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Common Units

Assumed net loss to be allocated

Basic and diluted loss per unit

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, 2017

☐

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

Sanchez Midstream Partners LP

(Exact Name of Registrant as Specified in Its Charter)

Delaware	11-3742489
(State of organization)	(I.R.S. Employer Identification No.)

1000 Main Street, Suite 3000
Houston, Texas	77002
(Address of Principal Executive Offices)	(Zip Code)

Telephone Number: (713) 783-8000

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

Title of each class		Name of each exchange on which registered
Common Units representing Limited Partner
Interests		NYSE American

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

Large accelerated filer ☐

Accelerated filer ☒

Non‑accelerated filer ☐

(Do not check if a

smaller reporting company)

Smaller reporting company ☒

Emerging growth company ☐

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

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

Aggregate market value of Sanchez Midstream Partners LP Common Units, without par value, held by non-affiliates as of June 30, 2017 was approximately $136,104,424 based upon the NYSE American closing price.

Common Units outstanding on March 6, 2018: 14,965,134 common units.

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; our acquisition strategy; our financing strategy; our 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, processing and other agreements; our future operating results; the ability of our partners to perform under our joint ventures and partnerships; our future capital expenditures; and our plans, objectives, expectations, forecasts, outlook and intentions.

All of these types of statements, other than statements of historical fact included in this 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.

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

our ability to successfully execute our business, acquisition and financing strategies;

our 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, processing and other agreements;

the ability of our partners to perform under our joint ventures and partnerships;

the availability, proximity and capacity of, and costs associated with, gathering, processing, compression and transportation facilities;

our ability to utilize the services, personnel and other assets of the sole member of our general partner, SP Holdings, LLC (“Manager”), pursuant to existing services agreements;

the credit worthiness and performance of our counterparties, including financial institutions, operating partners and other parties;

the timing and extent of changes in prices for, and demand for, natural gas, NGLs and oil;

our ability to successfully execute our hedging strategy and the resulting realized prices therefrom;

the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may, therefore, be imprecise;

our ability to access the credit and capital markets to obtain financing on terms we deem acceptable, if at all, and to otherwise satisfy our capital expenditure requirements;

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 Midstream Partners,” “the Partnership,” “we,” “us,” “our” or like terms refer collectively to Sanchez Midstream Partners LP (formerly Sanchez Production Partners LP), its consolidated subsidiaries and, where the context provides, the entities in which we have a 50% ownership interest.

“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 oil or other liquid hydrocarbons.

“MBbl/d” means one thousand barrels of 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 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” refers to the combination of ethane, propane, butane, natural gasolines and other components that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.

“our general partner” refers to Sanchez Midstream Partners GP LLC (formerly 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

Item 1.Business

Overview

We were formed in 2005 as a Delaware limited liability company until our conversion in 2015 into a Delaware limited partnership. We are a growth-oriented publicly-traded limited partnership focused on the acquisition, development, ownership and operation of midstream and other energy-related assets in North America. The Partnership has ownership stakes in oil and natural gas gathering systems, natural gas pipelines, and a natural gas processing facility, all located in the Western Eagle Ford in South Texas. Our assets include a gathering system on the Western portion of the Catarina asset operated by Sanchez Energy in the Eagle Ford Shale in South Texas (“Western Catarina Midstream”), our wholly owned SECO Pipeline (defined below), a 50% interest in a gathering system that connects to Western Catarina Midstream (the Carnero Gathering Line, defined below), a 50% interest in a cryogenic natural gas processing plant (the Raptor Gas Processing Facility, defined below), and reversionary working interests and other production assets in Texas, Louisiana and Oklahoma.

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

Our Relationship with Sanchez Energy, Manager and SOG

We believe that our relationship with Sanchez Energy provides us with a strategic advantage and will continue to provide us with significant growth opportunities. As of March 6, 2018, Sanchez Energy owned approximately 15.2% of our outstanding common units. Since March 2015, we have completed three midstream asset acquisitions and two working interest acquisitions from Sanchez Energy. Pursuant to a right-of-first-offer, Sanchez Energy has agreed to offer us the right to acquire any midstream assets that it desires to sell. However, Sanchez Energy is under no obligation to sell any assets to us or to accept any offer for its assets that we may choose to make.

We have entered into a shared services agreement with Manager, pursuant to which Manager provides services that we require to operate our business, including overhead, technical, administrative, marketing, accounting, operational, information systems, financial, compliance, insurance, acquisition, disposition and financing services (the “Services Agreement”). Manager in turn has a shared services agreement in place with SOG. SOG also has a shared services agreement in place with Sanchez Energy. We believe that our relationships with Manager and SOG provide us with competitive advantages, including a cost-efficient means of operating our assets. Manager is the sole member of our general partner and has an interest in us through its ownership of all of our incentive distribution rights. Manager and SOG provide services that we require to operate our business, including overhead, technical, administrative, marketing, accounting, operational, information systems, financial, compliance, insurance, acquisition, disposition and financing services. SOG has a senior management team that averages over 20 years of industry experience and employs over 312 full-time employees, including approximately 67 technical staff and engineers. SOG was formed in 1972 and has drilled or participated in over 4,000 wells, directly and through joint ventures, and has successfully built and operated extensive midstream and gathering assets associated with its exploration and production assets. We plan on leveraging SOG’s extensive expertise and experience to execute on our business strategies. While we believe that our relationships with Sanchez Energy, Manager and SOG are a significant strength, they are also a source of potential risks and conflicts. Please read “Item 1A. Risk Factors.”

Business Strategy

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

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

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 a strong capital structure.

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

Business Segments

Our business activities are conducted by two operating segments for which we provide information in our consolidated financial statements for the years ended December 31, 2017 and 2016. These two segments are based on the nature of the operations that are undertaken by each segment and are our:

midstream business, which includes Western Catarina Midstream, SECO Pipeline (defined below) and our ownership interests in Carnero Processing, LLC (“Carnero Processing”) and Carnero Gathering, LLC (“Carnero Gathering”); and

production business, which includes non-operated oil and natural gas reserves located in the Eagle Ford Shale in South Texas and in other areas of Texas, Louisiana and Oklahoma.

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

Midstream Business

Western Catarina Midstream

In October 2015, we acquired from Sanchez Energy a gathering system (“Western Catarina Midstream”), which is located on the western portion of Sanchez Energy’s approximately 106,000 net acres in Dimmit, LaSalle and Webb Counties, Texas (such net acreage collectively “Sanchez Energy’s Catarina Asset” and the western portion of such net acreage “Western Catarina”). The gathering system consists of gathering assets, pipelines, processing units, compression units and other related assets in Western Catarina, which are located in Dimmit and Webb Counties, Texas and service upstream production from the Eagle Ford Shale. Western Catarina Midstream consists of approximately 150 miles of gathering pipelines, four main gathering and processing facilities, including stabilizers, storage tanks, compressors and dehydration units, and other related assets in Western Catarina, which are located in Dimmit and Webb Counties, Texas, and services upstream production from the Eagle Ford Shale. The gathering pipelines range in diameter from 4 to 12 inches, with capacity of 200 MMcf/d for natural gas, and 40 MBbl/d for crude oil and NGLs. There are four main gathering and processing facilities, which include eight stabilizers of 5,000 barrels per day, approximately 25,000 barrels of storage capacity, pressurized storage for NGLs, approximately 18,000 horsepower of compression and approximately 300 MMcf/d of dehydration capacity. The gathering system is currently used solely to support the gathering, processing and transportation of natural gas, NGLs and oil produced by Sanchez Energy at Sanchez Energy’s Catarina Asset. The gathering system has oil interconnects with the Plains All American Pipeline header system delivered to the Gardendale terminal, and to all four takeaway pipelines to Corpus Christi, and it has natural gas interconnects with Southcross Energy Partners, L.P., Kinder Morgan Inc., Energy Transfer Partners, L.P. and Transwestern Pipeline Company, LLC. Pipeline capacity on Western Catarina Midstream can be expanded through small compression projects at a nominal cost, with approximately $1.0 million in capital expenditures planned per year.

All of the revenues from Western Catarina Midstream are currently earned from Sanchez Energy. Pursuant to the Gathering Agreement, Sanchez Energy has agreed to tender all of its oil, natural gas and other hydrocarbon-based product volumes on approximately 35,000 dedicated acres in Western Catarina for processing and transportation through Western

Proved Reserves of Natural Gas, NGLs, and Oil

The following table reflects our estimates for proved natural gas, NGLs and oil reserves based on the SEC definitions that were used to prepare our financial statements for the periods presented. The standardized measure values shown in the table are not intended to represent the current market values of our estimated proved reserves.


Reserve data:	2017		2016
Estimated proved reserves:
Oil (MMBbl)		3.3		3.5
Natural gas (MMcf)		6.7		14.7
NGLs (MMBbl)		0.9		0.9
Total proved reserves (MMBoe)		5.3		6.9
Estimated proved developed reserves:
Oil (MMBbl)		3.3		3.5
Natural gas (MMcf)		6.7		14.6
NGLs (MMBbl)		0.9		0.9
Total proved developed reserves (MMBoe)		5.3		6.8
Proved developed reserves as a percent of total reserves		100%		100%
Standardized measure ($ in millions)⁽ᵃ⁾	$	56.7	$	49.6

(a)

Standardized measure is the present value of estimated future net revenues to be generated from the production of proved reserves. It is determined using SEC-required prices and costs in effect as of the time of estimation without giving effect to non-property related expenses (such as general and administrative expenses or debt service costs) and discounted using an annual discount rate of 10%. Our standardized measure does not include the impact of derivative transactions or future federal income taxes because we are not subject to federal income taxes. Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. The standardized measure shown should not be considered the current market value of our reserves. The 10% discount factor used to calculate present value, which is required, is not necessarily the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate.

Our 2017 estimates of total proved reserves decreased 1.6 MMBoe from 2016 primarily due to divestitures totaling approximately 1.7 MMBoe, partially offset by an increase of 0.8 MMBoe due to higher commodity prices.

As of December 31, 2017, we have no remaining proved undeveloped reserves (“PUD”) in our reserves base.

We expect to make minimum capital expenditures related to recompletion of existing wells during the year ending December 31, 2018.

At December 31, 2016 and December 31, 2017, Ryder Scott Co. LP (“Ryder Scott”), an independent oil and natural gas engineering firm, prepared estimates of all our proved reserves. We used Ryder Scott’s estimates of our proved reserves to prepare our financial statements. Ryder Scott maintains a degreed staff of highly competent technical personnel. The average experience level of Ryder Scott’s technical staff of engineers, geoscientists and petro physicists exceeds 20 years, including five to 15 years with a major oil company. The engineering information presented in Ryder Scott’s report was overseen by Mr. Eric Nelson, P.E. Mr. Nelson is an experienced reservoir engineer having been a practicing petroleum engineer since 2002. He has more than 12 years of experience in reserves evaluation with Ryder Scott. He has a Bachelor of Science degree in Chemical Engineering from the University of Tulsa and Master of Business Administration degree from the University of Texas. Mr. Nelson is a Registered Professional Engineer in the State of Texas. Our activities with Ryder Scott are coordinated by a reservoir engineer employed by us who has approximately 37 years of experience in the oil and natural gas industry and an engineering degree from the University of Tennessee and a Master of Business Administration from the University of New Orleans. He is a member of the Society of Petroleum Engineers. He has prior reservoir engineering and reserves management experience at Exxon Mobil Corporation, Dominion Resources and Hilcorp Energy. He has extensive experience in managing oil and natural gas reserves processes. He serves as the key technical person reviewing the reserve reports prepared by Ryder Scott prior to review by the audit committee of the board of directors of our general partner and approval by the board of directors of our general partner.

Production and Price History

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


	For the Year Ended
	December 31,
	2017		2016		Variance
Net production:
Natural gas (Mcf)		2,521		4,327		(1,806)	(42)	%
Oil production (MBbl)		414		331		83	25	%
NGLs (MBbl)		102		81		21	26	%
Total production (MBoe)		936		1,133		(197)	(17)	%
Average daily production (Boe/d)		2,565		3,096		(531)	(17)	%
Average sales prices:
Natural gas price per Mcf with hedge settlements	$	3.48	$	4.00	$	(0.52)	(13)	%
Natural gas price per Mcf without hedge settlements	$	2.40	$	2.40	$	—	—	%
Oil price per Bbl with hedge settlements	$	64.83	$	81.92	$	(17.09)	(21)	%
Oil price per Bbl without hedge settlements	$	49.32	$	40.76	$	8.56	21	%
Liquid price per Bbl without hedge settlements	$	19.58	$	14.41	$	5.17	36	%
Total price per Boe with hedge settlements	$	40.19	$	40.24	$	(0.05)	—	%
Total price per Boe without hedge settlements	$	30.41	$	22.11	$	8.30	38	%
Average unit costs per Boe:
Field operating expenses (a)	$	14.47	$	13.67	$	0.80	6	%
Lease operating expenses	$	12.89	$	12.64	$	0.25	2	%
Production taxes	$	1.58	$	1.03	$	0.55	53	%
Depreciation, depletion and amortization	$	10.17	$	5.93	$	4.24	71	%

(a)

Field operating expenses include lease operating expenses (average production costs) and production taxes.

Existing Wells

The following table sets forth information at December 31, 2017, relating to the existing wells in which we owned a working interest as of that date. Gross wells are the total number of producing wells in which we have an interest, and net wells are the sum of our fractional working interests owned in gross wells.


	Natural Gas		Oil
	Gross	Net	Gross	Net
Operated	—	—	—	—
Non-operated	91	17	107	40
Total	91	17	107	40

We did not convert any proved undeveloped wells into proved producing wells in 2017.

Drilling Activity

With respect to oil and natural gas wells drilled and completed during the years ended December 31, 2017 and 2016, the information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that are capable of producing commercial quantities of oil or natural gas, regardless of whether they produce a reasonable rate of return. No exploratory wells were drilled on any of our properties during the years ended December 31, 2017 or 2016. During the year ended December 31, 2017, 1 gross well was drilled, or approximately 0.2

net wells. During the year ended December 31, 2016, 1 gross well was recompleted, or approximately 0.7 net wells. There were no wells in progress at December 31, 2017.

Developed and Undeveloped Acreage

The following table sets forth information related to our leasehold acreage as of December 31, 2017.


	Developed		Undeveloped
	Acreage(a)		Acreage(b)
	Gross(c)	Net(d)	Gross(c)	Net(d)
Total	2,188	632	—	—

(a)

Developed acres are acres pooled within or assigned to productive wells/units.

(b)

Undeveloped acres are acres on which wells have not been drilled or acres that have not been pooled into a productive unit.

(c)

A gross acre is an acre in which a working interest is either fully or partially leased. The number of gross acres may include minerals not under lease as a result of leasing some but not all joint mineral owners under any given tract.

(d)

A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

Leases

Most of our reserves are wellbore rights only. We have a small lease position of less than 1,000 net acres in Louisiana.

Marketing and Major Customers

Our oil and natural gas production in the onshore Texas, Oklahoma and Louisiana Gulf Coast region is marketed by the operators of our properties.

Sanchez Energy, whose earned revenues contribute exclusively to our midstream segment, accounted for 63% and 76% of total revenue for the years ended December 31, 2017 and 2016, respectively. Additional information regarding our relationship with Sanchez Energy is provided in Item 13. “Certain Relationships and Related Transactions, and Manager Independence.”

Markets and Competition

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

The natural gas gathering, compression, treating and transportation business is very competitive. Upon such time that we seek to obtain customers in addition to Sanchez Energy for Western Catarina Midstream, our competitors will include other midstream companies, producers and intrastate and interstate pipelines. Competition for volumes is primarily based on reputation, commercial terms, reliability, service levels, location, available capacity, capital expenditures and fuel efficiencies.

Neither SOG nor any of its related companies are restricted from competing with us. Additional information regarding our relationship with SOG is provided in Item 13. “Certain Relationships and Related Transactions, and Manager Independence.”

Governmental Regulation

Environmental Laws

Our operations are subject to stringent and complex federal, state and local laws and regulations governing environmental protection as well as the discharge of materials into the environment. These laws and regulations may, among other things:

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, the EPA finalized rules that lower the National Ambient Air Quality Standard (“NAAQS”) for ozone from 75 parts per billion (“ppb”) to 70 ppb, and the EPA published a final rule in November 2017 stating that 85% of U.S. counties are designated as “attainment/unclassified” but has not issued any non-attainment designations for the remaining 15%. States can also impose air emissions limitations that are more stringent than the federal standards imposed by the EPA. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the Clean Air Act and associated state laws and regulations. Rules restricting air emissions may require a number of modifications to our operations, including the installation of new equipment. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our operating results. However, we believe that our operations will not be materially adversely affected by any such requirements, and the requirements are not expected to be any more burdensome to us than to other similarly situated companies. We believe that our operations are in substantial compliance with federal and state air emission standards.

Climate Change

While the U.S. Congress has from time to time considered legislation to reduce emissions of greenhouse gases (“GHGs”), the prospect for adoption of significant legislation at the federal level to reduce GHG emissions is perceived to be low at this time. Requirements intended to reduce greenhouse gases have been adopted at the federal, regional and state levels. For example, in June 2016, the EPA adopted Subpart OOOOa establishing standards for methane emissions from oil and gas production. However, in June 2017, the EPA published a proposed rule to stay portions of the Subpart OOOOa standards, and until the rule is finalized, future implementation of the 2016 standard is uncertain. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations that limit emissions of GHGs could adversely affect demand for the oil and natural gas that production operators produce, some of whom are our customers, which could thereby reduce demand for our midstream services. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical

effects, such as increased frequency and severity of storms, droughts and floods and other climatic events; if any such effects were to occur, it is uncertain if they would have an adverse effect on our financial condition and operations.

Hydraulic Fracturing

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

Endangered Species

The Endangered Species Act (“ESA”), and analogous state laws, restrict activities that may affect listed endangered or threatened species or their habitats. If endangered species are located in areas where we operate, our operations or any work performed related to them could be prohibited or delayed or expensive mitigation may be required. While some of our operations may be located in areas that are designated as habitats for endangered or threatened species, we believe that we are in compliance with the ESA. Additional listings under the ESA and similar state laws could result in the imposition of restrictions on our operations and consequently have an adverse effect on our business.

Gathering System Regulation

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

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

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

operated in violation of the NGA or the NGPA, this could result in the imposition of civil penalties as well as a requirement to disgorge charges collected for such service in excess of the cost-based rate established by the FERC.

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

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

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

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

Pipeline Safety Regulation

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

Our natural gas pipelines are subject to regulation by Pipelines and Hazardous Materials Safety Administration (“PHMSA”) pursuant to the Natural Gas Pipeline Safety Act of 1968 (“NGPSA”) and the Pipeline Safety Improvement Act of 2002 (“PSIA”), as reauthorized and amended by the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006 (“PIPES Act”). The NGPSA regulates safety requirements in the design, construction, operation and maintenance

of gas pipeline facilities, while the PSIA establishes mandatory inspections for all U.S. oil and natural gas transmission pipelines in high-consequence areas (“HCAs”).

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

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.

PHMSA regularly revises its pipeline safety regulations and has published advanced notices of proposed rulemakings and notices of proposed rulemaking to solicit comments on the need for changes to its natural gas and liquid pipeline safety regulations. In the past few years, PHMSA issued advisory bulletins providing guidance on applicable regulatory requirements, including those that must be followed for the abandonment of a pipeline; aspects of overall pipeline integrity, including the need for corrosion-control systems on buried and insulated pipeline segments, to conduct in-line inspections for all threats, and to ensure in-line inspection tool findings are accurate and verified; the need of owners and operators of natural gas facilities to take appropriate steps to prevent damage to pipeline facilities from accumulated snow or ice; actions pipeline operators should consider taking to ensure the integrity of pipelines in the event of severe flooding or hurricane damage; notice of construction; flow reversal procedures; product changes and conversion; integrity management program evaluation metrics; and incident response plans. Further changes to PHMSA’s rules are expected in the future.

For example, in July 2015, PHMSA issued a notice of proposed rulemaking proposing, among other things, to extend operator qualification requirements to operators of certain natural gas gathering lines and to add a specific timeframe for operators’ notifications of accidents or incidents. In January 2017, PHMSA issued a final rule adding a specific timeframe for operators’ notifications of accidents or incidents but delayed final action on the operator qualification proposals until a later date. The final rule became effective March 24, 2017. In addition, in October 2015, PHMSA issued a notice of proposed rulemaking proposing changes to its hazardous liquid pipeline safety regulations, including to extend: (i) reporting requirements to all onshore or offshore, regulated or unregulated hazardous liquid gathering lines; and (ii) certain integrity management periodic assessment and remediation requirements to regulated onshore gathering lines. On January 13, 2017, PHMSA issued a final rule amending its regulations to impose new reporting requirements for certain unregulated pipelines, including all hazardous liquid gathering lines. The final rule also significantly extends and expands the reach of certain integrity management requirements, regardless of the pipeline’s proximity to a HCA. However, this final rule remains subject to review and approval by the new administration, pursuant to a memorandum issued by the White House to heads of federal agencies. It is unclear whether the final rule will be revised and when it will be implemented. In April 2016, PHMSA issued a notice of proposed rulemaking that would expand integrity management requirements and impose new pressure requirements on currently regulated gas transmission pipelines and would also significantly expand the regulation of gas gathering lines, subjecting previously unregulated pipelines to requirements regarding damage prevention, corrosion control, public education programs, maximum allowable operating pressure limits

and other requirements. PHMSA has not yet finalized these proposed regulations. While we cannot predict the outcome of legislative or regulatory initiatives, such regulatory changes and any legislative changes could have a material effect on our operations, particularly by extending more stringent and comprehensive safety regulations (such as integrity management requirements) to pipelines and gathering lines not previously subject to such requirements. While we expect any legislative or regulatory changes to allow us time to become compliant with new requirements, costs associated with compliance may have a material effect on our operations.

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

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

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

Other Laws and Regulation

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

We believe that we are in substantial compliance with existing environmental laws and regulations applicable to our current operations and that our continued compliance with existing requirements should not have a material adverse impact on our financial condition and results of operations. As of December 31, 2017, we had no accrued environmental obligations. We are not aware of any environmental issues or claims that will require material capital expenditures or that will otherwise have a material impact on our financial position or results of operations. However, we cannot predict how future environmental laws and regulations may impact our operations, and therefore, cannot provide assurance that the passage of more stringent laws or regulations in the future will not have a negative impact on our financial condition, results of operations or cash flows.

Employees

Pursuant to the Services Agreement, Manager provides services that we require to operate our business, including overhead, technical, administrative, marketing, accounting, operational, information systems, financial, compliance, insurance and acquisition, disposition and financing services. In connection with providing the services under the Services Agreement, Manager receives compensation consisting of: (i) a quarterly fee equal to 0.375% of the value of our properties other than our assets located in Oklahoma, (ii) reimbursement for all allocated overhead costs as well as any direct third-

Risks Related to Our Midstream Business

Because substantially all of our revenue relating to the operation of our midstream business is derived from Sanchez Energy, any development that materially and adversely affects Sanchez Energy’s operations, financial condition or market reputation could have a material and adverse impact on us.

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

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 the price of natural gas, NGLs or oil, 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.

A reduction in the price of natural gas, NGLs or oil could cause Sanchez Energy to record oil and natural gas property impairments, which would adversely affect its future business and development. Sanchez Energy utilizes the successful efforts method of accounting to account for its oil and natural gas exploration and development activities. Under this method of accounting, a company is required when facts and circumstances indicate that the carrying value may not be recoverable to determine whether the book value of its oil and natural gas properties (excluding unevaluated properties) is less than or equal to the estimated undiscounted future net cash flows using management’s expectations of future oil and natural gas prices. If net capitalized costs exceed estimated undiscounted future net cash flows, the measurement of impairment is based on estimated fair value, using estimated discounted future net cash flows. Sanchez Energy recorded no proved property impairments for the year ended December 31, 2017 and recorded approximately $3.7 million and $700.3 million of proved property impairments for the years ended December 31, 2016 and 2015, respectively. Sanchez Energy could incur additional non-cash impairments to its proved oil and natural gas properties in 2018 if the price of natural gas, NGLs or oil declines. These impairments, along with a substantial and sustained decline in oil and natural gas prices, may materially and adversely affect its future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.

We are subject to the risk of non-payment or non-performance by Sanchez Energy, including with respect to the Gathering Agreement and the SECO Pipeline Transportation Agreement with Sanchez Energy. We cannot predict the extent to which Sanchez Energy’s business would be impacted if conditions in the energy industry were to deteriorate, nor can we estimate the impact that such conditions would have on Sanchez Energy’s ability to execute its drilling and

development program or perform under its agreement with us. Any material non-payment or non-performance by Sanchez Energy would reduce our ability to make distributions to our unitholders.

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

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

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

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

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

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 (with the ability to bank up to 30 wells from a prior period). If Sanchez Energy fails to meet this minimum drilling commitment, Sanchez Energy would forfeit its acreage under the lease not held by production. Such a forfeiture could impact Sanchez Energy’s ability to develop additional acreage and replace declining production.

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

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

The Gathering Agreement contains provisions that can reduce the cash flow stability that the agreement was designed to achieve.

The Gathering Agreement is designed to generate stable cash flows for us over the life of the minimum volume commitment contract term while also minimizing direct commodity price risk. Under the minimum volume commitment, subject to certain adjustments, Sanchez Energy has agreed to ship a minimum volume of natural gas, NGLs and oil on Western Catarina Midstream or, in some cases, to pay a minimum monetary amount, over certain periods during the term of the minimum volume commitment, which is the first five years of the 15-year term of the Gathering Agreement. In addition, the Gathering Agreement also includes a minimum quarterly quantity, which is a total amount of natural gas, NGLs and oil that Sanchez Energy must flow on Western Catarina Midstream (or an equivalent monetary amount) each quarter during the minimum volume commitment term. If Sanchez Energy’s actual throughput volumes are less than its minimum volume commitment for the applicable period, it must extend the minimum volume commitment term on a nominal volume basis, but to no longer than the original five years (subject to certain exceptions), or, in some cases, make a shortfall payment to us at the end of that contract quarter, as applicable. The amount of the shortfall payment is based on the difference between the actual throughput volume shipped, processed or offset through an extension of the minimum volume commitment term for the applicable period and the minimum volume commitment for the applicable period, multiplied by the applicable fee. To the extent that Sanchez Energy’s actual throughput volumes are above its minimum volume commitment for the applicable period, the Gathering Agreement contains provisions that allow Sanchez Energy to use the excess volumes as a credit to shorten the minimum volume commitment term, but to no less than four years.

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

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 reserves of natural gas, NGLs and oil reserves connected to Western Catarina Midstream on a regular or ongoing basis; therefore, in the future, volumes of natural gas, NGLs and oil on the gathering system could be less than we anticipate.

We have not obtained and do not intend to obtain independent evaluations of the reserves of natural gas, NGLs and oil, including those of Sanchez Energy, connected to Western Catarina Midstream on a regular or ongoing basis. Moreover, even if we did obtain independent evaluations of the reserves of natural gas, NGLs and oil connected to Western Catarina Midstream, such evaluations may prove to be incorrect. Oil and natural gas reserve engineering requires

subjective estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices, future production levels and operating and development costs.

Accordingly, we may not have accurate estimates of total reserves dedicated to some or all of Western Catarina Midstream or the anticipated life of such reserves. If the total reserves or estimated life of the reserves connected to Western Catarina Midstream are less than we anticipate and we are unable to secure additional sources of natural gas, NGLs and oil, it could have a material adverse effect on our business, results of operations and financial condition and our ability to make cash distributions to our unitholders.

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

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

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.

All of our midstream assets are located in the Eagle Ford Shale in Texas, making us vulnerable to risks associated with operating in one major geographic area.

All of our midstream assets are located in Eagle Ford Shale in Texas. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, market limitations or interruption of the processing or transportation of natural gas, NGLs or oil.

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

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

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

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

We may not be able to attract additional third-party volumes, which could limit our ability to grow and would increase our dependence on Sanchez Energy.

Part of our long-term growth strategy includes identifying additional opportunities to offer gathering, processing and transportation services to other third parties. Our ability to increase throughput on our facilities and any related revenue from third parties is subject to numerous factors beyond our control, including competition from third parties and the extent to which we have available capacity when requested by third parties. To the extent that we lack available capacity on our facilities for third-party volumes, we may not be able to compete effectively with third-party gathering or processing systems for additional volumes. In addition, some of our competitors for third-party volumes have greater financial resources and access to larger supplies of oil and natural gas than those available to us, which could allow those competitors to price their services more aggressively than us. Moreover, the underlying lease for the properties on which Western Catarina Midstream is located restricts Western Catarina Midstream to the handling of hydrocarbons produced on the properties covered by the lease.

We may not be able to attract material third-party service opportunities. Our efforts to attract new unaffiliated customers may be adversely affected by (i) our relationship with Sanchez Energy, certain rights that it has under applicable agreements and with respect to Western Catarina Midstream the fact that a substantial portion of the capacity of the facility will be necessary to service Sanchez Energy’s production and development and completion schedule, (ii) the current nature of our facilities, (iii) our desire to provide services pursuant to fee-based contracts and (iv) the existence of current and future dedications to other gatherers by potential third-party customers. As a result, we may not have the capacity or ability to provide services to third parties, or potential third-party customers may prefer to obtain services pursuant to other forms of contractual arrangements under which we would be required to assume direct commodity exposure.

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

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

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

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

Our facilities connect to other pipelines or facilities owned and operated by unaffiliated third parties. The continuing operation of third-party pipelines, compressor stations and other midstream facilities is not within our control. These

pipelines, plants and other midstream facilities may become unavailable because of testing, turnarounds, line repair, maintenance, reduced operating pressure, lack of operating capacity, regulatory requirements and curtailments of receipt or deliveries due to insufficient capacity or because of damage from severe weather conditions or other operational issues. In addition, if the costs to us to access and transport on these third-party pipelines significantly increase, our profitability could be reduced. If any such increase in costs occurs or if any of these pipelines or other midstream facilities become unable to receive or transport natural gas, NGLs or oil, our operating margin, cash flow and ability to make cash distributions to our unitholders could be adversely affected.

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

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

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

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

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

Risks Related to Our Production Business

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;

loss or theft of data due to cyber-attacks; and

third party operation.

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

Unless we replace the reserves that we produce, our existing reserves will decline, which could adversely affect our production and adversely affect our cash from operations and our ability to pay distributions to our unitholders.

Producing oil and natural gas reservoirs are characterized by declining production rates that vary based on the reservoir characteristics and other factors. The rate of decline of our reserves and production included in our reserve report at the end of the most recently completed fiscal year will change if production from our existing wells declines in a different manner than we have estimated and may change when we make acquisitions and under other circumstances. The rate of decline may also be greater than we have estimated due to decreased capital spending or lack of available capital to make capital expenditures. Our future oil and natural gas reserves and production and, therefore, our cash flows and income, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically acquiring additional recoverable reserves, as we do not intend to drill new wells. We may not be able to develop or acquire additional reserves to replace our current and future production at acceptable costs, which could adversely affect our business, financial condition, results of operations and ability to pay distributions to our unitholders.

Our estimated reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our estimated reserves.

It is not possible to measure underground accumulations of oil and natural gas in an exact way. Oil and natural gas reserve engineering requires subjective estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices, production levels and operating and development costs. Our independent reserve engineers do not independently verify the accuracy and completeness of information and data furnished by us. In

estimating our level of oil and natural gas reserves, we and our independent reserve engineers make certain assumptions that may prove to be incorrect, including assumptions relating to:

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.

Our oil and natural gas production in Oklahoma, as well as the onshore Texas and Louisiana Gulf Coast region, is marketed by the operators of our properties. To the extent these or other customers reduce the volumes of oil and natural gas that they purchase from us and are not replaced by new customers, or the market prices for oil and natural gas decline in our market areas, our revenues and cash available for distribution could decline.

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

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

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

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

Our oil and natural gas properties may be exposed to unanticipated water disposal or processing costs.

Where water produced from properties fails to meet the quality requirements of applicable regulatory agencies or wells produce water in excess of the applicable volumetric permit limit, the wells may have to be shut in or upgraded for water handling or treatment. The costs to treat or dispose of this produced water may increase if any of the following occur:

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

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

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

Our operations are subject to complex and stringent laws and regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. Failure or delay in obtaining regulatory approvals or leases could have a material adverse effect on our ability to develop our properties. In addition, regulations regarding conservation practices and the protection of correlative rights affect our operations by limiting the quantity of oil and natural gas we may produce and sell.

Increased regulation of hydraulic fracturing could result in reductions or delays in the production of natural gas, NGLs and oil by Sanchez Energy, which could reduce the throughput on our facilities and adversely impact our revenues.

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

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

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

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

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 Western Catarina Midstream and 4.5 thereafter. Outstanding borrowings in excess of our borrowing base must be repaid or we must pledge other oil and natural gas properties as additional collateral. We may elect to pay any borrowing base deficiency in three equal monthly installments such that the deficiency is eliminated in a period of three months. Any increase in our borrowing base must be approved by all of the lenders.

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

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

In order to increase our asset base, we will need to make expansion capital expenditures. If we do not make sufficient or effective expansion capital expenditures, we will be unable to expand our business operations and, as a result, we will be unable to increase our future cash distributions. To fund our expansion capital expenditures and investment capital expenditures, we will be required to use cash from our operations or incur borrowings. Such uses of cash from our operations will reduce cash available for distribution to our unitholders. Alternatively, we may sell additional common units or other securities to fund our capital expenditures. Our ability to obtain bank financing or our ability to access the capital markets for future equity or debt offerings may be limited by our or Sanchez Energy’s financial condition at the time of any such financing or offering and the covenants in our existing debt agreements, as well as by general economic conditions, contingencies and uncertainties that are beyond our control. Even if we are successful in obtaining the necessary funds, the terms of such financings could limit our ability to pay distributions to our unitholders. In addition, incurring additional debt may significantly increase our interest expense and financial leverage, and issuing additional limited partner interests may result in significant unitholder dilution and would increase the aggregate amount of cash required to maintain the then-current distribution rate, which could materially decrease our ability to pay distributions at the prevailing distribution rate. None of our general partner, Sanchez Energy or any of their respective affiliates is committed to providing any direct or indirect support to fund our growth.

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

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

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

We have the ability to pay distributions to unitholders under our Credit Agreement from available cash, including cash from borrowings under the Credit Agreement, as long as no event of default exists and provided that no distribution

to unitholders may be made if the borrowings outstanding, net of available cash, under our Credit Agreement exceed 90% of the borrowing base, after giving effect to the proposed distribution. We have obtained waivers of the Credit Agreement limitation in the past and may need to do so in the future. Our available cash is reduced by any cash reserves established by the board of directors of our general partner for the proper conduct of our business and the payment of fees and expenses. Our ability to pay distributions to our unitholders in any quarter will be solely dependent on our ability to generate sufficient cash from our operations and is subject to the approval of the board of directors of our general partner.

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

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

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

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

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

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

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

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

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

Under the swaps regulatory provisions of the Dodd-Frank Act and the rules adopted thereunder, we could have to clear on a designated clearing organization and execute on certain markets any swap that we enter into that falls within a class of swaps designated by the CFTC for mandatory clearing unless we qualify for an exception from such requirements as to such swap. The CFTC has designated six classes of interest rate swaps and credit default swaps for mandatory clearing, but has not yet proposed rules designating any class of physical commodity swaps or other class of swaps for mandatory clearing. Although we expect to qualify for the end-user exception from the mandatory clearing and trade execution requirements for the swaps that we enter into to hedge our commercial risks, if we were to fail to qualify for that exception as to a swap we enter into and were required to clear that swap, we would have to post margin with respect to such swap, our cost of entering into and maintaining such swap could increase and we would have less flexibility with respect to that swap than we would enjoy were the swap not cleared. Moreover, the application of the mandatory clearing and trade execution requirements and other swap regulations to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging.

As required by the Dodd-Frank Act, the CFTC and the federal banking regulators have adopted rules requiring certain market participants to collect initial and variation margin with respect to uncleared swaps from their counterparties except as to any uncleared swaps as to which the counterparty qualifies for the end user exception from the mandatory clearing exception. Although those rules do not require initial margin to be collected from non-financial end users of uncleared swaps, an affected market participant must collect from its counterparty to any uncleared swap that is a non-

financial end user, but that does not qualify for the end user exception with respect to that uncleared swap, variation margin with respect to that swap at those times and in those forms and amounts as the market participant determines appropriately addresses the credit risk posed by that counterparty and the risk of that swap. The requirements of those rules relating to initial margin are being phased through September 1, 2020. Were we not to qualify for the end user exception as to any of our uncleared swaps and otherwise have to post initial or variation margin as to our uncleared swaps in the future, our cost of entering into and maintaining swaps would increase. In addition, our counterparties that are subject to the regulations imposing the Basel III capital requirements on them may increase the cost to us of entering into swaps with them or contractually require us to post collateral or greater amounts of collateral with them in connection with such swaps to offset their increased capital costs or to reduce their capital costs to maintain those swaps on their balance sheets.

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

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

Risks Related to Our Distributions to Unitholders

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

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

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 revenue generated from our facilities;

the amount of oil and natural gas that we produce;

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

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

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

Oil and natural gas prices are very volatile. If commodity prices decline significantly for a temporary or prolonged period, our cash from operations may decline and may adversely impact our ability to invest in new midstream facilities, our financial condition and our profitability.

Our revenue, profitability and operating cash flows depend in part upon the prices and demand for oil and natural gas, and a drop in prices can significantly affect our financial results and impede our growth. Changes in oil and natural gas prices have a significant impact on the value of our reserves and on our operating cash flows and may also impact the fees generated by us from our midstream facilities. In particular, declines in commodity prices will directly reduce the value of our reserves, our operating cash flows, our ability to borrow money or raise capital and our ability to pay distributions and may indirectly reduce the cash flows from our midstream facilities. Prices for oil and natural gas may fluctuate widely in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors that are beyond our control, such as:

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 capital expenditures, which will reduce any cash available for distribution to our unitholders.

We will need to make capital expenditures to maintain our facilities and infrastructure over the long-term. These expenditures could increase as a result of, among others:

changes in labor and material costs;

changes in leasehold and right-of-way costs; and

government regulations relating to safety, taxation and the environment.

Our capital expenditures will reduce the amount of cash that we may have available for distribution to our unitholders. In addition, our actual capital expenditures will vary from quarter to quarter.

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

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

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

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

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

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 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.

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

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

Risks Inherent in an Investment in Our Common Units

Our general partner and its affiliates will have conflicts of interest with us. They will not owe any fiduciary duties to us or our common unitholders, but instead will owe us and our common unitholders limited contractual duties, and they may favor their own interests to the detriment of us and our other common unitholders.

Manager, an affiliate of SOG, owns and controls our general partner and appoints all but two of the directors of our general partner. Although our general partner has a duty to manage us in a manner that is not adverse to us and our unitholders, the directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner that is beneficial to Manager and its affiliates. Conflicts of interest will arise between SOG, Manager and their affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these

conflicts of interest, our general partner may favor its own interests and the interests of Manager and its affiliates over our interests and the interests of our unitholders. These conflicts include the following situations, among others:

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 our 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 our general partner or any committee thereof (including the conflicts committee) believed that such determination, other action or failure to act was adverse to the interests of the partnership or, with regard to certain determinations by the board of directors of our general partner relating to the conflict transactions described below, the board of directors of our general partner did not believe that the specified standards were met, and, except as specifically provided by our partnership agreement, neither our general partner, the board of directors of our general partner nor any committee thereof (including the conflicts committee) will be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;

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:

approved by the conflicts committee of the board of directors of our general partner, although our general partner is not obligated to seek such approval;

approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner and its affiliates;

determined by the board of directors of our general partner to be on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

determined by the board of directors of our general partner to be fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.

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

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

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

Our partnership agreement is governed by Delaware law. Our partnership agreement includes exclusive forum, venue and jurisdiction provisions designating Delaware courts as the exclusive venue for most claims, suits, actions and proceedings involving us or our officers, directors and employees and limitations regarding claims, suits, actions or proceedings. By taking ownership of a common unit, a limited partner is irrevocably consenting to these provisions and limitations regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of Delaware courts. If a dispute were to arise between a limited partner and us or our officers, directors or employees, the limited partner may be required to pursue its legal remedies in Delaware, which may be an inconvenient or distant location and which is considered to be a more corporate-friendly environment. Furthermore, if any limited partner, our general partner or person holding any beneficial interest in us brings any claims, suits, actions or proceedings (including, but not limited to, those asserting a claim of breach of a fiduciary duty) and such person does not obtain a judgment on the merits that substantially

achieves, in substance and amount, the full remedy sought, then such limited partner, our general partner or person holding any beneficial interest in us shall be obligated to reimburse us and our “affiliates,” as defined in Section 1.1 of our partnership agreement (including our general partner, the directors and officers of our general partner, SOG and Manager) for all fees, costs and expenses of every kind and description, including, but not limited to, all reasonable attorneys’ fees and other litigation expenses, that the parties may incur in connection with such claim, suit, action or proceeding. This provision may have the effect of increasing a unitholder’s cost of asserting a claim and therefore, discourage lawsuits against us and our general partner’s directors and officers. Because fee-shifting provisions such as these are relatively new developments in corporate and partnership law, the enforceability of such provisions are uncertain; in addition, future legislation could restrict or limit this provision of our partnership agreement and its effect of saving us and our affiliates from fees, costs and expenses incurred in connection with claims, actions, suits or proceedings.

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

Our common unitholders have limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s and our general partner’s decisions regarding our business. Common unitholders will have no right on an annual or ongoing basis to elect our general partner or its board of directors. Rather, the board of directors of our general partner will be appointed by Manager. Furthermore, if common unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which our common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price. Our partnership agreement also contains provisions limiting the ability of common unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting our common unitholders’ ability to influence the manner or direction of management.

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

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

Our general partner interest or the control of our general partner may be transferred to a third-party without unitholder consent.

Our general partner is able to transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of any assets it may own without the consent of our common unitholders. Furthermore, there is no restriction in the partnership agreement on the ability of Manager to transfer its membership interest in our general partner to a third party. The new members of our general partner would then be in a position to replace the board of directors and officers of our general partner in order to control the decisions taken by such board of directors and officers.

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

Manager is able to transfer its incentive distribution rights to a third party at any time without the consent of our common unitholders. If Manager transfers its incentive distribution rights to a third party but retains its ownership interest in our general partner, our general partner may not have the same incentive to grow our partnership and increase quarterly distributions to unitholders over time as it would if Manager had retained ownership of the incentive distribution rights. For example, a transfer of incentive distribution rights by Manager could reduce the likelihood of SOG or its affiliates accepting offers made by us relating to assets owned by it or its affiliates, as they would have less of an economic incentive to grow our business, which in turn would impact our ability to grow our asset base.

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

As of March 6, 2018, there were 31,000,887 Class B preferred units issued and outstanding which are convertible at any time into not less than 31,000,887 common units (plus additional common units resulting from the issuance of paid-in-kind distributions, if any, on such preferred units). Any future conversion of the Class B preferred units would dilute the percentage ownership held by our common unitholders. Additionally, any future conversion of Class B preferred units will result in the payment of distributions on any additional common units issued as a result of such conversion, and we may not have sufficient available cash to maintain or increase the quarterly distribution amount on our common units following the payment of such distributions.

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

Our partnership agreement does not limit the number of additional limited partner interests, including limited partner interests that rank senior to our common units that we may issue at any time without the approval of our common unitholders. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

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 our 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 American does not require a publicly traded limited partnership like us to comply with certain of its corporate governance requirements.

Because we are a publicly traded limited partnership, the NYSE American does not require us to have a majority of independent directors on our general partner’s board of directors or to establish a compensation committee or a nominating and corporate governance committee. Accordingly, unitholders will not have the same protections afforded to certain corporations that are subject to all of the NYSE American corporate governance requirements.

Tax Risks

Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by states and localities. If the Internal Revenue Service (“IRS”) were to treat us as a corporation for U.S. federal income tax purposes or if we were otherwise subject to a material amount of entity-level taxation, then our cash available for distribution would be substantially reduced.

The anticipated after-tax economic benefit of an investment in our common units depends largely on us being treated as a partnership for U.S. federal income tax purposes. Despite the fact that we are a limited partnership under Delaware law, we will be treated as a corporation for U.S. federal income tax purposes unless we satisfy a “qualifying income” requirement. Based on our current operations, we believe that we satisfy the qualifying income requirement and will continue to be treated as a partnership for U.S. federal income tax purposes. Failure to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to taxation as an entity. We have not requested, and do not plan to request, a ruling from the IRS with respect to our treatment as a partnership for U.S. federal income tax purposes.

If we were treated as a corporation for U.S. federal income tax purposes, we would pay U.S. federal income tax on our taxable income at the corporate income tax rate, and we would also likely pay additional state and local income taxes at varying rates. Distributions to unitholders would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions or credits would flow through to the unitholders. Because a tax would be imposed on us as a corporation, our cash available for distribution to our unitholders would be reduced.

At the state level, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of a material amount of any these taxes in the jurisdictions in which we own assets or conduct business could substantially reduce the cash available for distribution to our unitholders.

If we were treated as a corporation for U.S. federal income tax purposes or otherwise subjected to a material amount of entity-level taxation, there would be a material reduction in the anticipated cash flow and after-tax return to our unitholders likely causing a substantial reduction in the value of our common units.

Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for U.S. federal, state or local income tax purposes, the minimum quarterly distribution and the target distributions may be adjusted to reflect the impact of that law on us.

The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative or legislative changes or differing judicial interpretation at any time. For example, from time to time members of the U.S. Congress have proposed and considered substantive changes to the existing U.S. federal income tax laws that would affect publicly traded partnerships. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible for us to meet the exception to be treated as a partnership for U.S. federal income tax purposes and could negatively impact the value of an investment in our common units.

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

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

Pursuant to recently enacted legislation, our ability to deduct business interest expense will be limited for U.S. federal income tax purposes to an amount equal to our business interest income and 30% of our “adjusted taxable income” during the taxable year, computed without regard to any business interest income or expense, and in the case of taxable years beginning before 2022, any deduction allowable for depreciation, amortization, or depletion. Business interest expense that we are not entitled to fully deduct will be allocated to each unitholder as excess business interest and can be carried forward by the unitholder to successive taxable years and used to offset any excess taxable income allocated by us to the unitholder. Any excess business interest expense allocated to a unitholder will reduce the unitholder’s tax basis in its partnership interest in the year of the allocation even if the expense does not give rise to a deduction to the unitholder in that year.

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

Investment in common units by tax-exempt entities, including employee benefit plans and individual retirement accounts (known as IRAs), raises issues unique to them. For example, virtually all of our income allocated to organizations exempt from U.S. federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Tax-exempt entities with multiple unrelated trades or businesses cannot aggregate losses from one unrelated trade or business to offset income from another to reduce total unrelated business taxable income. As a result, it may not be possible for tax-exempt entities to utilize losses from an investment in us to offset unrelated business taxable income from another unrelated trade or business and vice versa. Tax-exempt entities should consult a tax advisor before investing in our common units.

Non-U.S. unitholders will be subject to U.S. federal income taxes and withholding with respect to income and gain from owning our common units.

Non-U.S. persons are generally taxed and subject to U.S. federal income tax filing requirements on income effectively connected with a U.S. trade or business. Income allocated to our unitholders and, under recently enacted legislation, any gain from the sale of our units will generally be considered to be “effectively connected” with a U.S. trade or business. As a result, distributions to a non-U.S. unitholder will be subject to withholding at the highest applicable effective tax rate and a non-U.S. unitholder who sells or otherwise disposes of a common unit will also be subject to U.S. federal income tax on the gain realized from the sale or disposition of that unit.

Recently enacted legislation also imposes a U.S. federal income tax withholding obligation of 10% of the amount realized upon a non-U.S. person’s sale or exchange of an interest in a partnership that is engaged in a U.S. trade or business. However, application of this withholding rule to dispositions of publicly traded partnership interests has been temporarily suspended by the IRS until regulations or other guidance have been issued. Non-U.S. persons should consult a tax advisor before investing in our common units.

We treat each purchaser of our common units as having the same tax benefits without regard to the common units purchased. The IRS may challenge this treatment, which could adversely affect the value of our common units.

Because we cannot match transferors and transferees of common units, we have adopted depletion, depreciation and amortization positions that may not conform with all aspects of existing U.S. Treasury regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. Our counsel is unable to opine as to the validity of such filing positions. A successful IRS challenge also could affect the timing of these tax benefits or the amount of gain on the sale of common units and could have a negative impact on the value of our common units or result in audits of and adjustments to our unitholders’ tax returns.

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

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

A unitholder whose common units are loaned to a “short seller” to cover a short sale of common units may be considered as having disposed of those common units. If so, the unitholder would no longer be treated for U.S. federal income tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.

Because a unitholder whose common units are loaned to a “short seller” to cover a short sale of common units may be considered as having disposed of the loaned common units, the unitholder may no longer be treated for U.S. federal income tax purposes as a partner with respect to those common units during the period of the loan to the short seller, and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Our counsel has not rendered an opinion regarding the treatment of a unitholder whose common units are loaned to a short seller to effect a short sale of common units; therefore, our unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult with their tax advisor about whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their common units.

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

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

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

As a result of investing in our common units, our unitholders may become subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire properties.

In addition to U.S. federal income taxes, our unitholders will likely be subject to other taxes, including state and local income taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property now or in the future, even if they do not reside in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Furthermore, our unitholders may be subject to penalties for failure to comply with those requirements. It is the responsibility of each unitholder to file all U.S. federal, state and local tax returns that may be required of such unitholder. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in our common units.

Item 1B. Unresolved Staff Comments

None.

PART II

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

Our common units are listed on the NYSE American under the symbol “SNMP.” On March 6, 2018, the market price for our common units was $10.70 per unit, resulting in an aggregate market value of units held by non-affiliates of approximately $115.4 million. The following table presents the high and low closing price for our common units during the periods indicated.


	Common Stock
	High		Low

2017
First Quarter	$	15.70	$	11.00
Second Quarter	$	15.50	$	11.35
Third Quarter	$	12.85	$	9.55
Fourth Quarter	$	12.95	$	10.00

2016
First Quarter	$	12.86	$	9.65
Second Quarter	$	10.54	$	8.76
Third Quarter	$	11.65	$	9.64
Fourth Quarter	$	15.65	$	10.36

Holders

The number of unitholders of record of our common units was approximately 63 as of March 6, 2018. The number of registered holders does not include holders that have common units held for them in “street name,” meaning that our 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

The board of directors of our general partner has declared the following distributions on our common units relating to the years ended December 31, 2016 and December 31, 2017:


	Distribution		Date of	Date of	Date of
Three months ended	per unit		declaration	record	distribution
March 31, 2016	$	0.4121	May 10, 2016	May 20, 2016	May 31, 2016
June 30, 2016	$	0.4183	August 10, 2016	August 22, 2016	August 31, 2016
September 30, 2016	$	0.4246	October 31, 2016	November 10, 2016	November 30, 2016
December 31, 2016	$	0.4310	February 9, 2017	February 20, 2017	February 28, 2017
March 31, 2017	$	0.4375	May 10, 2017	May 22, 2017	May 31, 2017
June 30, 2017	$	0.4441	August 9, 2017	August 22, 2017	August 31, 2017
September 30, 2017	$	0.4508	November 7, 2017	November 20, 2017	November 30, 2017
December 31, 2017	$	0.4508	February 8, 2018	February 20, 2018	February 28, 2018

The table below reflects the payments of distributions on Class B preferred units during the years ended December 31, 2016 and December 31, 2017:


	Cash distribution		Date of	Date of	Date of
Three months ended	per unit		declaration	record	distribution
March 31, 2016	$	0.4500	May 10, 2016	May 20, 2016	May 31, 2016
June 30, 2016	$	0.4500	August 10, 2016	August 22, 2016	August 31, 2016
September 30, 2016	$	0.4500	October 31, 2016	November 10, 2016	November 30, 2016
December 31, 2016 (a)	$	0.2258	February 9, 2017	February 20, 2017	February 28, 2017
March 31, 2017 (a)	$	0.2258	May 10, 2017	May 22, 2017	May 31, 2017
June 30, 2017	$	0.28225	August 9, 2017	August 22, 2017	August 31, 2017
September 30, 2017	$	0.28225	November 7, 2017	November 20, 2017	November 30, 2017
December 31, 2017	$	0.28225	February 8, 2018	February 20, 2018	February 28, 2018

(a)

The partnership elected to pay the fourth quarter 2016 and first quarter 2017 distribution on the Class B preferred units in part cash and, with the consent of the Class B preferred unitholder, in part common units (in lieu of additional Class B preferred units). Accordingly, the partnership declared a cash distribution of $0.2258 per Class B preferred unit and an aggregate distribution of 208,594 common units, each paid on February 28, 2017 to holders of record on February 20, 2017, and the Partnership declared a cash distribution of $0.2258 per Class B preferred unit and an aggregate distribution of 184,697 common units, each paid on May 31, 2017 to holders of record on May 22, 2017.

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:

Our cash distribution policy is subject to restrictions on distributions under our Credit Agreement, which contains financial tests that we must meet and covenants that we must satisfy. Should we be unable to meet these financial tests or satisfy these covenants or if we are otherwise in default under our Credit Agreement, we will be prohibited from making cash distributions notwithstanding our cash distribution policy.

Our general partner has the authority to establish cash reserves for the prudent conduct of our business and for future cash distributions to our unitholders, and the establishment of or increase in those reserves could result in a reduction in cash distributions from levels we currently anticipate pursuant to our stated cash distribution policy. Our partnership agreement does not set a limit on the amount of cash reserves that our general partner may

establish. Any decision to establish cash reserves made by our general partner in good faith will be binding on our unitholders.

Prior to making any distribution on our common units, and pursuant to the Services Agreement, we will pay Manager an administrative fee and reimburse our general partner and its affiliates, including Manager, for all direct and indirect expenses that they incur on our behalf. Neither our partnership agreement nor the Services Agreement limits the amount of expenses for which our general partner and its affiliates may be reimbursed. These expenses may include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates may impact our ability to pay distributions to our unitholders.

While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including the provisions requiring us to make cash distributions contained therein, may be amended with the consent of our general partner and the approval of a majority of the outstanding common units (including common units held by Sanchez Energy and its affiliates, if any).

Even if our cash distribution policy is not modified or revoked, the decisions regarding the amount of distributions to pay under our cash distribution policy and whether to pay any distribution are determined by our general partner, taking into consideration the terms of our partnership agreement.

Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act (the “Delaware Act”), we may not make a distribution if the distribution would cause our liabilities to exceed the fair value of our assets.

We may lack sufficient cash to pay distributions to our unitholders due to cash flow shortfalls attributable to a number of operational, commercial or other factors as well as increases in our operating or general and administrative expenses, principal and interest payments on our outstanding debt, tax expenses, working capital requirements or anticipated cash needs.

If we make distributions out of capital surplus, as opposed to operating surplus, any such distributions would constitute a return of capital and would result in a reduction in the minimum quarterly distribution and the target distribution levels. We do not anticipate that we will make any distributions from capital surplus.

Our ability to make distributions to our unitholders depends on the performance of our assets and subsidiaries and the ability of our subsidiaries to distribute cash to us. The ability of our subsidiaries to make distributions to us may be restricted by, among other things, the provisions of future indebtedness, applicable state laws and other laws and regulations.

As long as our Class B preferred units remain outstanding, our ability to make distributions to common unitholders is prohibited unless our available cash less working capital borrowings during or subsequent to the quarter is at least 1.65 times the amount of the Class B preferred unit distribution for such quarter.

General Partner Interest

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

Incentive Distribution Rights

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

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


		Marginal Percentage Interest
		in Distributions
			Manager
			(as Holder of
	Total Quarterly		Incentive
	Distribution	Common	Distribution
	Per Common Unit	Unitholders	Rights)
Minimum Quarterly Distribution	up to $0.50	100.00%	0.00%

	above $0.50
First Target Distribution	up to	100.00%	0.00%
	$0.575

	above $0.575
Second Target Distribution	up to	87.00%	13.00%
	$0.625

	above $0.625
Third Target Distribution	up to	77.00%	23.00%
	$0.875

Thereafter	above $0.875	64.50%	35.50%

Manager’s right to receive incentive distributions is reduced by a percentage equal to the number of common units held by Sanchez Energy and its affiliates resulting from the common unit issuance made to SN UR Holdings, LLC, a subsidiary of Sanchez Energy, in November 2016, divided by all common units outstanding as of the time of distribution.

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, 2017.

Unregistered Sales of Securities

In connection with providing services under the Services Agreement for the year ended December 31, 2017, the Partnership issued 822,036 common units to Manager. 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 2017.

Default Upon Senior Securities

There were no defaults on senior securities for the years ended December 31, 2017 or 2016.

Item 6. Selected Financial Data

Following the scaled back disclosure requirements for a smaller reporting company, we are not required to provide the information required by this item.

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 the acquisition of Western Catarina Midstream, our management began to analyze our performance based on the aggregate amount of throughput volumes on the gathering system. We must connect additional wells or well pads within the dedicated areas in order to maintain or increase throughput volumes on Western Catarina Midstream. Our success in connecting additional wells is impacted by successful drilling activity by Sanchez Energy on the acreage dedicated to Western Catarina Midstream, 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. Construction of the SECO Pipeline was completed in August 2017, and throughput volumes are dependent on gas processed at the Raptor Gas Processing Facility and demand for dry gas in markets in South Texas. Natural gas is currently being transported through the SECO Pipeline under the SECO Pipeline Transportation Agreement. Future throughput volumes on the pipeline are dependent on the continuation of this month-to-month agreement with Sanchez Energy, execution of a new agreement with Sanchez Energy, or execution of an agreement with third-party.

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 settled early; (xii) (gain) loss on embedded derivatives; and (xiii) acquisition and divestiture costs.

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 (loss). Our non-GAAP financial measure of Adjusted EBITDA should not be considered as an alternative to GAAP net income (loss). Adjusted EBITDA has important limitations as an analytical tool because it excludes some but not all items that affect net income (loss). 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):


	For the Years Ended
	December 31,
	2017		2016
Net income (loss)	$	(3,040)	$	19,231
Adjusted by:
Interest expense, net		8,341		5,093
Depreciation, depletion and amortization		34,830		33,799
Asset impairments		4,688		7,646
Accretion expense		773		1,127
(Gain) loss on sale of assets		(4,150)		219
Unit-based compensation expense		3,373		1,941
Unit-based asset management fees		8,820		6,984
Distributions in excess of equity earnings		5,792		2,568
Loss on mark-to-market activities		7,558		27,780
Commodity derivatives settled early		(3,602)		(3,198)
Gain on embedded derivative		—		(47,794)
Acquisition and divestiture costs		1,646		—
Adjusted EBITDA	$	65,029	$	55,396

Significant Operational Factors

Throughput. During the year ended December 31, 2017, Sanchez Energy transported average daily production through Western Catarina Midstream of approximately 11.6 MBbls/d of oil, 163.9 MMcf/d of natural gas and 12.2 MBbls/d of water. During the year ended December 31, 2016, Sanchez Energy transported average daily production through Western Catarina Midstream of approximately 13.3 MBbls/d of oil, 181.7 MMcf/d of natural gas and an insignificant amount of water. During the year ended December 31, 2017 Sanchez Energy transported average daily production through SECO Pipeline of approximately 61.1 MMcf/d of natural gas.

Production. Our production for the year ended December 31, 2017 was 936 MBOE, or an average of 2,565 BOE per day, compared with approximately 1,133 MBOE, or an average of 3,096 BOE per day, for the year ended December 31, 2016.

Capital Expenditures. For the year ended December 31, 2017, we spent approximately $32.8 million in capital expenditures, consisting of $30.3 million related to the development of the SECO Pipeline and $2.5 million related to the development of Western Catarina Midstream. For the year ended December 31, 2016, we spent approximately $4.7 million in capital expenditures, related to the development of Western Catarina Midstream.

Hedging Activities. For the year ended December 31, 2017, the non-cash mark-to-market loss for our commodity derivatives was approximately $5.2 million, compared to a loss of $27.8 million for the same period in 2016.

Results of Operations by Segment

Midstream Operating Results

The following table sets forth the selected financial and operating data pertaining to the Midstream segment, and reflects the realignment of our operating segments discussed in Note 17. “Reportable Segments” for the periods indicated (in thousands):


	For the Years Ended
	December 31,
	2017		2016		Variance
Revenues:
Gathering and transportation sales	$	55,825	$	53,972	$	1,853	3	%
Earnings from equity investments		7,986		2,301		5,685	NM	(a)
Total midstream revenues		63,811		56,273		7,538	13	%
Operating costs:
Lease operating expenses		928		654		274	42	%
Transportation operating expenses		11,600		12,478		(878)	(7)	%
Earnout rebate		64		—		64	NM	(a)
Depreciation and amortization expense		25,308		27,077		(1,769)	(7)	%
Accretion expense		274		252		22	9	%
Total operating expenses		38,174		40,461		(2,287)	(6)	%
Operating income	$	25,637	$	15,812	$	9,825	62	%

(a) Variances deemed to be Not Meaningful “NM.”

Gathering and transportation sales. We consummated the acquisition of Western Catarina Midstream from Sanchez Energy and entered into the related Gathering Agreement with Sanchez Energy in October 2015. On June 30, 2017, the Gathering Agreement was amended to add an incremental infrastructure fee to be paid by SN Catarina based on water that is delivered through the gathering system through March 31, 2018. During the year ended December 31, 2017, Sanchez Energy transported average daily production through Western Catarina Midstream of approximately 11.6 MBbls/d of oil, 163.9 MMcf/d of natural gas and 12.2 MBbls/d of water. During the year ended December 31, 2016, Sanchez Energy transported average daily production through Western Catarina Midstream of approximately 13.3 MBbls/d of oil, 181.7 MMcf/d of natural gas and an insignificant amount of water. During the year ended December 31, 2017, Sanchez Energy transported average daily production through SECO Pipeline of approximately 61.1 MMcf/d of natural gas.

Earnings from equity investments. Earnings from equity investments increased $5.7 million to $8.0 million for the year ended December 31, 2017, compared to $2.3 million for the same period in 2016. This increase was the result of benefitting from a full year of earnings for Carnero Gathering, as well as a half year of earnings from Carnero Processing for the year ended December 31, 2017.

Lease operating expense. Lease operating expenses, which includes ad valorem taxes, increased $0.2 million, or 42%, to $0.9 million for the year ended December 31, 2017, compared to $0.7 million during the same period in 2016. This increase was a result of a crank shaft failure at the central processing facility on Western Catarina Midstream.

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 decreased $0.9 million, or 7%, to $11.6 million for the year ended December 31, 2017, compared to $12.5 million during the same period in 2016. The decrease was due to less maintenance and fewer repairs on our midstream assets.

Depreciation, depletion 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, depletion and amortization expense decreased $1.8 million, or 7%, to $25.3 million for the year ended December 31, 2017, compared to $27.1 million during the same period in 2016. The decrease was the result of accelerated depreciation recognized at the end of 2016 relating to a decrease in estimated useful life on some of our midstream assets.

Production Operating Results

The following tables set forth the selected financial and operating data pertaining to the production segment, and reflects the realignment of our operating segments discussed in Note 17. “Reportable Segments” for the periods indicated (in thousands, except net production and average sales and costs):


	For the Years Ended
	December 31,
	2017		2016		Variance
Revenues:
Natural gas sales at market price	$	6,054	$	10,396	$	(4,342)	(42)	%
Natural gas hedge settlements		2,730		6,919		(4,189)	(61)	%
Natural gas mark-to-market activities		(2,067)		(5,803)		3,736	64	%
Natural gas total		6,717		11,512		(4,795)	(42)	%
Oil sales		20,417		13,493		6,924	51	%
Oil hedge settlements		6,422		13,622		(7,200)	(53)	%
Oil mark-to-market activities		(3,138)		(21,977)		18,839	86	%
Oil total		23,701		5,138		18,563	NM	(a)
NGL sales		1,997		1,167		830	71	%
Miscellaneous expense		(91)		(1,104)		1,013	92	%
Earnings (losses) from equity investments		(101)		81		(182)	NM	(a)
Total revenues		32,223		16,794		15,429	92	%
Operating costs:
Lease operating expenses		12,066		14,327		(2,261)	(16)	%
Cost of sales		77		328		(251)	(77)	%
Production taxes		1,476		1,167		309	26	%
(Gain) loss on sale of assets		(4,150)		219		(4,369)	NM	(a)
Depreciation, depletion and amortization		9,522		6,722		2,800	42	%
Asset impairments		4,688		7,646		(2,958)	(39)	%
Accretion expense		499		875		(376)	(43)	%
Total operating expenses		24,178		31,284		(7,106)	(23)	%
Operating income (loss)	$	8,045	$	(14,490)	$	22,535	(156)	%

(a) Variances deemed to be Not Meaningful “NM.”


	For the Year Ended
	December 31,
	2017		2016		Variance
Net production:
Natural gas (Mcf)		2,521		4,327		(1,806)	(42)	%
Oil production (MBbl)		414		331		83	25	%
NGLs (MBbl)		102		81		21	26	%
Total production (MBoe)		936		1,133		(197)	(17)	%
Average daily production (Boe/d)		2,565		3,096		(531)	(17)	%
Average sales prices:
Natural gas price per Mcf with hedge settlements	$	3.48	$	4.00	$	(0.52)	(13)	%
Natural gas price per Mcf without hedge settlements	$	2.40	$	2.40	$	—	—	%
Oil price per Bbl with hedge settlements	$	64.83	$	81.92	$	(17.09)	(21)	%
Oil price per Bbl without hedge settlements	$	49.32	$	40.76	$	8.56	21	%
Liquid price per Bbl without hedge settlements	$	19.58	$	14.41	$	5.17	36	%
Total price per Boe with hedge settlements	$	40.19	$	40.24	$	(0.05)	—	%
Total price per Boe without hedge settlements	$	30.41	$	22.11	$	8.30	38	%
Average unit costs per Boe:
Field operating expenses (a)	$	14.47	$	13.67	$	0.80	6	%
Lease operating expenses	$	12.89	$	12.64	$	0.25	2	%
Production taxes	$	1.58	$	1.03	$	0.55	53	%
Depreciation, depletion and amortization	$	10.17	$	5.93	$	4.24	71	%

(a)

Field operating expenses include lease operating expenses (average production costs) and production taxes.

Production: For the year ended December 31, 2017, 44% of our production was oil, 11% was NGLs and 45% was natural gas compared to the year ended December 31, 2016, where 29% of our production was oil, 7% was NGLs and 64% was natural gas. The production mix between the periods has shifted to a higher oil production as a result of multiple asset divestitures in 2017. Combined production has decreased by 197 MBoe for the year ended December 31, 2017, primarily due to the closing of the Oklahoma Production Divestiture and the Texas Production Divestiture, partially offset by the Production Acquisition (which only contributed a partial year of production in 2016 when compared to a full year in 2017).

Sales of natural gas, NGLs and oil. Unhedged oil sales increased $6.9 million, or 51%, to $20.4 million for the year ended December 31, 2017, compared to $13.5 million for the same period in 2016. Sales of NGLs increased $0.8 million, or 71%, to $2.0 million for the year ended December 31, 2017, compared to $1.2 million for the same period in 2016. Unhedged natural gas sales decreased approximately $4.3 million, or 42%, to $6.1 million for the year ended December 31, 2017, compared to $10.4 million for the same period in 2016. The total increase in sales of natural gas, NGLs and oil for the year ended December 31, 2017 was primarily the result of increased production from the Production Acquisition and higher market prices, partially offset by our Oklahoma Production Divestiture and Texas Production Divestiture.

Including hedges and mark-to-market activities, our total production related revenue increased approximately $15.4 million for the year ended December 31, 2017, compared to the same period in 2016. This increase was primarily the result of a $22.6 million increase in gains on mark-to-market activities plus a $6.9 million increase in oil sales, partially offset by an $11.4 million decrease in settlements on oil and natural gas derivatives.

The following tables provide an analysis of the impacts of changes in average realized production volumes and prices between the periods on our unhedged revenues from the year ended December 31, 2017 compared to the year ended December 31, 2016 (in thousands, except average sales prices):


	2017		2016			Average		Revenue
	Average		Average		Sales Price		2017	Increase/(Decrease)
	Sales Price		Sales Price		Difference		Volume	due to Price
Natural gas (Mcf)	$	2.40	$	2.40	$	—	2,521	$	24
Oil (MBbl)	$	49.32	$	40.76	$	8.56	414	$	3,542
NGLs (Mbl)	$	19.58	$	14.41	$	5.17	102	$	527
Total oil equivalent (MBoe)	$	30.41	$	22.11	$	8.30	936	$	4,093


	2017	2016	Production	2016		Revenue
	Production	Production	Volume	Average		Decrease
	Volume	Volume	Difference	Sales Price		due to Production
Natural gas (Mcf)	2,521	4,327	(1,806)	$	2.40	$	(4,339)
Oil (MBbl)	414	331	83	$	40.76	$	3,383
NGLs (MBbl)	102	81	21	$	14.41	$	302
Total oil equivalent (MBoe)	936	1,133	(197)	$	22.11	$	(654)

A 10% increase or decrease in our average realized sales prices, excluding the impact of derivatives, would have increased or decreased our revenues for the year ended December 31, 2017 by $2.8 million.

Hedging and mark-to-market activities. We apply mark-to-market accounting to our derivative contracts; therefore, the full volatility of the non-cash change in fair value of our outstanding contracts is reflected in oil and natural gas revenues. For the year ended December 31, 2017, the non-cash mark-to-market losses were $5.2 million, compared to a loss of $27.8 million for the same period in 2016. The 2017 non-cash gain resulted from higher future expected oil prices on these derivative transactions. Cash settlements received for our commodity derivatives (inclusive of net cash of $3.6 million received in conjunction with hedge repositioning during the year and settlements receivable) were $9.1 million for the year ended December 31, 2017, compared to $20.6 million for the year ended December 31, 2016

Field operating expenses. Our field operating expenses generally consist of lease operating expenses, labor, vehicles, supervision, transportation, minor maintenance, tools and supplies expenses, as well as production and ad valorem taxes.

Lease operating expenses decreased $2.2 million, or 16%, to $12.1 million for the year ended December 31, 2017, compared to $14.3 million for the same period in 2016. This decrease in operating expenses was primarily due to our Mid-Continent Divestiture, Oklahoma Production Divestiture and Texas Production Divestiture. On a per unit basis, lease operating expenses were $12.89 and $12.64 per Boe, for the years ended December 31, 2017 and 2016, respectively.

Depreciation, depletion and amortization expense. Depreciation, depletion and amortization expense includes the depreciation, depletion and amortization of acquisition costs and equipment costs. Depletion is calculated using units-of-production under the successful efforts method of accounting. Assuming other variables remain constant, as the production of natural gas, NGLs, and oil increases or decreases, our depletion expense would increase or decrease as well.

Our depreciation, depletion and amortization expense for the year ended December 31, 2017 was $9.5 million, or $10.17 per Boe, compared to $6.7 million, or $5.93 per Boe, for the same period in 2016. The increase is primarily the result of the Mid-Continent Divestiture, Oklahoma Production Divestiture and Texas Production Divestiture as well as a reduction in proved reserves due to changes in our development plans. Our non-oil and natural gas properties are depreciated using the straight-line basis.

Impairment expense. For the year ended December 31, 2017, we recorded non-cash charges of $4.7 million, to impair certain of our oil and natural gas properties in Texas as part of the Production Acquisition. During the same period in 2016, our non-cash impairment charges were approximately $7.6 million, with $1.3 million from our Texas and Louisiana properties and $6.3 million from our Oklahoma properties. The impairment expense recorded during the year

ended December 31, 2017 resulted from decreases in expectations for oil and natural gas prices in the future as well as changes to our expected future production estimates in certain areas.

Consolidated Earnings Results

The following table sets forth the reconciliation of segment operating income to net income (loss) for periods indicated (in thousands):


	For the Years Ended
	December 31,
	2017		2016		Variance
Reconciliation of segment operating income to net income (loss):
Total segment operating income	$	33,682	$	1,322	$	32,360	NM	(a)
General and administrative		(22,655)		(22,901)		246	(1)	%
Unit-based compensation expense		(3,373)		(1,941)		(1,432)	74	%
Interest expense, net		(8,341)		(5,093)		(3,248)	64	%
Gain on embedded derivative		—		47,794		(47,794)	NM	(a)
Other income (expense)(b)		(2,353)		50		(2,403)	NM	%
Net income (loss)	$	(3,040)	$	19,231	$	(22,271)	NM	(a)

(a)

Amounts Variances deemed to be Not Meaningful “NM”

(b)

Other expense in 2017 excludes earnout rebate. As the rebate is reviewed by the CODM at the segment level, it was included in the Midstream segment operating costs.

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 Manager in connection with the Services Agreement and other costs not directly associated with field operations. General and administrative expenses, inclusive of unit-based compensation expense, increased 5%, to $26.0 million for the year December 31, 2017, compared to $24.8 million for the same period in 2016. This increase was primarily driven by an increase in asset management fees and outstanding equity awards related to the restricted unit grant on March 21, 2017.

Interest expense, net. Interest expense increased $3.2 million, or 64%, to $8.3 million for the year ended December 31, 2017, compared to $5.1 million for the same period in 2016. This increase was the result of net draws on our Credit Agreement and letters of credit outstanding during the first quarter 2017, primarily to fund capital projects in our joint ventures with Targa.

Gain (loss) on embedded derivatives. For information related to embedded derivatives see Note 5. “Derivative and Financial Instruments.”

Liquidity and Capital Resources

As of December 31, 2017, we had approximately $0.3 million in cash and cash equivalents and approximately $11.0 million available for borrowing under the Credit Agreement in effect on such date, as discussed below. During the years ended December 31, 2017 and 2016, we paid approximately $7.5 million and $4.4 million, respectively, in cash for interest on borrowings under our Credit Agreement and approximately $0.1 million and $0.3 million, respectively, in cash for the commitment fee on undrawn commitments.

Our capital expenditures during the year ended December 31, 2017 were funded with cash on hand, borrowings under our Credit Agreement, and proceeds from sales of common units in connection with our at-the-market facility. In the future, capital and liquidity are anticipated to be provided by operating cash flows, borrowings under our Credit Agreement and proceeds from the issuance of additional limited partner units. We expect that the combination of these capital resources will be adequate to meet our short-term working capital requirements, long-term capital expenditures program and expected quarterly cash distributions.

We expect that our future cash requirements relating to working capital, maintenance capital expenditures and quarterly cash distributions to our partners will be funded from cash flows internally generated from our operations. Our expansion capital expenditures will be funded by borrowings under our Credit Agreement or from potential capital market transactions. However, there can be no assurance that operations and other capital resources will provide cash in sufficient amounts to maintain our current debt level, planned levels of capital expenditures, operating expenses or any cash distributions that we may make to unitholders.

Credit Agreement

We have entered into a credit agreement with Royal Bank of Canada, as administrative agent and collateral agent, and the lenders party thereto that provides a maximum commitment of $500.0 million and has a maturity date of March 31, 2020 (the “Credit Agreement”). Borrowings under the Credit Agreement are secured by various mortgages of oil and natural gas properties that we own as well as various security and pledge agreements among the Partnership and certain of its subsidiaries and the administrative agent.

The amount available for borrowing at any one time under the Credit Agreement is limited to the borrowing base for our oil and natural gas properties and our midstream assets. Borrowings under the Credit Agreement are available for direct investment in oil and natural gas properties, acquisitions, and working capital and general business purposes. The Credit Agreement has a sub-limit of $15.0 million which may be used for the issuance of letters of credit. The initial borrowing base under the Credit Agreement was $200.0 million. 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 and the amount of distributions received from joint ventures multiplied by 5.0 initially, 4.75 for the second full quarter after the acquisition of Western Catarina Midstream and 4.5 thereafter. Outstanding borrowings in excess of our borrowing base must be repaid or we must pledge other oil and natural gas properties as additional collateral. We may elect to pay any borrowing base deficiency in three equal monthly installments such that the deficiency is eliminated in a period of three months. Any increase in our borrowing base must be approved by all of the lenders. As of December 31, 2017, the borrowing base under the Credit Agreement was $249.3 million, with an elected commitment amount of $200.0 million.

At our election, interest for borrowings under the Credit Agreement are determined by reference to (i) the London interbank rate (“LIBOR”) plus an applicable margin between 2.25% and 3.25% per annum based on utilization or (ii) a domestic bank rate (“ABR”) plus an applicable margin between 1.25% and 2.25% per annum based on utilization plus (iii) a commitment fee of 0.500% per annum based on the unutilized borrowing base. Interest on the borrowings for ABR loans and the commitment fee are generally payable quarterly. Interest on the borrowings for LIBOR loans are generally payable at the applicable maturity date.

The Credit Agreement contains various covenants that limit, among other things, our ability to incur certain indebtedness, grant certain liens, merge or consolidate, sell all or substantially all of our assets, make certain loans, acquisitions, capital expenditures and investments, and pay distributions.

In addition, we are required to maintain the following financial covenants:

current assets to current liabilities of at least 1.0 to 1.0 at all times;

senior secured net debt to consolidated adjusted EBITDA for the last twelve months, as of the last day of any fiscal quarter, of not greater than 4.5 to 1.0 if the adjusted EBITDA of our midstream operations equals or exceeds one-third of total Adjusted EBITDA or 4.0 to 1.0 if the adjusted EBITDA of our midstream operations is less than one-third of total adjusted EBITDA; and

minimum interest coverage ratio of at least 2.5 to 1.0 if the adjusted EBITDA of our midstream operations is greater than one-third of our total adjusted EBITDA.

Commitments and Contractual Obligations

As of December 31, 2017, our contractual obligations included our long-term debt, in the form of a Credit Agreement, asset retirement obligations (“ARO”), and earnout derivative. The following table summarizes our contractual obligations as of December 31, 2017 (in thousands):


	Less than 1						More than
	Year		1-3 Years		3-5 Years		5 years		Total
Long-Term Debt	$	—	$	189,000	$	—	$	—	$	189,000
ARO(a)		—		—		—		6,074		6,074
Earnout derivative(b)		151		1,127		2,019		3,105		6,402
Total	$	151	$	190,127	$	2,019	$	9,179	$	201,476

(a)

Amounts represent the present value of our estimate of future asset retirement obligations. Because these costs typically extend many years into the future, estimating these future costs requires management to make estimates and judgments that are subject to future revisions based upon numerous factors, including the rate of inflation, changing technology and the political and regulatory environment. See Note 9, “Asset Retirement Obligations.”

(b)

Amounts represent the present value of our estimate of future earnout obligations. These costs are contingent and subject to various factors, which are discussed in Note 4, “Fair Value Measurements.”

Open Commodity Hedge Positions

We enter into hedging arrangements to reduce the impact of oil and natural gas price volatility on our operations. By removing the price volatility from a significant portion of our oil and natural gas production, we have mitigated, but not eliminated, the potential effects of changing prices on our cash flow from operations. While mitigating the negative effects of falling commodity prices, these derivative contracts also limit the benefits we might otherwise receive from increases in commodity prices. These derivative contracts also limit our ability to have additional cash flows to fund higher severance taxes, which are usually based on market prices for oil and natural gas. Our operating cash flows are also impacted by the cost of oilfield services. In the event of inflation increasing service costs or administrative expenses, our hedging program will limit our ability to have increased operating cash flows to fund these higher costs. Increases in the market prices for oil and natural gas will also increase our need for working capital as our commodity hedging contracts cash settle prior to our receipt of cash from our sales of the related commodities to third parties. In 2016, we restructured a portion of our commodity derivative portfolio by liquidating “in-the-money” oil and natural gas derivatives settling in fourth quarter 2016 and using the proceeds from the sale liquidation to enhance the fixed price on natural gas derivatives to be settled in 2017. Cash settlement receipts of approximately $3.2 million from the termination of the oil and natural gas derivatives were applied as premiums for the enhanced natural gas derivatives in 2016. In August 2017, we repositioned certain of our oil and natural gas hedges in anticipation of the sale of the Texas Production Assets and, in the process, received $3.6 million in net cash from the counterparties on those hedges.

It is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. All of our derivatives are currently collateralized by the assets securing our Credit Agreement and therefore currently do not require the posting of cash collateral. This is significant since we are able to lock in sales prices on a substantial amount of our expected future production without posting cash collateral based on price changes prior to the hedges being cash settled.

The following tables as of December 31, 2017, summarize, for the periods indicated, our hedges currently in place through December 31, 2020. All of these derivatives are accounted for as mark-to-market activities.

MTM Fixed Price Swaps—NYMEX (Henry Hub)


	For the Year Ended December 31, (volume in MMBtu)
	March 31,			June 30,			September 30,			December 31,			Total
		Average			Average			Average			Average			Average
	Volume	Price		Volume	Price		Volume	Price		Volume	Price		Volume	Price
2018	132,088	$	3.00	126,600	$	3.00	121,600	$	3.00	117,040	$	3.00	497,328	$	3.00
2019	119,832	$	2.85	115,784	$	2.85	112,032	$	2.85	108,552	$	2.85	456,200	$	2.85
2020	105,104	$	2.85	102,008	$	2.85	99,136	$	2.85	96,200	$	2.85	402,448	$	2.85
													1,355,976

MTM Fixed Price Basis Swaps–West Texas Intermediate (WTI)


	For the Year Ended December 31, (volume in Bbls)
	March 31,			June 30,			September 30,			December 31,			Total
		Average			Average			Average			Average			Average
	Volume	Price		Volume	Price		Volume	Price		Volume	Price		Volume	Price
2018	70,600	$	59.63	66,432	$	59.71	62,840	$	59.78	59,704	$	59.84	259,576	$	59.74
2019	62,528	$	60.41	59,552	$	60.44	57,024	$	60.48	54,824	$	60.52	233,928	$	60.46
2020	52,776	$	53.50	50,960	$	53.50	49,224	$	53.50	47,624	$	53.50	200,584	$	53.50
													694,088

Operating Cash Flows

Our net operating cash flows for the year ended December 31, 2017, were $52.1 million, compared to net cash flow provided by operating activities of $40.2 million for the same period in 2016. This increase was primarily related to the impact of higher average commodity prices between the periods resulting in an increase of $4.1 million, as well as return from equity investment greater than equity earnings for the period of $5.8 million.

Our operating cash flows are subject to many variables, the most significant of which is the volume of oil and natural gas transported through our midstream assets, volatility of oil and natural gas prices and our level of production of oil and natural gas. Oil and natural gas prices are determined primarily by prevailing market conditions, which are dependent on regional and worldwide economic activity, weather and other factors beyond our control. Our future operating cash flows will depend on oil and natural gas transported through our midstream assets, as well as the market prices of oil and natural gas and our hedging program.

Investing Activities

Our net cash flows used in investing activities for the year ended December 31, 2017 were $32.7 million, consisting of $31.7 million related to midstream activities, including pipeline construction, and contributions to Carnero Processing and Carnero Gathering totaling $13.7 million. These outflows were offset by $11.7 million related to proceeds from sales of oil and natural gas properties.

Our net cash flows used in investing activities for the year ended December 31, 2016 were $138.5 million, which was primarily related to $24.2 million for cash consideration paid in the Production Acquisition and $107.3 million for cash consideration paid for the Carnero Gathering and Carnero Processing acquisitions.

Financing Activities

Our cash flows used by financing activities were $20.1 million for the year ended December 31, 2017, compared to $92.7 million provided by financing activities for the same period in 2016. During the year ended December 31, 2017, we had borrowings under our Credit Agreement of $48.0 million and proceeds from issuance of common units of $1.3 million. We distributed $31.5 million and $25.2 million to Class B preferred unitholders and common unitholders, respectively, during the same period. Additionally, we paid $0.6 million in offering costs and repaid $12.0 million of borrowings.

Our cash flows provided by financing activities were $92.7 million for the year ended December 31, 2016. We had net borrowings under our Credit Agreement of $46.0 million. We received $99.2 million from the issuance of common units during the period, while incurring $5.4 million in offering expenses. We also made cash distributions on our common and Class B preferred units of $6.7 million and $37.2 million, respectively

Off-Balance Sheet Arrangements

As of December 31, 2017, we had no off-balance sheet arrangements with third parties, and we maintain no debt obligations that contain provisions requiring accelerated payment of the related obligations in the event of specified levels of declines in credit ratings.

Credit Markets and Counterparty Risk

We actively monitor the credit exposure and risks associated with our counterparties. Additionally, we continue to monitor global credit markets to limit our potential exposure to credit risk where possible. Given our midstream focus, our primary credit exposure relates to the credit worthiness of our counterparties under our gathering and processing agreements. Sanchez Energy, whose earned revenues contribute exclusively to our midstream segment, accounted for 63% of total revenue for the year ended December 31, 2017. As of December 31, 2017, we had no past due receivables from Sanchez Energy, and through December 31, 2017, we have not suffered any significant losses with our counterparties as a result of nonperformance.

Certain key counterparty relationships are described below:

Derivative Counterparties

As of December 31, 2017, our derivatives were with ING, SunTrust Bank, Comerica and Royal Bank of Canada, all of whom are lenders in our Credit Agreement. All of our derivatives are currently collateralized by the assets securing our Credit Agreement and therefore currently do not require the posting of cash collateral. As of December 31, 2017, each of these financial institutions had an investment grade credit rating.

Credit Agreement

As of December 31, 2017, the banks and their percentage commitments in our Credit Agreement were: Royal Bank of Canada (14%), Compass Bank (12.5%), SunTrust Bank (12.5%), Capital One, N.A. (12.5%), Comerica Bank (12.5%), CIT Bank, N.A. (9%), Citibank, N.A. (9%), Credit Suisse AG, Cayman Islands (9%) and ING Capital LLC (9%). As of December 31, 2017, each of these financial institutions had an investment grade credit rating.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of these financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions. The results of these estimates and assumptions form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in the preparation of our financial statements.

As of December 31, 2017, there were no changes with regard to the critical accounting policies disclosed in our Annual Report on Form 10-K for the year ended December 31, 2016, which was filed with the SEC on March 28, 2017. The policies disclosed included the accounting for oil and natural gas properties, oil and natural gas reserve quantities, revenue recognition and hedging activities. Please read Note 2 to the consolidated financial statements for a discussion of additional accounting policies and estimates made by management.

Oil and Natural Gas Properties

We follow the successful efforts method of accounting for our oil and natural gas production activities. Under this method of accounting, costs relating to leasehold acquisition, property acquisition and the development of proved areas are capitalized when incurred. If proved reserves are found on an undeveloped property, leasehold cost is transferred to proved properties. Under this method of accounting, costs relating to the development of proved areas are capitalized when incurred.

Depreciation and depletion of producing oil and natural gas properties is recorded at the field level, based on the units-of-production method. Unit rates are computed for unamortized drilling and development costs using proved developed reserves and for unamortized leasehold costs using all proved reserves. Acquisition costs of proved properties are amortized on the basis of all proved reserves, developed and undeveloped, and capitalized development costs (including wells and related equipment and facilities) are amortized on the basis of proved developed reserves. As more fully described in Note 7 to our consolidated financial statements, proved reserves estimates are subject to future revisions when additional information becomes available.

All other properties, including the 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 3 to 15 years for furniture and equipment, and up to 36 years for gathering facilities.

Estimated asset retirement costs are recognized when the asset is acquired or placed in service, and are amortized over proved reserves using the units-of-production method. Asset retirement costs are estimated by our engineers using existing regulatory requirements and anticipated future inflation rates.

Oil and natural gas properties are reviewed for impairment when facts and circumstances indicate that their carrying value may not be recoverable. We assess impairment of capitalized costs of proved oil and natural gas properties by comparing net capitalized costs to estimated undiscounted future net cash flows using expected prices. If net capitalized costs exceed estimated undiscounted future net cash flows, the measurement of impairment is based on estimated fair value, which would consider estimated future discounted cash flows. Cash flow estimates for the impairment testing are based on third party reserve reports and exclude derivative instruments. Refer to Note 7 to our consolidated financial statements for additional information.

Reserves of Natural Gas, NGLs and Oil

Our estimate of proved reserves is based on the quantities of natural gas, NGLs and oil that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Management estimates the proved reserves attributable to our ownership based on various factors, including consideration of the reserve report prepared by Ryder Scott, an independent oil and natural gas consulting firm. On an annual basis, our proved reserve estimates and the reserve report prepared by Ryder Scott is reviewed by the audit committee of the board of directors of our general partner and the board of directors of our general partner. Our financial statements for 2017 and 2016 were prepared using Ryder Scott’s estimates of our proved reserves.

Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. The accuracy of our reserve estimates is a function of many factors including the following: the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions and the judgments of the individuals preparing the estimates.

Our proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the actual quantities of oil and natural gas eventually recovered.

Revenue Recognition

and oil are generally sold on a monthly basis. Most of the contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a specific tank battery, gathering or transmission line, quality of natural gas, NGLs and oil, and prevailing supply and demand conditions, so that the price of the natural gas, NGLs and oil fluctuates to remain competitive with other available natural gas, NGLs and oil supplies. As a result, revenues from the sale of natural gas, NGLs and oil will suffer if market prices decline and benefit if they increase. We believe that the pricing provisions of our natural gas, NGLs and oil contracts are customary in the industry.

Gas imbalances occur when sales are more or less than the entitled ownership percentage of total gas production. We use the entitlements method when accounting for gas imbalances. Any amount received in excess is treated as a liability. If less than the entitled share of the production is received, the excess is recorded as a receivable. There were no material gas imbalance positions at December 31, 2017 and 2016.

Revenues relating to the gathering and transportation sales of oil and natural gas are recognized in the period service is provided. Under these arrangements, the Partnership receives a fee or fees for services provided. The revenue the Partnership recognizes from gathering and transportation services is generally directly related to the volume of oil and natural gas that flows through its systems.

Hedging Activities

We have implemented a hedging program to limit our exposure to changes in commodity prices for our oil and natural gas sales. We do not enter into speculative trading positions.

We account for all our open derivatives as mark-to-market activities using the mark-to market accounting method. Using this method, the contracts are carried at their fair value on our consolidated balance sheets as either short term or long term assets or liabilities based on their anticipated settlement date. We recognize all unrealized and realized gains and losses related to these contracts on our consolidated statements of operations under the captions “Natural gas sales” and “Oil sales,” which comprise our total revenues for commodity derivatives.

We experience earnings volatility as a result of using the mark-to-market accounting method. This accounting treatment can cause earnings volatility as the positions related to future oil and natural gas production are marked-to-market. These non-cash unrealized gains or losses are included in our current Statement of Operations until the derivatives are cash settled as the commodities are produced and sold. Increases in the market price of oil or natural gas relative to the fixed future prices for our hedges, result in unrealized, non-cash mark-to-market losses on those derivatives and lower reported net income. Decreases in the market price of oil or natural gas relative to the fixed future prices for our hedges, result in unrealized, non-cash mark-to-market gains on those derivatives and higher reported net income. Although these gains and losses are required to be reported immediately in earnings as market prices change, the fair value of the related future physical transaction is not marked-to-market and therefore is not reflected as revenues or expenses or as an accounts receivable or accounts payable in our financial statements. This mismatch impacts our reported results of operations and our reported working capital position until the derivatives are cash settled and the future physical transaction occurs. Upon cash settlement of the derivatives, the sale of the physical commodity at then-current market prices offsets the previously reported mark-to-market gains or losses such that the cumulative net cash realized results in a net sale of the physical oil and natural gas production at the fixed future prices for our hedge. When our derivative positions are cash settled, the realized gains and losses of those derivative positions are included in our statement of operations as sales of natural gas, NGLs and oil depending on the derivative.

If we were to account for our derivatives as cash flow hedges, we would record changes in the fair value of derivatives designated as hedges that are effective in offsetting the variability in cash flows of forecasted transactions in other comprehensive income until the forecasted transactions occur. At the time the forecasted transactions occur, we would reclassify the amounts recorded in other comprehensive income into earnings. We would record the ineffective portion of changes in the fair value of derivatives used as hedges immediately in earnings. When amounts for hedging activities are reclassified from “Accumulated other comprehensive income (loss)” on the balance sheet to the Statement of Operations, we would record settled oil and natural gas derivatives as “Oil and natural gas sales” and settled interest rate swaps as “Interest expense (income).”

PART III

Item 10. Directors, Executive Officers and Corporate Governance

The following table shows information for members of the board of directors and executive officers of our general partner as of March 6, 2018. All of the directors of our general partner are elected by Manager, as the sole member of our general partner. Members of the board of directors of our general partner hold office until their successors have bene elected or qualified or until the earlier of their death, resignation, removal or disqualification. Executive officers hold office at the discretion of, and may be removed by, the board of directors of our general partner.


Name	Age	Position with Sanchez Midstream Partners LP
Alan S. Bigman	50	Independent Director
Kirsten A. Hink	51	Chief Accounting Officer
Jack Howell	31	Director
Richard S. Langdon	67	Independent Director
G.M. Byrd Larberg	65	Independent Director
Antonio R. Sanchez, III	44	Director; Chairman of the Board
Eduardo A. Sanchez	38	Director
Patricio D. Sanchez	37	Director; President & Chief Operating Officer
Luke R. Taylor	40	Director
Charles C. Ward	57	Chief Financial Officer and Secretary
Gerald F. Willinger	50	Director; Chief Executive Officer

Alan S. Bigman was elected as a director of our general partner in March 2015 and was previously a director of Sanchez Production Partners LLC, having been first elected in July 2014. Mr. Bigman is an independent member of the Conflicts Committee of our general partner’s board of directors and is the Chairman of the Audit Committee of our general partner’s board of directors. Mr. Bigman currently serves as an independent non-executive Director and Chairman of the Audit Committee of a $1.5 billion dollar privately held chemicals company. His extensive board experience also includes Basell Polyolefins, an international chemical producer and predecessor of LyondellBasell, where he served as a non-executive Director before his appointment as Chief Financial Officer, and Svyazinvest, then Russia’s largest telecom company, as well as several others. Mr. Bigman’s executive experience includes fourteen years in positions with Access Industries, a privately-held, U.S.-based industrial group, and in senior positions with its portfolio companies. From June 1996 to March 1998, Mr. Bigman was Senior Vice President of Access Industries, overseeing strategic investments. From March 1998 until September 2003, Mr. Bigman served as Vice President and Director of Corporate Finance of Tyumen Oil Company (TNK), a major Russian oil and gas producer and refiner, where he raised over $5 billion to finance the growth of the company from its privatization in 1997 through a sale of a 50% stake to British Petroleum (BP) in 2003, creating TNK-BP, a $20 billion joint venture. From 2003 to 2004, he served as Vice President and Director of Corporate Finance for SUAL, a large Russian aluminum smelter, where he reorganized the finance function and executed strategic merger transactions. From September 2004 until December 2005, Mr. Bigman rejoined Access Industries as Senior Vice President. In January 2006, Mr. Bigman was appointed Chief Financial Officer of Basell Polyolefins, an international chemicals company based in The Netherlands, where he served through 2007 and co-led the acquisition of Lyondell to create one of the largest global chemical companies. In January 2008 Mr. Bigman was appointed Chief Financial Officer of LyondellBasell Industries, the successor company to Basell Polyolefins and Lyondell. LyondellBasell's US operations filed for bankruptcy in January 2009. Mr. Bigman continued to serve as Chief Financial Officer until August 2009, and worked for the company in a project role through March 2010. From 2011 through 2012, he served on a project basis as Director, Capital Markets and M&A of KCAD Deutag, an oilfield services company based in Aberdeen, UK, where he was responsible for reorganizing and staffing the company’s finance, corporate development and tax functions.

Kirsten A. Hink was elected Chief Accounting Officer of our general partner in May 2015. Mrs. Hink has served as Senior Vice President and Chief Accounting Officer of Sanchez Energy since January 2015, and she previously served as Sanchez Energy’s Vice President and Principal Accounting Officer from March 2012. Prior to joining Sanchez Energy, Mrs. Hink served as the Controller of Vanguard Natural Resources, LLC from January 2011 to February 2012. From January 2010 to December 2010, she served as Assistant Controller of Mariner Energy, Inc. She served as the Chief Accounting

Officer for Edge Petroleum Corporation, or Edge, from July 2008 through December 2009 and the Vice President and Controller for Edge from October 2003 through July 2008. Prior to that time, she served as Controller of Edge from December 31, 2000 to October 2003 and Assistant Controller of Edge from June 2000 to December 2000. Edge filed for Chapter 11 bankruptcy protection in October 2009. Mrs. Hink is a Certified Public Accountant in the State of Texas.

Jack Howell was elected as a director of our general partner in October 2015. Mr. Howell has been with Stonepeak Infrastructure Partners (“Stonepeak”) since 2015. Mr. Howell currently serves as a Senior Managing Director at Stonepeak. Prior to joining Stonepeak, he covered the oil and gas sector for Davidson Kempner, a hedge fund that focuses on distressed investments, from 2014 to 2015. Prior to Davidson Kempner, Mr. Howell worked for Denham Capital, an energy-focused private equity firm from 2011 to 2014. Mr. Howell started his career as an Analyst in Credit Suisse’s oil and gas investment banking group from 2009 to 2011.

Richard S. Langdon was elected as a director of our general partner in March 2015 and was previously a director of Sanchez Production Partners LLC, having been first elected in December 2006. Mr. Langdon is an independent member of the Audit Committee and Conflicts Committee of our general partner’s board of directors. Mr. Langdon is also currently the President and Chief Executive Officer of Badlands Energy, Inc., a privately held exploration and production company, and its publicly traded predecessor entity, Gasco Energy, Inc., since May 2013. Mr. Langdon has also served as a Director of Badlands Energy, Inc. and its predecessor, Gasco Energy, Inc., since 2003. Badlands Energy filed for Chapter 11 bankruptcy in August 2017. In addition to his current Badlands Energy titles, Mr. Langdon is also serving as Debtor-in-Possession for Badlands Energy, Inc. Mr. Langdon also currently serves on the board of directors, as chairman of the audit committee and as a member of the compensation committee of Gulfslope Energy, Inc., which capacities he has served in since March 2014. Mr. Langdon was the President and Chief Executive Officer of KMD Operating Company LLC (“KMD Operating”), a privately held production company, from November 2011 until December 2015 and Matris Exploration Company L.P., a privately held production company, from July 2004 until the merger of Matris Exploration into KMD Operating in November 2011, which merger was effective January 2011. Mr. Langdon also served as President and Chief Executive Officer of Sigma Energy Ventures, LLC, a privately held production company, from November 2007 until November 2013. From 1997 until 2002, Mr. Langdon served as Executive Vice President and Chief Financial Officer of EEX Corporation, a publicly traded exploration and production company that merged with Newfield Exploration Company in 2002. Prior to that, he held various positions with the Pennzoil Companies from 1991 to 1996, including Executive Vice President—International Marketing—Pennzoil Products Company; Senior Vice President—Business Development—Pennzoil Company; and Senior Vice President—Commercial & Control—Pennzoil Exploration & Production Company.

G. M. Byrd Larberg was elected as a director of our general partner in March 2015. He was previously a director of Sanchez Production Partners LLC, having been first elected in July 2014. Mr. Larberg is an independent member of the Audit Committee of our general partner’s board of directors and is the Chairman of the Conflicts Committee of our general partner’s board of directors. Mr. Larberg also serves as a member of the board of directors of Horizon Energy, a private Exploration Company with both Domestic and International focus, which position he has held since late 2016. From 2010 to 2012, Mr. Larberg served as a member of the board of directors of Risco Resources, a small independent exploration company headquartered in Jakarta, Indonesia, which was sold in 2012. Mr. Larberg served as a member of the board of directors of 3GIG, an exploration-focused software firm headquartered in Houston, Texas, from 2008 to 2013 and now serves as an advisor to the board. He is active on the board of the Houston Metropolitan YMCA, as past chairman of the board. He was a board member of Meridian Resources, a Houston-based exploration company, from 2007 until it was acquired by Alta Mesa in 2010. Mr. Larberg began his career at Shell Exploration and Production Company as a geologist in 1976. Over the next twenty-one years, he held various leadership positions within Shell, and served as Vice President of Exploration and Production, Africa and Latin America for Pecten International, an affiliate of Shell Oil Company, from 1993 to 1996. Mr. Larberg left Shell and joined Burlington Resources in 1998. From 1998 to 2006, Mr. Larberg held several key positions at Burlington Resources, beginning as Vice President of Exploration for Burlington Resources International. In 2000, Mr. Larberg was elected Executive Vice President and Chief Operating Officer of Burlington Resources International, a position he held until 2003, when he moved to the corporate office as Vice President of Geosciences. In this capacity, he was responsible for technical excellence for the Geology and Geophysical programs across the company, G&G technology business development, and management of the company-wide exploration portfolio. Mr. Larberg retired from Burlington Resources in April 2006 following the company’s purchase by ConocoPhillips. Mr. Larberg was a director of Duma Hydrocarb Energy Corporation, a publicly traded production company, for a brief period in 2014. He occasionally consults in the areas of technical and portfolio management for exploration companies, including Pemex, Maersk, ONGC and Ecopetrol, Repsol and OMX.

Antonio R. Sanchez, III was elected as a director of our general partner in March 2015 and was previously a director of Sanchez Production Partners LLC, having been first elected in August 2013. Mr. Sanchez, III is Chairman of our general partner’s board of directors. He has served as the Chief Executive Officer of Sanchez Energy, a publicly traded exploration and production company, and has been a member of Sanchez Energy’s board of directors since its formation in August 2011. He has been directly involved in the oil and gas industry for over 12 years. Mr. Sanchez, III is also the Co-President of SOG, which he joined in October 2001. He was the President of SEP Management I, LLC and was a Managing Director of Sanchez Energy Partners I, LP until their dissolution in December 2016. In his capacities as a director and officer of these companies, Mr. Sanchez, III has managed all aspects of their daily operations, including exploration, production, finance, capital markets activities, engineering and land management. From 1997 to 1999, Mr. Sanchez, III was an investment banker specializing in mergers and acquisitions with J.P. Morgan Securities Inc. From 1999 to 2001, Mr. Sanchez, III worked in a variety of positions, including sales and marketing, product development and investor relations, at Zix Corporation, a publicly traded encryption technology company (NASDAQ: ZIXI). Mr. Sanchez, III was also a member of the board of directors of Zix Corporation from May 2003 to June 2014.

Eduardo A. Sanchez was elected as a director of our general partner in June 2015. Mr. Sanchez served as president of Sanchez Energy Corporation from October 2015 to November 2017, President and Chief Executive Officer of Sanchez Resources, LLC from February 2010 until November 2017, co-president of SOG from July 2014 to November 2017, and chief executive officer of Sanchez Oil & Gas Mexico Holdings, LLC from August 2015 to December 2017. Prior to his work at Sanchez Resources, LLC, Mr. Sanchez worked at Commonwealth Associates, Inc. focusing on private equity and debt placements in small and midsize market capitalization businesses including those in the energy sector.

Patricio D. Sanchez was elected President & Chief Operating Officer of our general partner in March 2017, Chief Operating Officer of our general partner in May 2015 and a director in June 2015. Mr. Sanchez has served as co-president of SOG since June 2014 and prior to that from April 2010 to June 2014 as Executive Vice President. Mr. Sanchez has served as an Executive Vice President of Sanchez Energy Corporation since November 2016. Mr. Sanchez has also been the managing member of Santerra Holdings, LLC, an oil and gas production company, since February 2012. Mr. Sanchez has managed many aspects of these companies’ daily operations, including exploration, production, finance, capital markets activities, engineering and land management.

Luke R. Taylor was elected as a director of our general partner in October 2015. Mr. Taylor has served as a Senior Managing Director with Stonepeak since August 2011 and has served as a member of Stonepeak’s investment committee since 2015. Mr. Taylor sits on the boards of the following private companies: Golar Power, which develops, owns and operates integrated LNG-based transportation and downstream solutions, Ironclad Energy Partners, which develops, owns and operates energy generation and utility infrastructure assets, and Tidewater Holdings, which is an inland barge and terminal operator in the Pacific Northwest. Mr. Taylor is a former director of Paradigm Energy Partners, Orion Holdings and Northstar Renewable Power. Prior to joining Stonepeak, Mr. Taylor was a Senior Vice President with Macquarie Capital based in New York from August 2005 to May 2011.

Charles C. Ward was elected Chief Financial Officer & Secretary of our general partner in March 2015. He previously served as Chief Financial Officer and Treasurer of Sanchez Production Partners LLC from March 2008 until its conversion to a limited partnership in March 2015 and Secretary from July 2014 until March 2015. Mr. Ward also served as a Vice President of Constellation Energy Commodities Group, Inc. from November 2005 until December 2008. Prior to that time, he was a Vice President of Enron Creditors Recovery Corp. from March 2002 to November 2005.

Gerald F. Willinger was elected as a director of our general partner in March 2015 and was previously a director of Sanchez Production Partners LLC, having been first elected in August 2013. Mr. Willinger was elected Interim Chief Executive Officer of our general partner in April 2015 and Chief Executive Officer in December 2015. Mr. Willinger has served as a Managing Director of Sanchez Capital Advisors, LLC since February 2010. Mr. Willinger was also a co-founder, officer and director of Sanchez Resources from February 2010 to November 2017 when Sanchez Resources was acquired by Sanchez Energy Corporation. From 1998 to 2000, Mr. Willinger was an investment banker with Goldman, Sachs & Co. Mr. Willinger served in various private equity investment management roles at MidOcean Partners, LLC and its predecessor entity, DB Capital Partners, LLC, from 2000 to 2003 and at the Cypress Group, LLC from 2003 to 2006. Prior to joining Sanchez Capital Advisors, LLC, Mr. Willinger was a Senior Analyst for Silver Point Capital, LLC, a credit-opportunity fund, from 2006 to 2009.

Messrs. Howell and Taylor were elected to the board of directors of our general partner in October 2015 pursuant to a board representation and standstill agreement entered into in connection with our issuance of Class B preferred units to Stonepeak Catarina Holdings LLC. Pursuant to the agreement, we and our general partner agreed to permit Stonepeak to designate two persons to serve on our general partner’s board of directors. The right to designate one board member will immediately terminate on such date as Stonepeak no longer owns at least 25% of the outstanding Class B preferred units issued to it; and the right to designate the second board member will immediately terminate on such date as no Class B preferred units are outstanding. Stonepeak also has the right to appoint the three independent members to the board of directors if all of the Class B preferred units have not been redeemed by December 31, 2021, with such right continuing until all Class B preferred units have been redeemed.

Messrs. Antonio R. Sanchez, III, Eduardo A. Sanchez and Patricio D. Sanchez are brothers.

Qualifications of Board of Directors

The sole member of our general partner elects all of the persons to our general partner’s board of directors, except for two persons who are appointed by holders of our Class B preferred units. The following sets forth the specific experience, qualifications, attributes and skills that led the sole member of our general partner to conclude that the persons appointed by it should serve as directors:

Mr. Bigman brings considerable financial, managerial, transaction and corporate governance experience to the board of directors of our general partner. During his career, he has held management positions of increasing responsibility in major energy corporations throughout the world where he has successfully lead financings, financial restructurings, mergers and acquisitions involving companies focused on various aspects of the hydrocarbon value chain. With respect to energy finance, as Vice President and Director of Corporate Finance for TNK, a leading Russian oil and gas producer, he raised capital to finance the growth of the company from its privatization in 1997 through a sale of a 50% stake to British Petroleum (BP) in 2003, creating TNK-BP, a $20 billion joint venture. In the area of corporate governance, Mr. Bigman served on the board of directors of Basell Polyolefins, where he was a member of the audit and compensation committees, which is beneficial for our board operations. He has also served on several international boards, including the board of Svyazinvest, Russia’s largest telecommunications holding company, and JKX Oil and Gas, a UK public company focused on international oil and gas assets.

Mr. Langdon brings to the board of directors of our general partner considerable financial and managerial experience in the energy industry as well as his entrepreneurial abilities, which are valuable to us. He has served as the Chief Financial Officer of EEX Corporation, a publicly traded production company that merged with Newfield Exploration. He has also held significant commercial positions with the Pennzoil Companies, including roles in business development and marketing. He was also the founder and owner of two privately held oil and gas companies. Mr. Langdon has extensive experience in finance and accounting that adds significant value to the board’s oversight role of our financial reporting. He has prior public company board and audit committee experience, which is beneficial for our board operations, and served as the chairman of the audit committee of Gasco Energy, Inc., a publicly traded production company until he was named Gasco’s President and Chief Executive Officer.

Mr. Larberg brings to the board of directors of our general partner significant technical, operational and financial management experience in the oil and natural gas industry. His background provides a unique perspective on the dynamics of the oil and natural gas production industry. He has considerable governance experience, having previously served on the boards of several other companies. Taken together, this wealth of experience is invaluable to our board as we look to grow the Partnership.

Mr. Sanchez, III brings to the board of directors of our general partner substantial oil and gas/energy industry experience in both public and private entities. In his current capacity as Chief Executive Officer of Sanchez Energy, he brings the perspective of leading a quickly growing, publicly-traded upstream company focused on asset value maximization and the creation of shareholder value. In his current capacity as Co-President of SOG, he brings particular expertise in operating multiple oil and natural gas entities through a shared service model.

Mr. Eduardo Sanchez brings to the board of directors of our general partner substantial oil and gas/energy industry experience in both public and private entities. Through his past experience as the President of Sanchez Energy and co-

president of SOG, he brings the perspective of leading a quickly growing publicly-traded upstream company focused on asset value maximization and the creation of shareholder value and particular expertise in operating multiple oil and natural gas entities through a shard service model.

Mr. Patricio Sanchez brings to the board of directors of our general partner substantial oil and gas/energy industry experience in both public and private entities. As an Executive Vice President at Sanchez Energy, he brings the perspective of leading a quickly growing, publicly-traded upstream company focused on asset value maximization and the creation of shareholder value. In his current capacity as Co-President of SOG, he brings particular expertise in operating multiple oil and gas entities through a shared service model.

Mr. Willinger brings to the board of directors of our general partner substantial experience in risk management, finance and negotiated transactions in the energy industry. He has a valuable perspective on master limited partnerships, which provides the board with unique insights into master limited partnership management and growth opportunities. In addition, he brings an expansive network of both private and public capital providers, which is useful for the board when evaluating possible capital sources.

The following sets forth the specific experience, qualifications, attributes and skills that led the holders of our Class B preferred units to conclude that the persons appointed by them should serve as directors:

Mr. Howell brings to the board of directors of our general partner extensive oil and gas investing experience, along with experience in oil and gas transaction financings and mergers and acquisitions.

Mr. Taylor brings to the board of directors of our general partner significant investment experience in energy and infrastructure companies, along with experience in finance and mergers and acquisitions.

Committees of the Board of Directors

The board of directors of our general partner has two standing committees: an audit committee and a conflicts committee. We do not have a compensation committee, but rather the board of directors of our general partner approves equity grants to directors, officers, employees and service providers.

Audit Committee

As described in the audit committee charter, the audit committee is directly responsible for the appointment, compensation, retention and oversight of the work of the independent public accountants to audit our financial statements, including assessing the independent auditor’s qualifications and independence, and establishes the scope of, and oversees, the annual audit. The committee also approves any other services provided by public accounting firms. The board of directors of our general partner has delegated to the audit committee the review and approval of our decision to enter into derivative transactions and our exemption from the swap clearing and swap execution requirements of the Dodd-Frank Act. The audit committee provides assistance to the board in fulfilling its oversight responsibility to the unitholders, the investment community and others relating to the integrity of our financial statements, our compliance with legal and regulatory requirements, the independent auditor’s qualifications and independence and the performance of our internal audit function. The audit committee oversees our system of disclosure controls and procedures and system of internal controls regarding financial, accounting, legal compliance and ethics that management and the board of directors of our general partner established. In doing so, it is the responsibility of the audit committee to maintain free and open communication between the committee and our independent auditors, the internal accounting function and our management.

Messrs. Bigman (chair), Langdon and Larberg are members of the audit committee. The board of directors of our general partner has determined that Mr. Bigman is an “audit committee financial expert” as that term is defined in the applicable rules of the SEC and that he is “independent” as defined in applicable NYSE American listing standards.

Conflicts Committee

Under our partnership agreement, the board of directors of our general partner has appointed a conflicts committee composed of the independent directors, G. M. Byrd Larberg, chairman, Alan Bigman and Richard Langdon, to review

Summary Compensation Table

The following table sets forth the compensation of our named executive officers (which are the chief executive officer and the two next most highly compensated officers of our general partner) for 2017 and 2016:


				Cash		Unit		All Other
Name and Principal Position	Year	Salary		Bonus		Awards (a)		Compensation (b)		Total

Gerald F. Willinger	2017	$	600,000	$	—	$	1,299,982	$	192,756	$	2,092,738
Chief Executive Officer (c)	2016	$	600,000	$	—	$	99,991	$	68,590	$	768,581

Patricio D. Sanchez	2017	$	400,000	$	—	$	899,985	$	68,152	$	1,368,137
President & Chief Operating Officer (c)(d)	2016	$	400,000	$	—	$	99,991	$	51,748	$	551,739

Charles C. Ward	2017	$	275,000	$	—	$	499,992	$	17,134	$	792,126
Chief Financial Officer and Secretary (c)	2016	$	275,000	$	—	$	—	$	1,380,689	$	1,655,689

(a)

For 2016, Messrs. Willinger and Sanchez were each issued 9,661 units under the Plan for director compensation with a grant date fair value of $99,991, based on the $10.35 price per common unit on April 19, 2016, which was the closing price as reported on the NYSE American on the day before the date of grant. For 2017, Messrs. Willinger and Sanchez were each issued 6,369 units under the Plan for director compensation with a grant date fair value of $99,993, based on the $15.70 price per common unit on March 31, 2017, which was the closing price as reported on the NYSE American on the day before the date of grant. On March 21, 2017, the board of directors of our general partner awarded executive bonuses for services rendered in 2017, which were paid in the form of restricted units under the Plan to vest one year after the date of grant. Messrs. Willinger, Sanchez and Ward received 82,191, 54,794 and 34,246 restricted units, respectively, with a grant date fair value per common unit of $1,199,989, $799,992, and $499,992, respectively, based on a price per common unit of $14.60, which was the closing price on the date of grant as reported on the NYSE American.

(b)

The amount in this column reflects the amount of matching contributions made under our 401k plan, parking cost paid for our executive officers, the aggregate incremental cost of the personal use of aircraft made available by SOG, and allocated to the Partnership and the cost of life insurance for our executive officers. Mr. Ward also received cash a cash severance payment in January 2016 of $1,363,375 relating to the termination of his employment agreement. For Messrs. Willinger and Sanchez, the amounts for 2017 and 2016 also include $44,500 and $50,500, respectively, in director compensation paid in cash. For Messrs. Willinger and Sanchez, the amounts for 2017 include the aggregate incremental cost of the personal use of aircraft made available by SOG and allocated the Partnership of $129,866 and $22,404, respectively.

(c)

Our named executive officers are eligible to participate in benefit plans such as medical, dental, life, and disability insurance, 401k and flexible spending accounts on the same terms as all employees or service providers.

(d)

Mr. Sanchez was elected Chief Operating Officer in May 2015 and President & Chief Operating Officer in March 2017.

None of the executive officers of our general partner have employment agreements.

Outstanding Equity Awards at Fiscal Year-End 2017

The following table sets forth the outstanding equity awards and their market value using the closing price of our common units on NYSE American at December 31, 2017 for the named executive officers:


	Number of		Fair Market
	Units Not		Value of Units
Name	Vested		Not Vested⁽ᵃ⁾

Gerald F. Willinger	93,426	(b)	$	1,324,698

Patricio D. Sanchez	66,029	(b)	$	924,701

Charles C. Ward	39,246	(b)	$	555,492

(a)

Amounts are based on the closing price of our common units of $11.10 as reported on the NYSE American on December 31, 2017.

(b)

Reflects restricted units granted under the Plan on December 1, 2015 and March 21, 2017, which units vest pro-rata over a three-year period and on their first anniversary, respectively. Except in connection with a change in control (as defined in the Plan) or in the discretion of the board of directors of our general partner, any unvested restricted units will be forfeited upon such time as the holder is no longer an officer, employee, consultant or director of us, our general partner, any of their affiliates or any other person performing bona fide services for us.

Compensation of Directors

The board of directors of our general partner has approved the following compensation program for its directors:

a cash retainer of $10,000, payable quarterly on the last day of each fiscal quarter;

an equity grant of $100,000 of fully vested common units on March 31 of each year;

a $1,500 fee for each meeting of the board of directors of our general partner and $1,000 for each substantive meeting of the Audit Committee and $3,500 for each substantive meeting of the Conflicts Committee attended by a member thereof;

a cash retainer of $3,500 for the chair of the Audit Committee and $2,500 for the chair of the Conflicts Committee, each payable quarterly on the last day of each fiscal quarter; and

eligibility for independent directors to participate in health benefits generally available to all employees and reimbursement for up to $500,000 of life insurance.

The following table sets forth a summary of the 2017 compensation for the directors of our general partner’s board of directors, except for Messrs. Willinger and Patricio Sanchez whose director compensation is included above under “—Summary Compensation Table”:


	Director Compensation
	Fees Earned or Paid		Unit		All Other
Name	in Cash		Awards (a)		Compensation (e)		Total
Alan S. Bigman	$	68,500	$	99,993	$	20,152	$	188,645
Jack Howell (b)	$	—	$	—	$	—	$	—
Richard S. Langdon(c)	$	104,500	$	99,993	$	—	$	204,493
G. M. Byrd Larberg	$	64,500	$	99,993	$	—	$	164,493
Antonio R. Sanchez, III(d)	$	43,000	$	99,993	$	—	$	142,993
Eduardo A. Sanchez(d)	$	43,000	$	99,993	$	—	$	142,993
Luke R. Taylor (b)	$	—	$	—	$	—	$	—

(a)

The amounts shown in this column represent the aggregate grant date fair value of the units granted under the Plan, computed in accordance with FASB ASC Topic 718, based on the $15.70 closing price per common unit as reported on the NYSE American on March 31, 2017, the day before the date of grant for all directors.

(b)

As the designated directors appointed by Stonepeak, Messrs. Howell and Taylor waived any director fees to which they were otherwise entitled.

(c)

Fees earned or paid in cash includes the last of three annual payments of $50,000, which occurred on April 5, 2017.

(d)

Mr. Antonio R. Sanchez, III and Mr. Eduardo A. Sanchez also each hold 11,235 outstanding unvested equity awards with a fair market value of $124,709 as of December 31, 2017, based on an $11.10 per unit closing price as reported by the NYSE American on such date.

(e)

All other compensation includes amounts for health insurance premium fees paid by us for the director.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters

The following table sets forth the beneficial ownership of our units, as of March 6, 2018, held by:

each unitholder known by us to beneficially own more than 5% of our outstanding units;

each of the directors of our general partner’s board of directors;

each of our general partner’s named executive officers (as such term is defined by the SEC); and

the directors and executive officers of our general partner as a group.

The amounts and percentage of common units and Class B preferred units beneficially owned are reported on the basis of the SEC rules governing the determination of beneficial ownership of securities. Under the SEC rules, a person is deemed to be a “beneficial owner” of a security if that person has or shares “voting power,” which includes the power to

vote or to direct the voting of such security, and/or “investment power,” which includes the power to dispose of or to direct the disposition of such security. A person is also deemed to be a beneficial owner of any securities of which that person has a right to acquire beneficial ownership within 60 days. Under these rules, more than one person may be deemed a beneficial owner of the same securities, and a person may be deemed a beneficial owner of securities as to which he has no economic interest.

Percentage of total units beneficially owned is based on 14,965,134 common units and 31,000,887 Class B preferred units outstanding as of March 6, 2018, the number of common units beneficially owned and the number of Class B preferred units beneficially owned is based upon ownership as of March 6, 2018, except with respect to the amounts reported on filings on Schedule 13G or 13D, which amounts are based upon holdings as of March 1, 2018 unless otherwise specified therein. Except as indicated by footnote, to our knowledge the persons named in the table below have sole voting and investment power with respect to all units shown as beneficially owned by them, subject to community property laws where applicable.


							Percentage of
	Common Units Beneficially			Class B Preferred Units			Total Units
	Owned			Beneficially Owned(1)			Beneficially
Name and address of Beneficial Owner(2)	Number	Percentage		Number	Percentage		Owned(1)
Stonepeak Catarina Holdings, LLC(3)	393,291	2.6	%	31,000,887	100	%	68.3	%
Goldman Sachs Asset Management, L.P.(4)	1,145,389	7.7	%	—	—		2.5	%
SN UR Holdings, LLC(5)	2,272,727	15.2	%	—	—		4.9	%
Alan S. Bigman(6)	21,293	*		—	—		*
Kirsten A. Hink	12,500	*		—	—		*
Jack Howell	—	—		—	—		—
Richard S. Langdon	26,866	*		—	—		*
G. M. Byrd Larberg	21,293	*		—	—		*
Antonio R. Sanchez, III(7)	333,465	2.2	%	—	—		*
Eduardo A. Sanchez	304,990	2.0	%	—	—		*
Patricio D. Sanchez	361,005	2.4	%	—	—		*
Luke R. Taylor	—	—		—	—		—
Charles C. Ward	101,378	*		—	—		*
Gerald F. Willinger	214,925	1.4	%	—	—		*
All directors and executive officers as a group (11 persons)	1,397,715	9.3	%	—	—		3.2	%

*Less than 1%

(1)

The holder of Class B preferred units has the right to convert such units into our common units at any time.

(2)

Unless otherwise set forth below, the address of all of all beneficial owners is c/o Sanchez Midstream Partners LP, 1000 Main Street, Suite 3000, Houston, Texas 77002.

(3)

Ownership data as reported on Schedule 13D/A filed on May 31, 2017 by Stonepeak Catarina Holdings LLC, Stonepeak Catarina Upper Holdings LLC, Stonepeak Infrastructure Fund (Orion Aiv) LP, Stonepeak Associates LLC, Stonepeak GP Holdings LP, Stonepeak GP Investors LLC, Stonepeak GP Investors Manager LLC, Michael Dorrell and Trent Vichie. The principal business address of each reporting person is 717 Fifth Avenue, 25th Floor, New York, New York 10022.The filing lists each filing person as having shared voting and dispositive power over the common units and the Class B preferred units.

(4)

Ownership data as reported on Schedule 13G filed on January 31, 2018 by Goldman Sachs Asset Management, L.P. and GS Investment Strategies, LLC. The principal business address of the reporting person is Goldman Sachs Asset Management, 200 West Street, New York, NY 10282. The filing lists each filing person as having shared voting and dispositive power over the common units.

(5)

Ownership data as reported on Schedule 13G filed on November 28, 2016 by SN UR Holdings, LLC and Sanchez Energy Corporation. The principal business address of each filing reporting person is 1000 Main Street, Suite 3000, Houston, Texas 77002. The filing lists each filing person as having shared voting and dispositive power over the common units.

(6)

Of these common units, 800 are held by Mr. Bigman’s children.

(7)

Mr. Antonio R. Sanchez III owns 325,951 common units. Mr. Sanchez is a co-manager of SOG, which owns 35,320 common units and of which Mr. Sanchez shares voting and dispositive power.

Equity Compensation Plan Information

The following table reflects our equity compensation plan information for our only equity compensation plan, the Sanchez Midstream Partners LP Long-Term Inventive Plan (the “Plan”), as of December 31, 2017:


	Number of
	Securities			Number of securities
	to be issued upon	Weighted-average		remaining available
	exercise of	exercise price of		for future
	outstanding options,	outstanding options,		issuance under equity
	warrants, and rights	warrants, and rights		compensation plans
Plan Category
Equity compensation plans approved by security holders	—	$	—	1,599,135
Equity compensation plans not approved by security holders	—	$	—	—
Total	—	$	—	1,599,135

Item 13. Certain Relationships and Related Transactions, and Director Independence

Manager

We are controlled by our general partner, Sanchez Midstream Partners GP LLC. The sole member of our general partner is Manager, which has no officers. The sole manager and member of Manager is SP Capital Holdings, LLC, which has no officers. The co-managers of SP Capital Holdings, LLC are Antonio R. Sanchez, III, Eduardo A. Sanchez, Patricio D. Sanchez and their father, Antonio R. Sanchez, Jr. SP Capital Holdings, LLC is owned by Antonio R. Sanchez, III (26%), Eduardo A. Sanchez (26%), and Patricio D. Sanchez (26%), along with their sister, Ana Lee Sanchez Jacobs (18%), and Antonio R. Sanchez, Jr (4%).

In May 2014, we entered into the Services Agreement with Manager pursuant to which Manager provides services that we require to operate our business, including overhead, technical, administrative, marketing, accounting, operational, information systems, financial, compliance, insurance, acquisition, disposition and financing services. In connection with providing the services under the Services Agreement, Manager receives compensation consisting of: (i) a quarterly fee equal to 0.375% of the value of our properties other than our assets located in Oklahoma, (ii) reimbursement for all allocated overhead costs as well as any direct third-party costs incurred and (iii) for each asset acquisition, asset disposition and financing, a fee not to exceed 2% of the value of such transaction. Each of these fees, not including the reimbursement of costs, will be paid in cash unless Manager elects for such fee to be paid in our equity. For the fees earned during the year ended December 31, 2017, Manager elected to receive 707,527 of our common units, valued at $8.8 million, in lieu of cash. During the years ended December 31, 2017 and 2016, we incurred costs of approximately $8.8 million and $7.5 million, respectively, under the Services Agreement.

In connection with our conversion from a limited liability company to a limited partnership in March 2015, all of our incentive distribution rights were granted to Manager. Pursuant to the terms of our partnership agreement, if, for any quarter, we have distributed cash from operating surplus to our common unitholders in an amount equal to the minimum quarterly distribution, then we will make additional distributions from operating surplus for that quarter among our common unitholders and Manager (as the holder of our incentive distribution rights) in the following manner:

first, 100% to all common unitholders, pro rata, until each unitholder receives a total of $0.575 per unit for that quarter;

second, 87.0% to all common unitholders, pro rata, and 13.0% to the holders of our incentive distribution rights, until each unitholder receives a total of $0.625 per unit for that quarter;

third, 77.0% to all common unitholders, pro rata, and 23.0% to the holders of our incentive distribution rights, until each unitholder receives a total of $0.875 per unit for that quarter; and

thereafter, 64.5% to all common unitholders, pro rata, and 35.5% to the holders of our incentive distribution rights.

No incentive distribution payments have been made since their date of issuance.

SOG

SOG provides services to us through a contractual relationship with SP Holdings. Antonio R. Sanchez, III and Patricio D. Sanchez are Co-Presidents of SOG; Antonio R. Sanchez, Jr. is the Chief Executive Officer and sole director of SOG; Ana Lee Sanchez Jacobs is an Executive Vice President of SOG; and Gerald F. Willinger is an Executive Vice President of SOG. The controlling owners of SOG are Antonio R. Sanchez, Jr. and Santig, Ltd. The general partner of Santig, Ltd. is Sanchez Management Corporation, which is owned 100% by Antonio R. Sanchez, Jr. Antonio R. Sanchez, Jr. is Chairman and President of Sanchez Management Corporation and Antonio R. Sanchez, III is Executive Vice President of Sanchez Management Corporation.

In May 2014, we entered into a Contract Operating Agreement with SOG (the “Operating Agreement”) pursuant to which SOG either provides services to operate, develop and produce our oil and natural gas properties or engages a third-party operator to do so, other than with respect to our properties in the Mid-Continent region. In connection with providing services under the Operating Agreement, SOG will be reimbursed for all direct charges under COPAS. Aside from reimbursed costs, no amounts have been paid to SOG under the Operating Agreement during the years ended December 31, 2017 and 2016.

In May 2014, we and certain of our subsidiaries entered into a Geophysical Seismic Data Use License Agreement with SOG (the “License Agreement”) pursuant to which SOG provides us with a non-exclusive, royalty-free license to use seismic, geophysical and geological information relating to our oil and natural gas properties that is proprietary to SOG and not restricted by agreements that SOG has with landowners or seismic data vendors. No amounts are payable under the License Agreement.

Sanchez Energy

Since January 1, 2015, we have completed three midstream acquisitions and two working interest acquisitions from Sanchez Energy, and acquired a Lease Option from Sanchez Energy (defined below), which was subsequently terminated. Antonio R. Sanchez, Jr., the father of Antonio R. Sanchez, III, Eduardo A. Sanchez and Patricio D. Sanchez, is a director and Executive Chairman of the board of directors of Sanchez Energy, Antonio R. Sanchez, III, is a director and Chief Executive Officer of Sanchez Energy, Eduardo A. Sanchez is the former President of Sanchez Energy and Patricio D. Sanchez is an Executive Vice President of Sanchez Energy. The employees of SOG, including Kirsten A. Hink, our Chief Accounting Officer, provide common services to both us and Sanchez Energy. The beneficial ownership of Sanchez Energy’s common stock as of March 5, 2018 by Antonio R. Sanchez, Jr., Antonio R. Sanchez, III, Eduardo A. Sanchez and Patricio D. Sanchez was 6.8%, 3.0%, 1.4% and 1.2%, respectively.

We entered into the Gathering Agreement with Sanchez Energy in October 2015. For the years ended December 31, 2017 and 2016, Sanchez Energy paid us approximately $52.8 million and $50.1 million, respectively, pursuant to the terms of the Gathering Agreement. On June 30, 2017, the Gathering Agreement was amended to add an incremental infrastructure fee to be paid by SN Catarina based on water that is delivered through the gathering system through March 31, 2018.

As part of the Carnero Gathering Transaction that closed in July 2016, we are required to pay Sanchez Energy an earnout based on natural gas received above a threshold volume and tariff at Carnero Gathering’s delivery points from Sanchez Energy and other producers. For the years ended December 31, 2017 and 2016, we did not make an earnout payment to Sanchez Energy. However, we had a payable of $0.1 million to Sanchez Energy at year end December 31, 2017 related to the earnout.

In October 2016, we and a wholly-owned subsidiary of Sanchez Energy, entered into a lease option purchase agreement pursuant to which Sanchez Energy’s subsidiary sold and conveyed to us an option to acquire a ground lease to which Sanchez Energy’s subsidiary was a party for a tract of land leased from the Calhoun Port Authority in Point Comfort, Texas (the “Lease Option”). In addition, if Sanchez Energy or any of its affiliates entered into an option to engage in the construction of or participation in a Project (as defined below) and/or received the benefit of an acreage dedication from an affiliate of Sanchez Energy relating to a Project, then such option and/or acreage dedication would also be assigned to us, if we exercise the Lease Option. We were to pay Sanchez Energy’s subsidiary $1.00 if the Lease Option was exercised, along with $250,000 if we or any other person affiliated with us elected to construct, own or operate a marine storage terminal on or within five miles of the Port Comfort lease or participated as an investor in the same, within five miles thereof (a “Project”), or Sanchez Energy or its affiliates conveyed an acreage dedication to or an option regarding a Project. On September 11, 2017, Sanchez Energy, Sanchez Energy’s subsidiary and we entered into an agreement that terminated the Lease Option.

We completed the Carnero Processing Transaction in November 2016. Additionally, in conjunction with our public offering of common units in November 2016, the Partnership entered into a Common Unit Purchase Agreement with SN UR Holdings, LLC (the “Purchaser”), a wholly-owned subsidiary of Sanchez Energy, whereby we issued to the Purchaser 2,272,727 common units for proceeds of approximately $25.0 million.

In September 2017, we entered into the SECO Pipeline Transportation Agreement. For the year ended December 31, 2017, SN Catarina paid us approximately $0.9 million pursuant to the terms of that agreement.

Class B Preferred Unit Issuance

Under our partnership agreement, in the event that we did not raise at least $75.0 million through the issuance of additional common units prior to September 30, 2016 (with the conversion of our Class A preferred units counting toward such amount) or if any Class A preferred units remained outstanding after March 31, 2016, the cash portion of the distribution rate on our Class B preferred units would increase by 4.0% per annum until consummation of such issuance or conversion, as applicable. We did not raise at least $75.0 million through the issuance of additional common units prior to September 30, 2016 and, therefore, the increased distribution rate was utilized for the quarter ended September 30, 2016. We issued common units in November 2016, which satisfied the equity raise requirement to decrease quarterly distributions to their original level starting with the quarter ended December 31, 2016.

As a result of the common unit issuance in November 2016, and in accordance with our partnership agreement, in December 2016, we issued an additional 9,851,996 Class B preferred units to Stonepeak. Stonepeak disagreed with our calculation of the additional Class B preferred units due under our partnership agreement and in January 2017, we and Stonepeak entered into a settlement agreement to settle the disputed calculation. Pursuant to the settlement agreement, and in accordance with Section 5.4 of our partnership agreement, we issued 1,704,446 Class B preferred units to Stonepeak in a privately negotiated transaction as consideration for the Settlement Agreement, with the “Class B Preferred Unit Price” under our partnership agreement being established at $11.29 per Class B preferred unit.

In October 2015, as amended in January 2017, we entered into a registration rights agreement with Stonepeak pursuant to which we agreed to register, upon Stonepeak’s request, the resale of the common units issuable upon conversion of the Class B preferred units along with any other common units held by Stonepeak. In addition, we and our general partner entered into a board representation and standstill agreement with Stonepeak pursuant to which we and our general partner have agreed to permit Stonepeak to designate two persons to serve on the board of directors of our general partner.

Item 14. Principal Accounting Fees and Services

We engaged our principal accountant, KPMG LLP (“KPMG”), to audit our financial statements and perform other professional services for the fiscal years ended December 31, 2017 and 2016.

Audit Fees. The aggregate fees billed for the financial statement audit or services provided in connection with statutory or regulatory filings for the years ended December 31, 2017 and 2016 were $816,000 and $712,000, respectively.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant, has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.


		Sanchez Midstream Partners LP

	By:	Sanchez Midstream Partners GP LLC,
		its general partner

Date: March 9, 2018	By	/S/ Gerald F. Willinger
	Name	Gerald F. Willinger
	Title	Chief Executive Officer

KNOW ALL PERSONS BY THESE PRESENTS, that each person whose signature appears below, constitutes and appoints Gerald F. Willinger and Charles C. Ward, and each of them, as his true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10-K, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents full power and authority to do and perform each and every act and thing requisite or necessary to be done in connection therewith, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or their or his substitute or substitutes, may lawfully do or cause to be done by virtue hereof.

This report has been signed below by the following persons on behalf of the general partner of the registrant and in the capacities and on the dates indicated.


Signature	Title	Date

/s/ Antonio R. Sanchez, III	Director; Chairman of the Board	March 9, 2018
Antonio R. Sanchez, III

/s/ Gerald F. Willinger	Director; Chief Executive Officer	March 9, 2018
Gerald F. Willinger	(Principal Executive Officer)

/S/ Charles C. Ward	Chief Financial Officer & Secretary	March 9, 2018
Charles C. Ward	(Principal Financial Officer)

/S/ Patricio D. Sanchez	Director; President & Chief Operating Officer	March 9, 2018
Patricio D. Sanchez	(Principal Operating Officer)

/S/ Kirsten A. Hink	Chief Accounting Officer	March 9, 2018
Kirsten A. Hink	(Principal Accounting Officer)

/S/ Alan S. Bigman	Director	March 9, 2018
Alan S. Bigman

/S/ Jack Howell	Director	March 9, 2018
Jack Howell

/S/ Richard S. Langdon	Director	March 9, 2018
Richard S. Langdon

/S/ G. M. Byrd Larberg	Director	March 9, 2018
G. M. Byrd Larberg

/S/ Eduardo A. Sanchez	Director	March 9, 2018
Eduardo A Sanchez

/S/ Luke R Tayler	Director	March 9, 2018
Luke R. Taylor

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Unitholders of Sanchez Midstream Partners LP and the Board of Directors of

Sanchez Midstream Partners GP LLC:

Opinion on Internal Control Over Financial Reporting

We have audited Sanchez Midstream Partners LP (formerly Sanchez Production Partners LP) and subsidiaries’ (the Partnership) internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Partnership as of December 31, 2017 and 2016, the related consolidated statements of operations, changes in partners’ capital, and cash flows for each of the years in the two-year period ended December 31, 2017, and the related notes (collectively, the consolidated financial statements), and our report dated March 9, 2018 expressed an unqualified opinion on those consolidated financial statements.

Basis for Opinion

The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Controls Over Financial Reporting. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/KPMG LLP

Houston, Texas

March 9, 2018

SANCHEZ MIDSTREAM PARTNERS LP and SUBSIDIARIES

Consolidated Statements of Operations

(In thousands, except unit data)


		For the Years Ended
		December 31,
		2017		2016
Revenues
Natural gas sales	$	6,626	$	10,408
Oil sales		23,701		5,138
Natural gas liquid sales		1,997		1,167
Gathering and transportation sales		55,825		53,972
Total revenues		88,149		70,685
Expenses:
Operating expenses:
Lease operating expenses		12,994		14,981
Transportation operating expenses		11,600		12,478
Cost of sales		77		328
Production taxes		1,476		1,167
General and administrative		22,655		22,901
Unit-based compensation expense		3,373		1,941
Gain (loss) on sale of assets		(4,150)		219
Depreciation, depletion and amortization		34,830		33,799
Asset impairments		4,688		7,646
Accretion expense		773		1,127
Total operating expenses		88,316		96,587
Other (income) expense
Interest expense, net		8,341		5,093
Gain on embedded derivative		—		(47,794)
Earnings from equity investments		(7,885)		(2,382)
Other (income) expense		2,417		(50)
Total other (income) expenses		2,873		(45,133)
Total expenses		91,189		51,454
Income (loss) before income taxes		(3,040)		19,231
Income tax expense		—		—
Net income (loss)		(3,040)		19,231
Less:
Preferred unit paid-in-kind distributions		(2,625)		—
Preferred unit distributions		(33,250)		(39,375)
Preferred unit amortization		(1,796)		(24,340)
Net loss attributable to common unitholders	$	(40,711)	$	(44,484)
Net loss per unit
Common units - Basic and Diluted	$	(2.90)	$	(9.55)
Weighted Average Units Outstanding
Common units - Basic and Diluted		14,039,726		4,658,970

See accompanying notes to consolidated financial statements.

SANCHEZ MIDSTREAM PARTNERS LP and SUBSIDIARIES

Consolidated Balance Sheets

(In thousands, except unit data)


	December 31,
	2017		2016
ASSETS
Current assets
Cash and cash equivalents	$	321	$	957
Accounts receivable		495		1,212
Accounts receivable - related entities		13,099		5,987
Prepaid expenses		2,670		2,041
Fair value of derivative instruments		942		4,568
Total current assets		17,527		14,765
Oil and natural gas properties and related equipment
Oil and natural gas properties, equipment and facilities (successful efforts method)		170,750		758,913
Gathering and transportation assets		184,969		152,209
Material and supplies		—		1,056
Less: accumulated depreciation, depletion, amortization and impairment		(142,574)		(689,358)
Oil and natural gas properties and equipment, net		213,145		222,820
Other assets
Intangible assets, net		172,166		185,766
Fair value of derivative instruments		1,318		3,964
Equity investments		123,715		111,614
Other non-current assets		552		776
Total assets	$	528,423	$	539,705

LIABILITIES AND PARTNERS' CAPITAL
Liabilities
Current liabilities
Accounts payable and accrued liabilities	$	1,782	$	951
Accounts payable and accrued liabilities - related entities		10,353		7,046
Royalties payable		371		706
Fair value of derivative instruments		756		740
Other liabilities		151		—
Total current liabilities		13,413		9,443
Other liabilities
Asset retirement obligation		6,074		13,579
Long-term debt, net of debt issuance costs		187,808		151,322
Fair value of derivative instruments		273		1,356
Other liabilities		6,251		4,270
Total other liabilities		200,406		170,527
Total liabilities		213,819		179,970
Commitments and contingencies (See Note 12)
Mezzanine equity
Class B preferred units, 31,000,887 and 29,296,441 units issued and outstanding as of December 31, 2017 and 2016, respectively		343,912		342,991
Partners' capital (deficit)
Common units, 14,965,134 and 13,447,749 units issued and outstanding as of December 31, 2017 and 2016, respectively		(29,308)		16,744
Total partners' capital (deficit)		(29,308)		16,744
Total liabilities and partners' capital	$	528,423	$	539,705

See accompanying notes to consolidated financial statements.

SANCHEZ MIDSTREAM PARTNERS LP and SUBSIDIARIES

Consolidated Statements of Cash Flows

(In thousands)


	For the Years Ended
	December 31,
	2017		2016
Cash flows from operating activities:
Net income (loss)	$	(3,040)	$	19,231
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation, depletion and amortization		21,262		21,901
Amortization of debt issuance costs		524		507
Revisions to asset retirement obligation included in DD&A		—		(1,858)
Asset impairments		4,688		7,646
Accretion of plugging and abandonment liability		773		1,127
Distributions (return on investment) from equity investments		8,720		2,950
Equity earnings in affiliate		(7,885)		(2,382)
Bad debt expense		—		35
(Gain) loss from disposition of property and equipment		(4,150)		210
Total mark-to-market on commodity derivative contracts		(3,947)		7,239
Cash settlements on commodity derivative contracts		5,487		18,780
Cash settlements on terminated commodity derivatives		3,602		—
Unit-based compensation		3,373		2,044
Loss on earnout derivative		2,353		—
Gain on embedded derivative		—		(47,794)
Amortization of intangible assets		13,568		13,756
Costs for plug and abandon activities		(60)		(183)
Changes in Operating Assets and Liabilities:
Accounts receivable		644		(159)
Accounts receivable - related entities		(6,590)		(4,472)
Prepaid expenses		(629)		(1,297)
Other assets		144		730
Accounts payable and accrued liabilities		9,997		(3,876)
Accounts payable and accrued liabilities- related entities		3,566		6,011
Royalties payable		(300)		17
Net cash provided by operating activities		52,100		40,163
Cash flows from investing activities:
Cash paid for acquisitions		1,468		(25,622)
Development of oil and natural gas properties		(441)		(939)
Proceeds from sale of assets		11,665		38
Construction of gathering and transportation assets		(31,693)		(4,730)
Purchases of and contributions to equity affiliates		(13,684)		(107,271)
Net cash used in investing activities		(32,685)		(138,524)
Cash flows from financing activities:
Payments for offering costs		(611)		(5,403)
Proceeds from issuance of debt		48,000		72,000
Repayment of debt		(12,000)		(26,000)
Issuance of common units		1,290		99,196
Repurchase of common units under repurchase program		—		(2,948)
Units tendered by employees for tax withholdings		—		(140)
Distributions to common unitholders		(25,192)		(6,696)
Class B preferred unit cash distributions		(31,500)		(37,168)
Debt issuance costs		(38)		(94)
Net cash provided by (used in) financing activities		(20,051)		92,747
Net decrease in cash and cash equivalents		(636)		(5,614)
Cash and cash equivalents, beginning of period		957		6,571
Cash and cash equivalents, end of period	$	321	$	957
Supplemental disclosures of cash flow information:
Change in accrued capital expenditures	$	1,064	$	1,119
Cash paid during the period for interest	$	7,643	$	4,449
Transfer of embedded derivative to Class B preferred units	$	—	$	145,283

See accompanying notes to consolidated financial statements.

SANCHEZ MIDSTREAM PARTNERS LP and SUBSIDIARIES

Consolidated Statements of Changes in Partners’ Capital

(In thousands, except unit data)


	Class A Preferred Units			Common Units			Total
	Units	Amount		Units	Amount		Capital
Partners' Deficit, December 31, 2015	11,694,364	$	17,112	3,240,813	$	(45,285)	$	(28,173)
Units tendered by employees for tax withholding	—		—	(12,227)		(140)		(140)
Units forfeited by employees	—		—	(2,000)		—		—
Unit-based compensation programs	—		—	67,627		2,044		2,044
Issuance of common units, net of offering costs of $5.3 million	—		—	9,226,595		96,278		96,278
Class A Preferred Units converted to common units	(11,694,364)		(17,112)	1,169,441		17,112		—
Common units retired via unit repurchase program	—		—	(242,500)		(2,948)		(2,948)
Cash distributions to common unit holders	—		—	—		(6,696)		(6,696)
Distributions - Class B preferred units	—		—	—		(62,852)		(62,852)
Net income	—		—	—		19,231		19,231
Partners' Capital, December 31, 2016	—		—	13,447,749		16,744		16,744
Unit-based compensation programs	—		—	217,481		3,373		3,373
Issuance of common units, net of offering costs of $0.6 million	—		—	906,613		11,228		11,228
Cash distributions to common unit holders	—		—	—		(25,192)		(25,192)
Common units issued as Class B Preferred distributions	—		—	393,291		5,250		5,250
Distributions - Class B preferred units	—		—	—		(37,671)		(37,671)
Net loss	—		—	—		(3,040)		(3,040)
Partners' Deficit, December 31, 2017	—	$	—	14,965,134	$	(29,308)	$	(29,308)

See accompanying notes to consolidated financial statements.

in fiscal years beginning after December 15, 2017. Early adoption is permitted, and the Partnership is currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements.

In October 2016, the FASB issued ASU 2016-16 “Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory,” which eliminates a current exception in U.S. GAAP to the recognition of the income tax effects of temporary differences that result from intra-entity transfers of non-inventory assets. The intra-entity exception is being eliminated under the ASU. The standard is required to be applied on a modified retrospective basis and became effective beginning with the first quarter of 2018. Early adoption is permitted, and the Partnership is currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements.

In August 2016, the FASB issued ASU No. 2016-15, “Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments” effective for annual and interim periods beginning after December 15, 2017. This ASU is intended to clarify the presentation of cash receipts and payments in specific situations. Early adoption is permitted including adoption in an interim period. We chose to adopt ASU 2016-15 for the year ended December 31, 2016 on a retrospective basis.

In February 2016, the FASB issued ASU No. 2016-02 “Leases (Topic 842),” effective for annual and interim periods for public companies beginning after December 15, 2018, with a modified retrospective approach to be used for implementation. ASU 2016-02 updates the previous lease guidance by requiring the recognition of a right-to-use asset and lease liability on the statement of financial position for those leases previously classified as operating leases under the old guidance. In addition, ASU 2016-02 updates the criteria for a lessee’s classification of a finance lease. The Partnership will not early adopt this standard, and will apply the revised lease rules for our interim and annual reporting periods starting January 1, 2019. The Partnership is currently evaluating the impact of these rules on its consolidated financial statements and has started the assessment process by evaluating the population of leases under the revised definition. The adoption of this standard will result in an increase in the assets and liabilities on the Partnership’s consolidated balance sheets. The quantitative impacts of the new standard are dependent on the leases in force at the time of adoption. As a result, the evaluation of the effect of the new standards will extend over future periods.

In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606).” In March, April, and May of 2016, the FASB issued rules clarifying several aspects of the new revenue recognition standard. The new guidance is effective for fiscal years and interim periods beginning after December 15, 2017. This guidance outlines a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized. The new model will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods and services. The new standard also requires more detailed disclosures related to the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The Partnership will apply the modified retrospective approach. As part of the assessment, the Partnership formed an implementation work team, completed trainings on the new revenue recognition model and gathered our material revenue contracts covering current revenue streams for which the impacts to the consolidated financial statements under the revised standards were evaluated. Upon adoption of the standard, while we do not anticipate material changes to our current revenue processes, we could be required to present revenue from the Gathering Agreement and revenue from the SECO Pipeline Transportation Agreement as separate line items within the statement of operations.

Other accounting standards that have been issued by the FASB or other standards-setting bodies are not expected to have a material impact on the Partnership’s financial position, results of operations and cash flows.

Use of Estimates

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying footnotes. These estimates and the underlying assumptions affect the amounts of assets and liabilities reported, disclosures about contingent assets and liabilities and reported amounts of revenues and expenses. The estimates that are particularly significant to our financial statements include estimates of our reserves of natural gas, NGLs and oil; future cash flows from oil and natural gas properties; depreciation, depletion and amortization; asset retirement obligations; certain revenues

and operating expenses; fair values of commodity derivatives and fair values of assets and liabilities. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. These estimates and assumptions are based on management’s best estimates and judgment. Management evaluates its estimates and assumptions on an on-going basis using historical experience and other factors, including the current economic environment, which management believes to be reasonable under the circumstances. Such estimates and assumptions are adjusted when facts and circumstances dictate. As future events and their effects cannot be determined with precision, actual results could differ from the estimates. Any changes in estimates resulting from continuing changes in the economic environment will be reflected in the financial statements in future periods.

Cash and Cash Equivalents

All highly liquid investments with original maturities of three months or less are considered cash equivalents.

Restricted Cash

We had no restricted cash as of December 31, 2017 and 2016.

Accounts Receivable, Net

Our accounts receivable are primarily from our contractual agreements with Sanchez Energy and its subsidiaries, operators of our oil and natural gas properties and counterparties to our financial instruments. Oil receivables are generally collected within 30 days after the end of the month. Natural gas receivables are generally collected within 60 days after the end of the month. We review all outstanding accounts receivable balances and record a reserve for amounts that we expect will not be fully recovered. Actual balances are not applied against the reserves until substantially all collection efforts have been exhausted. Our allowance for doubtful accounts was $0.4 million as of December 31, 2017 and 2016.

Concentration of Credit Risk and Accounts Receivable

Financial instruments that potentially subject us to a concentration of credit risk consist of cash and cash equivalents, accounts receivable and derivative financial instruments. We place our cash with high credit quality financial institutions. We place our derivative financial instruments with financial institutions that participate in our Credit Agreement and maintain an investment grade credit rating. Substantially all of our accounts receivables are due from operators of our oil and natural gas properties. These sales are generally unsecured and, in some cases, may carry a parent guarantee. As we generally have fewer than 10 large customers for our oil and natural gas sales, we routinely assess the financial strength of our customers. Bad debt expense is recognized on an account-by-account review and when recovery is not probable. Our allowance for doubtful accounts was $0.4 million as of December 31, 2017 and 2016. We have no off-balance-sheet credit exposure related to our operations or customers.

Sanchez Energy, whose earned revenues contribute exclusively to our midstream segment, accounted for 63% and 76% of total revenue for the years ended December 31, 2017 and 2016, respectively.

Derivatives and Hedging Activities

We use derivative financial instruments to achieve a more predictable cash flow from our oil and natural gas production by reducing our exposure to price fluctuations.

We account for all our open derivatives as mark-to-market activities. All derivative instruments are recorded in the consolidated balance sheets as either an asset or a liability measured at fair value with changes in fair value recognized in earnings. All of our open derivatives are effective as economic hedges of our commodity price exposure. These contracts are accounted for using the mark-to-market accounting method. Using this method, the contracts are carried at their fair value on our consolidated balance sheets as either short-term or long-term assets or liabilities based on their anticipated settlement date. We recognize all unrealized and realized gains and losses related to these contracts on our consolidated statements of operations under the caption “Oil sales” or “Natural gas sales.”

Revenue Recognition

Sales are recognized when natural gas, NGLs and oil have been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Natural gas, NGLs and oil are generally sold on a monthly basis. Most of the contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a specific tank battery, gathering or transmission line, quality of natural gas, NGLs and oil, and prevailing supply and demand conditions, so that the price of the natural gas, NGLs and oil fluctuates to remain competitive with other available natural gas, NGLs and oil supplies. As a result, revenues from the sale of natural gas, NGLs and oil will suffer if market prices decline and benefit if they increase. We believe that the pricing provisions of our natural gas, NGLs and oil contracts are customary in the industry.

Income Taxes

SNMP and each of its wholly-owned subsidiary LLCs are treated as a partnership for federal and state income tax purposes. All of our taxable income or loss, which may differ considerably from net income or loss reported for financial reporting purposes, is passed through to the federal income tax returns of our members. As such, no federal income tax for these entities has been provided for in the accompanying financial statements.

Earnings per Unit

Net income (loss) per common unit for the period is based on any distributions that are made to the unitholders (common units) plus an allocation of undistributed net income (loss), divided by the weighted average number of common units outstanding. The two-class method dictates that net income (loss) for a period be reduced by the amount of distributions and that any residual amount representing undistributed net income (loss) be allocated to common unitholders and other participating unitholders to the extent that each unit may share in net income (loss). Unit-based awards granted but unvested are eligible to receive distributions. The underlying unvested restricted unit awards are considered participating securities for purposes of determining net income (loss) per unit. Undistributed income (loss) is allocated to participating securities based on the proportional relationship of the weighted average number of common units and unit-based awards outstanding. Undistributed losses (including those resulting from distributions in excess of net income) are allocated to common units. Undistributed losses are not allocated to unvested restricted unit awards as they do not participate in net losses. Distributions declared and paid in the period are treated as distributed earnings in the computation of earnings per common unit even though cash distributions are not necessarily derived from current or prior period earnings.

Environmental Cost

We record environmental liabilities at their undiscounted amounts on our balance sheets in other current and long-term liabilities when our environmental assessments indicate that remediation efforts are probable and the costs can be reasonably estimated. Estimates of our environmental liabilities are based on currently available facts, existing technology and presently enacted laws and regulations taking into consideration the likely effects of other societal and economic factors, and include estimates of associated legal costs. These amounts also consider prior experience in remediating contaminated sites, other companies’ clean-up experience and data released by the federal Environmental Protection Agency (“EPA”) or other organizations. Our estimates are subject to revision in future periods based on actual costs or new circumstances. We capitalize costs that benefit future periods and we recognize a current period charge in operation

relating to the assets arising prior to the closing date (the “Oklahoma Production Divestiture”). The Oklahoma Production Divestiture closed July 17, 2017, and we recorded a gain of $2.4 million on the sale during the third quarter of 2017.

Carnero Processing Acquisition

In November 2016, we acquired from Sanchez Energy a 50% interest in Carnero Processing, a joint venture that is 50% owned and operated by Targa, for aggregate cash consideration of approximately $55.5 million and the assumption of remaining capital contribution commitments to Carnero Processing, estimated at approximately $24.5 million as of the date of acquisition. Carnero Processing owns a 260 MMcf/d cryogenic natural gas processing plant in La Salle County, Texas (the “Raptor Gas Processing Facility”), that receives wet gas from dedicated acres in Western Catarina with capacity to accommodate further throughput from Sanchez Energy and third parties.

The Partnership made capital contributions to Carnero Processing totaling $18.8 million between November 22, 2016 and December 31, 2017.

Production Acquisition

In November 2016, we completed the acquisition from SN Cotulla Assets, LLC and SN Palmetto, LLC, each a wholly-owned subsidiary of Sanchez Energy, 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 $24.2 million after $2.8 million in normal and customary closing adjustments. The effective date of the transaction was July 1, 2016. The Production Acquisition included initial conveyed working interests and net revenue interests for each property which escalate on January 1 for 2017 and 2018, at which point, SNMP’s interests in the Production Acquisition properties will stay constant for the remainder of the respective lives of the assets.

The total purchase price was allocated to the assets purchased and liabilities assumed based upon their fair values on the date of acquisition as follows (in thousands):


Proved developed reserves	$	25,016
Fair value of assets acquired		25,016
Asset retirement obligations		(832)
Fair value of net assets acquired	$	24,184

Carnero Gathering Transaction

In July 2016, we acquired from Sanchez Energy a 50% interest in Carnero Gathering, a joint venture that is 50% owned and operated by Targa, for an initial payment of approximately $37.0 million and the assumption of remaining capital commitments to Carnero Gathering, estimated at approximately $7.4 million as of the acquisition date (the “Carnero Gathering Transaction”). In addition, we are required to pay Sanchez Energy an earnout based on natural gas received above a threshold volume and tariff at Carnero Gathering’s delivery points from Sanchez Energy and other producers. Carnero Gathering owns a total of approximately 45 miles of high pressure natural gas gathering pipelines that currently connect Western Catarina Midstream to nearby pipelines and the Raptor Gas Processing Facility in South Texas (the “Carnero Gathering Line”). The Carnero Gathering Line is designed to directly connect to the Raptor Gas Processing Facility. Sanchez Energy has entered into a 15-year gathering agreement with Carnero Gathering pursuant to which Sanchez Energy is required to maintain a minimum quarterly volume delivery commitment for the first five years after the Raptor Gas Processing Facility’s in-service date. See Note 11. “Investments” for additional information relating to the Carnero Gathering Transaction.

The Partnership made capital contributions to Carnero Gathering totaling $8.8 million between July 5, 2016 and December 31, 2017.

Mid-Continent Divestiture

In June 2016, certain wholly-owned subsidiaries of the Partnership entered into an agreement to sell substantially all of our operated oil and natural gas wells, leases and other associated assets and interests in Oklahoma and Kansas (other than those arising under or related to a concession agreement with the Osage Nation) (the “Mid-Continent Divestiture”) for cash consideration of $7,120, effective as of August 1, 2016 (the “Effective Time”). In addition, the buyer agreed to assume all obligations relating to the assets arising after the Effective Time and all plugging and abandonment costs relating to the assets arising prior to the Effective Time. The sale closed on July 15, 2016, and we recorded a $0.2 million loss related to an intangible asset balance comprised of marketing contracts from a 2007 acquisition which were included in the Mid-Continent Divestiture.

4. FAIR VALUE MEASUREMENTS

Measurements of fair value of derivative instruments are classified according to the fair value hierarchy, which prioritizes the inputs to the valuation techniques used to measure fair value. Fair value is the price that would be received upon the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurements are classified and disclosed in one of the following categories:

Level 1 – Measured based on unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. Active markets are considered those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 – Measured based on quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that can be valued using observable market data. Substantially all of these inputs are observable in the marketplace throughout the term of the derivative instrument, can be derived from observable data, or supported by observable levels at which transactions are executed in the marketplace.

Level 3 – Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e., supported by little or no market activity).

Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Management's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

The following table summarizes the fair value of our assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2017 (in thousands):


	Fair Value Measurements at December 31, 2017
	Active Markets for		Observable
	Identical Assets		Inputs		Unobservable Inputs
	(Level 1)		(Level 2)		(Level 3)		Fair Value
Oil derivative instrument
Derivative assets	$	—	$	1,231	$	—	$	1,231
Midstream derivative instrument
Earnout derivative liability		—		—		(6,402)		(6,402)
Total	$	—	$	1,231	$	(6,402)	$	(5,171)

The following table summarizes the fair value of our assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2016 (in thousands):


	Fair Value Measurements at December 31, 2016
	Active Markets for		Observable
	Identical Assets		Inputs		Unobservable Inputs
	(Level 1)		(Level 2)		(Level 3)		Fair Value
Oil derivative instrument
Derivative assets	$	—	$	6,436	$	—	$	6,436
Midstream derivative instrument
Earnout derivative liability		—		—		(4,270)		(4,270)
Total	$	—	$	6,436	$	(4,270)	$	2,166

As of December 31, 2017 and 2016, the estimated fair value of cash and cash equivalents, accounts receivable, other current assets and current liabilities approximated their carrying value due to their short-term nature.

Fair Value on a Non-Recurring Basis

The Partnership follows the provisions of ASC Topic 820-10 for nonfinancial assets and liabilities measured at fair value on a non-recurring basis. The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs under the fair value hierarchy. We periodically review oil and natural gas properties for impairment when facts and circumstances indicate that their carrying values may not be recoverable.

A reconciliation of the beginning and ending balances of the Partnership’s asset retirement obligations is presented in Note 9, ‘‘Asset Retirement Obligation.’’

The following table summarizes the non-recurring fair value measurements of our assets and liabilities as of December 31, 2017 (in thousands):


	Fair Value Measurements at December 31, 2017
	Active Markets for		Observable
	Identical Assets		Inputs		Unobservable Inputs
	(Level 1)		(Level 2)		(Level 3)
Impairment(a)	$	—	$	—	$	7,277
Total net assets	$	—	$	—	$	7,277

(a)

During the year ended December 31, 2017, we recorded a non-cash impairment charge of $4.7 million to impair our producing oil and natural gas acquired in the Production Acquisition. The carrying values of the impaired proved properties were reduced to a fair value of $7.3 million, estimated using inputs characteristic of a Level 3 fair value measurement.

The following table summarizes the non-recurring fair value measurements of our assets and liabilities as of December 31, 2016 (in thousands):


	Fair Value Measurements at December 31, 2016
	Active Markets for		Observable
	Identical Assets		Inputs		Unobservable Inputs
	(Level 1)		(Level 2)		(Level 3)
Impairment(a)	$	—	$	—	$	10,733
Acquisitions(b)		—		—		24,184
Total net assets	$	—	$	—	$	34,917

(a)

For the year ended December 31, 2016, we recorded a non-cash impairment charge of $7.6 million to impair our producing oil and natural gas properties in Texas and Louisiana (acquired prior to the Eagle Ford Acquisition) and in Oklahoma. The carrying values of the impaired proved properties were reduced to a fair value of $10.7 million, estimated using inputs characteristic of a Level 3 fair value measurement.

(b)

During the year ended December 31, 2016, we acquired oil and natural gas properties with a fair value of $24.2 million. See Note 3. “Acquisitions and Divestitures” for fair value allocation

The following table sets forth a reconciliation of changes in the fair value of the Partnership's embedded and earnout derivatives classified as Level 3 in the fair value hierarchy (in thousands):


	December 31,
	2017		2016
Beginning balance	$	(4,270)	$	(193,077)
Initial fair value of earnout derivative		221		(4,270)
Gain on embedded derivative		—		47,794
Loss on earnout derivative		(2,353)		—
Transfer to mezzanine equity		—		145,283
Ending balance	$	(6,402)	$	(4,270)

Loss included in earnings related to derivatives still held as of December 31, 2017 and 2016 respectively	$	(2,353)	$	—

5. DERIVATIVE AND FINANCIAL INSTRUMENTS

To reduce the impact of fluctuations in oil and natural gas prices on our revenues, we periodically enter into derivative contracts with respect to a portion of our projected oil and natural gas production through various transactions that fix or modify the future prices to be realized. These hedging activities are intended to support oil and natural gas prices at targeted levels and to manage exposure to oil and natural gas price fluctuations. It is never our intention to enter into derivative contracts for speculative trading purposes.

Under ASC Topic 815, “Derivatives and Hedging,” all derivative instruments are recorded on the consolidated balance sheets at fair value as either short-term or long-term assets or liabilities based on their anticipated settlement date. We will net derivative assets and liabilities for counterparties where we have a legal right of offset. Changes in the derivatives’ fair values are recognized currently in earnings unless specific hedge accounting criteria are met. We have not elected to designate any of our current derivative contracts as hedges; however, changes in the fair value of all of our derivative instruments are recognized in earnings and included as realized and unrealized gains (losses) on derivative instruments in the consolidated statements of operations.

As of December 31, 2017, we had the following derivative contracts in place for the periods indicated, all of which are accounted for as mark-to-market activities:

MTM Fixed Price Swaps – NYMEX (Henry Hub)


	For the Year Ended December 31, (volume in MMBtu)
	March 31,			June 30,			September 30,			December 31,			Total
		Average			Average			Average			Average			Average
	Volume	Price		Volume	Price		Volume	Price		Volume	Price		Volume	Price
2018	132,088	$	3.00	126,600	$	3.00	121,600	$	3.00	117,040	$	3.00	497,328	$	3.00
2019	119,832	$	2.85	115,784	$	2.85	112,032	$	2.85	108,552	$	2.85	456,200	$	2.85
2020	105,104	$	2.85	102,008	$	2.85	99,136	$	2.85	96,200	$	2.85	402,448	$	2.85
													1,355,976

MTM Fixed Price Basis Swaps – West Texas Intermediate (WTI)


	For the Year Ended December 31, (volume in Bbls)
	March 31,			June 30,			September 30,			December 31,			Total
		Average			Average			Average			Average			Average
	Volume	Price		Volume	Price		Volume	Price		Volume	Price		Volume	Price
2018	70,600	$	59.63	66,432	$	59.71	62,840	$	59.78	59,704	$	59.84	259,576	$	59.74
2019	62,528	$	60.41	59,552	$	60.44	57,024	$	60.48	54,824	$	60.52	233,928	$	60.46
2020	52,776	$	53.50	50,960	$	53.50	49,224	$	53.50	47,624	$	53.50	200,584	$	53.50
													694,088

The following table sets forth a reconciliation of the changes in fair value of the Partnership’s commodity derivatives for the years ended December 31, 2017 and 2016 (in thousands):


	December 31,
	2017		2016
Beginning fair value of commodity derivatives	$	6,436	$	31,018
Net gains (losses) on crude oil derivatives		3,284		(8,355)
Net gains on natural gas derivatives		663		1,116
Net settlements on derivative contracts:
Oil		(6,422)		(13,622)
Natural gas		(2,730)		(6,919)
Net premiums on derivative contracts		—		3,198
Ending fair value of commodity derivatives	$	1,231	$	6,436

The effect of derivative instruments on our consolidated statements of operations was as follows (in thousands):



	Location of Gain(Loss)	Year Ended December 31,
Derivative Type	in Income	2017		2016
Commodity – Mark-to-Market	Oil sales	$	3,284	$	(8,355)
Commodity – Mark-to-Market	Natural gas sales		663		1,116
		$	3,947	$	(7,239)

Derivative instruments expose us to counterparty credit risk. Our commodity derivative instruments are currently contracted with four counterparties. We generally execute commodity derivative instruments under master agreements which allow us, in the event of default, to elect early termination of all contracts with the defaulting counterparty. If we choose to elect early termination, all asset and liability positions with the defaulting counterparty would be net cash settled at the time of election. We include a measure of counterparty credit risk in our estimates of the fair values of derivative instruments. In August 2017, we repositioned certain of our oil and natural gas hedges in anticipation of the sale of the Texas Production Assets and, in the process, received $3.6 million in net cash from the counterparties on those hedges. As of December 31, 2017 and 2016, the impact of non-performance credit risk on the valuation of our derivative instruments was not significant.

Embedded Derivatives

The Partnership entered into a contract for the sale of preferred units in October 2015 which contained provisions that were required to be bifurcated from the contract and valued as a derivative. The embedded derivative was valued through the use of a Monte Carlo model which utilized observable inputs, the Partnership’s unit prices at various timelines, as well as unobservable inputs related to the weighted probabilities of certain redemption scenarios. In November 2016, we completed a public offering and private placement of common units. As a result of these equity issuances, the Class B conversion rate was determined and the provisions that were required to bifurcate were removed. At that time, the fair value of the derivative was transferred to mezzanine equity.

Earnout Derivative

As part of the Carnero Gathering Transaction, 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. The earnout derivative was valued through the use of a Monte Carlo model which utilized observable inputs such as the earnout price and volume commitment, as well as unobservable inputs related to the weighted probabilities of various throughput scenarios.

The following table sets forth a reconciliation of the changes in fair value of the Partnership’s embedded and earnout derivatives for the years ended December 31, 2017 and 2016 (in thousands):


	December 31,
	2017		2016
Beginning fair value of embedded derivative	$	(4,270)	$	(193,077)
Initial fair value of earnout derivative		221		(4,270)
Gain on embedded derivative		—		47,794
Loss on earnout derivative		(2,353)		—
Transfer to mezzanine equity		—		145,283
Ending fair value of embedded derivative	$	(6,402)	$	(4,270)

6. LONG-TERM DEBT

Credit Agreement

We have entered into a credit agreement with Royal Bank of Canada, as administrative agent and collateral agent, and the lenders party thereto (the “Credit Agreement”). The Credit Agreement provides a maximum commitment of $500.0 million and has a maturity date of March 31, 2020. Borrowings under the Credit Agreement are secured by various mortgages of oil and natural gas properties that we own as well as various security and pledge agreements among the Partnership and certain of its subsidiaries and the administrative agent.

The amount available for borrowing at any one time under the Credit Agreement is limited to the borrowing base for our midstream assets and our oil and natural gas. Borrowings under the Credit Agreement are available for direct investment in oil and natural gas properties, acquisitions, and working capital and general business purposes. The Credit Agreement has a sub-limit of $15.0 million which may be used for the issuance of letters of credit. The initial borrowing base under the Credit Agreement was $200.0 million. The borrowing base for the credit available for the upstream oil and 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 and the amount of distributions received from joint ventures multiplied by 5.0 initially, 4.75 for the second full quarter after the acquisition of Western Catarina Midstream and 4.5 thereafter. Outstanding borrowings in excess of our borrowing base must be repaid or we must pledge other oil and natural gas properties as additional collateral. We may elect to pay any borrowing base deficiency in three equal monthly installments such that the deficiency is eliminated in a period of three months. Any increase in our borrowing base must be approved by all of the lenders. As of December 31, 2017, the borrowing base under the Credit Agreement was $249.3 million, with an elected commitment amount of $200.0 million.

(iii) a commitment fee of 0.500% per annum based on the unutilized borrowing base. Interest on the borrowings for ABR loans and the commitment fee are generally payable quarterly. Interest on the borrowings for LIBOR loans are generally payable at the applicable maturity date.

The Credit Agreement contains various covenants that limit, among other things, our ability to incur certain indebtedness, grant certain liens, merge or consolidate, sell all or substantially all of our assets, make certain loans, Acquisitions, capital expenditures and investments, and pay distributions.

In addition, we are required to maintain the following financial covenants:

current assets to current liabilities of at least 1.0 to 1.0 at all times;

minimum interest coverage ratio of at least 2.5 to 1.0 if the adjusted EBITDA of our midstream operations is greater than one-third of our total adjusted EBITDA.

The Credit Agreement also includes customary events of default, including events of default relating to non-payment of principal, interest or fees, inaccuracy of representations and warranties when made or when deemed made, violation of covenants, cross-defaults, bankruptcy and insolvency events, certain unsatisfied judgments, loan documents not being valid and a change in control. A change in control is generally defined as the occurrence of one of the following events: (i) our existing general partner ceases to be our sole general partner or (ii) certain specified persons shall cease to own more than 50% of the equity interests of our general partner or shall cease to control our general partner. If an event of default occurs, the lenders will be able to accelerate the maturity of the Credit Agreement and exercise other rights and remedies.

The Credit Agreement limits our ability to pay distributions to unitholders. We have the ability to pay distributions to unitholders from available cash, including cash from borrowings under the Credit Agreement, as long as no event of default exists and provided that no distributions to unitholders may be made if the borrowings outstanding, net of available cash, under the 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.

At December 31, 2017, we were in compliance with the financial covenants contained in the Credit Agreement. We monitor compliance on an ongoing basis. If we are unable to remain in compliance with the financial covenants contained in our Credit Agreement or maintain the required ratios discussed above, the lenders could call an event of default and accelerate the outstanding debt under the terms of the Credit Agreement, such that our outstanding debt could become then due and payable. We may request waivers of compliance from the violated financial covenants from the lenders, but there is no assurance that such waivers would be granted.

Debt Issuance Costs

As of December 31, 2017 and 2016, our unamortized debt issuance costs were $1.2 million and $1.7 million, respectively. These costs are amortized to interest expense in our consolidated statements of operations over the life of our Credit Agreement. Amortization of debt issuance costs recorded during the year ended December 31, 2017 and 2016 were $0.5 million.

7. OIL AND NATURAL GAS PROPERTIES AND RELATED EQUIPMENT

Gathering and transportation assets consist of the following (in thousands):


	December 31,
	2017		2016
Gathering and transportation assets
Midstream assets	$	184,969	$	152,209
Less: Accumulated depreciation and amortization		(26,870)		(15,020)
Total gathering and transportation assets	$	158,099	$	137,189

Oil and natural gas properties consist of the following (in thousands):



	December 31,
	2017		2016
Oil and natural gas properties and related equipment
Property costs
Proved property	$	170,750	$	758,366
Unproved property		—		46
Land		—		501
Total property costs		170,750		758,913
Materials and supplies		—		1,056
Total		170,750		759,969
Less: Accumulated depreciation, depletion, amortization and impairments		(115,704)		(674,338)
Oil and natural gas properties and equipment, net	$	55,046	$	85,631

Oil and Natural Gas Properties We follow the successful efforts method of accounting for our oil and natural gas production activities. Under this method of accounting, costs relating to leasehold acquisition, property acquisition and the development of proved areas are capitalized when incurred. If proved reserves are found on an undeveloped property, leasehold cost is transferred to proved properties.

Proved Reserves Accounting rules require that we price our oil and natural gas proved reserves at the preceding twelve-month average of the first-day-of-the-month reference prices as adjusted for location and quality differentials. Such SEC-required prices are utilized except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts. Our proved reserve estimates exclude the effect of any derivatives we have in place.

Our estimate of proved reserves is based on the quantities of natural gas, NGLs, and oil that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Proved reserves are calculated based on various factors, including consideration of an independent reserve engineers’ report on proved reserves and an economic evaluation of all of our properties on a well-by-well basis. The process used to complete the estimates of proved reserves at December 31, 2017 and 2016 is described in detail in Note 19, “Supplemental Information on Oil and Natural Gas Producing Activities.”

Reserves and their relation to estimated future net cash flows impact depletion and impairment calculations. As a result, adjustments to depletion and impairments are made concurrently with changes to reserve estimates. The accuracy of reserve estimates is a function of many factors including the following: the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions and the judgments of the individuals preparing the estimates.

Proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of oil and natural gas eventually recovered.

Depreciation, Depletion and Amortization Depreciation and depletion of producing oil and natural gas properties is recorded at the field level, based on the units-of-production method. Unit rates are computed for unamortized drilling and development costs using proved developed reserves and for unamortized leasehold costs using all proved reserves.

Acquisition costs of proved properties are amortized on the basis of all proved reserves, developed and undeveloped, and capitalized development costs (including wells and related equipment and facilities) are amortized on the basis of proved developed reserves.

Depreciation, depletion, amortization and impairments consisted of the following (in thousands):


	Year Ended
	December 31,
	2017		2016
Depreciation, depletion and amortization of oil and natural gas-related assets	$	9,413	$	6,722
Depreciation, depletion and amortization of gathering and transportation related assets		11,849		13,320
Amortization of intangible assets		13,568		13,757
Total Depreciation, depletion and amortization		34,830		33,799
Asset impairments		4,688		7,646
Total	$	39,518	$	41,445

Impairment of Oil and Natural Gas Properties and Other Non-Current Assets Oil and natural gas properties are reviewed for impairment on a field-by-field basis when facts and circumstances indicate that their carrying value may not be recoverable. We assess impairment of capitalized costs of proved oil and natural gas properties by comparing net capitalized costs to estimated undiscounted future net cash flows using expected prices. If net capitalized costs exceed estimated undiscounted future net cash flows, the measurement of impairment is based on estimated fair value, which would consider estimated future discounted cash flows. The cash flow estimates are based upon third-party reserve reports using future expected oil and natural gas prices adjusted for basis differentials. Other significant inputs, besides reserves, used to determine the fair values of proved properties include estimates of: (i) future operating and development costs; (ii) future commodity prices; and (iii) a market-based weighted average cost of capital rate. These inputs require significant judgments and estimates by the Partnership’s management at the time of the valuation and are the most sensitive and subject to change. Cash flow estimates for impairment testing exclude derivative instruments.

The recoverability of gathering and transportation assets is evaluated when facts or circumstances indicate that their carrying value may not be recoverable. Asset recoverability is measured by comparing the carrying value of the asset or asset group with its expected future pre-tax undiscounted cash flows. These cash flow estimates require us to make projections and assumptions for many years into the future for pricing, demand, competition, operating cost and other factors. If the carrying amount exceeds the expected future undiscounted cash flows, we recognize an impairment equal to the excess of net book value over fair value. The determination of the fair value using present value techniques requires us to make projections and assumptions regarding the probability of a range of outcomes and the rates of interest used in the present value calculations. Any changes we make to these projections and assumptions could result in significant revisions to our evaluation of recoverability of our gathering and transportation assets and the recognition of additional impairments. Upon disposition or retirement of gathering and transportation assets, any gain or loss is recorded to operations.

For the year ended December 31, 2017, we recorded non-cash charges of $4.7 million, to impair certain producing oil and natural gas properties in Texas acquired as part of the Production Acquisition. For the year ended December 31, 2016, we recorded non-cash charges of $7.6 million, with $1.3 million from our Texas and Louisiana properties and $6.3 million from our Oklahoma properties.

Asset Retirement Obligation As described in Note 9, “Asset Retirement Obligations,” estimated asset retirement costs are recognized when the asset is acquired or placed in service, and are amortized over proved developed reserves using the units-of-production method. Asset retirement costs are estimated by our engineers using existing regulatory requirements and anticipated future inflation rates.

Exploration and Dry Hole Costs Exploration and dry hole costs represent abandonments of drilling locations, dry hole costs, delay rentals, geological and geophysical costs and the impairment, amortization and abandonment associated with leases on our unproved properties. All such costs on oil and natural gas properties relating to unsuccessful exploratory wells are charged to expense as incurred. We recorded no exploration or dry hole costs for the years ended December 31, 2017 and 2016.

Materials and Supplies Materials and supplies consist of well equipment, parts and supplies. They are valued at the lower of cost or market, using either the specific identification or first-in first-out method, depending on the inventory type. Materials and supplies are capitalized as used in the development or support of our oil and natural gas properties.

8. PROVISION FOR INCOME TAXES

Publicly traded partnerships like ours are treated as corporations unless they have 90% or more in qualifying income (as that term is defined in the Internal Revenue Code). We satisfied this requirement in each of the years ended December 31, 2017 and 2016 and, as a result, are not subject to federal income tax. However, our partners are individually responsible for paying federal income taxes on their share of our taxable income. Net earnings for financial reporting purposes may differ significantly from taxable income reportable to our unitholders as a result of differences between the tax basis and financial reporting basis of certain assets and liabilities and other factors. We do not have access to information regarding each partner's individual tax basis in our limited partner interests.

Provision for income taxes reflects franchise tax obligations in the state of Texas (the "Texas Margin Tax"). Deferred income tax assets and liabilities are recognized for temporary differences between the assets and liabilities of our tax paying entities for financial reporting and tax purposes.

For the years ended December 31, 2017 and 2016, we had no federal or state income tax provision or benefit.

A reconciliation of the provision for (benefit from) income taxes with amounts determined by applying the statutory U.S. federal income tax rate to income before income taxes is as follows (in thousands):


	For the Years Ended December 31,
	2017			2016
Pre-tax net book income (loss)	$	(3,040)		$	19,231
Texas Margin Tax (a)		(438)			255
Return to accrual		—			—
Valuation allowance		438			(255)
Provision for income taxes	$	—		$	—

Effective income tax rate		0.00	%		0.00	%

(a)

Although the Texas Margin Tax is not considered a state income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers our Texas-sourced revenues and expenses.

The following table presents the significant components of deferred tax assets and deferred tax liabilities at the dates indicated (in thousands):


	December 31,
	2017		2016
Deferred tax assets (liabilities):
Derivative assets	$	7	$	(230)
Depreciable, depletable property, plant and equipment		78		753
Other		1		2
Deferred tax assets:		86		525
Valuation allowance		(86)		(525)
Total deferred tax assets	$	—	$	—

As of December 31, 2017 and 2016, the Partnership had no material uncertain tax positions.

The Partnership files income tax returns in the U.S. and various state jurisdictions. The Partnership is no longer subject to examination by federal income tax authorities prior to 2014. State statutes vary by jurisdiction.

9. ASSET RETIREMENT OBLIGATION

We recognize the fair value of a liability for an asset retirement obligation (“ARO”) in the period in which it is incurred if a reasonable estimate of fair value can be made. Each period, we accrete the ARO to its then present value. The associated asset retirement cost (“ARC”) is capitalized as part of the carrying amount of our oil and natural gas properties, equipment and facilities. Subsequently, the ARC is depreciated using the units-of-production method or straight line for midstream assets. The AROs recorded by us relate to the plugging and abandonment of oil and natural gas wells, and decommissioning of oil and natural gas gathering and other facilities.

Inherent in the fair value calculation of ARO are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions result in adjustments to the recorded fair value of the existing ARO, a corresponding adjustment is made to the ARC capitalized as part of the oil and natural gas property balance.

The following table is a reconciliation of the ARO (in thousands):



	December 31,
	2017		2016
Asset retirement obligation, beginning balance	$	13,579	$	20,364
Liabilities added from acquisitions		198		912
Sold		(8,416)		(6,291)
Revisions to cost estimates		—		(2,399)
Settlements		(60)		(134)
Accretion expense		773		1,127
Asset retirement obligation, ending balance	$	6,074	$	13,579

Additional AROs increase the liability associated with new oil and natural gas wells and other facilities as these obligations are incurred. Abandonments of oil and natural gas wells reduce the liability for AROs. In 2017 and 2016, there were no significant expenditures for abandonments and there were no assets legally restricted for purposes of settling existing AROs. During the year ended December 31, 2017, obligations were sold as part of the Oklahoma Production Divestiture and Texas Production Divestiture and during the year ended December 31, 2016 as part of the Mid-Continent Divestiture that significantly lowered the Partnership’s future abandonment obligations.

10. INTANGIBLE ASSETS

Intangible assets are comprised of customer and marketing contracts. The intangible assets balance includes $172.2 million related to the Gathering Agreement with Sanchez Energy that was entered into as part of the Western Catarina Midstream transaction. Pursuant to the 15-year agreement, Sanchez Energy tenders all of its petroleum, natural gas and other hydrocarbon-based product volumes on 35,000 dedicated acres in the Western Catarina of the Eagle Ford Shale in Texas for processing and transportation through Western Catarina Midstream, with a right to tender additional volumes outside of the dedicated acreage. These intangible assets are being amortized using the straight-line method over the 15 year life of the agreement.

Amortization expense for the years ended December 31, 2017 and 2016 was $13.6 million and $13.8 million, respectively. These costs are amortized to depreciation, depletion, and amortization expense in our consolidated statement of operations. Intangible assets as of December 31, 2017 and 2016 are detailed below (in thousands):


	December 31,
	2017		2016
Beginning balance	$	185,766	$	199,741
Disposals		(32)		(219)
Amortization		(13,568)		(13,756)
Ending balance	$	172,166	$	185,766

11. INVESTMENTS

In July 2016, we completed the Carnero Gathering Transaction pursuant to which we acquired from Sanchez Energy a 50% interest in Carnero Gathering, a joint venture that is 50% owned and operated by Targa, for an initial payment of approximately $37.0 million and the assumption of remaining capital commitments to Carnero Gathering, estimated at approximately $7.4 million as of the acquisition date. During the year ended December 31, 2017, the Partnership made approximately $5.4 million of capital contributions to Carnero Gathering. Prior to the sale, Sanchez Energy, though a wholly owned subsidiary, had invested approximately $26.0 million in Carnero Gathering. The fair value of the intangible asset for the contractual customer relationship related to Carnero Gathering was valued at approximately $13.0 million. This amount is being amortized over a contract term of fifteen years and decreases earnings from Carnero Gathering.

As part of the Carnero Gathering Transaction, 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. This earnout is considered as contingent consideration and its estimated fair value of $6.4 million was recorded on the balance sheet as a deferred liability as of December 31, 2017. No earnout payments were made in the year ended December 31, 2017.

As of December 31, 2017, the Partnership has paid approximately $46.2 million for the Carnero Gathering Transaction related to the initial payment and contributed capital. The Partnership has accounted for this investment as an equity method investment. Targa is the operator of the joint venture and has significant influence with respect to the normal day-to-day construction and operating decisions. We have included the investment balance in the “Equity investments” caption in our consolidated balance sheet. For the year ended December 31, 2017, the Partnership recorded earnings of approximately $6.6 million in equity investments from Carnero Gathering, which was offset by $0.9 million related to the amortization of the contractual customer intangible asset. We have included these equity method earnings in the “Earnings from equity investments” line within the consolidated statements of operations. Cash distributions of approximately $7.6 million were received during the year ended December 31, 2017.

In November 2016, we completed the Carnero Processing Transaction pursuant to which we acquired from Sanchez Energy a 50% interest in Carnero Processing, a joint venture that is 50% owned and operated by Targa, for aggregate cash consideration of approximately $55.5 million and the assumption of remaining capital contribution commitments to Carnero Processing, estimated at approximately $24.5 million as of the date of acquisition. During the year ended

December 31, 2017, the Partnership made approximately $8.2 million of capital contributions to the joint venture. Prior to the sale, Sanchez Energy, though a wholly owned subsidiary, had invested approximately $48.0 million in Carnero Processing.

As of December 31, 2017, the Partnership has paid approximately $74.7 million for the Carnero Processing Transaction related to the initial payment and contributed capital. The Partnership has accounted for this investment as an equity method investment. Targa is the operator of the joint venture and has significant influence with respect to the normal day-to-day construction and operating decisions. We have included the investment balance in the “Equity investments” caption in our consolidated balance sheet. The Partnership recorded earnings of approximately $2.2 million in the “Earnings from equity investments” line within our consolidated statements of operation for the year ended December 31, 2017. Cash distributions of approximately $1.1 million were received during the year ended December 31, 2017.

Summarized financial information of unconsolidated entities is as follows (in thousands):


	Years Ended December 31,
	2017		2016
Sales	$	136,178	$	12,465
Total expenses		118,077		2,677
Net income	$	18,101	$	9,788


	As of December 31,
	2017		2016
Current assets	$	38,344	$	27,779
Noncurrent assets		193,748		152,112
Current liabilities		24,710		16,577

12. COMMITMENTS AND CONTINGENCIES

As part of the Carnero Gathering Transaction, 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. This earnout has an approximate value of $6.4 million and was recorded on the balance sheet as a deferred liability as of December 31, 2017. We did not have any other material commitments and contingencies and no earnout payments were made as of December 31, 2017 or 2016.

13. RELATED PARTY TRANSACTIONS

Sanchez-Related Agreements

We are controlled by our general partner. The sole member of our general partner is Manager, which has no officers. In May 2014, we entered into the Services Agreement with Manager pursuant to which Manager provides services that we require to operate our business, including overhead, technical, administrative, marketing, accounting, operational, information systems, financial, compliance, insurance, and acquisition, disposition and financing services. In connection with providing 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. Each of these fees, not including the reimbursement of costs, is paid in cash unless Manager elects for such fee to be paid in our equity. The Services Agreement has a ten-year term and will be automatically renewed for an additional ten years unless both Manager and the Partnership provide notice of termination to the other with at least 180 days’ notice. During the years ended December 31, 2017 and

2016, we incurred costs of approximately $8.8 million and $7.5 million, respectively, to Manager under the Services Agreement.

Manager utilizes SOG to provide the services under the Services Agreement. In May 2014, we entered into a Contract Operating Agreement with SOG pursuant to which SOG either provides services to operate, develop and produce our oil and natural gas properties or engages a third-party operator to do so, other than with respect to our properties in the Mid-Continent Region. We also have entered into the Geophysical Seismic Data Use License Agreement with SOG pursuant to which SOG provides us a non-exclusive, royalty-free license to use seismic, geophysical and geological information relating to our oil and natural gas properties that is proprietary to SOG and not restricted by agreements that SOG has with landowners or seismic data vendors.

SOG, headquartered in Houston, Texas, is a private full-service oil and natural gas company engaged in the exploration and development of oil and natural gas primarily in the South Texas and onshore Gulf Coast areas on behalf of its affiliates. The Chairman of the board of directors of our general partner, Antonio R. Sanchez, III, the President and Chief Operating Officer of our general partner as well as one of our directors, Patricio D. Sanchez, one of our directors, Eduardo A. Sanchez, along with their immediate family members Ana Lee Sanchez Jacobs and Antonio R. Sanchez, Jr., collectively, either directly or indirectly, own a majority of the equity interests of SOG. In addition, Antonio R. Sanchez, Jr. is a member of the board of directors of SOG, and such other individuals, as well as Ana Lee Sanchez Jacobs, are officers of SOG.

Sanchez-Related Transactions

We have entered into several transactions with Sanchez Energy since January 1, 2016. Antonio R. Sanchez, Jr. is a director and Executive Chairman of the Board of Sanchez Energy, and Antonio R. Sanchez, III, is a director and Chief Executive Officer of Sanchez Energy. In addition, Eduardo Sanchez is the President of Sanchez Energy and Patricio Sanchez is an Executive Vice President of Sanchez Energy. The employees of SOG, including Kirsten A. Hink, our Chief Accounting Officer, provide common services to both us and Sanchez Energy.

In conjunction with the acquisition of Western Catarina Midstream, we entered into the 15-year gas gathering agreement with Sanchez Energy pursuant to which Sanchez Energy agreed to tender all of its crude petroleum, natural gas and other hydrocarbon-based product volumes on approximately 35,000 dedicated acres in the Western Catarina area of the Eagle Ford Shale in Texas for processing and transportation through Western Catarina Midstream, with the potential to tender additional volumes outside of the dedicated acreage (the “Gathering Agreement”). During the first five years of the term of the Gathering Agreement, Sanchez Energy is required to meet a minimum quarterly volume delivery commitment of 10,200 barrels per day of oil and condensate and 142,000 Mcf per day of natural gas, subject to certain adjustments. Sanchez Energy is required to pay gathering and processing fees of $0.96 per barrel for crude oil and condensate and $0.74 per Mcf for natural gas that are tendered through Western Catarina Midstream, in each case, subject to an annual escalation for a positive increase in the consumer price index. For the years ended December 31, 2017 and 2016, Sanchez Energy paid us approximately $52.8 million and $50.1 million, respectively, pursuant to the terms of the gathering and processing agreement. On June 30, 2017, the Gathering Agreement was amended to add an incremental infrastructure fee to be paid by SN Catarina based on water that is delivered through the gathering system through March 31, 2018.

As part of the Carnero Gathering Transaction, we are required to pay Sanchez Energy an earnout based on natural gas received above a threshold volume and tariff at Carnero Gathering’s delivery points from Sanchez Energy and other producers. For the years ended December 31, 2017 and 2016, we did not make any earnout payments to Sanchez Energy. However, we had a payable of $0.1 million to Sanchez Energy at year end December 31, 2017 related to the earnout.

In November 2016, in conjunction with our public offering of common units, the Partnership entered into a Common Unit Purchase Agreement with SN UR Holdings, LLC, a wholly-owned subsidiary of Sanchez Energy, whereby we issued to the Purchaser 2,272,727 common units for proceeds of approximately $25.0 million.

consideration of approximately $55.5 million and the assumption of remaining capital contribution commitments to Carnero Processing, estimated at approximately $24.5 million as of the date of acquisition. Also in November 2016, the Partnership consummated a Purchase and Sale Agreement with SN Cotulla Assets, LLC and SN Palmetto, LLC, each a wholly-owned subsidiary of Sanchez Energy, to purchase working interests 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 for approximately $24.2 million. In October 2016, we entered into an agreement with Sanchez Energy providing us an option to acquire a ground lease, which the parties mutually terminated in September 2017.

As of December 31, 2017 and 2016, the Partnership had a net receivable from related parties of approximately $13.1 million, and $6.0 million, respectively, which are included in “Accounts receivable – related entities” in the consolidated balance sheets. As of December 31, 2017 and 2016, the Partnership also had a net payable to related parties of approximately $10.4 million, and $7.0 million, respectively. The net receivable/payable as of December 31, 2016 consist primarily of revenues receivable from oil and natural gas production and transportation, offset by costs associated with that production and transportation and obligations for general and administrative costs.

Sanchez Energy is an independent exploration and production company focused on the acquisition and development of U.S. onshore unconventional oil and natural gas resources, with a current focus on the horizontal development of significant resource potential from the Eagle Ford Shale in South Texas where it has assembled approximately 487,000 gross leasehold acres (285,000 net acres). The Chairman of the board of directors of our general partner, Antonio R. Sanchez, III, is Sanchez Energy’s Chief Executive Officer and a member of its board of directors. A member of the board of directors of our general partner, Eduardo A. Sanchez, is the former President of Sanchez Energy. The President and Chief Operating Officer of our general partner, Patricio D. Sanchez, who is also a member of the board of directors of our general partner, is an Executive Vice President of Sanchez Energy. Antonio R. Sanchez, Jr., the father of Antonio R. Sanchez, III, Eduardo A. Sanchez, and Patricio D. Sanchez, is the Executive Chairman of the board of directors of Sanchez Energy. Antonio R. Sanchez, Jr., Antonio R. Sanchez, III, Eduardo A. Sanchez and Patricio D. Sanchez was 6.8%, 3.0%, 1.4% and 1.2%, respectively, of Sanchez Energy’s shares outstanding as of March 5, 2018. As of March 6, 2018, Sanchez Energy indirectly, through one of its wholly owned subsidiaries, beneficially owns approximately 15.2% of the outstanding common units of SNMP.

14. UNIT-BASED COMPENSATION

The Sanchez Midstream Partners LP Long-Term Incentive Plan (the “Plan”) allows for restricted common unit grants. Restricted common unit activity under the Plan during the period is presented in the following table:


		Weighted
		Average
	Number of	Grant Date
	Restricted	Fair Value
	Units	Per Unit
Outstanding at December 31, 2015	361,357	$	14.18
Granted	67,627		10.35
Vested	(195,613)		12.69
Returned/Cancelled	(14,227)		15.81
Outstanding at December 31, 2016	219,144	$	14.22
Granted	220,814		14.73
Vested	(153,487)		14.20
Returned/Cancelled	(3,333)		13.59
Outstanding at December 31, 2017	283,138	$	14.64

In March 2017, the Partnership issued 171,231 restricted common units pursuant to the Plan to executives of the Partnership’s general partner that vest on the first anniversary of grant. In April 2017, the Partnership issued 44,583 restricted common units pursuant to the Plan to certain directors of the Partnership’s general partner that vested immediately on the date of grant. The unit-based compensation expense for the award was based on the fair value on the day before the date of grant. During the year ended December 31, 2016, the Partnership issued 67,627 restricted common units pursuant to the Plan to certain directors of the Partnership’s general partner that vested immediately on the date of the grant. The unit-based compensation expense for the award was based on the fair value on the day before the date of grant.

As of December 31, 2017, 1,599,135 common units remain available for future issuance to participants under the LTIP.

15. DISTRIBUTIONS TO UNITHOLDERS

The table below reflects the payment of cash distributions on common units relating to the years ended December 31, 2017 and 2016.


	Distribution		Date of	Date of	Date of
Three months ended	per unit		declaration	record	distribution
March 31, 2016	$	0.4121	May 10, 2016	May 20, 2016	May 31, 2016
June 30, 2016	$	0.4183	August 10, 2016	August 22, 2016	August 31, 2016
September 30, 2016	$	0.4246	October 31, 2016	November 10, 2016	November 30, 2016
December 31, 2016	$	0.4310	February 9, 2017	February 20, 2017	February 28, 2017
March 31, 2017	$	0.4375	May 10, 2017	May 22, 2017	May 31, 2017
June 30, 2017	$	0.4441	August 9, 2017	August 22, 2017	August 31, 2017
September 30, 2017	$	0.4508	November 7, 2017	November 20, 2017	November 30, 2017
December 31, 2017	$	0.4508	February 8, 2018	February 20, 2018	February 28, 2018

The table below reflects the payment of distributions on Class B preferred units during the years ended December 31, 2017 and 2016.


	Cash distribution		Date of	Date of	Date of
Three months ended	per unit		declaration	record	distribution
March 31, 2016	$	0.4500	May 10, 2016	May 20, 2016	May 31, 2016
June 30, 2016	$	0.4500	August 10, 2016	August 22, 2016	August 31, 2016
September 30, 2016	$	0.4500	October 31, 2016	November 10, 2016	November 30, 2016
December 31, 2016 (a)	$	0.2258	February 9, 2017	February 20, 2017	February 28, 2017
March 31, 2017 (a)	$	0.2258	May 10, 2017	May 22, 2017	May 31, 2017
June 30, 2017	$	0.28225	August 9, 2017	August 22, 2017	August 31, 2017
September 30, 2017	$	0.28225	November 7, 2017	November 20, 2017	November 30, 2017
December 31, 2017	$	0.28225	February 8, 2018	February 20, 2018	February 28, 2018

(a)

The Partnership elected to pay the fourth quarter 2016 and first quarter 2017 distributions on the Class B preferred units in part cash and, with the consent of the Class B preferred unitholder, in part common units (in lieu of additional Class B preferred units). Accordingly, the Partnership declared a cash distribution of $0.2258 per Class B preferred unit and an aggregate distribution of 208,594 common units, each paid on February 28, 2017 to holders of record on February 20, 2017, and the Partnership declared a cash distribution of $0.2258 per Class B preferred unit and an aggregate distribution of 184,697 common units, each paid on May 31, 2017 to holders of record on May 22, 2017.

Under the terms of our partnership agreement, holders of the Class B preferred units receive a quarterly distribution, at the election of the board of directors of our general partner, of 10.0% per annum if paid in full in cash or 12.0% per annum if paid in part cash (8.0% per annum) and in part paid-in-kind units (4.0% per annum). Distributions are to be paid on or about the last day of each of February, May, August and November after the end of each quarter.

In accordance with the partnership agreement, on December 6, 2016, we issued an additional 9,851,996 Class B preferred units to Stonepeak. On January 25, 2017, the Partnership and Stonepeak entered into a Settlement Agreement and Mutual Release (the “Settlement Agreement”) to settle a dispute arising from the calculation of an adjustment to the number of Class B preferred units pursuant to Section 5.10(g) of the Second Amended and Restated Agreement of Limited Partnership of the Partnership (the “Amended Partnership Agreement”). Pursuant to the Settlement Agreement, and in accordance with Section 5.4 of the Amended Partnership Agreement, the Partnership issued 1,704,446 Class B preferred units to Stonepeak in a privately negotiated transaction as partial consideration for the Settlement Agreement, with the “Class B Preferred Unit Price” being established at $11.29 per Class B preferred unit. Pursuant to the terms of the Amended Partnership Agreement, the Class B preferred units are convertible at any time, at the option of Stonepeak, into common units of the Partnership, subject to the requirement to convert a minimum of $17.5 million of Class B preferred units. The issuance of the Class B preferred units pursuant to the Settlement Agreement was made in reliance upon an exemption from the registration requirements of the Securities Act of 1933 pursuant to Section 4(a)(2) thereof.

The Class B preferred units are accounted for as mezzanine equity in the consolidated balance sheet consisting of the following (in thousands):


	December 31,
	2017		2016
Mezzanine equity beginning balance	$	342,991	$	172,111
Discount		—		(87)
Amortization of discount		1,796		23,477
Distributions		35,875		39,375
Distributions paid		(36,750)		(37,168)
Transfer embedded derivative to Class B preferred units		—		145,283
Total mezzanine equity	$	343,912	$	342,991

Earnings per Unit

Our general partner does not have an economic interest in the Partnership and, therefore, does not participate in the Partnership’s net income.

The following table presents the weighted average basic and diluted units outstanding for the periods indicated:



	December 31,
	2017	2016
Common units - Basic and Diluted	14,039,726	4,658,970
Weighted Common units - Basic and Diluted	14,039,726	4,658,970

At December 31, 2017 and 2016, we had 283,138 and 219,144 common units that were restricted unvested common units granted and outstanding, respectively. No losses were allocated to participating restricted unvested units because such securities do not have a contractual obligation to share in the Partnership’s losses.

The following table presents our basic and diluted loss per unit for the year ended December 31, 2017 (in thousands, except for per unit amounts):

The following table presents our basic and diluted loss per unit for the year ended December 31, 2016 (in thousands, except for per unit amounts):

17. REPORTING SEGMENTS

“Midstream” and “Production” best describe the operating segments of the businesses that we separately report. The factors used to identify these reportable segments are based on the nature of the operations that are undertaken by each segment. The Midstream segment operates the gathering, processing and transportation of natural gas, NGLs and oil. The Production segment operates to produce crude oil and natural gas. These segments are broadly understood across the petroleum and petrochemical industries.

These functions have been defined as the operating segments of the Partnership because they are the segments (1) that engage in business activities from which revenues are earned and expenses are incurred; (2) whose operating results are regularly reviewed by the Partnership’s chief operating decision maker (“CODM”) to make decisions about resources to be allocated to the segment and to assess its performance; and (3) for which discrete financial information is available. Operating segments are evaluated for their contribution to the Partnership’s consolidated results based on operating income, which is defined as segment operating revenues less expenses.

We realigned the composition of our operating segments to reflect management's view of the operating results during the fourth quarter 2017. The following tables present financial information for each operating segment for the periods indicated based on the realignment of our operating segments (in thousands):


	For the Year Ended December 31, 2017
	Production		Midstream		Total
Segment operating revenues:
Natural gas sales	$	6,626	$	—	$	6,626
Oil sales		23,701		—		23,701
Natural gas liquid sales		1,997		—		1,997
Gathering and transportation sales		—		55,825		55,825
Earnings (losses) from equity investments		(101)		7,986		7,885
Total segment operating revenues		32,223		63,811		96,034

Segment operating costs:
Lease operating expenses		12,066		928		12,994
Transportation operating expenses		—		11,600		11,600
Earnout rebate		—		64		64
Cost of sales		77		—		77
Production taxes		1,476		—		1,476
Gain on sale of assets		(4,150)		—		(4,150)
Depreciation, depletion and amortization		9,522		25,308		34,830
Asset impairments		4,688		—		4,688
Accretion expense		499		274		773
Total segment operating costs		24,178		38,174		62,352

Segment operating income	$	8,045	$	25,637	$	33,682


	For the Year Ended December 31, 2016
	Production		Midstream		Total
Segment operating revenues:
Natural gas sales	$	10,408	$	—	$	10,408
Oil sales		5,138		—		5,138
Natural gas liquid sales		1,167		—		1,167
Gathering and transportation sales		—		53,972		53,972
Earnings from equity investments		81		2,301		2,382
Total segment operating revenues		16,794		56,273		73,067

Segment operating costs:
Lease operating expenses		14,327		654		14,981
Transportation operating expenses		—		12,478		12,478
Cost of sales		328		—		328
Production taxes		1,167		—		1,167
Loss on sale of assets		219		—		219
Depreciation, depletion and amortization		6,722		27,077		33,799
Asset impairments		7,646		—		7,646
Accretion expense		875		252		1,127
Total segment operating costs		31,284		40,461		71,745

Segment operating income (loss)	$	(14,490)	$	15,812	$	1,322


	For the Years Ended
	December 31,
	2017		2016
Reconciliation of segment operating income to net income (loss):
Total segment operating income	$	33,682	$	1,322
General and administrative		(22,655)		(22,901)
Unit-based compensation expense		(3,373)		(1,941)
Interest expense, net		(8,341)		(5,093)
Gain on embedded derivative		—		47,794
Other income (expense)(a)		(2,353)		50
Net income (loss)	$	(3,040)	$	19,231

(a)

Other expense in 2017 excludes earnout rebate. As the rebate is reviewed by the CODM at the segment level, it was included in the Midstream segment operating costs.

The following table summarizes the total assets and capital expenditures by operating segment based on the segment realignment as of December 31, 2017 and 2016 (in thousands):


	December 31, 2017
	Production		Midstream		Corporate (a)		Total
Other financial information
Total assets	$	58,623	$	468,656	$	1,144	$	528,423
Capital expenditures(b)	$	441	$	46,452	$	—	$	46,893


	December 31, 2016
	Production		Midstream		Corporate (a)		Total
Other financial information
Total assets	$	96,262	$	440,675	$	2,768	$	539,705
Capital expenditures(b)	$	939	$	18,595	$	—	$	19,534

(b)

Corporate assets not reviewed by the CODM on a segment basis consists of cash, some prepaids, and other assets.

(a)

Inclusive of capital contributions made to equity method investments.

The following table summarizes the percentage of revenue earned from those customers in the Midstream segment that exceed 10% of the Partnership's consolidated revenue for the periods presented below. Because all remaining production properties are non-operated, there are no customers in the Production segment that exceed 10% of the Partnership’s consolidated revenue.


	For the Years Ended
	December 31,
	2017			2016
Midstream
Sanchez Energy		63	%		76	%
Total		63	%		76	%

18. VARIABLE INTEREST ENTITIES

During the year ended December 31, 2016, the Partnership adopted ASU 2015-02, “Consolidation—Amendments to the Consolidation Analysis,” which introduces a separate analysis for determining if limited partnerships and similar entities are variable interest entities (“VIEs”) and clarifies the steps a reporting entity would have to take to determine whether the voting rights of stockholders in a corporation or similar entity are substantive.

As noted above in Note 11, “Investments,” the Partnership purchased a 50% membership interest in Carnero Gathering from Sanchez Energy for an initial payment of approximately $37.0 million and the assumption of remaining capital commitments to Carnero Gathering, estimated at approximately $7.4 million as of the date of the acquisition. The Partnership determined that the Carnero Gathering joint venture is more similar to a limited partnership than a corporation. Under the revised guidance of ASU 2015-02, a limited partnership or similar entity with equity at risk will not be a VIE if a partner is able to exercise kick-out rights over the general partner(s) or is able to exercise substantive participating rights. We concluded that the Carnero Gathering joint venture is a VIE under the revised guidance because we cannot remove Targa as operator and we do not have substantive participating rights. In addition, Targa has the discretion to direct activities of the VIE regarding the risks associated with price, operations, and capital investment which have the most significant impact on the VIE’s economic performance.

The Partnership’s investment in Carnero Gathering represents a VIE that could expose the Partnership to losses. The amount of losses the Partnership could be exposed to from the Carnero Gathering joint venture is limited to the capital investment of approximately $47.9 million.

As of December 31, 2017, the Partnership had invested approximately $46.2 million in Carnero Gathering. As of December 31, 2017, no debt has been incurred by Carnero Gathering. We have included this VIE in the “Equity investments” long-term asset line on the balance sheet.

As noted above in Note 11, “Investments,” the Partnership purchased a 50% membership interest in Carnero Processing from Sanchez Energy for an initial payment of approximately $55.5 million and the assumption of remaining capital commitments to Carnero Processing, estimated at approximately $24.5 million as of the date of the acquisition. The Partnership determined that the Carnero Processing joint venture is more similar to a limited partnership than a corporation. Under the revised guidance of ASU 2015-02, a limited partnership or similar entity with equity at risk will not be a VIE if a limited partner is able to exercise kick-out rights over the general partner(s) or is able to exercise

substantive participating rights. We concluded that the Carnero Processing joint venture is a VIE under the revised guidance because we cannot remove Targa as operator and we do not have substantive participating rights. In addition, Targa has the discretion to direct activities of the VIE regarding the risks associated with price, operations, and capital investment which have the most significant impact on the VIE’s economic performance.

Similar to the Partnership’s investment in Carnero Gathering, the Partnership’s investment in Carnero Processing represents a VIE that could expose the Partnership to losses. The amount of losses the Partnership could be exposed to from the Carnero Processing joint venture is limited to the capital investment of approximately $75.8 million.

As of December 31, 2017, the Partnership had invested approximately $74.7 million in Carnero Processing. As of December 31, 2017, no debt has been incurred by Carnero Processing. We have included this VIE in the “Equity investments” long-term asset line on the balance sheet.

Below is a tabular comparison of the carrying amounts of the assets and liabilities of the VIE and the Partnership’s maximum exposure to loss as of December 31, 2017 and 2016 (in thousands):


	December 31,
	2017		2016
Capital investments	$	121,010	$	107,320
Earnings in equity investments		10,288		2,301
Distributions received		(11,632)		(2,950)
Estimated earnout accrued		4,049		4,270
Equity in equity investments	$	123,715	$	110,941

	December 31,
	2017		2016
Equity in equity investments	$	123,715	$	110,941
Guarantees of capital investments		—		17,584
Maximum exposure to loss	$	123,715	$	128,525

19. SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS PRODUCING ACTIVITIES (UNAUDITED)

The Supplementary Information on Oil and Natural Gas Producing Activities is presented as required by the appropriate authoritative guidance. The supplemental information includes capitalized costs related to oil and natural gas producing activities; costs incurred for the acquisition of oil and natural gas producing activities, exploration and development activities and the results of operations from oil and natural gas producing activities.

Supplemental information is also provided for per unit production costs; oil and natural gas production and average sales prices; the estimated quantities of proved oil and natural gas reserves; the standardized measure of discounted future net cash flows associated with proved reserves and a summary of the changes in the standardized measure of discounted future net cash flows associated with proved reserves.

Costs

The following table sets forth our capitalized costs as of December 31, 2017 and 2016 (in thousands):


	December 31,
	2017		2016
Capitalized costs at the end of the period:⁽ᵃ⁾
Oil and natural gas properties and related equipment (successful efforts method)
Property costs
Proved property	$	170,750	$	758,366
Unproved property		—		46
Land		—		501
Total property costs		170,750		758,913
Materials and supplies		—		1,056
Total		170,750		759,969
Less: Accumulated depreciation, depletion, amortization and impairments		(115,704)		(674,338)
Oil and natural gas properties and equipment, net	$	55,046	$	85,631

(a)

Capitalized costs include the cost of equipment and facilities for our oil and natural gas producing activities. Proved property costs include capitalized costs for leaseholds holding proved reserves; development wells and related equipment and facilities (including uncompleted development well costs); and support equipment. Unproved property costs include capitalized costs for oil and natural gas leaseholds where proved reserves do not exist.

The following table sets forth costs incurred for oil and natural gas producing activities for the years ended December 31, 2017 and 2016 (in thousands):


	For the Years Ended December 31,
	2017		2016
Costs incurred for the period:
Acquisition of properties
Proved	$	—	$	25,622
Development costs		441		937
Oil and natural gas properties and equipment, net	$	441	$	26,559

The development costs for the year ended December 31, 2017 and 2016 primarily represent costs related to recompletions. The properties acquired in 2016 were related to the Production Acquisition, for additional information see Note 3. “Acquisitions and Divestitures.”

We had no exploration and dry hole costs in 2017 and 2016.

Results of Operations

The revenues and expenses associated directly with oil and natural gas producing activities are reflected in the Consolidated Statements of Operations. All of our oil and natural gas producing activities are located in the United States.

Net Proved Reserves of Natural Gas, NGLs and Oil

The following table sets forth information with respect to changes in proved developed and undeveloped reserves. This information excludes reserves related to royalty and net profit interests. All of our reserves are located in the United States.


				Natural Gas
	Total	Oil	Natural Gas	Liquids
	(MMBoe)	(in MMBoe)	(in MMBoe)	(in MMBoe)
Net proved reserves
December 31, 2015	11,642	3,159	7,736	747
Purchase of reserves in place	1,397	1,049	176	172
Sales of reserves in place	(610)	(47)	(563)	—
Revisions of previous estimates	(4,426)	(316)	(4,202)	92
Production	(1,133)	(331)	(721)	(81)
December 31, 2016	6,870	3,514	2,426	930
Sales of reserves in place	(1,731)	(358)	(1,280)	(93)
Revisions of previous estimates	1,062	504	383	175
Production	(936)	(414)	(420)	(102)
December 31, 2017	5,265	3,246	1,109	910

Proved developed reserves:
December 31, 2016	6,870	3,514	2,426	930
December 31, 2017	5,265	3,246	1,109	910

Reserves and Related Estimates

Our estimate of proved reserves is based on the quantities of oil and natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters.

Our year end December 31, 2017 and 2016, proved reserve estimates were 5.3 MMBoe and 6.9 MMBoe, respectively. Reserve estimates for those periods were prepared by, Ryder Scott, an independent petroleum engineering firm, and are used for the applicable disclosures in our financial statements.

Our 2017 estimates of total proved reserves decreased 1.6 MMBoe from 2016 primarily due to a decrease in reserves of 1.7 MMBoe due to the Oklahoma Production Divestiture and Texas Production Divestiture. For proved reserves, the production weighted average product price over the remaining lives of the properties used in our reserve report were: $48.69 per barrel for oil, $21.34 per barrel for NGLs and $3.04 per Mcf for natural gas.

Our 2016 estimates of total proved reserves decreased 4.7 MMBoe from 2015 due to a downward revision of previous estimates of 4.4 MMBoe offset by an increase of 1.4 MMBoe related to the purchase of reserves in place. The downward revision was due to lower commodity prices as well as a decrease in proved developed not producing and PUD reserves, partially offset by an increase in PDP reserves from our Production Acquisition. Our reserves are 35% natural gas and are sensitive to lower prices for natural gas and basis differentials in the Mid-Continent region. For proved reserves, the production weighted average product price over the remaining lives of the properties used in our reserve report were: $38.85 per barrel for oil, $13.84 per barrel for NGLs and $2.28 per Mcf for natural gas. Proved developed producing reserves were lower due to natural production decline and our sale of reserves in place.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves, Including a Reconciliation of Changes Therein

The following table sets forth the standardized measure of the discounted future net cash flows attributable to our proved oil and natural gas reserves. Certain information concerning the assumptions used in computing the valuation of proved reserves and their inherent limitations are discussed below.

Future cash inflows are calculated by applying the SEC-required prices of oil and natural gas relating to our proved reserves to the year-end quantities of those reserves. Future cash inflows exclude the impact of our hedging program. Future development and production costs represent the estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves, assuming continuation of existing economic conditions. In addition, asset retirement obligations are included within future production and development costs. There are no future income tax expenses because the Partnership is a non-taxable entity.

The assumptions used to compute estimated future cash inflows do not necessarily reflect expectations of actual revenues or costs or their present values. In addition, variations from expected production rates could result directly or indirectly from factors outside of our control, such as unexpected delays in development, changes in prices or regulatory or environmental policies. The reserve valuation further assumes that all reserves will be disposed of by production; however, if reserves are sold in place, additional economic considerations could also affect the amount of cash eventually realized.

The following table summarizes the standardized measure of estimated discounted future cash flows from the oil and natural gas properties (in thousands):


	For the Years Ended December 31,
	2017		2016
Future cash inflows	$	197,739	$	182,612
Future production costs		(101,300)		(102,569)
Future estimated development costs		(4,346)		(8,872)
Future net cash flows		92,093		71,171
10% annual discount for estimated timing of cash flows		(35,396)		(21,535)
Standardized measure of discounted estimated future net cash flows related to proved oil and natural gas reserves	$	56,697	$	49,636

The following table summarizes the principal sources of change in the standardized measure of estimated discounted future net cash flows (in thousands):


	For the Years Ended December 31,
	2017		2016
Beginning of the period	$	49,636	$	67,852
Sales and transfers of oil and natural gas, net of production costs		(14,758)		(8,700)
Net changes in prices and production costs related to future production		15,036		(7,868)
Changes in development costs		3,854		5,040
Changes in extensions and discoveries		160		—
Revisions of previous quantity estimates		9,137		(17,924)
Purchases and sales of reserves in place		(11,952)		9,134
Accretion discount		4,964		6,175
Change in production rates, timing, and other		620		(4,073)
Standardized measure of discounted future net cash flows related to proved oil and natural gas reserves	$	56,697	$	49,636

20. SUBSEQUENT EVENTS

On February 8, 2018, the board of directors of our general partner declared a fourth quarter 2017 cash distribution on its common units of $0.4508 per unit ($1.8032 per unit annualized) payable on February 28, 2018 to holders of record on February 20, 2018. The Partnership also declared a fourth quarter distribution on the Class B preferred units and elected to pay the distribution in cash. Accordingly, the Partnership declared a cash distribution of $0.28225 per Class B preferred unit, paid on February 28, 2018 to holders of record on February 20, 2018.

HIDDEN_ROW
Exhibit
Number			Description

1.1			At Market Issuance Sales Agreement, dated as of April 16, 2017, between Sanchez Production Partners LP and FBR Capital Markets & Co. (incorporated herein by reference to Exhibit 1.1 to the Current Report on Form 8-K filed by Sanchez Production Partners LP on April 6, 2017, File No. 001-33147).

2.1			Contribution Agreement, dated as of August 9, 2013, by and between Constellation Energy Partners LLC and Sanchez Energy Partners I, LP (incorporated herein by reference to Exhibit 2.1 to the Current Report on Form 8-K field by Constellation Energy Partners LLC on August 9, 2013, File No. 001-33147).

2.2			Purchase and Sale Agreement, dated as of March 31, 2015, between SEP Holdings III, LLC, Sanchez Production Partners LP and SEP Holdings IV, LLC (incorporated herein by reference to Exhibit 2.1 to the Current Report on Form 8-K filed by Sanchez Production Partners LP on April 1, 2015, File No. 001-33147).

2.3			Purchase and Sale Agreement, dated as of September 25, 2015, by and among Sanchez Energy Corporation, SN Catarina, LLC and Sanchez Production Partners LP (incorporated herein by reference to Exhibit 2.1 the Current Report on Form 8-K filed by Sanchez Production Partners LP on September 29, 2015, File No. 001-33147).

2.4			Purchase and Sale Agreement between certain wholly-owned subsidiaries of Sanchez Production Partners LP and Gateway Resources U.S.A., Inc., dated June 15, 2016, as amended, by that certain Amendment No. 1 to Purchase and Sale Agreement, dated June 15, 2016 (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q filed by Sanchez Production Partners LP on August 12, 2016, File No. 001-33147).

2.5			Purchase and Sale Agreement by and among Sanchez Energy Corporation, SN Midstream, LLC and Sanchez Production Partners LP, dated July 5, 2016 (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q filed by Sanchez Production Partners LP on August 12, 2016, File No. 001-33147).

2.6			Purchase and Sale Agreement, dated October 6, 2016, by and among Sanchez Energy Corporation, SN Midstream, LLC and Sanchez Production Partners LP (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K filed by Sanchez Production Partners LP on October 7, 2016, File No. 001-33147).

2.7			Purchase and Sale Agreement, dated October 6, 2016, by and among SN Cotulla Assets, LLC, SN Palmetto, LLC, SEP Holdings IV, LLC and Sanchez Production Partners LP (incorporated by reference to Exhibit 2.2 to the Current Report on Form 8-K filed by Sanchez Production Partners LP on October 7, 2016, File No. 001-33147).

2.8			Purchase and Sale Agreement, dated October 6, 2016, by and among Sanchez Energy Corporation, SN Terminal, LLC and Sanchez Production Partners LP (incorporated by reference to Exhibit 2.3 to the Current Report on Form 8-K filed by Sanchez Production Partners LP on October 7, 2016, File No. 001-33147).
2.9			Membership Interest Purchase and Sale Agreement between Sanchez Midstream Partners LP (f/k/a/ Sanchez Production Partners LP) and Exponent Energy, LLC dated May 10, 2017 (incorporated by reference to Exhibit 2.1 to the Quarterly Report on Form 10-Q filed by Sanchez Midstream Partners LP on August 14, 2017, File No. 001-33147).
2.10			Purchase and Sale Agreement between SEP Holdings IV, LLC and Sendero Petroleum, LLC dated June 30, 2017 (incorporated by reference to Exhibit 2.2 to the Quarterly Report on Form 10-Q filed by Sanchez Midstream Partners LP on August 14, 2017, File No. 001-33147).
2.11			Amendment No. 1 to Purchase and Sale Agreement between SEP Holdings IV, LLC and Sendero Petroleum, LLC dated July 31, 2017 (incorporated by reference to Exhibit 2.3 to the Quarterly Report on Form 10-Q filed by Sanchez Midstream Partners LP on August 14, 2017, File No. 001-33147).
2.12			Purchase and Sale Agreement between Sanchez Midstream Partners LP and Dallas Petroleum Group, LLC dated October 12, 2017 (incorporated by reference to Exhibit 2.1 to the Quarterly Report on Form 10-Q filed by Sanchez Midstream Partners LP on November 14, 2017, File No. 001-33147).
3.1			Certificate of Conversion of Sanchez Production Partners LLC (incorporated herein by reference to Exhibit 4.1 to the Post-Effective Amendment No. 1 to the Registration Statement on Form S-4 filed by Sanchez Production Partners LP on March 6, 2015, File No. 333-198440).

3.2			Certificate of Limited Partnership of Sanchez Production Partners LP (incorporated herein by reference to Exhibit 4.2 to the Post-Effective Amendment No. 1 to the Registration Statement on Form S-4 filed by Sanchez Production Partners LP on March 6, 2015, File No. 333-198440).

3.3			Certificate of Amendment to Certificate of Limited Partnership (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K filed by Sanchez Midstream Partners LP on June 2, 2017, File No. 001-33147).
3.4			Second Amended and Restated Agreement of Limited Partnership of Sanchez Production Partners LP (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K filed by Sanchez Production Partners LP on October 14, 2015, File No. 001-33147).

3.5			Amendment No. 1 to Second Amended and Restated Agreement of Limited Partnership of Sanchez Production Partners LP, effective as of January 25, 2017 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed by Sanchez Production Partners LP on January 27, 2017, File No. 001-33147).
3.6			Amendment No. 2 to Second Amended and Restated Agreement of Limited Partnership of Sanchez Midstream Partners LP (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed by Sanchez Midstream Partners LP on August 15, 2017, File No. 001-33147).

3.7			Limited Liability Company Agreement of Sanchez Production Partners GP LLC (incorporated herein by reference to Exhibit 4.5 to the Post-Effective Amendment No. 1 to the Registration Statement on Form S-4 filed by Sanchez Production Partners LP on March 6, 2015, File No. 333-198440).

3.8			Amendment No. 1 to Limited Liability Company Agreement of Sanchez Production Partners GP LLC (incorporated herein by reference to Exhibit 3.1 to the Quarterly Report on Form 10-Q/A filed by Sanchez Production Partners LP on September 3, 2015, File No. 001-33147).

3.9			Amendment No. 2 to Limited Liability Company Agreement of Sanchez Production Partners GP LLC (incorporated herein by reference to Exhibit 3.2 to the Current Report on Form 8-K filed by Sanchez Production Partners LP on October 14, 2015, File No. 001-33147).

4.1			Registration Rights Agreement, dated as of October 14, 2015, between Sanchez Production Partners LP and the purchaser named therein (incorporated herein by reference to Exhibit 4.1 to the Current Report on Form 8-K filed by Sanchez Production Partners LP on October 14, 2015, File No. 001-33147).

10.1			Amendment No. 1 to Registration Rights Agreement, effective January 25, 2017, by and between Stonepeak Catarina Holdings LLC and Sanchez Production Partners LP (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed by Sanchez Production Partners LP on January 27, 2017, File No. 001-33147).

10.2			Registration Rights Agreement, dated November 22, 2016, between Sanchez Production Partners LP and SN UR Holdings, LLC (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed by Sanchez Production Partners LP on November 22, 2016, File No. 001-33147).

10.3			Purchase Agreement, dated November 16, 2016, between Sanchez Production Partners LP and SN UR Holdings, LLC (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by Sanchez Production Partners LP on November 22, 2016, File No. 001-33147).

10.4			Third Amended and Restated Credit Agreement, dated as of March 31, 2015, among Sanchez Production Partners LP, Royal Bank of Canada, as administrative agent and collateral agent, and the lenders party thereto (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by Sanchez Production Partners LP on April 1, 2015, File No. 001-33147).

10.5			Amendment and Waiver of Third Amended and Restated Credit Agreement, dated as of August 12, 2015, between Sanchez Production Partners LP, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent and as Collateral Agent (incorporated herein by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q filed by Sanchez Production Partners LP on August 14, 2015, File No. 001-33147).

10.6			Joinder, Assignment and Second Amendment to Third Amended and Restated Credit Agreement, dated as of October 14, 2015, among Sanchez Production Partners LP, Royal Bank of Canada, as administrative agent and collateral agent, and the lenders party thereto (incorporated herein by reference to Exhibit 10.3 to the Current Report on Form 8-K filed by Sanchez Production Partners LP on October 14, 2015, File No. 001-33147).


10.7			Third Amendment to Third Amended and Restated Credit Agreement, dated as of November 12, 2015, among Sanchez Production Partners LP, Royal Bank of Canada, as administrative agent and collateral agent, and the lenders party thereto (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by Sanchez Production Partners LP on November 13, 2015, File No. 001-33147).

10.8			Fourth Amendment to Third Amended and Restated Credit Agreement among Sanchez Production Partners LP, the guarantors party thereto, each of the lenders party thereto, and Royal Bank of Canada, as administrative agent and collateral agent, dated July 5, 2016 (incorporated by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q filed by Sanchez Production Partners LP on August 12, 2016, File No. 001-33147).

10.9			Fifth Amendment to the Third Amended and Restated Credit Agreement dated as of April 17, 2017, between Sanchez Production Partners LP, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent and as Collateral Agent (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q filed by Sanchez Production Partners LP on May 15, 2017, File No. 001-33147).
10.10			Sixth Amendment to the Third Amended and Restated Credit Agreement dated as of November 7, 2017, between Sanchez Midstream Partners LP, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent and as Collateral Agent (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q filed by Sanchez Midstream Partners LP on November 14, 2017, File No. 001-33147).
10.11*			Seventh Amendment to the Third Amended and Restated Credit Agreement dated as of February 5, 2018, between Sanchez Midstream Partners LP, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent and as Collateral Agent.
10.12*			Summary Compensation of Executive Officers of Sanchez Midstream Partners GP LLC.

10.13*			Summary Compensation of Directors of Sanchez Midstream Partners GP LLC.

10.14			Amended and Restated Shared Services Agreement, dated as of March 6, 2015, between SP Holdings, LLC and Sanchez Production Partners LP (incorporated herein by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q filed by Sanchez Production Partners LP on May 15, 2015, File No. 001-33147).

10.15			Contract Operating Agreement, dated May 8, 2014, between Constellation Energy Partners LLC and Sanchez Oil & Gas Corporation (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K filed by Constellation Energy Partners LLC on May 8, 2014, File No. 001-33147).

10.16			Geophysical Seismic Data Use License Agreement, dated May 8, 2014, between Constellation Energy Partners, LLC, certain subsidiaries thereof, and Sanchez Oil & Gas Corporation (incorporated herein by reference to Exhibit 10.4 to the Current Report on Form 8-K filed by Constellation Energy Partners LLC on May 8, 2014, File No. 001-33147).

10.17			Amendment One to License Agreement, dated as of March 6, 2015, by and among Sanchez Oil and Gas Corporation, Sanchez Production Partners LP and SEP Holdings IV, LLC (incorporated herein by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q filed by Sanchez Production Partners LP on May 15, 2015, File No. 001-33147).

10.18			Firm Gathering and Processing Agreement, dated as of October 14, 2015, by and between Catarina Midstream, LLC and SN Catarina, LLC (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by Sanchez Production Partners LP on October 14, 2015, File No. 001-33147).


10.19			Amendment No. 1 to Firm Gathering and Processing Agreement by and between SN Catarina, LLC and Catarina Midstream, LLC, dated June 30, 2017 (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q filed by Sanchez Midstream Partners LP on August 14, 2017, File No. 001-33147).
10.20+			Board Representation and Standstill Agreement, dated as of October 14, 2015, between Sanchez Production Partners LP and the purchaser named therein (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K filed by Sanchez Production Partners LP on October 14, 2015, File No. 001-33147).
10.21+			Sanchez Production Partners LP Long-Term Incentive Plan (incorporated herein by reference to Exhibit 4.6 to the Post-Effective Amendment No. 1 to the Registration Statement on Form S-4 filed by Sanchez Production Partners LP on March 6, 2015, File No. 333-198440).

10.22+			Form of Award Agreement Relating to Restricted Units (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by Sanchez Production Partners LP on December 3, 2015, File No. 001-33147).

10.23+			Form of Award Agreement Relating to Restricted Units (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by Sanchez Production Partners LP on March 28, 2017, File No. 001-33147).
10.24			Settlement Agreement and Release, effective January 25, 2017, by and between Stonepeak Catarina Holdings LLC and Sanchez Production Partners LP (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by Sanchez Production Partners LP on January 27, 2017, File No. 001-33147).

21.1*			List of subsidiaries of Sanchez Midstream Partners LP.

23.1*			Consent of KPMG LLP.

23.2*			Consent of Ryder Scott Co. LP.

31.1*			Certification of Chief Executive Officer of Sanchez Midstream Partners GP LLC pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2*			Certification of Chief Financial Officer and Secretary of Sanchez Midstream Partners GP LLC pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1*			Certification of Chief Executive Officer of Sanchez Midstream Partners GP LLC pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2*			Certification of Chief Financial Officer and Secretary of Sanchez Midstream Partners GP LLC pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

99.1*			Report of Ryder Scott Co. LP

101.INS*			XBRL Instance Document

101.SCH*			XBRL Schema Document

101.CAL*			XBRL Calculation Linkbase Document

		Page
PART I
Item 1.	Business	5
Item 1A.	Risk Factors	19
Item 1B.	Unresolved Staff Comments	51
Item 2.	Properties	52
Item 3.	Legal Proceedings	52
Item 4.	Mine Safety Disclosures	52

PART II
Item 5.	Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	53
Item 6.	Selected Financial Data	56
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operation	57
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	72
Item 8.	Financial Statements and Supplementary Data	72
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	72
Item 9A.	Controls and Procedures	72
Item 9B.	Other Information	73

PART III
Item 10.	Managers, Executive Officers and Corporate Governance	74
Item 11.	Executive Compensation	79
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	81
Item 13.	Certain Relationships and Related Transactions, and Manager Independence	83
Item 14.	Principal Accounting Fees and Services	85

PART IV
Item 15.	Exhibits and Financial Statement Schedules	87
Item 16.	Form 10-K Summary	92
	Signatures	93

101.LAB*			XBRL Label Linkbase Document

101.PRE*			XBRL Presentation Linkbase Document

101.DEF*			XBRL Definition Linkbase Document


		Page

Sanchez Midstream Partners LP and Subsidiaries:
Reports of Independent Registered Public Accounting Firm		F-2
Consolidated Statements of Operations		F-4
Consolidated Balance Sheets		F-5
Consolidated Statements of Cash Flows		F-6
Consolidated Statements of Changes in Partners’ Capital		F-7
Notes to Consolidated Financial Statements		F-8