NGLs and oil;

demand for natural gas, NGLs and oil;

levels of reserves;

geologic considerations;

environmental or other governmental regulations, including the availability and maintenance of drilling permits and the regulation of hydraulic fracturing; and

the costs of producing natural gas, NGLs and oil and the availability and costs of drilling rigs and other equipment.

Under the terms of Sanchez Energy’s Catarina lease, Sanchez Energy is subject to annual drilling and development requirements.  For example, at the present time, the lease requires Sanchez Energy to drill 50 wells per year.  If Sanchez Energy fails to meet this minimum drilling commitment, Sanchez Energy would forfeit its acreage under the lease not held by production.  Such a forfeiture could impact Sanchez Energy’s ability to develop additional acreage and replace declining production.

Fluctuations in energy prices can also greatly affect the development of reserves.  Sanchez Energy could elect to reduce its drilling and completion activity if commodity prices decrease.  Declines in commodity prices could have a negative impact on Sanchez Energy’s development and production activity, and if sustained, could lead to a material decrease in such activity.  Sustained reductions in development or production activity in our areas of operation could lead to reduced utilization of our services.

Due to these and other factors, even if reserves are known to exist in areas served by our facilities, Sanchez Energy and other producers may choose not to develop, or be prohibited from developing, those reserves.  If reductions in development activity result in our inability to maintain the current levels of throughput on our facilities, those reductions could reduce our revenue and cash flow and adversely affect our ability to make cash distributions to our unitholders.

The gathering and processing agreement with Sanchez Energy contains provisions that can reduce the cash flow stability that the agreement was designed to achieve.

The gathering and processing agreement with Sanchez Energy relating to the Western Catarina gathering system is designed to generate stable cash flows for us over the life of the minimum volume commitment contract term while also minimizing direct commodity price risk.  Under the minimum volume commitment, subject to certain adjustments, Sanchez Energy has agreed to ship a minimum volume of natural gas, NGLs and oil on the Western Catarina gathering system 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 and processing agreement.  In addition, the gathering and processing agreement also includes a minimum quarterly quantity, which is a total amount of natural gas, NGLs and oil that Sanchez Energy must flow on the Western Catarina gathering system (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 and processing agreement contains provisions that allow Sanchez Energy to use the excess volumes as a credit to shorten the minimum volume commitment term, but to no less than four years.

Under certain circumstances, it is possible that the combined effect of the minimum volume commitment provisions could result in our receiving no revenues or cash flows from Sanchez Energy in a given period.  In the most extreme circumstances:

we could incur operating expenses with no corresponding revenues from Sanchez Energy; or

Sanchez Energy could cease shipping throughput volumes at a time when its aggregate minimum volume commitment has been satisfied with previous throughput volume shipments, which could be in as early as four years.

If either of these circumstances were to occur, it would have a material adverse effect on our results of operations and financial condition and cash flows and our ability to make cash distributions to our unitholders.

We do not intend to obtain independent evaluations of natural gas, NGLs and oil reserves connected to the Western Catarina gathering system 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 natural gas, NGLs and oil reserves, including those of Sanchez Energy, connected to the Western Catarina gathering system on a regular or ongoing basis.  Moreover, even if we did obtain independent evaluations of the natural gas, NGLs and oil reserves connected to the Western Catarina gathering system, such evaluations may prove to be incorrect.  Crude oil and natural gas reserve engineering requires subjective estimates of underground accumulations of crude oil and natural gas and assumptions concerning future crude 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 the Western Catarina gathering system or the anticipated life of such reserves.  If the total reserves or estimated life of the reserves connected to the Western Catarina gathering system are less than we anticipate and we are unable to secure additional sources of natural gas, NGLs and oil, it could have a material adverse effect on our business, results of operations and financial condition and our ability to make cash distributions to our unitholders.

Interruptions in operations at our facilities may adversely affect our operations and cash flows available for distribution to our unitholders.

Our operations depend upon the infrastructure that we have developed, constructed or acquired.  Any significant interruption at any of our facilities, or in our ability to gather, treat or process natural gas, NGLs and oil, would adversely affect our operations and cash flows available for distribution to our unitholders.  Operations at our facilities could be partially or completely shut down, temporarily or permanently, as the result of circumstances not within our control, such as:

unscheduled turnarounds or catastrophic events at our physical plants or pipeline facilities;

restrictions imposed by governmental authorities or court proceedings;

labor difficulties that result in a work stoppage or slowdown;

a disruption in the supply of resources necessary to operate a facility;

damage to our facilities resulting from natural gas, NGLs and oil that do not comply with applicable specifications; and

inadequate transportation or market access to support production volumes, including lack of availability of pipeline capacity.

The Western Catarina gathering system is concentrated in two counties in the Eagle Ford Shale in Texas, making us vulnerable to risks associated with operating in one major geographic area.

All of the Western Catarina gathering system is located in two counties 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.

A shortage of equipment and skilled labor in the Eagle Ford Shale could reduce equipment availability and labor productivity and increase labor and equipment costs, which could have a material adverse effect on our business and results of operations.

Gathering and processing services require special equipment and laborers skilled in multiple disciplines, such as equipment operators, mechanics and engineers, among others.  The increased levels of production in the Eagle Ford Shale may result in a shortage of equipment and skilled labor.  If we experience shortages of necessary equipment or skilled labor in the future, our labor and equipment costs and overall productivity could be materially and adversely affected.  If

our equipment or labor prices increase or if we experience materially increased health and benefit costs for employees, our results of operations could be materially and adversely affected.

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 the Western Catarina gathering system is located restricts the Western Catarina gathering system 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 the Western Catarina gathering system 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 the facility, (iii) our desire to provide services pursuant to fee-based contracts and (iv) the existence of current and future dedications to other gatherers by potential third-party customers.  As a result, we may not have the capacity or ability to provide services to third parties, or potential third-party customers may prefer to obtain services pursuant to other forms of contractual arrangements under which we would be required to assume direct commodity exposure.

Increased competition from other companies that provide gathering services could have a negative impact on the demand for our services, which could adversely affect our financial results.

Our ability to renew or replace volume of throughput after the expiration of the five-year minimum volume commitment from the Western Catarina gathering and processing agreement sufficient to maintain current revenues and cash flows could be adversely affected by the activities of our competitors.  Our facilities compete primarily with other natural gas, NGL and oil gathering and processing systems.  Some competitors have greater financial resources than us and may now, or in the future, have access to greater supplies of natural gas, NGLs and oil than we do.  Some of these competitors may expand or construct facilities that would create additional competition for the services that we provide to Sanchez Energy or other future customers.  In addition, Sanchez Energy or other future customers may develop their own facilities instead of using our midstream assets.  Moreover, Sanchez Energy and its affiliates are not limited in their ability to compete with us outside of the dedicated areas.

All of these competitive pressures could make it more difficult for us to retain Sanchez Energy as a customer and/or attract new customers as we seek to expand our business, which could have a material adverse effect on our business, financial condition, results of operations and ability to make cash distributions to our unitholders.

If third-party pipelines or other midstream facilities interconnected to our facilities become partially or fully unavailable, our operating margin, cash flow and ability to make cash distributions to our unitholders could be adversely affected.

Our facilities connect to other pipelines or facilities owned and operated by unaffiliated third parties.  The continuing operation of third-party pipelines, compressor stations and other midstream facilities is not within our control.  These pipelines, plants and other midstream facilities may become unavailable because of testing, turnarounds, line repair, maintenance, reduced operating pressure, lack of operating capacity, regulatory requirements and curtailments of receipt or deliveries due to insufficient capacity or because of damage from severe weather conditions or other operational issues.  In addition, if the costs to us to access and transport on these third-party pipelines significantly increase, our profitability could be reduced.  If any such increase in costs occurs or if any of these pipelines or other midstream facilities become

unable to receive or transport natural gas, NGLs or oil, our operating margin, cash flow and ability to make cash distributions to our unitholders could be adversely affected.

We do not own all of the land on which the Western Catarina gathering system is located, which could result in disruptions to our operations.

We do not own all of the land on which the Western Catarina gathering system has been constructed, and we are, therefore, subject to the possibility of more onerous terms or increased costs to retain necessary land use if we do not have valid rights-of-way or if such rights-of-way lapse or terminate.  We currently have certain rights to construct and operate our pipelines on land owned by third parties for a specific period of time and may need to obtain other rights in the future from third parties and governmental agencies to continue these operations or expand the Western Catarina gathering system.  Our loss of these rights or inability to obtain additional rights, through our inability to renew or obtain right-of-way contracts or otherwise, could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to you.

Our right-of-first-offer with Sanchez Energy for midstream assets is subject to risks and uncertainty, and thus may not enhance our ability to grow our business.

Pursuant to the purchase agreement entered into in connection with the acquisition of midstream assets in the Western Catarina area from Sanchez Energy, subject to certain exceptions, Sanchez Energy has agreed to provide us the first right to make an offer to purchase midstream assets that it desires to transfer to any unaffiliated person through 2030.  The acquisition of additional assets in connection with the exercise of our right-of-first-offer will depend upon, among other things, our ability to agree on the price and other terms of the sale, our ability to obtain financing on acceptable terms for the acquisition of such assets and our ability to acquire such assets on the same or better terms than third parties.  We can offer no assurance that we will be able to successfully acquire any assets pursuant to this right.

In addition, Sanchez Energy is under no obligation to accept any offer made by us.  Furthermore, for a variety of reasons, we may decide not to exercise this right when it becomes available.

Our participation in joint ventures exposes us to liability or harm to our reputation for failures of our partner.

In 2016, we purchased from Sanchez Energy a 50% equity interest in each of Carnero Gathering and Carnero Processing, each a joint venture that is 50% owned by Targa. We and Targa are jointly and severally liable for all liabilities and obligations of Carnero Gathering and Carnero Processing. If Targa fails to perform or is financially unable to bear its portion of required capital contributions or other obligations, including liabilities stemming from claims or lawsuits, we could be required to make additional investments, provide additional services or pay more than our proportionate share of a liability to make up for Targa’s shortfall. Further, if we are unable to adequately address Targa’s performance issues, Sanchez Energy, the main customer on the facilities, may terminate its agreements, which could result in legal liability to us, harm our reputation and reduce cash flows from the Carnero Gathering System and the Raptor Plant.

Drilling for and producing oil and natural gas are costly and high-risk activities with many uncertainties that could adversely affect our business, financial condition, results of operation, operating cash flows and any ability to pay distributions to our unitholders.

Drilling activities are subject to many risks, including the risk that commercially productive reservoirs will not be discovered. Drilling for oil and natural gas can be uneconomic, not only from dry holes, but also from productive wells that do not produce sufficient revenues to be commercially viable. In addition, drilling and producing operations may be curtailed, delayed or cancelled as a result of other factors, including:

the high cost, shortages or delivery delays of drilling rigs, equipment, labor and other services;

unexpected operational events and drilling conditions;

adverse weather conditions;

facility or equipment malfunctions;

title problems;

piping, casing or cement failures;

compliance with environmental and other governmental requirements;

unusual or unexpected geological formations;

loss or damage to oilfield drilling and service tools;

loss of drilling fluid circulation;

formations with abnormal pressures;

environmental hazards, such as natural gas leaks, oil spills, compressor incidents, pipeline ruptures and discharges of toxic gases;

water pollution;

fires;

accidents or natural disasters;

blowouts, craterings and explosions;

uncontrollable flows of oil, natural gas or well fluids; and

loss or theft of data due to cyber-attacks.

Any of these events can cause increased costs or restrict the ability to drill wells and conduct operations.  Any delay in the drilling program or significant increase in costs could impact our ability to generate sufficient cash flows to operate our business.  Increased costs could include losses from personal injury or loss of life; damage to or destruction or loss of property, natural resources, equipment, and data; pollution; environmental contamination; loss of wells; and regulatory penalties.

We ordinarily maintain insurance against certain losses and liabilities arising from our operations; however, insurance against all operational risks is not available to us. In addition, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could therefore occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could have a material adverse impact on our business, financial condition, results of operations and ability to pay distributions.

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:

future oil and natural gas prices;

production levels;

capital expenditures;

operating and development costs;

the effects of regulation;

the accuracy and reliability of the underlying engineering and geologic data; and

the availability of funds.

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 actual prices that are received for oil and natural gas;

actual operating costs in producing oil and natural gas;

the amount and timing of actual production;

the amount and timing of capital expenditures;

supply of and demand for oil and natural gas; and

changes in governmental regulations or taxation.

The timing of both production and the incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus, their actual present value. In addition, the 10% discount factor used when calculating our discounted future net cash flows in compliance with the Financial Accounting Standard Board’s Accounting Standards may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general. Any material inaccuracies in these reserve estimates or underlying assumptions could materially affect the quantities and present value of our reserves, which could adversely affect our business, results of operations, financial condition and ability to pay distributions.

Future price declines or downward reserve revisions may result in additional write-downs of our asset carrying values, which could adversely affect our results of operations and limit our ability to borrow funds.

Declines in oil and natural gas prices may result in our having to make substantial downward adjustments to our estimated proved reserves.  If this occurs, or if our estimates of development costs increase or production data factors change, accounting rules may require us to write-down, as a noncash charge to earnings, the carrying value of our properties for impairments.  We capitalize costs to acquire, find and develop our oil and natural gas properties under the successful efforts accounting method.  We are required to perform impairment tests on our assets periodically and whenever events or circumstances warrant a review of our assets.  To the extent such tests indicate a reduction of the estimated useful life or estimated future cash flows of our assets, the carrying value may not be recoverable and therefore would require a write-down.  We have incurred impairment charges in the past and may do so again in the future.  Any impairment could be substantial and have a material adverse effect on our results of operations in the period incurred and on our ability to borrow funds under our Credit Agreement, which in turn may adversely affect our ability to make cash distributions to our unitholders.

We depend on certain key customers for sales of our oil and natural gas. To the extent these and other customers reduce the volumes of oil or natural gas they purchase from us and are not replaced by new customers, our revenues and cash available for distribution could decline.

We currently sell our natural gas produced in the Cherokee Basin to Macquarie Energy LLC; Keystone Gas Corporation; Scissortail Energy, LLC; Cotton Valley Compression, L.L.C.; Cherokee Basin Pipeline, LLC and ONEOK Energy Services Company, L.P. Our oil production in the Cherokee Basin is primarily purchased by Sunoco Partners Marketing and Terminals, L.P. and Coffeyville Resources Refining and Marketing, LLC. Our natural gas production in the Woodford Shale and our oil production in the Central Kansas Uplift are marketed by the operators of the wells.  Our oil and natural gas production in the onshore Texas and Louisiana Gulf Coast region is marketed by the operators of our properties. To the extent these or other customers reduce the volumes of oil and natural gas that they purchase from us and are not replaced by new customers, or the market prices for oil and natural gas decline in our market areas, our revenues and cash available for distribution could decline.

Seasonal weather conditions may adversely affect our ability to conduct production activities.

Oil and natural gas operations are often adversely affected by seasonal weather conditions, primarily during periods of severe weather or rainfall, and during periods of extreme cold. Power outages and other damages resulting from tornados, ice storms, flooding and other strong storms or weather events may prevent wells from being operated in an optimal manner. These weather conditions may reduce oil and natural gas production, which could impact or reduce our future operating cash flows.

Certain of our undeveloped leasehold acreage are subject to leases that may expire in the near future, and our concession agreement with the Osage Nation has certain terms and conditions which must be fulfilled by us.

Some of the leases that we hold are still within their original lease term and are not currently held by production. Unless we establish commercial production on the properties subject to these leases, these leases will expire. Our concession agreement with the Osage Nation also has certain terms and conditions which must be fulfilled by us. If our leases expire or our concession with the Osage Nation terminates, we will lose our right to develop the related properties, which would reduce our future operating cash flows and our cash available to pay distributions.

Shortages of drilling rigs, supplies, oilfield services, equipment and crews could delay operations and reduce our future operating cash flows and cash available to make future investments or to pay distributions.

Higher oil and natural gas prices generally increase the demand for drilling rigs, supplies, services, equipment and crews, and can lead to shortages of, and increasing costs for, drilling equipment, services and personnel. Shortages of, or increasing costs for, experienced drilling crews and equipment and services could restrict the ability to conduct the operations. Any significant increase in operating costs could reduce our revenues, operating cash flows and cash available to make future investments or to pay distributions.

The coalbeds from which we produce natural gas frequently contain water that may hamper our ability to produce natural gas in commercial quantities or adversely affect our profitability.

Unlike conventional natural gas production, coalbeds frequently contain water that must be removed in order for the natural gas to desorb from the coal and flow to the wellbore. Our ability to remove and dispose of sufficient quantities of water from the coal seam will determine whether or not we can produce natural gas in commercial quantities. In addition, the cost of water disposal may be significant, may increase over time and may reduce our profitability.

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:

permits cannot be renewed or obtained from applicable regulatory agencies;

water of lesser quality or requiring additional treatment is produced;

the wells produce excess water; or

new laws and regulations require water to be disposed of or treated in a different manner.

We may be unable to compete effectively with larger companies in the oil and natural gas industry, which may adversely affect our ability to generate sufficient revenue to allow us to pay distributions to our unitholders.

The oil and natural gas industry is intensely competitive with respect to acquiring productive properties, marketing oil and natural gas and securing equipment and trained personnel, and we compete with other companies that have greater resources.  Many of our competitors are major independent oil and natural gas companies and possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to develop and acquire more productive properties than our financial and personnel resources permit.  Our ability to acquire additional properties will be dependent on our ability to evaluate, select and finance the acquisition of suitable properties and our ability to consummate transactions in a highly competitive environment. Factors that affect our ability to acquire properties include availability of desirable acquisition targets, staff and resources to identify and evaluate properties and available funds.  Many of our larger competitors not only drill for and produce oil and natural gas, but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis.  These companies may be able to pay more for oil and natural gas properties and evaluate, bid for and purchase a greater number of properties than our financial or human resources permit.  In addition, there is substantial competition for investment capital in the oil and natural gas industry. Our inability to compete effectively with other companies could have a material adverse effect on our business activities, financial condition and results of operations.

Risks Related to Regulatory Compliance

Potential regulatory actions could increase our operating or capital costs and delay our operations or otherwise alter the way we conduct our business.

Our business activities are subject to extensive federal, state, local and Native American tribal regulations. Changes to existing regulations or new regulations may unfavorably impact us, our suppliers or our customers. In the United States, legislation that directly impacts the oil and natural gas industry has been proposed covering areas such as emission reporting and reductions, hydraulic fracturing of wells, the repeal of certain oil and natural gas tax incentives and tax deductions and the treatment and disposal of produced water. The EPA has also ruled that carbon dioxide, methane and other greenhouse gases endanger human health and the environment. This allows the EPA to adopt and implement regulations restricting greenhouse gases under existing provisions of the federal Clean Air Act. In addition, provisions of the Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank Act”), which regulate financial derivatives, may impact our ability to enter into derivatives or require burdensome collateral or reporting requirements. These and other potential regulations could increase our costs, reduce our liquidity, impact our ability to hedge our future oil and natural gas sales, delay our operations or otherwise alter the way that we conduct our business, negatively impacting our financial condition, results of operations and cash flows.

We are subject to federal, state, local and Native American tribal laws and regulations as interpreted and enforced by governmental and Native American tribal authorities possessing jurisdiction over various aspects of the production and transportation of oil and natural gas. The possibility exists that any new laws, regulations or enforcement policies could be more stringent than existing laws and could significantly increase our compliance costs. If we are not able to recover the resulting costs from insurance or through increased revenues, our ability to pay distributions to our unitholders could be adversely affected.

Our failure to obtain or maintain necessary permits could adversely affect our operations.

Our operations are subject to complex and stringent laws and regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities and Native American tribal authorities. For example, we have a concession agreement from the Osage Nation for a substantial portion of our leases in the Cherokee Basin. 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 natural gas, NGLs and oil production by Sanchez Energy, which could reduce the throughput on our facilities and adversely impact our revenues.

A substantial portion of Sanchez Energy’s natural gas, NGLs and oil production is being developed from unconventional sources, such as shale formations.  These reservoirs require hydraulic fracturing completion processes to release the liquids and natural gas from the rock so it can flow through casing to the surface.  Hydraulic fracturing is a well stimulation process that utilizes large volumes of water and sand (or other proppant) combined with fracturing chemical additives that are pumped at high pressure to crack open previously impenetrable rock to release hydrocarbons.  Hydraulic fracturing is typically regulated by state oil and gas commissions and similar agencies.  Various studies are currently underway by the EPA and other federal and state agencies concerning the potential environmental impacts of hydraulic fracturing activities.  For example, the EPA issued an advanced notice of proposed rulemaking under the Toxic Substances Control Act in 2014 requesting comments related to disclosures for hydraulic fracturing chemicals.  At the same time, certain environmental groups have suggested that additional laws may be needed to more closely and uniformly regulate the hydraulic fracturing process, and legislation has been proposed by some members of the U.S. Congress to provide for such regulation.  We cannot predict whether any such legislation will ever be enacted and if so, what its provisions would be.  If additional levels of regulation and permits were required through the adoption of new laws and regulations at the federal or state level, that could lead to delays and process prohibitions that could reduce the volumes of liquids and natural gas that move through our facilities, which in turn could materially adversely affect our revenues and results of operations.

Sanchez Energy may incur significant liability under, or costs and expenditures to comply with, environmental and worker health and safety regulations, which are complex and subject to frequent change.

As an owner, lessee or operator of gathering pipelines and compressor stations, we are subject to various stringent federal, state and local laws and regulations relating to the discharge of materials into, and protection of, the environment.  Numerous governmental authorities, such as the EPA and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly response actions.  These laws and regulations may impose numerous obligations that are applicable to our and our customer’s operations, including the acquisition of permits to conduct regulated activities, the incurrence of capital or operating expenditures to limit or prevent releases of materials from our or our customers’ operations, the imposition of specific standards addressing worker protection, and the imposition of substantial liabilities and remedial obligations for pollution or contamination resulting from our and our customer’s operations.  Failure to comply with these laws, regulations and permits may result in joint and several, strict liability and the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, and the issuance of injunctions limiting or preventing some or all of our operations.  Private parties, including the owners of the properties through which our facilities pass and facilities where wastes resulting from our operations are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance, as well as to seek damages for non-compliance, with environmental laws and regulations or for personal injury or property damage.  We may not be able to recover all or any of these costs from insurance or Sanchez Energy.  In addition, we may experience a delay in obtaining or be unable to obtain required permits, which may interrupt our operations and limit our growth and revenues, which in turn could affect our profitability.  There is no assurance that changes in or additions to public policy regarding the protection of the environment will not have a significant impact on our operations and profitability.

The operation of our facilities also poses risks of environmental liability due to leakage, migration, releases or spills from our facilities to surface or subsurface soils, surface water or groundwater.  Certain environmental laws impose strict as well as joint and several liability for costs required to remediate and restore sites where hazardous substances, hydrocarbons, or solid wastes have been stored or released.  We may be required to remediate contaminated properties currently or formerly operated by us or facilities of third parties that received waste generated by our operations regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken.  In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations.  Moreover, public interest in the protection of the environment has increased dramatically in recent years.  The trend of more expansive and stringent environmental legislation and regulations applied to the oil and natural gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability.

We may incur significant costs and liabilities as a result of pipeline integrity management program testing and any related pipeline repair or preventative or remedial measures.

The DOT has adopted regulations requiring pipeline operators to develop integrity management programs for transportation pipelines located where a leak or rupture could do the most harm in HCAs. The regulations require operators to:

perform ongoing assessments of pipeline integrity;

identify and characterize applicable threats to pipeline segments that could impact a high consequence area;

improve data collection, integration and analysis;

repair and remediate the pipeline as necessary; and

implement preventive and mitigating actions.

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.  Effective August 1, 2016, to account for inflation, PHMSA increased the maximum administrative civil penalties for violation of the pipeline safety laws and regulations to $205,638 per day, with a maximum of $2,056,380 for a series of violations.  Should our facilities fail to comply with DOT or comparable state regulations, we could be subject to substantial penalties and fines.

PHMSA has also published advanced notices of proposed rulemaking and notices of proposed rulemaking to solicit comments on the need for changes to its safety regulations as well as advisory bulletins.  In April 2016, PHMSA issued a notice of proposed rulemaking that would expand integrity management requirements and impose new pressure requirements on currently regulated gas transmission pipelines and would also significantly expand the regulation of gas gathering lines, subjecting previously unregulated pipelines to requirements regarding damage prevention, corrosion control, public education programs, maximum allowable operating pressure limits and other requirements.  In addition, in 2012, PHMSA issued an advisory bulletin providing guidance on the verification of records related to pipeline maximum allowable operating pressure, which could result in additional requirements for the pressure testing of pipelines or the reduction of maximum operating pressures.  The adoption of these and other laws or regulations that apply more comprehensive or stringent safety standards could require us to install new or modified safety controls, pursue new capital projects, or conduct maintenance programs on an accelerated basis, all of which could require us to incur increased operational costs that could be significant.  While we cannot predict the outcome of legislative or regulatory initiatives, such legislative and regulatory changes could have a material effect on our cash flows.  Please read “Item 1. Business—Governmental Regulation—Pipeline Safety Regulation” for more information.

Because we handle oil, natural gas and other petroleum products in our business, we may incur significant costs and liabilities in the future resulting from a failure to comply with new or existing environmental regulations.

The operations of our wells, gathering systems, processing facilities, pipelines and other facilities are subject to stringent and complex federal, state and local environmental laws and regulations.  Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations.  There is an inherent risk that we may incur environmental costs and liabilities due to the nature of our business and the substances we handle.  Certain environmental statues, including RCRA, CERCLA and analogous state laws and regulations, impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances have been disposed of or otherwise released.  In addition, an accidental release from one of our facilities could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage and fines or penalties for related violations of environmental laws or regulations.

Moreover, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase our compliance costs and the cost of any remediation that may become necessary, and these costs may not be recoverable from insurance.

Risks Related to Financing and Credit Environment

Our Credit Agreement has substantial restrictions and financial covenants and requires periodic borrowing base redeterminations.

We depend on our Credit Agreement for future capital needs.  The Credit Agreement restricts our ability to obtain additional financing, make investments, lease equipment, sell assets and engage in business combinations.  We are also required to comply with certain financial covenants and ratios.  Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of cash flows from our operations and events or circumstances beyond our control, including events and circumstances that may stem from the condition of financial markets and commodity price levels.  Our failure to comply with any of the restrictions and covenants under the Credit Agreement could result in an event of default, which could cause all of our existing indebtedness to become immediately due and payable.  Each of the following is also an event of default:

failure to pay any principal when due or any interest, fees or other amount prior to the expiration of certain grace periods;

a representation or warranty made under the loan documents or in any report or other instrument furnished thereunder is incorrect when made;

failure to perform or otherwise comply with the covenants in the Credit Agreement or other loan documents, subject, in certain instances, to certain grace periods;

any event that permits or causes the acceleration of the indebtedness;

bankruptcy or insolvency events involving us or our subsidiaries;

certain changes in control as specified in the covenants to the Credit Agreement;

the entry of, and failure to pay, one or more adverse judgments in excess of $2.5 million or one or more non-monetary judgments that could reasonably be expected to have a material adverse effect and for which enforcement proceedings are brought or that are not stayed pending appeal; and

specified events relating to our employee benefit plans that could reasonably be expected to result in liabilities in excess of $2.5 million in any year.

The Credit Agreement will mature on March 31, 2020.  We may not be able to renew or replace the facility at similar borrowing costs, terms, covenants, restrictions or borrowing base, or with similar debt issue costs.

The amount available for borrowing at any one time under the Credit Agreement is limited to the separate borrowing bases associated with our oil and natural gas properties and our midstream assets.  The borrowing base for the credit available for the upstream oil and natural gas properties is re-determined semi-annually in the second and fourth quarters of the year, and may be re-determined at our request more frequently and by the lenders, in their sole discretion, based on reserve reports as prepared by petroleum engineers, using, among other things, the oil and natural gas pricing prevailing at such time.  The borrowing base for the credit available for our midstream properties is equal to the rolling four quarter EBITDA of our midstream operations multiplied by 5.0 initially, 4.75 for the second full quarter after acquiring the Western Catarina gathering system and 4.5 thereafter.  Outstanding borrowings in excess of our borrowing base must be repaid or we must pledge other oil and natural gas properties as additional collateral.  We may elect to pay any borrowing base deficiency in three equal monthly installments such that the deficiency is eliminated in a period of three months.  Any increase in our borrowing base must be approved by all of the lenders.

Our Credit Agreement contains a condition to borrowing and a representation that no material adverse effect has occurred, which includes, among other things, a material adverse change in, or material adverse effect on the business, operations, property, liabilities (actual or contingent) or condition (financial or otherwise) of us and our subsidiaries who are guarantors taken as a whole.  If a material adverse effect were to occur, we would be prohibited from borrowing under the Credit Agreement and we would be in default under the Credit Agreement, which could cause all of our existing indebtedness to become immediately due and payable. 

We will be required to make substantial capital expenditures to increase our asset base.  If we are unable to obtain needed capital or financing on satisfactory terms, our ability to make cash distributions may be diminished or our financial leverage could increase.

In order to increase our asset base, we will need to make expansion capital expenditures.  If we do not make sufficient or effective expansion capital expenditures, we will be unable to expand our business operations and, as a result, we will be unable to increase our future cash distributions.  To fund our expansion capital expenditures and investment capital expenditures, we will be required to use cash from our operations or incur borrowings.  Such uses of cash from our operations will reduce cash available for distribution to our unitholders.  Alternatively, we may sell additional common units or other securities to fund our capital expenditures.  Our ability to obtain bank financing or our ability to access the capital markets for future equity or debt offerings may be limited by our or Sanchez Energy’s financial condition at the time of any such financing or offering and the covenants in our existing debt agreements, as well as by general economic conditions, contingencies and uncertainties that are beyond our control.  Even if we are successful in obtaining the necessary funds, the terms of such financings could limit our ability to pay distributions to our unitholders.  In addition, incurring additional debt may significantly increase our interest expense and financial leverage, and issuing additional

limited partner interests may result in significant unitholder dilution and would increase the aggregate amount of cash required to maintain the then-current distribution rate, which could materially decrease our ability to pay distributions at the prevailing distribution rate.  None of our general partner, Sanchez Energy or any of their respective affiliates is committed to providing any direct or indirect support to fund our growth.

We may not be able to extend, replace or refinance our Credit Agreement on terms reasonably acceptable to us, or at all, which could materially and adversely affect our business, liquidity, cash flows and prospects.

Our Credit Agreement matures on March 31, 2020. We may not be able to extend, replace or refinance our existing Credit Agreement on terms reasonably acceptable to us, or at all, with our existing syndicate of banks or with replacement banks. In addition, we may not be able to access other external financial resources sufficient to enable us to repay the debt outstanding under our Credit Agreement upon its maturity. Any of the foregoing could materially and adversely affect our business, liquidity, cash flows and prospects.

Our Credit Agreement may restrict us from paying any distributions on our outstanding units.

We have the ability to pay distributions to unitholders under our Credit Agreement from available cash, including cash from borrowings under the Credit Agreement, as long as no event of default exists and provided that no distribution to unitholders may be made if the borrowings outstanding, net of available cash, under our Credit Agreement exceed 90% of the borrowing base, after giving effect to the proposed distribution. Our available cash is reduced by any cash reserves established by the board of directors of our general partner for the proper conduct of our business and the payment of fees and expenses. Our ability to pay distributions to our unitholders in any quarter will be solely dependent on our ability to generate sufficient cash from our operations and is subject to the approval of the board of directors of our general partner.

Our ability to access the capital and credit markets to raise capital and borrow on favorable terms will be affected by disruptions in the capital and credit markets, which could adversely affect our operations, our ability to make acquisitions and our ability to pay distributions to our unitholders.

Disruptions in the capital and credit markets could limit our ability to access these markets or significantly increase our cost to borrow.  Some lenders may increase interest rates, enact tighter lending standards, refuse to refinance existing debt at maturity on favorable terms or at all and may reduce or cease to provide funding to borrowers.  If we are unable to access the capital markets on favorable terms, our ability to make acquisitions and pay distributions could be affected.

We are exposed to credit risk in the ordinary course of our business activities.

We are exposed to risks of loss in the event of nonperformance by our customers, vendors, lenders in our Credit Agreement and counterparties to our hedging arrangements. Some of our customers, vendors, lenders and counterparties may be highly leveraged and subject to their own operating and regulatory risks. Despite our credit review and analysis, we may experience financial losses in our dealings with these and other parties with whom we enter into transactions as a normal part of our business activities. Any nonpayment or nonperformance by our customers, vendors, lenders or counterparties could have a material adverse impact on our business, financial condition, results of operations or ability to pay distributions.

Our future debt levels may limit our flexibility to obtain additional financing and pursue other business opportunities.

We may incur substantial additional indebtedness in the future under our Credit Agreement or otherwise. Our future indebtedness could have important consequences to us, including:

our ability to obtain additional financing, if necessary, for working capital, maintenance and investment capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;

covenants and financial tests contained in our existing and future credit and debt instruments may affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities;

increased cash flows required to make principal and interest payments on our indebtedness could reduce the funds that would otherwise be available to fund operations, capital expenditures, future business development or any distributions to unitholders; and

our debt level may make us more vulnerable than our competitors with less debt to competitive pressures or a downturn in our business or the economy generally.

Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future debt, we will be forced to take actions such as reducing any distributions, reducing or delaying business activities, acquisitions, investments and/or capital expenditures, selling assets, restructuring or refinancing our indebtedness, or seeking additional equity capital or bankruptcy protection. We may not be able to affect any of these remedies on satisfactory terms or at all.

Periods of inflation or stagflation, or expectations of inflation or stagflation, could increase our costs and adversely affect our business and operating results.

During periods of inflation or stagflation, our costs of doing business could increase, including increases in the variable interest rates that we pay on amounts we borrow under our Credit Agreement.  As we have hedged a large percentage of our future expected production volumes, the cash flows generated by that future hedged production will be capped. If any of our operating, administrative or capital costs were to increase as a result of inflation or any temporary or long-term increase in the cost of goods and services, such a cap could have a material adverse effect on our business, financial condition, results of operations, ability to pay distributions and the market price of our common units.

An increase in interest rates may cause the market price of our common units to decline and may increase our borrowing costs.

Like all equity investments, an investment in our common units is subject to certain risks. In exchange for accepting these risks, investors may expect to receive a higher rate of return than would otherwise be obtainable from lower-risk investments. Accordingly, as interest rates rise, the ability of investors to obtain higher risk-adjusted rates of return by purchasing government-backed debt or other interest-bearing securities may cause a corresponding decline in demand for riskier investments generally, including equity investments such as publicly-traded limited partnership interests. Reduced demand for our common units resulting from investors seeking other more favorable investment opportunities may cause the trading price of our common units to decline.

Higher interests rates may also increase the borrowing costs associated with our Credit Agreement. If our borrowing costs were to increase, our interest payments on our debt may increase, which would reduce the amount of cash available for our operating or capital activities or for any distribution to unitholders.

The swaps regulatory provisions of the Dodd-Frank Act and the rules adopted thereunder and other regulations, including EMIR, may adversely affect our ability to hedge risks associated with our business and our results of operations and cash flows.

The swaps regulatory provisions of the Dodd-Frank Act and the rules of the Commodity Futures Trading Commission (“CFTC”) thereunder now in effect and adopted by the CFTC in the future may adversely affect our ability to manage certain of our risks on a cost effective basis. As mandated by the Dodd-Frank Act, the CFTC has proposed rules to set limits on the positions market participants may hold in certain core futures and futures equivalent contracts, option contracts or swaps for or linked to certain physical commodities, including certain oil and natural gas, subject to exceptions for certain bona fide hedging and other types of transactions. If the position limits in the proposed rules or other similar position limits are imposed, our ability to execute our hedging strategies described above could be compromised.

Under the swaps regulatory provisions of the Dodd-Frank Act and the rules adopted thereunder, we could have to clear on a designated clearing organization and execute on certain markets any swap that we enter into that falls within a class of swaps designated by the CFTC for mandatory clearing unless we qualify for an exception from such requirements as to such swap.  The CFTC has designated six classes of interest rate swaps and credit default swaps for mandatory clearing, but has not yet proposed rules designating any class of physical commodity swaps or other class of swaps for

mandatory clearing. Although we expect to qualify for the end-user exception from the mandatory clearing and trade execution requirements for the swaps that we enter into to hedge our commercial risks, if we were to fail to qualify for that exception as to a swap we enter into and were required to clear that swap, we would have to post margin with respect to such swap, our cost of entering into and maintaining such swap could increase and we would have less flexibility with respect to that swap than we would enjoy were the swap not cleared. Moreover, the application of the mandatory clearing and trade execution requirements and other swap regulations to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging.

As required by the Dodd-Frank Act, the CFTC and the federal banking regulators have adopted rules requiring certain market participants to collect initial and variation margin with respect to uncleared swaps from their counterparties except as to any uncleared swaps as to which the counterparty qualifies for the end user exception from the mandatory clearing exception.  Although those rules do not require initial margin to be collected from non-financial end users of uncleared swaps, an affected market participant must collect from its counterparty to any uncleared swap that is a non-financial end user, but that does not qualify for the end user exception with respect to that uncleared swap, variation margin with respect to that swap at those times and in those forms and amounts as the market participant determines appropriately addresses the credit risk posed by that counterparty and the risk of that swap.  The requirements of those rules relating to initial margin are being phased through September 1, 2020.  Were we not to qualify for the end user exception as to any of our uncleared swaps and otherwise have to post initial or variation margin as to our uncleared swaps in the future, our cost of entering into and maintaining swaps would increase.  In addition, our counterparties that are subject to the regulations imposing the Basel III capital requirements on them may increase the cost to us of entering into swaps with them or contractually require us to post collateral or greater amounts of collateral with them in connection with such swaps to offset their increased capital costs or to reduce their capital costs to maintain those swaps on their balance sheets.

The European Market Infrastructure Regulation (“EMIR”) includes regulations related to the trading, reporting, clearing of derivatives and providing margin with respect to derivatives.  EMIR may result in increased costs for OTC derivative counterparties and also lead to an increase in the costs of, and demand for, the liquid collateral with respect to any swap to which we are a party and that is governed by EMIR.  Therefore, EMIR may impact our ability to maintain or enter into derivatives with certain of our European counterparties.

The Dodd-Frank Act’s swaps regulatory provisions, the related rules described above and the record keeping, reporting and business conduct rules imposed by the Dodd-Frank Act on other swaps market participants, as well as EMIR and the regulations imposing the Basel III capital requirements on certain swaps market participants, could significantly increase the cost of derivative contracts (including through requirements to post margin or other collateral, which could adversely affect our available liquidity), materially alter the terms of the derivative contracts that we enter into, particularly the provisions relating to the our need to provide margin with respect to, or collateralize our obligations under such derivative contracts, reduce the availability of derivatives to protect against certain risks that we encounter, reduce our ability to monetize or restructure our existing derivative contracts and to execute our hedging strategies. If, as a result of the swaps regulatory regime discussed above, we were to reduce our use of swaps to hedge our risks, such as commodity price risks that we encounter in our operations, our results of operations and cash flows may become more volatile and could be otherwise adversely affected.

Risks Related to Our Distributions to Unitholders

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

A principal focus of our strategy is to increase the quarterly cash distributions that we pay to our unitholders over time.  Our ability to increase our distributions depends on our ability to complete expansion projects and make acquisitions that result in an increase in cash generated.  We may be unable to complete successful, accretive expansion projects or acquisitions for any of the following reasons:

an inability to identify attractive expansion projects or acquisition candidates or we are outbid by competitors;

an inability to obtain necessary rights-of-way or governmental approvals, including from regulatory agencies;

an inability to successfully integrate the businesses that we develop or acquire;

an inability to obtain financing for such expansion projects or acquisitions on economically acceptable terms, or at all;

incorrect assumptions about volumes, reserves, revenues and costs, including synergies and potential growth; or

an inability to secure adequate customer commitments to use the newly developed or acquired facilities.

We may not have sufficient available cash from operations to pay our quarterly distributions to unitholders following the establishment of cash reserves and the payment of fees and expenses.

The amount of available cash from which we may pay distributions is defined in both our Credit Agreement and our partnership agreement.  The amount of available cash that we distribute is subject to the definition of operating surplus in our partnership agreement. Ultimately, the amount of available cash that we may distribute to our unitholders principally depends upon the amount of cash that we generate from our operations, which will fluctuate from quarter to quarter based on numerous factors generally described in this caption “Risk Factors.”  These and other factors that affect that amount that we can distribute include:

the amount of oil and natural gas that we produce;

the amount of revenue generated from our facilities;

the demand for and the price at which we are able to sell our oil and natural gas production;

the results of our hedging activity;

the level of our operating costs;

the costs that we incur to acquire midstream assets and oil and natural gas properties;

whether we are able to continue our development activities at economically attractive costs;

the borrowing base under our Credit Agreement as determined by our lenders;

the amount of our indebtedness outstanding;

the level of our interest expense, which depends on the amount of our indebtedness and the interest payable thereon;

the amount of working capital required to operate our business and our ability to make working capital borrowings under our Credit Agreement;

fluctuations in our working capital needs;

the amount of cash reserves established by the board of directors of our general partner for the proper conduct of our business, including the maintenance of our asset base and the payment of future distributions on our common units and incentive distribution rights; and

the level of our maintenance capital expenditures.

As a result of these factors, we may not have sufficient available cash to maintain or increase our quarterly distributions. The amount of available cash that we could distribute from our operating surplus in any quarter to our unitholders may fluctuate significantly from quarter to quarter and may be significantly less than any prior distributions that we have previously made. If we do not have sufficient available cash or operating cash flows to maintain or increase quarterly distributions, the market price of our common units may decline substantially.

In order for us to make a distribution from available cash under our Credit Agreement, our outstanding debt balances, net of available cash, must be less than 90% of our borrowing base, as determined by our lenders, after giving effect to the proposed distribution. Our available cash excludes any cash reserves established by the board of directors of our general

partner for the proper conduct of our business and the payment of fees and expenses. We are subject to additional future borrowing base redeterminations before our Credit Agreement matures in March 2020 and cannot forecast the level at which our lenders will set our future borrowing base. If our lenders reduce our borrowing base because of any of the numerous factors generally described in this caption “Risk Factors,” our outstanding debt balances, net of available cash, may exceed 90% of the borrowing base, as determined by our lenders, and we may be unable to make quarterly distributions.

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

The amount of cash that we have available for distribution depends primarily on our operating cash flows, including cash from reserves and working capital (which may include short-term borrowings), and not solely on our profitability, which is affected by non-cash items. As a result, we may be unable to pay distributions even when we record net income, and we may pay distributions during periods when we incur net losses.

Oil and natural gas prices are very volatile. If commodity prices decline significantly for a temporary or prolonged period, our cash from operations may decline and may adversely impact our ability to invest in new drilling opportunities, 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. In particular, declines in commodity prices will reduce the value of our reserves, our operating cash flows, our ability to borrow money or raise capital and our ability to pay distributions. 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:

the domestic and foreign supply of and demand for oil and natural gas;

the price and level of foreign imports of oil and natural gas;

the level of consumer product demand; 

weather conditions;

overall domestic and global economic conditions;

political and economic conditions in oil and natural gas producing countries, including those in West Africa, the Middle East and South America;

the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;

the impact of U.S. dollar exchange rates on oil and natural gas prices; technological advances affecting energy consumption;

domestic and foreign governmental regulations and taxation;

the impact of energy conservation efforts;

the costs, proximity and capacity of oil and natural gas pipelines and other transportation facilities;

the price and availability of alternative fuels; and

the increase in the supply of natural gas due to the development of natural gas.

In the past, the prices of oil and natural gas have been extremely volatile, and we expect this volatility to continue. If we raise our distribution level in response to increased operating cash flows during periods of relatively high commodity prices, we may not be able to sustain those distribution levels during periods of lower commodity price levels.

Our operations require substantial capital expenditures, which will reduce any cash available for distribution to our unitholders.

We will need to make substantial capital expenditures to maintain our reserves over the long-term. These maintenance capital expenditures may include capital expenditures associated with completion of additional wells to offset the production decline from our producing properties or additions to our inventory of unproved properties or our proved reserves to the extent such additions maintain our asset base. These expenditures could increase as a result of:

changes in our reserves;

changes in oil and natural gas prices;

changes in labor and drilling costs;

our ability to acquire, locate and produce reserves;

changes in leasehold acquisition or concession costs; and

government regulations relating to safety, taxation and the environment.

Our maintenance capital expenditures will reduce the amount of cash that we may have available for distribution to our unitholders. In addition, our actual capital expenditures will vary from quarter to quarter. If we fail to make sufficient capital expenditures, our future production levels will decline, which may materially and adversely affect our future revenues and amount of cash available for distribution to our unitholders.

Each quarter we are required to deduct estimated maintenance capital expenditures from operating surplus, which may result in less cash available for distribution to unitholders than if actual maintenance capital expenditures were deducted.

Our partnership agreement requires us to deduct estimated, rather than actual, maintenance capital expenditures from operating surplus. The amount of estimated maintenance capital expenditures deducted from operating surplus will be subject to review and potential change by the board of directors of our general partner at least once a year. In years when our estimated maintenance capital expenditures are higher than actual maintenance capital expenditures, the amount of cash available for distribution to unitholders will be lower than if actual maintenance capital expenditures were deducted from operating surplus. If we underestimate the appropriate level of estimated maintenance capital expenditures, we may have less cash available for distribution in future periods when actual capital expenditures begin to exceed our previous estimates. Over time, if we do not set aside sufficient cash reserves or have available sufficient sources of financing and make sufficient expenditures to maintain our asset base, we will be unable to pay distributions in full, if at all.

Our hedging activities could result in financial losses or could reduce our income, which may adversely affect our ability to pay distributions.

To achieve more predictable cash flows and to reduce our exposure to adverse fluctuations in the prices of oil and natural gas, our current practice is to hedge, subject to the terms of our Credit Agreement, a significant portion of our expected production volumes for up to five years. As a result, we will continue to have direct commodity price exposure on the unhedged portion of our production volumes. The extent of our commodity price exposure is related largely to the effectiveness and scope of our hedging activities. For example, the derivative instruments that we utilize are generally based on posted market prices, which may differ significantly from the actual oil and natural gas prices that we realize in our operations.

Our actual future production may be significantly higher or lower than we estimated at the time we entered into hedging transactions for such period. If the actual amount is higher than we estimate, we will have greater commodity

price exposure than we intended. If the actual amount is lower than the nominal amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flows from our sale or purchase of the underlying physical commodity, which may result in a substantial diminution of our liquidity. As a result of these factors, our hedging activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows. In addition, our hedging activities are subject to the following risks:

a counterparty may not perform its obligation under the applicable derivative instrument;

there may be a change in the expected differential between the underlying commodity price in the derivative instrument and the actual price received; and

the steps that we take to monitor our derivative financial instruments may not detect and prevent violations of our risk management policies and procedures.

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

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

the risk that reserves expected to support the acquired assets may not be of the anticipated magnitude or may not be developed as anticipated;

the risk of title defects discovered after closing;

inaccurate assumptions about revenues and costs, including synergies;

significant increases in our indebtedness and working capital requirements;

an inability to transition and integrate successfully or timely the businesses we acquire;

the cost of transition and integration of data systems and processes;

potential environmental problems and costs;

the assumptions of unknown liabilities;

limitations on rights to indemnity from the seller;

the diversion of management’s attention from other business concerns;

increased demands on existing personnel and on our organizational structure;

disputes arising out of acquisitions;

customer or key employee losses of the acquired businesses; and

the failure to realize expected growth or profitability.

The scope and cost of these risks may ultimately be materially greater than estimated at the time of the acquisition.  Furthermore, our future acquisition costs may be higher than those we have achieved historically.  Any of these factors could adversely impact our future growth and our ability to pay distributions.

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:

Neither our partnership agreement nor any other agreement requires Manager and its affiliates to pursue a business strategy that favors us or utilizes our assets. The directors and officers of Manager and its affiliates have a fiduciary duty to make these decisions in the best interests of the members of Manager and its affiliates, which may be contrary to our interests. Manager and its affiliates may choose to shift the focus of its investment and growth to areas not served by our assets.

Our general partner is allowed to take into account the interests of parties other than us, such as SOG, Manager and their affiliates, in resolving conflicts of interest.

Manager and its affiliates may be constrained by the terms of their respective debt instruments from taking actions, or refraining from taking actions, that may be in our best interests.

Our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing its duties, limit our general partner’s liabilities and restrict the remedies available to our unitholders for actions that, without such limitations, might constitute breaches of fiduciary duty.

Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.

Disputes may arise under our commercial agreements with Manager, SOG and their affiliates.

Our general partner determines the amount and timing of asset purchases and sales, borrowings, issuances of additional partnership units and the creation, reduction or increase of cash reserves, each of which can affect the amount of cash available for distribution to our unitholders.

Our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which will reduce operating surplus, or an expansion or investment capital expenditure, which will not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders.

Our general partner determines which costs incurred by it are reimbursable by us, the amount of which is not limited by our partnership agreement.

Our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make incentive distributions.

Our partnership agreement permits us to classify up to $20.0 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions to Manager as the holder of the incentive distribution rights.

Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf.

Our general partner intends to limit its liability regarding our contractual and other obligations.

Our general partner and its controlled affiliates may exercise their right to call and purchase all of the common units not owned by them if they own more than 80% of the common units.

Our general partner controls the enforcement of the obligations that it and its affiliates owe to us, including the obligations of SOG and its affiliates under their commercial agreements with us.

Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

Our general partner may elect to cause us to issue common units to Manager in connection with a resetting of the target distribution levels related to our incentive distribution rights without the approval of the conflicts committee of the board of directors of our general partner or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.

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:

the level of our quarterly distributions;

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

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

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

general economic conditions, including interest rates and governmental policies impacting interest rates;

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

future sales of our common units; and

other factors described in this proxy statement/prospectus and the documents incorporated herein.

Our partnership agreement replaces our general partner’s fiduciary duties to holders of our common units with contractual standards governing its duties.

Our partnership agreement contains provisions that eliminate the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law and replace those duties with several different contractual standards. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner, free of any duties to us and our unitholders other than the implied contractual covenant of good faith and fair dealing, which means that a court will fill gaps under the partnership agreement to enforce the reasonable expectations of the partners, but only where the language in the partnership agreement does not provide for a clear course of action. This provision entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our general partner may make in its individual capacity include:

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

whether to exercise its limited call right;

whether to seek approval of the resolution of a conflict of interest by the conflicts committee of the board of directors of our general partner; and

whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement.

Our partnership agreement restricts the remedies available to holders of our common units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

The effect of eliminating fiduciary standards in our partnership agreement is that the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law will be significantly restricted. For example, our partnership agreement provides that:

whenever our general partner, the board of directors of our general partner or any committee thereof (including the conflicts committee) makes a determination or takes, or declines to take, any other action in their respective capacities, our general partner, the board of directors of our general partner and any committee thereof (including the conflicts committee), as applicable, is required to make such determination, or take or decline to take such other action, in good faith, and under our partnership agreement, a determination, other action or failure to act by our general partner and any committee thereof (including the conflicts committee) will be deemed to be in good faith unless the general partner, the board of directors of the general partner or any committee thereof (including the conflicts committee) believed that such determination, other action or failure to act was adverse to the interests of the partnership or, with regard to certain determinations by the board of directors of our general partner relating to the conflict transactions described below, the board of directors of our general partner did not believe that the specified standards were met, and, except as specifically provided by our partnership agreement, neither our general partner, the board of directors of our general partner nor any

committee thereof (including the conflicts committee) will be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;

our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as such decisions are made in good faith;

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

our general partner will not be in breach of its obligations under the partnership agreement (including any duties to us or our unitholders) if a transaction with an affiliate or the resolution of a conflict of interest is:

In connection with a situation involving a transaction with an affiliate or a conflict of interest, any determination by our general partner or the conflicts committee must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the conflicts committee and the board of directors of our general partner determine that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest satisfies either of the standards set forth in the third and fourth sub-bullets above, then it will be presumed that, in making its decision, the board of directors of our general partner acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership challenging such determination, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

Furthermore, if any limited partner, our general partner or any person holding any beneficial interest in us brings any claims, suits, actions or proceedings (including, but not limited to, those asserting a claim of breach of a fiduciary duty) and such person does not obtain a judgment on the merits that substantially achieves, in substance and amount, the full remedy sought, then such limited partner, our general partner or person holding any beneficial interest in us shall be obligated to reimburse us and our “affiliates,” as defined in Section 1.1 of our partnership agreement (including our general partner, the directors and officers of our general partner, SOG and Manager) for all fees, costs and expenses of every kind and description, including, but not limited to, all reasonable attorney’s fees and other litigation expenses, that the parties may incur in connection with such claim, suit, action or proceeding.

Our partnership agreement includes exclusive forum, venue and jurisdiction provisions and limitations regarding claims, suits, actions or proceedings. By taking ownership of a common unit, a limited partner is irrevocably consenting to these provisions and limitations regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of Delaware courts.

Our partnership agreement is governed by Delaware law. Our partnership agreement includes exclusive forum, venue and jurisdiction provisions designating Delaware courts as the exclusive venue for most claims, suits, actions and proceedings involving us or our officers, directors and employees and limitations regarding claims, suits, actions or proceedings. By taking ownership of a common unit, a limited partner is irrevocably consenting to these provisions and limitations regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of Delaware courts.

If a dispute were to arise between a limited partner and us or our officers, directors or employees, the limited partner may be required to pursue its legal remedies in Delaware, which may be an inconvenient or distant location and which is considered to be a more corporate-friendly environment. Furthermore, if any limited partner, our general partner or person holding any beneficial interest in us brings any claims, suits, actions or proceedings (including, but not limited to, those asserting a claim of breach of a fiduciary duty) and such person does not obtain a judgment on the merits that substantially achieves, in substance and amount, the full remedy sought, then such limited partner, our general partner or person holding any beneficial interest in us shall be obligated to reimburse us and our “affiliates,” as defined in Section 1.1 of our partnership agreement (including our general partner, the directors and officers of our general partner, SOG and Manager) for all fees, costs and expenses of every kind and description, including, but not limited to, all reasonable attorneys’ fees and other litigation expenses, that the parties may incur in connection with such claim, suit, action or proceeding. This provision may have the effect of increasing a unitholder’s cost of asserting a claim and therefore, discourage lawsuits against us and our general partner’s directors and officers. Because fee-shifting provisions such as these are relatively new developments in corporate and partnership law, the enforceability of such provisions are uncertain; in addition, future legislation could restrict or limit this provision of our partnership agreement and its effect of saving us and our affiliates from fees, costs and expenses incurred in connection with claims, actions, suits or proceedings.

Holders of our common units will have limited voting rights and will not be entitled to elect our general partner or its directors.

Our common unitholders have limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s and our general partner’s decisions regarding our business. Common unitholders will have no right on an annual or ongoing basis to elect our general partner or its board of directors. Rather, the board of directors of our general partner will be appointed by Manager. Furthermore, if common unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which the 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 the common unitholders’ ability to influence the manner or direction of management.

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

Common unitholders’ voting rights are further restricted by a provision of our partnership agreement providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter.

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 the common unitholders. Furthermore, there is no restriction in the partnership agreement on the ability of Manager to transfer its membership interest in our general partner to a third party. The new members of our general partner would then be in a position to replace the board of directors and officers of our general partner with their own choices and to control the decisions taken by the board of directors and officers.

The incentive distribution rights held by Manager may be transferred to a third party without unitholder consent.

Manager is able to transfer its incentive distribution rights to a third party at any time without the consent of our common unitholders. If Manager transfers its incentive distribution rights to a third party but retains its ownership interest in our general partner, our general partner may not have the same incentive to grow our partnership and increase quarterly distributions to unitholders over time as it would if Manager had retained ownership of the incentive distribution rights. For example, a transfer of incentive distribution rights by Manager could reduce the likelihood of SOG or its affiliates

accepting offers made by us relating to assets owned by it or its affiliates, as they would have less of an economic incentive to grow our business, which in turn would impact our ability to grow our asset base.

Following the conversion of the Class B preferred units, you may experience dilution of your common units and we may not have sufficient available cash to enable us to maintain or increase the quarterly distribution amount on our common units.

As of March 23, 2017, there were 31,000,887 Class B preferred units issued and outstanding which are convertible at any time into not less than 31,000,887 common units (plus additional common units resulting from the issuance of paid-in-kind distributions, if any, on such preferred units). Any future conversion of the Class B preferred units would dilute the percentage ownership held by our common unit holders. Additionally, any future conversion of Class B preferred units will result in the payment of distributions on any additional common units issued as a result of such conversion, and we may not have sufficient available cash to maintain or increase the quarterly distribution amount on our common units following the payment of such distributions.

We are able to issue additional units without common unitholder approval, which would dilute unitholder interests.

Our partnership agreement does not limit the number of additional limited partner interests, including limited partner interests that rank senior to the 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 existing limited partners’ proportionate ownership interest in us will decrease;

the amount of cash available for distribution on each limited partnership interest may decrease;

because the amount payable to holders of incentive distribution rights is based on a percentage of the total cash available for distribution, the distributions to holders of incentive distribution rights will increase even if the per unit distribution on common units remains the same;

the ratio of taxable income to distributions may increase;

the relative voting strength of each previously outstanding limited partner interest may be diminished; and

the market price of the common units may decline.

Our general partner intends to limit its liability regarding our obligations.

Our general partner intends to limit its liability under contractual arrangements so that the counterparties to such arrangements have recourse only against our assets and not against our general partner or its assets. Our general partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to our general partner. Our partnership agreement permits our general partner to limit its liability, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our general partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our unitholders.

Manager, or any transferee holding a majority of the incentive distribution rights, may elect to cause us to issue common units to it in connection with a resetting of the minimum quarterly distribution and the target distribution levels related to the incentive distribution rights, without the approval of the conflicts committee of our general partner or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.

The holder or holders of a majority of the incentive distribution rights, which is initially Manager, has the right, at any time when such holders have received incentive distributions at the highest level to which they are entitled (35.5%) for each of the prior four consecutive fiscal quarters (and the amount of each such distribution did not exceed adjusted

operating surplus for each such quarter), to reset the minimum quarterly distribution and the initial target distribution levels at higher levels based on our cash distribution at the time of the exercise of the reset election. Following a reset election, the minimum quarterly distribution will be reset to an amount equal to the average cash distribution per unit for the two fiscal quarters immediately preceding the reset election (such amount is referred to as the “reset minimum quarterly distribution”), and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution. Manager has the right to transfer the incentive distribution rights at any time, in whole or in part, and any transferee holding a majority of the incentive distribution rights will have the same rights as Manager with respect to resetting target distributions.

In the event of a reset of the minimum quarterly distribution and the target distribution levels, the holders of the incentive distribution rights will be entitled to receive, in the aggregate, the number of common units equal to that number of common units which would have entitled the holders to an average aggregate quarterly cash distribution in the prior two quarters equal to the distributions on the incentive distribution rights in the prior two quarters. We anticipate that Manager would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not otherwise be sufficiently accretive to cash distributions per common unit. It is possible, however, that Manager or a transferee could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions that it receives related to its incentive distribution rights and may therefore desire to be issued common units rather than retain the right to receive incentive distribution payments based on target distribution levels that are less certain to be achieved in the then-current business environment. This risk could be elevated if our incentive distribution rights have been transferred to a third party. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued common units to Manager in connection with resetting the target distribution levels.

Your liability may not be limited if a court finds that unitholder action constitutes control of our business.

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law, and we conduct business in and outside of Delaware. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. You could be liable for any and all of our obligations as if you were a general partner if a court or government agency were to determine that:

we were conducting business in a state but had not complied with that particular state’s partnership statute; or

your right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.

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 MKT 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 MKT does not require us to have a majority of independent directors on our general partner’s board of directors or to establish a compensation committee or a nominating

and corporate governance committee. Accordingly, unitholders will not have the same protections afforded to certain corporations that are subject to all of the NYSE MKT corporate governance requirements.

We are a “smaller reporting company” and the reduced disclosure requirements applicable to smaller reporting companies may make our common units less attractive to investors.

We are considered a “smaller reporting company” (a company that has a public float of less than $75 million as of June 30, 2016).  We are therefore entitled to rely on certain reduced disclosure requirements, such as an exemption from providing selected financial data and executive compensation information.  We are also exempt from the requirement to obtain an external audit on the effectiveness of internal control over financial reporting provided in Section 404(b) of the Sarbanes-Oxley Act.  We have utilized this exemption for each year since the year ended December 31, 2011.  These exemptions and reduced disclosures in our SEC filings due to our status as a smaller reporting company mean our auditors do not review our internal control over financial reporting and may make it harder for investors to analyze our results of operations and financial prospects.  We cannot predict if investors will find our common units less attractive because we may rely on these exemptions.  If some investors find our common units less attractive as a result, there may be a less active trading market for our common units and our unit prices may be more volatile.

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

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

the risk that reserves expected to support the acquired assets may not be of the anticipated magnitude or may not be developed as anticipated;

the risk of title defects discovered after closing;

inaccurate assumptions about revenues and costs, including synergies;

significant increases in our indebtedness and working capital requirements;

an inability to transition and integrate successfully or timely the businesses we acquire;

the cost of transition and integration of data systems and processes;

potential environmental problems and costs;

the assumptions of unknown liabilities;

limitations on rights to indemnity from the seller;

the diversion of management’s attention from other business concerns;

increased demands on existing personnel and on our organizational structure;

disputes arising out of acquisitions;

customer or key employee losses of the acquired businesses; and

the failure to realize expected growth or profitability.

The scope and cost of these risks may ultimately be materially greater than estimated at the time of the acquisition.  Furthermore, our future acquisition costs may be higher than those we have achieved historically.  Any of these factors could adversely impact our future growth and our ability to pay distributions.

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. A publicly traded partnership may be treated as a corporation for U.S. federal income tax purposes unless it satisfies 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 rates, which is currently at a maximum marginal rate of 35%, and would likely pay state and local income tax at varying rates. Distributions to unitholders would generally be taxed as corporate distributions, and no income, gains, losses, deductions or credits would flow through to the unitholders. Because a tax would be imposed on us as a corporation, our cash available for distribution to our unitholders would be reduced.  Therefore, if we were treated as a corporation for U.S. federal income tax purposes or otherwise subjected to a material amount of entity-level taxation, there would be a material reduction in the anticipated cash flow and after-tax return to our unitholders likely causing a substantial reduction in the value of our common units.

In addition, changes in current state law may subject us to additional entity-level taxation by individual states. Due to widespread state budget deficits and for other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of any such taxes may materially reduce the cash available for distribution to our unitholders.

Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution 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 propose and consider substantive changes to the existing U.S. federal income tax laws that affect publicly traded partnerships. Further, final regulations under Section 7704(d)(l)(E) of the Code recently published in the Federal Register interpret the scope of the qualifying income requirements for publicly traded partnerships by providing industry-specific guidance.  Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible for us to meet the exception to be treated as a partnership for U.S. federal income tax purposes. We are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes could adversely affect an investment in our common units.

Certain U.S. federal income tax deductions currently available with respect to oil and natural gas exploration and development may be eliminated as a result of future legislation.

From time to time members of Congress propose changes that would, if enacted into law, make significant changes to U.S. tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas production companies.  The passage of any legislation changing U.S. federal income tax laws could eliminate

or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such change could increase the taxable income allocable to our unitholders and negatively impact the value of an investment in our common units.

Our common unitholders’ share of our income will be taxable to them even if they do not receive any cash distributions from us.

Common unitholders are required to pay U.S. federal income and other taxes and, in some cases, state and local income taxes, on their share of our taxable income, whether or not they receive cash distributions from us. Our common unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income. 

The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for U.S. federal income tax purposes.

We will be considered to have technically terminated our existing partnership and having formed a new partnership for U.S. federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once. Our termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1 if relief was not available, as described below) for one fiscal year and could result in a deferral of depreciation deductions allowable in computing our taxable income for the year of termination. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in such unitholder’s taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for U.S. federal income tax purposes, but instead we would be treated as a new partnership for U.S. federal income tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we were unable to determine in a timely manner that a termination occurred. Pursuant to an IRS relief procedure the IRS may allow, among other things, a constructively terminated partnership to provide a single Schedule K-1 for the calendar year in which a termination occurs.

A successful IRS contest of the U.S. federal income tax positions we take may adversely affect the market for our common units, and the costs of any contest will reduce cash available for distribution.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for U.S. federal income tax purposes or any other matter affecting us.  The IRS may adopt positions that differ from the positions we take.  It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take, and a court may disagree with some or all of those positions.  Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade.  In addition, our costs of any contest with the IRS will result in a reduction in cash available for distribution to our unitholders and thus will be borne indirectly by our unitholders.

Legislation applicable to partnership tax years beginning after 2017 alters the procedures for auditing partnerships and for assessing and collecting taxes due (including penalties and interest) as a result of a partnership-level federal income tax audit.  Under these partnership tax rules, under certain circumstances, the IRS may assess and collect taxes (including any applicable penalties and interest) directly from us in the year in which the audit is completed.  If we are required to pay taxes, penalties and interest as a result of audit adjustments, cash available for distribution to our unitholders may be substantially reduced.  In addition, because payment would be due for the taxable year in which the audit is completed, unitholders during that taxable year would bear the expense of the adjustment even if they were not unitholders during the audited tax year.

Tax-exempt entities and foreign persons face unique tax issues from owning common units that may result in adverse tax consequences to them.

Investment in common units by tax-exempt entities, including employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons 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 may be taxable to such a unitholder. Distributions to non-U.S. persons will be reduced by withholding taxes imposed at the highest effective applicable tax rate, and non-U.S. persons will be required to file U.S. federal income tax returns and pay tax on their share of our taxable income.

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 the 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. It 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.

Tax gain or loss on the disposition of our common units could be more or less than expected.

If a common unitholder sells common units, the unitholder will recognize gain or loss equal to the difference between the amount realized and the tax basis in those common units. Because distributions in excess of a unitholder’s allocable share of our net taxable income decrease the unitholder’s tax basis in its common units, the amount, if any, of such prior excess distributions with respect to the common units a unitholder sells will, in effect, become taxable income to the unitholder if it sells such common units at a price greater than its tax basis in those common units, even if the price received is less than its original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation, depletion and intangible drilling cost recapture. In addition, because the amount realized may include a unitholder’s share of our nonrecourse liabilities, a unitholder that sells common units may incur a tax liability in excess of the amount of cash received from the sale.

Unitholders may be subject to state and local taxes and return filing requirements in states where they do not live as a result of an investment in our common units.

In addition to U.S. federal income taxes, our unitholders are likely 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.

We have adopted certain valuation methodologies in determining a unitholder’s allocations of income, gain, loss and deduction. The IRS may challenge these methodologies or the resulting allocations, and such a challenge could adversely affect the value of our common units.

In determining the items of income, gain, loss and deduction allocable to our unitholders, we must routinely determine the fair market value of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we make many fair market value estimates ourselves using a methodology based on the market value of our common units as a means to determine the fair market value of our assets. The IRS may challenge these valuation methods and the resulting allocations of income, gain, loss and deduction.

A successful IRS challenge to these methods or allocations could adversely affect the timing or amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

We prorate our items of income, gain, loss and deduction between transferors and transferees of common units each month based upon the ownership of the common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred.

We prorate our items of income, gain, loss and deduction between transferors and transferees of common units each month based upon the ownership of the common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. Although recently issued final Treasury regulations allow publicly traded partnerships to use a similar monthly simplifying convention, such tax items must be prorated on a daily basis and these regulations do not specifically authorize all aspects of the proration method we have adopted.  Accordingly, our counsel is unable to opine as to the validity of this method.  If the IRS were to successfully change this method or new U.S. Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

A unitholder whose common units are loaned to a “short seller” to cover a short sale of common units may be considered as having disposed of those common units. If so, he 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, he 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 he 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 borrowing their common units.  

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties 

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

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

Item 3. Legal Proceedings 

Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any other material legal proceedings other than those that have been previously disclosed.  In addition, we are not aware of any legal or governmental proceedings against us, or contemplated to be brought against us, under various environmental protection statutes or other regulations to which we are subject.

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 MKT under the symbol “SPP.” On March 23, 2017, the market price for our common units was $14.25 per unit, resulting in an aggregate market value of units held by non-affiliates of approximately $150.3 million. The following table presents the high and low closing price for our common units during the periods indicated.

 

Holders

The number of unitholders of record of our common units was approximately 69 as of March 23, 2017.  The number of registered holders does not include holders that have common units held for them in “street name,” meaning that the common units are held for their accounts by a broker or other nominee.  In these instances, the brokers or other nominees are included in the number of registered holders, but the underlying unitholders that have units held in “street name” are not.

Distributions

From the second quarter of 2009 through the second quarter of 2015, we did not pay distributions on our common units.  Starting in the third quarter of 2015, the board of directors of our general partner has declared the following distributions on our common units:

 

The table below reflects the payments of distributions on Class B preferred units during the years ended December 31, 2016 and 2015:

 

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.   Under our current cash distribution policy, we target a minimum quarterly distribution to the holders of our common units of $0.50 per unit, or $2.00 per unit on an annualized basis, to the extent we have sufficient available cash after the establishment of cash reserves and the payment of costs and expenses.   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, 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 the 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:

 

 

Securities Authorized for Issuance Under Equity Compensation Plans

See “Item 12. Security Ownership of Certain Benefits Owners and Management and Related Unitholder Matters” for information regarding our equity compensation plan as of December 31, 2016.

Unregistered Sales of Securities

In connection with providing services under the Services Agreement for the second quarter of 2016, the Partnership issued 150,398 common units to Manager on September 1, 2016.  See Note 13, "Related Party Transactions" for additional information related to the Services Agreement. The issuance of these common units was exempt from the registration requirements of the Securities Act of 1933, as amended, pursuant to section 4(2) thereof as a transaction by an issuer not involving a public offering.

 

 

Issuer Purchases of Equity Securities

No issuer purchases of equity securities occurred during the fourth quarter of 2016.

Default Upon Senior Securities

There were no defaults on senior securities for the years ended December 31, 2016 or 2015.

 

 Item 6. Selected Financial Data 

As a smaller reporting company, we are not required to provide the information required by this item.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with accompanying financial statements and related notes included elsewhere in this Annual Report on Form 10-K. The following discussion contains forward-looking statements that reflect our future plans, estimates, forecasts, guidance, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Please read “Cautionary Note Regarding Forward-Looking Statements.”  Also, please read the risk factors and other cautionary statements described under the heading “Item 1A--Risk Factors” included elsewhere in this Annual Report.

Overview

We were formed in 2005 as a Delaware limited liability company until our conversion on in 2015 into a Delaware limited partnership.  We are focused on the acquisition, development, ownership and operation of midstream and other production assets in North America.  We currently own a gathering system in the Eagle Ford Shale (the “Western Catarina gathering system”), a 50% interest in a gathering system that connects to the Western Catarina gathering system, a 50% interest in a cryogenic natural gas processing plant, reversionary working interests and other production assets in Texas, Louisiana Oklahoma and Kansas.

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

Grow our business by acquiring fee-based midstream and production assets with minimal maintenance capital requirements and low overhead to increase unitholder value;

Support stable cash flows by aligning our asset base and operations with SOG's operational platform and Sanchez Energy's asset base;

Focus on stable, fixed-fee businesses;

Grow our business through increased throughput; and

Maintain financial flexibility and strong capital structure.

Significant Operational Factors in 2016

Some key highlights of our business activities for the year ended December 31, 2016 were:

In November 2016, we completed the acquisition of 50% of the outstanding membership interests in Carnero Processing from Sanchez Energy for approximately $55.5 million plus the assumption of approximately $24.5 million of remaining capital commitments.

In November 2016, we completed the acquisition of working interest in 23 producing Eagle Ford Shale wellbores located in Dimmit and Zavala counties in South Texas as well as escalating working interests in an additional 11 producing wellbores in the Palmetto Field in Gonzales, Texas from Sanchez Energy for approximately $25.6 million.

In November 2016, we completed a public offering of approximately 6,745,107 common units (which includes 194,305 common units as partial exercise of the underwriters’ option to purchase additional common units) representing limited partner interests for net proceeds of approximately $69.7 million, after deducting customary offering expenses.

In November 2016, concurrent with the public offering of units, we completed a private placement of 2,272,727 common units representing limited partner interests for net proceeds of approximately $25.0 million.

In July 2016, we completed the divestment of substantially all of the Partnership’s oil and natural gas wells, leases and other associated assets and interests in Oklahoma and Kansas for cash consideration of approximately $7,120.

In July 2016, we completed the acquisition of 50% of the issued and outstanding membership interests in Carnero Gathering from Sanchez Energy for total consideration of approximately $37.0 million, plus the assumption of approximately $7.4 million of remaining capital commitments to Carnero Gathering.

How We Evaluate Our Operations

We evaluate our business on the basis of the following key measures:

our throughput volumes on the gathering system upon acquiring those assets;

our operating expenses; and

our Adjusted EBITDA, a non-GAAP financial measure (for a definition of Adjusted EBITDA please read “—Non-GAAP Financial Measures–Adjusted EBITDA”).

Throughput Volumes

Upon acquisition of the Western Catarina gathering system, our management began to analyze our performance based on the aggregate amount of throughput volumes on the Western Catarina gathering system. We must connect additional wells or well pads within the dedicated areas in order to maintain or increase throughput volumes on the Western Catarina gathering system. Our success in connecting additional wells is impacted by successful drilling activity by Sanchez Energy on the acreage dedicated to the Western Catarina gathering system, our ability to secure volumes from Sanchez Energy from new wells drilled on non-dedicated acreage, our ability to attract hydrocarbon volumes currently gathered by our competitors and our ability to cost-effectively construct or acquire new infrastructure.

Operating Expenses

Our management seeks to maximize the Adjusted EBITDA in part by minimizing operating expenses. These expenses are or will be comprised primarily of field operating costs (which generally consists of lease operating expenses, labor, vehicles, supervision, transportation, minor maintenance, tools and supplies expenses, among other items), compression expense, ad valorem taxes and other operating costs, some of which will be independent of our oil and natural gas production or the throughput volumes on the gathering system but fluctuate depending on the scale of our operations during a specific period.

Non-GAAP Financial Measures—Adjusted EBITDA

To supplement our financial results and guidance presented in accordance with U.S. generally accepted accounting principles (“GAAP”), we use Adjusted EBITDA, a non-GAAP financial measure, in this annual report. We believe that non-GAAP financial measures are helpful in understanding our past financial performance and potential future results, particularly in light of the effect of various transactions effected by us. We define Adjusted EBITDA as net income (loss) adjusted by: (i) interest (income) expense, net, which includes interest expense, interest expense net (gain) loss on interest rate derivative contracts, and interest (income); (ii) income tax expense (benefit); (iii) depreciation, depletion and amortization; (iv) asset impairments; (v) accretion expense; (vi) (gain) loss on sale of assets; (vii) unit-based compensation programs; (viii) unit-based asset management fees; (ix) distributions in excess of equity earnings; (x) (gain) loss on mark-to-market activities; (xi) commodity derivatives settlements applied to future positions; and (xii) (gain) loss on embedded derivatives.

Adjusted EBITDA is a significant performance metric used by our management to indicate (prior to the establishment of any cash reserves by the board of directors of our general partner) the distributions that we would expect to pay to our unitholders. Specifically, this financial measure indicates to investors whether or not we are generating cash flows at a level that can sustain or support a quarterly distribution or any increase in our quarterly distribution rates. Adjusted EBITDA is also used as a quantitative standard by our management and by external users of our financial statements such as investors, research analysts, our lenders and others to assess: (i) the financial performance of our assets without regard to financing methods, capital structure or historical cost basis; (ii) the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness; and (iii) our operating performance and return on capital as compared to those of other companies in our industry, without regard to financing or capital structure.

We believe that the presentation of Adjusted EBITDA provides useful information to investors in assessing our financial condition and results of operations. The GAAP measure most directly comparable to Adjusted EBITDA is net income. Our non-GAAP financial measure of Adjusted EBITDA should not be considered as an alternative to GAAP net income. Adjusted EBITDA has important limitations as an analytical tool because it excludes some but not all items that affect net income. Adjusted EBITDA should not be considered in isolation or as a substitute for analysis of our results as reported under GAAP. Because Adjusted EBITDA may be defined differently by other companies in our industry, our definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies, thereby diminishing its utility.

The following table sets forth a reconciliation of Adjusted EBITDA to net income (loss), its most directly comparable GAAP performance measure, for each of the periods presented (in thousands):

 

Results of Operations by Segment

Midstream Operating Results

The following table sets forth the selected financial and operating data pertaining to the Midstream segment for the periods indicated (in thousands):

Items affecting the comparability of our financial results.  Historical results of operations for the periods presented for the Midstream segment are deemed to be not meaningful as this segment was acquired and placed into service in October 2015.  As a result, year-over-year variances are not applicable as any prior year revenues or expenses generated from the gathering and transportation of hydrocarbons relate exclusively to the fourth quarter of 2015.  See Note 3. “Acquisitions and Divestitures” for additional information relating to the Western Catarina gathering system acquisition.

Gathering and transportation sales.  We consummated the acquisition of the Western Catarina gathering system from Sanchez Energy, and we entered into the gathering and processing agreement with Sanchez Energy, in October 2015.  During the fiscal year ended December 31, 2016, Sanchez Energy transported average daily production through the gathering system of approximately 13.3 MBbl/d of crude oil and 181.5 MMcf/d of natural gas. From October 14, 2015 through December 31, 2015, Sanchez Energy transported average daily production through the gathering system of approximately 4.3 MBbl/d of crude oil and 55.3 MMcf/d of natural gas. 

Transportation operating expenses. Our operating expenses generally consist of gathering and transportation operating expenses, labor, vehicles, supervision, minor maintenance, tools, supplies, and integrity management expenses. Our transportation operating expense for the years ended December 31, 2016 and 2015 were $12.5 million and $2.2 million, respectively.

General and administrative expenses.  General and administrative expenses include the costs of our employees, related benefits, field office expenses, professional fees, direct and indirect costs billed by the Manager in connection with the Services Agreement and other costs not directly associated with field operations. Our general and administrative expenses for the year ended December 31, 2016 were $5.7 million. We did not incur any general and administrative costs during the year ended December 31, 2015.

Depreciation and amortization expense.    Gathering and transportation assets are stated at historical acquisition cost, net of any impairments, and are depreciated using the straight-line method over the useful lives of the assets, which range from 5 to 15 years for equipment, and up to 36 years for gathering facilities. Our depreciation, amortization and accretion expense for the years ended December 31, 2016 and 2015 were $27.1 million and $4.2 million, respectively.

Production Operating Results

The following tables set forth the selected financial and operating data pertaining to the production segment for the periods indicated (in thousands, except net production and average sales and costs):